##### Table of Contents



UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
   Form 10-K (Mark One)[X]
    
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2003
 or [  ]
    
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period from            to
 Commission file number 0-31095 Duke Energy Field Services, LLC  Delaware
(State or other jurisdiction
of incorporation or organization)
    
    76-0632293
(I.R.S. Employer
Identification No.)
 370 17th Street, Suite 2500Denver, Colorado
(Address of principal executive offices)
    
    80202
(Zip Code)
 Registrants telephone number, including area code303-595-3331
Securities registered pursuant to Section 12(b) of the Act: Name of Each ExchangeTitle of Each Class
    
    on Which RegisteredNone
    
    Not Applicable
 Securities registered pursuant to Section 12(g) of the Act:
Limited Liability Company Member Interests
(Title of class) Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months or for such shorter period that the
registrant was required to file such reports and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [  ] Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrants knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X] Indicate by check mark whether the registrant is an accelerated filer as
defined by Rule 12b-2 of the Act. Yes[  ] No[X] As of March 17, 2004, 69.7% of the registrants outstanding member
interests is beneficially owned by Duke Energy Corporation and 30.3% is
beneficially owned by ConocoPhillips. The aggregate market value of the voting
and non-voting member interests held by non-affiliates of the registrant
computed by reference to the price at which the member interests were last
sold, or the average bid and asked price for such member interests, as of the
last business day of the registrants most recently completed fiscal quarter
was $0. Documents incorporated by reference:
None




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TABLE OF CONTENTS  PART I.ITEM 1. Business.Our BusinessOur Business StrategyNatural Gas Gathering, Processing, Transportation, Marketing and StorageNatural Gas Liquids Transportation, Fractionation, Marketing and TradingTEPPCONatural Gas SuppliersCompetitionRegulationEnvironmental MattersEmployeesITEM 2. Properties.ITEM 3. Legal Proceedings.ITEM 4. Submission of Matters to a Vote of Security Holders.PART II.ITEM 5. Market for Registrants Common Equity and Related Stockholder Matters.ITEM 6. Selected Financial Data.ITEM 7. Managements Discussion and Analysis of Financial Condition and Results of Operations.ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.ITEM 8. Financial Statements and Supplementary Data.ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.ITEM 9A. Controls and ProceduresPART III.ITEM 10. Directors and Executive Officers of the Registrant.ITEM 11. Executive Compensation.ITEM 12. Security Ownership of Certain Beneficial Owners and Management.ITEM 13. Certain Relationships and Related Transactions.ITEM 14. Principal Accounting Fees and ServicesPART IV.ITEM 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.SIGNATURESEXHIBIT INDEXConsent of Deloitte & Touche LLPCertification of Chief Financial OfficerCertification of Chief Executive OfficerCertification of Chief Financial OfficerCertification of Chief Executive Officer    Table of Contents  DUKE ENERGY FIELD SERVICES, LLC
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2003 TABLE OF CONTENTS Item
    
    
    
    PagePART I.1.
    
    
    Business
    
    
    3Our Business
    
    
    3Our Business Strategy
    
    
    4Natural Gas Gathering, Processing, Transportation, Marketing
and Storage
    
    
    5Natural Gas Liquids Transportation, Fractionation,
Marketing and Trading
    
    
    10TEPPCO
    
    
    11Natural Gas Suppliers
    
    
    12Competition
    
    
    13Regulation
    
    
    13Environmental Matters
    
    
    14Employees
    
    
    152.
    
    
    Properties
    
    
    163.
    
    
    Legal Proceedings
    
    
    164.
    
    
    Submission of Matters to a Vote of Security Holders
    
    
    16PART II.5.
    
    
    Market for Registrants Common Equity and RelatedStockholder Matters
    
    
    176.
    
    
    Selected Financial Data
    
    
    187.
    
    
    Managements Discussion and Analysis of Financial Condition
and Results of Operations
    
    
    207A.
    
    
    Quantitative and Qualitative Disclosures About Market
Risk
    
    
    338.
    
    
    Financial Statements and Supplementary Data
    
    
    429.
    
    
    Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure
    
    
    759A.
    
    
    Controls and Procedures
    
    
    75PART III.10.
    
    
    Directors and Executive Officers of the Registrant
    
    
    7611.
    
    
    Executive Compensation
    
    
    7812.
    
    
    Security Ownership of Certain Beneficial Owners and
Management
    
    
    8213.
    
    
    Certain Relationships and Related Transactions
    
    
    8214.
    
    
    Principal Accounting Fees and Services
    
    
    84PART IV.15.
    
    
    Exhibits, Financial Statement Schedules and Reportson Form 8-K
    
    
    85Signatures
    
    
    86Exhibit Index
    
    
    87
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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS Our reports, filings and other public announcements may from time to time
contain statements that do not directly or exclusively relate to historical
facts. Such statements are forward-looking statements within the meaning of
the Private Securities Litigation Reform Act of 1995. You can typically
identify forward-looking statements by the use of forward-looking words, such
as may, could, project, believe, anticipate, expect, estimate,
potential, plan, forecast and other similar words. All statements that are not statements of historical facts, including
statements regarding our future financial position, business strategy, budgets,
projected costs and plans and objectives of management for future operations,
are forward-looking statements. These forward-looking statements reflect our intentions, plans,
expectations, assumptions and beliefs about future events and are subject to
risks, uncertainties and other factors, many of which are outside our control.
Important factors that could cause actual results to differ materially from the
expectations expressed or implied in the forward-looking statements include
known and unknown risks. Known risks include, but are not limited to, the
following:  
    
    our ability to access the debt and equity markets, which will depend
on general market conditions and the credit ratings for our debt
obligations;
    
    our use of derivative financial instruments to hedge commodity and interest rate risks;
    
    the level of creditworthiness of counterparties to transactions;
    
    the amount of collateral required to be posted from time to time in our transactions;
    
    changes in laws and regulations, particularly with regard to taxes,
safety and protection of the environment or the increased regulation of
the gathering and processing industry;
    
    the timing and extent of changes in commodity prices, interest rates,
foreign currency exchange rates and demand for our services;
    
    weather and other natural phenomena;
    
    industry changes, including the impact of consolidations, and changes in competition;
    
    our ability to obtain required approvals for construction or
modernization of gathering and processing facilities, and the timing of
production from such facilities, which are dependent on the issuance by
federal, state and municipal governments, or agencies thereof, of
building, environmental and other permits, the availability of
specialized contractors and work force and prices of and demand for
products;
    
    the extent of success in connecting natural gas supplies to gathering
and processing systems;
    
    general economic conditions, including any potential effects arising
from terrorist attacks and any consequential hostilities or other
hostilities; and
    
    The effect of accounting pronouncements issued periodically by
accounting standard-setting bodies. In light of these risks, uncertainties and assumptions, the events
described in the forward-looking statements might not occur or might occur to a
different extent or at a different time than we have described. We undertake no
obligation to publicly update or revise any forward-looking statements, whether
as a result of new information, future events or otherwise. 2




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PART I. 
 ITEM 1.Business. Duke Energy Field Services, LLC is a company formed in 1999 that holds to
the extent that it existed at the time, the combined North American midstream
natural gas gathering, processing, marketing and natural gas liquids (NGL)
business of Duke Energy Corporation (Duke Energy) and Phillips Petroleum
Company (Phillips) prior to its merger with Conoco Inc. (ConocoPhillips).
References to ConocoPhillips, for periods prior to the merger of Conoco Inc.
and Phillips, are references to Phillips. The transaction in which those
businesses were combined is referred to in thisForm 10-Kas the Combination.
Our limited liability company agreement limits the scope of our business to the
midstream natural gas industry in the United States and Canada, the marketing
of NGLs in Mexico and the transportation, marketing and storage of other
petroleum products, unless otherwise approved by our Board of Directors. Unless the context otherwise requires, descriptions of assets, operations
and results in thisForm 10-Kgive effect to the Combination and related
transactions, the transfer to us of additional midstream natural gas assets
acquired by Duke Energy or ConocoPhillips prior to the Combination and the
transfer to us of the general partner of TEPPCO Partners, L.P., all of which
are described in more detail under Managements Discussion and Analysis of
Financial Condition and Results of Operations. In thisForm 10-K, the terms
the Company, we, us and our refer to Duke Energy Field Services, LLC
and our subsidiaries, giving effect to the Combination and related
transactions. From a financial reporting perspective, we are the successor to Duke
Energys North American midstream natural gas business that existed at the time
of the Combination. The subsidiaries of Duke Energy that conducted this
business were contributed to us immediately prior to the Combination. For
periods prior to the Combination, Duke Energy Field Services and these
subsidiaries of Duke Energy are collectively referred to herein as the
Predecessor Company. We are a Delaware limited liability company, and we were formed on
December 15, 1999. Our principal executive offices are located at 370 17th
Street, Suite 2500, Denver, Colorado 80202. Our telephone number is
303-595-3331 and our internet website is www.defs.com. 
 Our Business The midstream natural gas industry is the link between exploration and
production of raw natural gas and the delivery of its components to end-use
markets. We operate in the two principal segments of the midstream natural gas
industry:  
    
    natural gas gathering, compression, treating, processing,
transportation, trading and marketing and storage (Natural Gas
Segment); and
    
    NGL fractionation, transportation, marketing and trading (NGLs
Segment). We believe that we are one of the largest gatherers of raw natural gas,
based on wellhead volume, in North America. We are the largest producer, and we
believe that we are one of the largest marketers, of NGLs in North America. In
2003:  
    
    we handled an average of approximately 7.7 trillion British thermal units (Btus) per day of raw natural gas;
    
    we produced an average of approximately 365,000 barrels per day of NGLs;
    
    we marketed and traded an average of approximately 575,000 barrels per day of NGLs; and
    
    we marketed an average of approximately 3.0 trillion Btus per day of natural gas. We gather raw natural gas through gathering systems located in seven major
natural gas producing regions: Permian Basin, Mid-Continent, East Texas-Austin
Chalk-North Louisiana, Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf
of Mexico and Western Canada. At December 31, 2003, our gathering systems
consisted of approximately 58,000 miles of gathering and transmission pipe,
with approximately 34,000 active receipt points. 3




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Our natural gas processing operations involve the separation of raw
natural gas gathered both by our gathering systems and by third party systems
into NGLs and residue gas. We process the raw natural gas at our 56 owned and
operated plants and at 10 third party operated facilities in which we hold an
equity interest. The NGLs separated from the raw natural gas by our processing operations
are either sold and transported as NGL raw mix or further separated through a
process known as fractionation into their individual components (ethane,
propane, butanes and natural gasoline) and then sold as individual components.
We fractionate NGL raw mix at our 10 owned and operated fractionators and at
four third party operated fractionators located on the Gulf Coast in which we
hold an equity interest. We sell NGLs to a variety of customers ranging from large, multi-national
petrochemical and refining companies to small regional retail propane
distributors. Substantially all of our NGL sales are made at market-based
prices, including approximately 40% of our NGL production that is committed to
ConocoPhillips and ChevronPhillips under an existing contract which expires
January 1, 2015. In addition, we use trading and storage to manage our price
risk and provide additional services to our customers. (See Natural Gas
Liquids Transportation, Fractionation, Marketing and Trading in this section.) The residue gas that results from our processing is sold at market-based
prices to marketers and end-users, including large industrial customers and
natural gas and electric utilities serving individual consumers. We market
residue gas directly or through our wholly-owned gas marketing company. We also
store residue gas at our 6.0 billion cubic foot natural gas storage facility. We own the general partner of TEPPCO Partners, L.P. (TEPPCO), a publicly
traded master limited partnership which owns and operates a network of
pipelines and storage and terminal facilities for refined products, liquefied
petroleum gases, petrochemicals, natural gas and crude oil. The general partner
is responsible for the management and operations of TEPPCO. We believe that our
ownership of the general partner of TEPPCO improves our business position in
the gathering and transportation sectors of the midstream natural gas industry. A discussion of the current business and operations of each of our
segments follows the description of our business strategy. For further
discussion of these segments, see Managements Discussion and Analysis of
Financial Condition and Results of Operations. For financial information
concerning our business segments, see Note 18, Business Segments, of the
Notes to Consolidated Financial Statements included in Item 8. Financial
Statements and Supplemental Data. 
 Our Business Strategy Our limited liability company agreement limits the scope of our business
to the midstream natural gas industry in the United States and Canada, the
marketing of NGLs in Mexico, and the transportation, marketing and storage of
other petroleum products, unless otherwise approved by our board of directors.
We have significant midstream natural gas operations in five of the largest
natural gas producing regions in North America. In the current economic
environment, we are pursuing the following strategies:  
    
    Leverage the size and focus of our existing operations.Our size,
scope and concentration of our assets in our regions of operation
provide for opportunities to acquire additional supplies of raw natural
gas. Our market presence and asset base generally provide us
opportunities to use our economies of scale to be a low cost provider in
connecting new raw natural gas supplies and providing value chain
gathering and processing services. In addition, we believe our size and
geographic diversity allow us to benefit from the growth of natural gas
production in multiple regions while mitigating the adverse effects from
a downturn in any one region.
    
    Increase our presence in each aspect of the midstream business.We
are active in each significant aspect of the midstream natural gas value
chain, including raw natural gas gathering, processing and
transportation, NGL fractionation, and NGL and residue gas
transportation and marketing. Each link in the value chain provides us
with an opportunity to earn incremental income from the raw natural gas
that we gather and from the NGLs and residue gas that we produce.
    
    Further streamline our cost structure.We believe that we have a
complementary base of assets from which to further extract operating
efficiencies and cost reductions, while continuing to provide superior
customer service. In addition, we continue to optimize our existing
assets by looking at potential plant consolidation and ensuring
reliability in our plant operations. 4




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Natural Gas Gathering, Processing, Transportation, Marketing and Storage Overview At December 31, 2003, our raw natural gas gathering and processing
operations consisted of:  
    
    approximately 58,000 miles of gathering and transmission pipe, with
connections to approximately 34,000 active receipt points; and
    
    56 owned and operated processing plants and ownership interests in 10
additional third party operated plants, with a combined processing
capacity of approximately 7.9 billion cubic feet per day. In 2003, we gathered, processed and/or transported approximately 7.7
trillion Btus per day of raw natural gas. As a result of new connections
resulting from both increased drilling and released raw natural gas, we
connected approximately 1,300 additional receipt points in 2003. Our raw natural gas gathering and processing operations are located in 10
states in the United States and two provinces in Western Canada. We provide
services in the following key North American natural gas and oil producing
regions: Permian Basin, Mid-Continent, East Texas-Austin Chalk-North Louisiana,
Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf of Mexico and Western
Canada. According to Hart Downstream Energy Services Gas Processors Report
dated November 17, 2003, we are the largest NGL producer in North America. Raw Natural Gas Supply Arrangements.We take ownership, control or custody
of raw natural gas primarily at the wellhead. The producer may dedicate to us
the raw natural gas produced from designated oil and natural gas leases for a
specific term. The term for purchase commitments of dedicated gas can range
from 30 days to life of lease. We obtain access to raw natural gas and provide
our midstream natural gas service principally under three types of processing
contracts: percentage-of-proceeds contracts, fee-based contracts and keep-whole
and wellhead-purchase contracts. See Managements Discussion and Analysis of
Financial Condition and Results of Operations  Overview  Effects of Our Raw
Natural Gas Supply Arrangements for a description of these types of contracts. Raw Natural Gas Gathering.We receive raw natural gas from a diverse group
of producers under contracts with varying durations to provide a stable supply
of raw natural gas through our processing plants. A significant portion of the
raw natural gas that is processed by us is produced by large producers,
including ConocoPhillips, Anadarko, BP, Devon, and Dominion, which together
account for approximately 15% of our processed raw natural gas. We continually seek new supplies of raw natural gas, both to offset
natural declines in production from connected wells and to increase throughput
volume. We obtain new well connections in our operating areas by contracting
for production from new wells or by obtaining raw natural gas that has been
released from other third party gathering systems. Producers may switch raw
natural gas from one gathering system to another to obtain better commercial
terms, conditions and service levels. We believe our asset base and scope of our operations provide us with
opportunities to add released raw natural gas to our systems. In addition, we
have unused processing capacity in the Offshore Gulf of Mexico and Rocky
Mountain regions, which contain quantities of proved natural gas reserves. We
also have a presence in other potential high-growth areas such as the Western
Canadian Sedimentary Basin. Gathering systems are operated at design pressures that will maximize
total throughput from all connected wells. On gathering systems where it is
economically feasible, we operate at a relatively low pressure, which can allow
us to offer a significant benefit to producers. Specifically, lower pressure
gathering systems allow wells, which produce at progressively lower field
pressures as they age, to remain connected to gathering systems and continue to
produce for longer periods of time. As the pressure of a well declines, it
becomes increasingly more difficult to deliver the remaining production in the
ground against a higher pressure that exists in the connecting gathering
system. Field compression is typically used to lower the pressure of a
gathering system. If field compression is not installed, then the remaining
production in the ground will not be produced because it cannot overcome the
higher gathering system pressure. In contrast, if field compression is
installed, then a well can continue delivering production that otherwise would
not be produced. Our field compression systems provide the flexibility of
connecting a high pressure well to the downstream side of the compressor even
though the well is producing at a pressure greater than the upstream side. As
the well ages and the pressure naturally declines, the well can be reconnected
to the upstream, low pressure side of the compressor and continue to produce.
By maintaining 5




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low pressure systems with field compression units, we believe that the
wells connected to our systems are able to produce longer and at higher volumes
before disconnection is required. Raw Natural Gas Processing.Most of our natural gas gathering systems feed
into our natural gas processing plants. Our processing plants received an
average of approximately 6.1 trillion Btus per day of raw natural gas and
produced an average of 365,000 barrels per day of NGLs during 2003. Our natural gas processing operations involve the extraction of NGLs from
raw natural gas, and, at certain facilities, the fractionation of NGLs into
their individual components (ethane, propane, butanes and natural gasoline). We
sell NGLs produced by our processing operations to a variety of customers
ranging from large, multi-national petrochemical and refining companies,
including one of our owners, ConocoPhillips, to small, regional retail propane
distributors. At four of our Mid-Continent facilities the element helium is
isolated from the raw gas stream and sold to industrial gas companies. We also remove off-quality crude oil, nitrogen, hydrogen sulfide, carbon
dioxide and brine from the raw natural gas stream. The nitrogen and carbon
dioxide are released into the atmosphere, and the crude oil and brine are
accumulated and stored temporarily at field compressors or at various plants.
The brine is transported to licensed disposal wells owned either by us or by
third parties. The crude oil is sold in the off-quality crude oil market. Residue Gas Marketing.In addition to our gathering and processing
activities, we are involved in the purchase and sale of residue gas, directly
or through our wholly owned gas marketing company and our affiliates. Our gas
marketing efforts involve supplying the residue gas demands of end-user
customers that are physically attached to our pipeline systems, supplying the
gas processing requirements associated with our keep-whole processing
agreements and selling gas into downstream pipelines. We are focused on
extracting the highest possible value for the residue gas that results from our
processing and transportation operations. Our gas asset based trading and marketing activities are supported by our
ownership of the Spindletop storage facility and various intrastate pipelines
which give us access to market centers/hubs such as Waha, Texas; Katy, Texas
and the Houston Ship Channel. We undertake these activities through the use of
fixed forward sales, basis and spread trades, storage opportunities, put/call
options, term contracts and spot market trading. Our Spindletop storage facility plays an important role in our ability to
act as a full-service natural gas trader and marketer. We lease over half of
the facilitys capacity to our customers, and we use the balance to manage
relatively constant natural gas supply volumes with uneven demand levels,
provide backup service to our customers and support our trading activities. Regions of Operations Our operations cover substantially all of the major natural gas producing
regions in the United States, as well as portions of Western Canada. Our
geographic diversity reduces the impact of regional price fluctuations and
regional changes in drilling activity. Our raw natural gas gathering and processing assets are managed in line
with the seven geographic regions in which we operate. The following table
provides information concerning the raw natural gas gathering systems and
processing plants owned or operated by us at December 31, 2003. Gas
    
    
    
    
    
    
    
    
    
    
    
    
    
    2003 Operating DataGathering
    
    Company
    
    Plants
    
    Net Plant
    
    Plant Inlet
    
    NGLsSystem
    
    Operated
    
    Operated
    
    Capacity(1)
    
    Volume(1)
    
    ProductionRegion
    
    (miles)
    
    Plants
    
    by Others
    
    (MMcf/d)(3)
    
    (BBtu/d)(3)
    
    (Bbls/d)(3)Permian Basin
    
    
    16,708
    
    
    
    15
    
    
    
    1
    
    
    
    1,294
    
    
    
    1,317
    
    
    
    118,232Mid-Continent
    
    
    28,191
    
    
    
    12
    
    
    
    1
    
    
    
    1,998
    
    
    
    1,834
    
    
    
    118,838East Texas-Austin Chalk-North
Louisiana
    
    
    4,123
    
    
    
    5
    
    
    
    
    
    
    
    1,095
    
    
    
    906
    
    
    
    53,082Onshore Gulf of Mexico
    
    
    4,613
    
    
    
    7
    
    
    
    1
    
    
    
    1,118
    
    
    
    857
    
    
    
    35,572Rocky Mountains
    
    
    3,240
    
    
    
    9
    
    
    
    
    
    
    
    475
    
    
    
    402
    
    
    
    21,733Offshore Gulf of Mexico
    
    
    685
    
    
    
    2
    
    
    
    6
    
    
    
    1,302
    
    
    
    328
    (2)
    
    
    10,049Western Canada
    
    
    904
    
    
    
    6
    
    
    
    1
    
    
    
    570
    
    
    
    426
    
    
    
    7,778Total
    
    
    58,464
    
    
    
    56
    
    
    
    10
    
    
    
    7,852
    
    
    
    6,070
    
    
    
    365,284
 6




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(1)
    
    Note that while capacity is measured volumetrically (in cubic feet),
inlet volumes are measured using heating value (in British thermal units).  (2)
    
    Excludes inlet volumes of about 290 BBtu/d net for plants operated by
others.  (3)
    
    MMcf/d: million cubic feet per day; BBtu/d: billion British thermal
units per day; Bbls/d: barrels per day. Our key suppliers of raw natural gas in these seven regions include major
integrated oil companies, independent oil and gas producers, intrastate
pipeline companies and natural gas marketing companies. Our principal
competitors in this segment of our business consist of major integrated oil
companies, independent oil and gas producers, independent oil and gas
gatherers, and interstate and intrastate pipeline companies. Regional Strategies.Continued raw natural gas supply is key to our
success. Maintaining our raw natural gas supply enables us to maintain
throughput volumes and asset utilization throughout our entire midstream
natural gas value chain. We evaluate the nature of the opportunity that a
particular region presents, including the nature of the gas reserves and
production profile, existing midstream infrastructure including capacity and
capabilities, the regulatory environment, the characteristics of the
competition and the competitive position of our assets and capabilities. In a
general sense, we employ one or more of the strategies described below:  
    
    Growth in regions where production is expected to grow
significantly and/or there is a need for additional gathering and
processing infrastructure, we plan to expand our gathering and
processing assets by following a disciplined acquisition strategy, by
expanding existing infrastructure and by constructing new gathering
lines and processing facilities.
    
    Consolidation in regions that include mature producing basins with
flat to declining production or that have excess gathering and
processing capacity, we seek opportunities to efficiently consolidate
the existing asset base to increase utilization and operating
efficiencies and realize economies of scale.
    
    Opportunistic in regions where production growth is not primarily
generated by new exploration drilling activity, we intend to optimize
our existing assets and selectively expand certain facilities or
construct new facilities to seize opportunities to increase our
throughput. These regions are generally experiencing stable to
increasing production through the application of new drilling
technologies like 3-D seismic, horizontal drilling and improved well
completion techniques. The application of new technologies is causing
the drilling of additional wells in areas of existing production and
recompletions of existing wells which create additional opportunities to
add new gas supplies. In each region, we plan to apply both our overall business strategy and
the strategy uniquely suited to each region. We believe this plan will yield
balanced growth initiatives, including new construction in certain high growth
areas, expansion of existing systems, combined with efficiency improvements
and/or asset consolidation. We also plan to rationalize assets and redeploy
capital to higher value opportunities. A description of our operations, key suppliers and principal competitors
in each region is set forth below: Permian Basin.Our facilities in this region are located in West Texas and
Southeast New Mexico. We own majority interests in, and we are the operator of,
15 natural gas processing plants in this region. In addition, we own a minority
interest in one natural gas processing plant that is operated by a third party.
Our natural gas processing plants are strategically located to access Permian
Basin production. Our plants have processing capacity net to our interest of
1.3 billion cubic feet of raw natural gas per day. Operations in this region
are primarily focused on gathering, processing and marketing of natural gas and
NGLs. We offer low, intermediate and high pressure gathering services, and
processing and treating services for both sweet and sour gas production. Two of
our processing facilities provide fractionation services. Residue gas sales are
enhanced by access to the Waha Hub where multiple pipeline interconnects source
gas for virtually every market in the United States. Our older facilities have
been modernized to improve product recoveries, and some of our plants include
facilities for the production of sulfur. During 2003, these plants operated at
an overall 84% capacity utilization rate. As we generally pursue a consolidation strategy in this region, our assets
will allow us to compete for new gas supplies in most major fields and benefit
from the increases in drilling and production from technological advances. In
addition, our ability to redirect gas between several processing plants allows
us to maximize utilization of our processing capacity in this region and
improve reliability. 7




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Our key suppliers in this region include ExxonMobil, Occidental, Anadarko,
ConocoPhillips, Dominion, ChevronTexaco, and Yates. Our principal competitors
in this region include Dynegy, Sid Richardson, ConocoPhillips, Western Gas, BP,
El Paso, Marathon and ChevronTexaco. Mid-Continent.
Our facilities in this region are located in Oklahoma,
Kansas, the Texas Panhandle and four counties in Southeast Colorado. In this
region, we own and are the operator of 12 natural gas processing plants. We
also own a minority interest in one other natural gas processing plant that is
operated by a third party. We gather and process raw natural gas primarily from
the Ardmore and Anadarko Basins, including the prolific Hugoton and
Panhandle fields. Our plants have processing capacity net to our interest of
2.0 billion cubic feet of raw natural gas per day. During 2003, our plants
operated at an overall 81% capacity utilization rate. Existing production in the Mid-Continent region is typically from mature
fields with shallow decline profiles that will provide our plants with a
dependable source of raw natural gas over a long term. With the development of
improved exploration and production techniques such as 3-D seismic and
horizontal drilling over the past several years, additional reserves have
become economically producible in this region. We hold large dedicated acreage
positions with various producers who have developed programs to add
substantially to their reserve base. The infrastructure of our plants and
gathering facilities is uniquely positioned to pursue our consolidation
strategy in this region. Our key suppliers in this region include ConocoPhillips, ExxonMobil,
Gungoll, Newfield, OXY USA, Dominion, EOG, Marathon, Chesapeake, Apache and
Anadarko. Our principal competitors in this region include Oneok, Cantera,
Mustang, Western Gas, Enogex., Regency, Pioneer, Enbridge, and BP. East Texas-Austin Chalk-North Louisiana.Our facilities in this region are
located in East Texas, North Louisiana and the Austin Chalk formation of East
Central Texas and Central Louisiana. We own majority interests in and are the
operator of five natural gas processing plants in this region. Our plants have
processing capacity net to our interest of 1.1 billion cubic feet of raw
natural gas per day. During 2003, these plants operated at an overall 72%
capacity utilization rate. Our East Texas operations are centered around our East Texas Complex,
located near Carthage, Texas. This plant complex is the third largest raw
natural gas processing facility in the continental United States, based on
liquids recovery, and in 2003 produced approximately 33,000 barrels per day of
NGLs. The plant is connected to and processes raw natural gas from our own
gathering systems as well as from several third party gathering systems,
including those owned by Gulf South, Anadarko and American Central. The complex
is adjacent to our Carthage Hub, which delivers residue gas to interconnects
with 11 interstate and intrastate pipelines. The Carthage Hub, with an
aggregate delivery capacity of 1.5 billion cubic feet per day, acts as a key
exchange point for the purchase and sale of residue gas. In the Austin Chalk area, where we provide essential low pressure
gathering and compression services, infill drilling and recompletion activity
continue to offset the lower decline rates of this mature production area.
Given the maturity of this area, consolidation of our own facilities and/or
consolidation with other gathering and processing companies could occur. In the
Eastern Chalk area (Brookeland and Masters Creek), consolidation of the gas
processing facilities was completed in July 2002. Gas prices are supporting new
drilling activity, which has reduced decline rates. Volume declines in the near
term, however, are expected to continue. Additional improvements in technology
or sustained higher gas prices could significantly increase activity and
reserve recovery in either of these two areas. In North Louisiana, we gathered and processed or gathered and transported
approximately 390 billion Btus per day in 2003. We operate one of the largest
intrastate pipelines in Louisiana, the PELICO System, which delivers gas to
industrial customers and electric generators within the state and also makes
deliveries to five interstate pipelines at or near the Perryville Hub. Our key suppliers in this region include Anadarko, Devon and
ConocoPhillips. Our principal competitors in this region include Gulf South,
Regency and Energy Transfer. Onshore Gulf of Mexico.Our facilities in this region are located in South
Texas and the Southeastern portions of the Texas Gulf Coast. We own a 100%
interest in and are the operator of seven natural gas processing plants and the
Spindletop gas storage facility in this region. In addition, we own a minority
interest in one natural gas processing plant that is operated by a third party.
Our plants have processing capacity net to our interest of 1.1 billion cubic
feet of raw natural gas per day. During 2003, the plants in this region ran at
an overall 68% capacity utilization rate. 8




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Our Spindletop natural gas storage facility is located near Beaumont,
Texas and has current working natural gas capacity of 6.0 billion cubic feet,
plus expansion potential of up to an additional 11.5 billion cubic feet. We
have numerous firm and interruptible services available including daily
services, 30-day services and service contracts for up to 10 years. This high
deliverability storage facility interconnects with 9 interstate and intrastate
pipelines and is positioned to meet the continuing changing gas demand market
including the hourly demand needs of the natural gas-fired electric generation
marketplace, currently the fastest growing demand segment of the natural gas
industry. To achieve growth in our Onshore Gulf of Mexico region, we intend to fully
integrate our acquired assets and use the diversity of our current asset base
to provide value-added services to our broad customer base. We will also seek
additional opportunities to participate in the anticipated growth in supply
from this region. Our key suppliers in this region include Apache, Dominion, Bass
Enterprises and El Paso. Our principal competitors in this region include
Gulfterra, Kinder Morgan, Crosstex and Houston Pipe Line. Rocky Mountains.Our facilities in this region are located in the DJ Basin
of Northern Colorado, the Greater Green River Basin and Overthrust Belt areas
of Southwest Wyoming and Northeast Utah. We own a 100% interest in and are the
operator of nine natural gas processing plants in this region. Our plants have
processing capacity of 475 million cubic feet of raw natural gas per day.
During 2003, our plants in this region operated at an overall 70% capacity
utilization rate. The Rocky Mountains region has well placed assets with strong competitive
positions in areas that are expected to benefit from increased drilling
activity, providing us with a platform for growth. In this region, we expect to
achieve growth through our existing assets, strategic acquisitions and
development of new facilities. In addition, we intend to pursue an
opportunistic strategy in areas of the region where new technologies and
recovery methods are being employed. Our key suppliers in the region include Patina, BP, Kerr-McGee and
Anadarko. Our principal competitors in this region include Kerr-McGee, Williams
and Western Gas. Offshore Gulf of Mexico.Our facilities in this region are located along
the Gulf Coast areas of Louisiana, Mississippi and Alabama. We own an average
48% interest in and are the operator of two natural gas processing plants in
this region. In addition, we own a 51% interest in one natural gas processing
plant and minority interests in five other natural gas processing plants, all
of which are operated by third parties. The plants have processing capacity net
to our interest of 1.3 billion cubic feet of raw natural gas per day. During
2003, our plants in this region operated at an overall 44% capacity utilization
rate. All of these plants straddle offshore pipeline systems delivering a lower
NGL content gas stream than that of our onshore gathering systems. In addition, we own a 71.8% interest in Dauphin Island Gathering Partners
(Dauphin Island), a partnership which owns and operates offshore gathering
and transmission systems. Dauphin Island has attractive market outlets,
including deliveries to Texas Eastern Transmission (TETCO), Gulfstream
Natural Gas System, Transco, Gulf South, and Florida Gas Transmission for
re-delivery to the Southeast, Mid-Atlantic, Northeast and New England natural
gas markets. Dauphin Islands leased capacity on TETCOs pipeline provides us
with a means to cross the Mississippi River to deliver or receive production
from the Venice, Louisiana natural gas hub area. Further, the Main Pass Oil
Gathering Company system, in which we own a 33.3% interest, also has access to
a variety of shallow-water and deep-water oil production platforms and dual
market outlets into Shells Delta terminal as well as ChevronTexacos Cypress
terminal. On May 31, 2002, we acquired 33.3% of the outstanding membership interests
in Discovery Producer Services, LLC (Discovery). The Discovery assets, which
were primarily constructed in 1997, extend from deepwater offshore Louisiana to
onshore delivery points approximately 30 miles south of New Orleans. Discovery
owns and operates a 600 million cubic feet per day (MMcf/d) interstate
pipeline, including a 30-inch mainline that extends to the edge of the outer
continental shelf, a condensate handling facility, a 600 MMcf/d cryogenic gas
processing plant, a 42,000 barrels per day fractionator, 400 MMcf/d of
deepwater gathering laterals and a fixed-leg platform at Grand Isle 115 to host
deepwater developments. We believe that the Offshore Gulf of Mexico production area will be one of
the most active regions for new drilling in the United States. Our strategic
plan for this region is to connect new facilities to our existing base so that
we can realize new offshore development opportunities. Our existing assets in
the eastern Gulf of Mexico are positioned to access new and ongoing production
developments. 9




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Our key suppliers in the Offshore Gulf of Mexico region include El Paso,
ExxonMobil, Dominion and ENI. Our principal competitors in this region include
BP, Shell, Williams and Gulfterra. Western Canada. We own interests in seven natural gas processing plants in
Western Canada and operate six of these plants. These facilities are located in
northeastern British Columbia, the Peace River Arch area of northwestern
Alberta and the central plains and foothills area of Alberta. In total, the
facilities in this region have processing capacity net to our interest of 570
million cubic feet of raw sour natural gas per day. During 2003, our processing
plants in this area operated at an overall 66% capacity utilization rate. Most
of our processing facilities in this area are new, with the majority having
been constructed since 1995. Our processing arrangements are primarily
fee-based, providing an income stream that is not directly subject to
fluctuations in commodity prices. Our operations in Canada are subject to risks
inherent in transactions involving foreign currencies. Our key suppliers in this region include Burlington, Canadian Natural
Resources, EnCana and Devon. Our principal competitors in the area include
Keyspan, Taylor, Enerpro and Altagas. 
 Natural Gas Liquids Transportation, Fractionation, Marketing and Trading Overview We market our NGLs and provide marketing services to third party NGL
producers and sales customers in significant NGL production and market centers
in the United States. In 2003, we marketed and traded approximately 575,000
barrels per day of NGLs, of which approximately 64% was production for our own
account. Our NGL services include plant tailgate purchases, transportation,
fractionation, flexible pricing options, price risk management and
product-in-kind agreements. Our primary NGL operations are located in close
proximity to our gathering and processing assets in each of the regions in
which we operate, other than Western Canada. In 2001, we acquired five propane rail terminals and constructed one in
the northeastern United States. Marketing propane from these rail terminals,
along with volume from TEPPCOs Providence, Rhode Island import facility,
accounts for approximately 27,000 barrels per day of wholesale business. We possess a large asset base of NGL fractionators and pipelines that are
used to provide value-added services to our refining, chemical, industrial,
retail and wholesale propane-marketing customers. We intend to capture premium
value in local markets while maintaining a low cost structure by maximizing
facility utilization at our 10 owned and operated fractionators and four
fractionators operated by others, including two at the Mont Belvieu market
center, and 13 pipeline systems. Our current total fractionation capacity is
approximately 166,000 barrels per day. Strategy Our interconnected natural gas processing operations provide us with an
opportunity to capture fee-based investment opportunities in certain NGL
assets, including pipelines, fractionators and terminals. In conjunction with
this investment strategy and as an enhancement to the margin generation from
our NGL assets, we also intend to focus on the following areas: producer
services, local sales and fractionation, market hub fractionation,
transportation and market center trading and storage, each of which is
discussed briefly below. Customer Services.We plan to continue to expand our services to
customers, including producers and end users, principally in the areas of price
risk management and marketing of their products. Over the last several years,
we have expanded our supply base significantly beyond our own equity production
by providing a long term market for third party NGLs at competitive prices. Local Sales and Fractionation.We will seek opportunities to maximize the
value of our product by continuing to expand local sales. We have fractionation
capabilities at 10 of our owned and operated raw natural gas processing plants,
and at two raw natural gas processing plants in which we own minority interests
and which are operated by others. Our ability to fractionate NGLs at regional
processing plants provides us with direct access to local NGL markets. Market Hub Fractionation.We will continue to focus on optimizing our
product slate from our two Mont Belvieu, Texas market center fractionators, the
Mont Belvieu I and Enterprise Products fractionators, where we have a combined
owned capacity of 57,000 barrels per day. The control of products from these
fractionators complements our market center trading activity. 10




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Transportation.We use company owned NGL pipelines to transport
approximately 43,000 barrels per day of our total NGL pipeline volumes,
providing transportation to market center fractionation hubs or to end use
markets. We also are a significant shipper on third party pipelines in the
Rocky Mountains, East Texas, Mid-Continent and Permian Basin producing regions
and, as a result, receive the benefit of incentive rates on many of our NGL
shipments. Market Center Trading and Storage.We use trading and storage at the Mont
Belvieu, Texas and Conway, Kansas NGL market centers to manage our price risk
and provide additional services to our customers. We undertake these activities
through the use of fixed forward sales, basis and spread trades, storage
opportunities, put/call options, term contracts and spot market trading. We
believe there are additional opportunities to grow our price risk management
services with our customer base. Wholesale Propane Marketing.We continue to expand our propane wholesale
marketing activity into areas where asset infrastructure exists. We currently
utilize rail, pipeline and waterborne import facility assets to transport
propane to market. Propane wholesale marketing involves the purchase of propane
from both our Natural Gas Segment and third party producers for delivery and
sale to wholesale and end use customers. Additionally, we provide our wholesale
customers price risk products such as fixed price and option contracts to
mitigate the seasonal price fluctuations of propane. Key Suppliers and Competition The marketing of NGLs is a highly competitive business that involves
integrated oil and natural gas companies, midstream gathering and processing
companies, trading houses, international liquid propane gas producers and
refining and chemical companies. There is competition to source NGLs from plant
operators for movement through pipeline networks and fractionation facilities
as well as to supply large consumers such as multi-state propane, refining and
chemical companies with their NGL needs. Our largest suppliers are our own
processing plants and Oneok, Koch, ConocoPhillips and RME. Our largest sales
customers are ChevronPhillips, ConocoPhillips, Dow Hydrocarbons and Formosa
Plastics which accounted for approximately 24%, 18%, 5%, and 4%, respectively,
of our total NGL transportation, fractionation and marketing revenues in 2003.
Our principal competitors in the marketing of NGLs are Enterprise Products,
Koch, Dynegy and Louis Dreyfus. In 2003, we marketed and traded an average of
approximately 575,000 barrels per day. 
 TEPPCO On March 31, 2000, we obtained by transfer from Duke Energy, ownership of
the general partner of TEPPCO, a publicly traded master limited partnership.
TEPPCO operates in three principal areas:  
    
    refined products, liquefied petroleum gases and petrochemicals transportation (Downstream Segment);
    
    crude oil gathering, transportation and marketing (Upstream Segment); and
    
    natural gas gathering, NGLs transportation and NGLs fractionation (Midstream Segment). TEPPCOs Downstream Segment is one of the largest pipeline common carriers
of refined petroleum products and liquefied petroleum gases in the United
States. This system is comprised of an approximate 4,600 mile products pipeline
system, extending from southeast Texas through central and midwest states to
the northeast United States and is the only pipeline system that transports
liquefied petroleum gases to the northeast United States from the Texas Gulf
Coast. Its operations include the interstate transportation, storage and
terminaling of petroleum products; short-haul shuttle transportation of
liquefied petroleum gas at its Mont Belvieu, Texas complex; and other ancillary
services. TEPPCOs Downstream Segment also owns and operates three
petrochemical pipelines in Texas between Mont Belvieu and Port Arthur. As of
February 10, 2003, TEPPCOs Downstream Segment also owns a 50% interest in
Centennial Pipeline LLC (Centennial), which owns and operates an interstate
refined petroleum products pipeline extending from the upper Texas Gulf Coast
to central Illinois. Marathon Ashland Petroleum LLC owns the other 50%
interest. At December 31, 2003, TEPPCOs Downstream Segment also owns a 50%
interest in Mont Belvieu Storage Partners, L.P. (MB Storage), which serves
the fractionation, refining and petroleum industries, providing substantial
capacity and flexibility for the transportation, terminaling and storage of
NGLs, liquefied petroleum gases and refined products. Louis Dreyfus owns the
other 50% interest. TEPPCOs Upstream Segment owns and operates approximately 3,650 miles of
crude oil trunk line and gathering pipelines, primarily in Oklahoma, New
Mexico, Texas and the Rocky Mountain region. It also owns a 50% interest in
Seaway Crude Pipeline Company (Seaway), which owns an approximately 500 mile,
large diameter crude oil pipeline that transports primarily imported 11




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crude oil from the Texas Gulf Coast to the mid-continent and midwest
refining sectors. ConocoPhillips owns the other 50% interest in Seaway. In
addition, TEPPCOs Upstream Segment owns crude oil storage tanks at Cushing,
Oklahoma and Midland, Texas, and interests in two crude oil pipelines operating
in New Mexico, Oklahoma and Texas. TEPPCOs Midstream Segment owns and operates approximately 500 miles of
NGLs pipelines located along the Texas Gulf Coast and two fractionators in
Colorado. In September 2001, TEPPCOs Midstream Segment acquired Jonah Gas
Gathering Company, which gathers natural gas in the Green River Basin in
southwestern Wyoming. The Jonah natural gas gathering system consists of
approximately 480 miles of pipelines. Natural gas gathered on the Jonah system
is delivered to several interstate pipeline systems that provide access to a
number of West Coast, Rocky Mountain and midwest markets. On March 1, 2002,
TEPPCOs Midstream Segment expanded its NGLs operations with the acquisition of
the Chaparral and Quanah pipelines, which consist of a combined 1,000 miles of
gathering and trunk pipelines extending from southeastern New Mexico and West
Texas to Mont Belvieu, Texas. On June 30, 2002, TEPPCOs Midstream Segment
acquired the Val Verde coal seam gas gathering system from a subsidiary of
Burlington Resources Inc. The Val Verde gathering system consists of 360 miles
of pipeline, 14 compressor stations and a large amine treating facility for the
removal of carbon dioxide. The system has a pipeline capacity of approximately
one billion cubic feet of gas per day. The Val Verde gathering system gathers
coal seam gas from the Fruitland Coal Formation of the San Juan Basin in New
Mexico and Colorado. The system is one of the largest coal seam gas gathering
and treating facilities in the United States. Certain of the assets of
TEPPCOs Midstream Segment are operated and commercially managed by us under
agreements with TEPPCO. The general partner of TEPPCO manages and directs TEPPCO under the TEPPCO
partnership agreement and the partnership agreements of its operating
partnerships. Under these partnership agreements, the general partner of TEPPCO
is reimbursed for all direct and indirect expenses it incurs and payments it
makes on behalf of TEPPCO. TEPPCO makes quarterly cash distributions of its available cash, which
consists generally of all cash receipts less disbursements and cash reserves
necessary for working capital, anticipated capital expenditures and
contingencies and debt payments, the amounts of which are determined by the
general partner of TEPPCO. The partnership agreements provide for incentive distributions payable to
the general partner of TEPPCO out of TEPPCOs available cash in the event
quarterly distributions to its unitholders exceed certain specified targets. In
general, subject to certain limitations, if a quarterly distribution exceeds a
target of $.275 per limited partner unit, the general partner of TEPPCO will
receive incentive distributions equal to:  
    
    15% of that portion of the distribution per limited partner unit
which exceeds the minimum quarterly distribution amount of $.275 but is
not more than $.325, plus
    
    25% of that portion of the quarterly distribution per limited partner
unit which exceeds $.325 but is not more than $.45, plus
    
    50% of that portion of the quarterly distribution per limited partner
unit which exceeds $.45. At TEPPCOs 2003 per unit distribution level, the general partner received
approximately 27% of the cash distributed by TEPPCO to its partners, which
consisted of 25% from the incentive cash distribution and 2% from the general
partner interest. During 2003, total cash distributions to the general partner
of TEPPCO were $55 million. At TEPPCOs current per unit distribution level, we
expect to receive total cash distributions of approximately $65 million in
2004. 
 Natural Gas Suppliers We purchase substantially all of our raw natural gas from producers under
varying term contracts. We take ownership of raw natural gas primarily at the
wellhead, settling payments with producers on terms set forth in the applicable
contracts. These producers range in size from small independent owners and
operators to large integrated oil companies, such as ConocoPhillips, our
largest single supplier. No single producer accounted for more than 10% of our
natural gas throughput in 2003. Each producer often dedicates to us the raw
natural gas produced from designated oil and natural gas leases for a specific
term. The term for dedicated gas can range from 30 days to life of lease. We
consider our relationships with our many producers to be good. For a
description of the types of contracts we have entered into with our suppliers,
see Managements Discussion and Analysis of Financial Condition and Results of
Operations  Overview  Effects of Our Raw Natural Gas Supply Arrangements. 12




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Competition We face strong competition in acquiring raw natural gas supplies. Our
competitors in obtaining additional gas supplies and in gathering and
processing raw natural gas include:  
    
    major integrated oil companies;
    
    major interstate and intrastate pipelines or their affiliates;
    
    independent oil and gas producers;
    
    other large raw natural gas gatherers that gather, process and market natural gas and/or NGLs; and
    
    a relatively large number of smaller raw natural gas gatherers of varying financial resources and experience. Competition for raw natural gas supplies is concentrated in geographic
regions based upon the location of gathering systems and processing plants.
Although we are one of the largest gatherers and processors in most of the
geographic regions in which we operate, most producers in these areas have
alternate gathering and processing facilities available to them. In addition,
producers have other alternatives, such as building their own gathering
facilities or in some cases selling their raw natural gas supplies without
processing. Competition for raw natural gas supplies in these regions is
primarily based on:  
    
    the reputation, efficiency and reliability of the gatherer/processor,
including the operating pressure of the gathering system;
    
    the availability of gathering and transportation;
    
    the pricing arrangement offered by the gatherer/processor; and
    
    the ability of the gatherer/processor to obtain a satisfactory price for the producers residue gas and extracted NGLs. In addition to competition in raw natural gas gathering and processing,
there is vigorous competition in the marketing of residue gas. Competition for
customers is based primarily upon the price of the delivered gas, the services
offered by the seller, and the reliability of the seller in making deliveries.
Residue gas also competes on a price basis with alternative fuels such as oil
and coal, especially for customers that have the capability of using these
alternative fuels and on the basis of local environmental considerations. Also,
to foster competition in the natural gas industry, certain regulatory actions
of the Federal Energy Regulatory Commission (FERC) and some states have
allowed buying and selling to occur at more points along transmission and
distribution systems. Competition in the NGLs marketing area comes from other midstream NGL
marketing companies, international producers/traders, chemical companies,
refineries and other asset owners. Along with numerous marketing competitors,
we offer price risk management and other services. We believe it is important
that we tailor our services to the end-use customer to remain competitive. 
 Regulation Natural Gas Transportation.We own ten natural gas intrastate pipelines
that are subject to state and federal regulation. Seven of these pipelines
provide service on behalf of interstate pipelines. Such service is governed by
Section 311 of the Natural Gas Policy Act of 1978 and causes such pipelines to
be subject to FERC regulation. FERC approves the maximum transportation rate
that can be charged and approves other terms and conditions of service when
these 7 intrastate pipelines receive gas from or deliver gas to interstate
pipelines. We are the managing partner of a FERC-regulated-pipeline, Dauphin Island
Gathering Partners (DIGP), and have a non-operating interest in another
FERC-regulated pipeline, Discovery Gas Transmission, LLC (Discovery). The
rates, terms and conditions of service and pipeline modification on these
pipelines are subject to regulation by the FERC under the Natural Gas Act of
1938 (NGA). The NGA requires, among other things, that pipeline rates be just
and reasonable and non-discriminatory. On November 25, 2003, the FERC issued new Standards of Conduct for
interstate natural gas pipelines and their energy affiliates (Standards of
Conduct). Under the Standards of Conduct, interstate pipeline entities cannot
share pipeline operating information, 13




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including daily operating information, future expansion plans and shipper
information, with their Energy Affiliates (as defined in the Standards of
Conduct). The new Standards of Conduct will apply to us as a result of our
ownership interest in DIGP and Discovery because we are considered an Energy
Affiliate under Order 2004. Energy Affiliate has been broadly defined in the
proposed rule to include any affiliate that buy[s], sell[s] trades or
administer[s] natural gas ... in U.S. energy or transmission markets.
Interstate pipelines are required to be in compliance with the rule by June 1,
2004. We do not anticipate any compliance issues with the
implementation of the Standards of Conduct. Natural Gas Gathering and Processing.The NGA exempts natural gas
gathering facilities from FERC jurisdiction. However, certain states in which
we own gathering facilities have adopted laws and regulations that require
gatherers either to purchase without undue discrimination as to source or
supplier or to take ratably, without undue discrimination, natural gas
production that may be tendered to the gatherer for handling. For example, the
states of Oklahoma and Kansas have adopted complaint-based statutes that allow
the Oklahoma Corporation Commission and the Kansas Corporation Commission,
respectively, to remedy discriminatory rates for providing gathering service
where the parties are unable to agree. In a similar way, the Railroad
Commission of Texas sponsors a complaint procedure for resolving grievances
about natural gas gathering access and rate discrimination. Transportation and Sales of Natural Gas Liquids.We own non-operating
interests in two pipelines that transport natural gas liquids (NGLs) in
interstate commerce. The rates, terms and conditions of service on these
pipelines are subject to FERC regulation under the Interstate Commerce Act. The
Interstate Commerce Act requires, among other things, that NGL pipeline rates
be just and reasonable and non-discriminatory. At this time, FERC allows NGL
pipeline rates to be established on a number of bases, including historic cost,
historic cost plus an index and market factors. While NGL sales prices are not
currently regulated, the ability to sell NGLs and the pricing of such NGLs is
often dependent on and affected by access to NGL pipelines and the rates, terms
and conditions of such pipelines. U.S. Department of Transportation.Some of our natural gas pipelines are
subject to regulation by the U.S. Department of Transportation (DOT) with
respect to design, installation, testing, construction, operation, replacement
and management. Comparable regulations exist in some states where we do
business. These regulations provide for safe pipeline operations and include
potential fines and penalties for violations. The Pipeline Safety Improvement
Act of 2002, which was enacted on December 17, 2002, establishes mandatory
inspections for all U.S oil and natural gas transmission pipelines and some
gathering lines in high-consequence areas within 10 years. The DOT has
developed regulations implementing the Pipeline Safety Improvement Act that
will require pipeline operators to implement integrity management programs,
including more frequent inspections and other safety protections in areas where
the consequences of potential pipeline accidents pose the greatest risk to
people and their property. At this time we are unable to estimate the expected
cost of complying with these regulations. Safety and Health.Certain federal statutes impose significant liability
upon the owner or operator of natural gas pipeline facilities for failure to
meet certain safety standards. In addition to the statutes referenced above, we
are subject to a number of federal and state laws and regulations, including
the federal Occupational Safety and Health Act and comparable state statutes,
whose purpose is to maintain the safety of workers, both generally and within
the pipeline industry. We have an internal program of inspection designed to
monitor and enforce compliance with pipeline and worker safety requirements. Canadian Regulation.Our Canadian assets in the province of Alberta are
regulated by the Alberta Energy and Utilities Board. In British Columbia our
assets are regulated by the BC Oil and Gas Commission. Our West Doe and Pesh
Creek natural gas gathering pipeline, which crosses the Alberta/British
Columbia border, falls under the jurisdiction of the National Energy Board of
Canada and are classified as a Group 2 company, which is regulated on a
complaint only basis by the National Energy Board. 
 Environmental Matters The operation of pipelines, plants and other facilities for gathering,
transporting, processing, treating, or storing natural gas, NGLs and other
products is subject to stringent and complex laws and regulations pertaining to
health, safety and the environment. As an owner or operator of these
facilities, we must comply with United States and Canadian laws and regulations
at the federal, state and local levels that relate to air and water quality,
hazardous and solid waste management and disposal, and other environmental
matters. Environmental regulations and laws affecting us include:  
    
    The Clean Air Act and the 1990 amendments to the Act, as well as
counterpart state laws and regulations affecting emissions to the air,
that impose responsibilities on the owners and/or operators of air
emissions sources including obtaining permits and annual compliance and
reporting obligations; 14




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
    
    The Federal Water Pollution Control Act and other amendments, which
require permits for facilities that discharge treated wastewater or
other materials into waters of the United States;  
    
    Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act and its amendments, which regulate the
management, treatment, and disposal of solid and hazardous wastes, and
state programs addressing parallel state issues;
    
    The Comprehensive Environmental Response, Compensation, and Liability
Act and its amendments, which may impose liability, regardless of fault,
for historic or future disposal or releases of hazardous substances into
the environment, including cleanup obligations associated with such
releases or discharges;
    
    State regulations for the reporting, assessment and remediation of
releases of material to the environment, including historic releases of
hydrocarbon liquids; and
    
    Canadian Environmental Laws. Costs of planning, designing, constructing and operating pipelines,
plants, and other facilities must incorporate compliance with environmental
laws and regulations and safety standards. Failure to comply with these laws
and regulations may trigger a variety of administrative, civil and potentially
criminal enforcement measures, including citizen suits which can include the
assessment of monetary penalties, the imposition of remedial requirements, the
issuance of injunctions or restrictions on operation. For further discussion of our environmental matters, including possible
liability and capital costs, see Managements Discussion and Analysis of
Financial Condition and Results of Operations  Environmental Considerations
and Note 2, Summary of Significant Accounting Policies of the Notes to
Consolidated Financial Statements. 
 Employees As of December 31, 2003, we had approximately 3,575 employees, which
includes approximately 1,050 employees of our wholly-owned subsidiary Texas
Eastern Products Pipeline Company, LLC, the general partner of TEPPCO. We are a
party to one collective bargaining agreement in the U.S. which covers
approximately 65 of our employees and one collective bargaining agreement in
Canada which covers approximately 20 employees. We believe our relations with
our employees are good. 15




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ITEM 2.Properties. For information regarding the Companys properties, see Item 1. Business
 Natural Gas Gathering, Processing, Transportation, Marketing and Storage,
and Natural Gas Liquids Transportation, Fractionation and Marketing, and
TEPPCO in this section, each of which is incorporated herein by reference. 
 ITEM 3.Legal Proceedings. See Note 15, Commitments and Contingent Liabilities, of the Notes to
Consolidated Financial Statements for discussion of the Companys legal
proceedings which is incorporated herein by reference. Management believes that the resolution of the matters discussed will not
have a material adverse effect on the consolidated results of operations or the
financial position of the Company. In addition to the foregoing, from time to time, we are named as parties
in legal proceedings arising in the ordinary course of our business. We believe
we have meritorious defenses to all of these lawsuits and legal proceedings and
will vigorously defend against them. Based on our evaluation of pending matters
and after consideration of reserves established, we believe that,
based on currently known information, these proceedings will not have a material adverse effect on our business,
financial position or results of operations. 
 ITEM 4.Submission of Matters to a Vote of Security Holders. No matters were submitted to a vote of the Companys members during the
last quarter of 2003. 16




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##### Table of Contents



PART II. 
 ITEM 5.Market for Registrants Common Equity and Related Stockholder Matters. Duke Energy beneficially owns 69.7% of our outstanding member interests
and ConocoPhillips beneficially owns the remaining 30.3%. There is no market
for our member interests. Our LLC Agreement restricts making any distributions
except by approval of both members or in an amount sufficient to pay specified
tax obligations of our members that arise from their ownership of member
interests. In 2003, our board of directors approved a plan to consider the
payment of a quarterly dividend to our members. Our board of
directors may consider net income, cash flow or any
other criteria deemed appropriate for determining the amount of the quarterly
dividend to be paid. In August 2000, we issued $300 million of preferred members interests to
affiliates of Duke Energy and ConocoPhillips in proportion to their ownership
interests. The proceeds from this financing were used to repay a portion of our
outstanding commercial paper. The preferred member interests are entitled to
cumulative preferential distributions of 9.5% per annum payable, unless
deferred, semiannually. On September 9, 2002, we redeemed $100 million, on
September 19, 2003, we redeemed $125 million, and on December 31, 2003, we
redeemed the remaining $75 million of our preferred members interest by paying
cash to each of our members (Duke Energy and ConocoPhillips) in proportion to
their ownership interests. At December 31, 2003, we have no preferred members
interests outstanding to Duke Energy and ConocoPhillips. Reference is made to Item 12 of this report regarding equity compensation
plan information, which is incorporated herein by reference. 17




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##### Table of Contents



ITEM 6.Selected Financial Data. The following table sets forth selected historical consolidated financial
and other data for the Company and the Predecessor Company. The selected
historical Annual Income Statement Data, Cash Flow Data and Balance Sheet Data
as of December 31, 2003, 2002, 2001 and 2000 and for the periods then ended
have been derived from the consolidated financial statements of the
Company. The selected historical combined financial data as of December 31,
1999 and for the period then ended has been derived from the Predecessor
Companys audited historical financial statements. The data should be read in conjunction with the financial statements and
related notes and other financial information appearing elsewhere in this Form
10-K. 2003
    
    2002
    
    2001
    
    2000 (a)
    
    1999 (b)(millions)Annual Income Statement
Data:Operating revenues:Sales of natural gas and petroleum products
    
    $
    8,580
    
    
    $
    5,727
    
    
    $
    8,081
    
    
    $
    6,981
    
    
    $
    1,955Transportation, storage and processing
    
    
    263
    
    
    
    238
    
    
    
    178
    
    
    
    116
    
    
    
    132Trading and marketing net margin
    
    
    (24
    )
    
    
    14
    
    
    
    48
    
    
    
    15
    
    
    
    15Total operating revenues
    
    
    8,819
    
    
    
    5,979
    
    
    
    8,307
    
    
    
    7,112
    
    
    
    2,102Operating costs and expenses:Natural gas and petroleum products
    
    
    7,544
    
    
    
    4,952
    
    
    
    7,046
    
    
    
    5,926
    
    
    
    1,636Operating and maintenance
    
    
    451
    
    
    
    434
    
    
    
    360
    
    
    
    314
    
    
    
    167Depreciation and amortization
    
    
    302
    
    
    
    290
    
    
    
    269
    
    
    
    225
    
    
    
    121General and administrative
    
    
    184
    
    
    
    167
    
    
    
    130
    
    
    
    171
    
    
    
    74Asset impairments
    
    
    4
    
    
    
    8
    
    
    
    
    
    
    
    
    
    
    
    Net loss (gain) on sale of assets
    
    
    
    
    
    
    4
    
    
    
    (1
    )
    
    
    (11
    )
    
    
    3Total operating costs and expenses
    
    
    8,485
    
    
    
    5,855
    
    
    
    7,804
    
    
    
    6,625
    
    
    
    2,001Operating income
    
    
    334
    
    
    
    124
    
    
    
    503
    
    
    
    487
    
    
    
    101Equity in earnings of unconsolidated affiliates
    
    
    49
    
    
    
    38
    
    
    
    30
    
    
    
    27
    
    
    
    23Interest expense, net
    
    
    170
    
    
    
    166
    
    
    
    166
    
    
    
    149
    
    
    
    53Income (loss) from continuing operations
before income taxes
    
    
    213
    
    
    
    (4
    )
    
    
    367
    
    
    
    365
    
    
    
    71Income tax expense (benefit)
    
    
    8
    
    
    
    10
    
    
    
    3
    
    
    
    (311
    )
    
    
    31Income (loss) from continuing operations
before cumulative effect of accounting change
    
    
    205
    
    
    
    (14
    )
    
    
    364
    
    
    
    676
    
    
    
    40Gain (loss) from discontinued operations
    
    
    32
    
    
    
    (33
    )
    
    
    
    
    
    
    4
    
    
    
    3Cumulative effect of accounting change
    
    
    (23
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Net income (loss)
    
    
    214
    
    
    
    (47
    )
    
    
    364
    
    
    
    680
    
    
    
    43Dividend on preferred members interest
    
    
    9
    
    
    
    25
    
    
    
    29
    
    
    
    12
    
    
    
    Earnings (deficit) available for members
interest
    
    $
    205
    
    
    $
    (72
    )
    
    $
    335
    
    
    $
    668
    
    
    $
    43
 18




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2003
    
    2002
    
    2001
    
    2000 (a)
    
    1999 (b)(millions)Balance Sheet Data (end of
period):Total assets
    
    $
    6,514
    
    
    $
    6,599
    
    
    $
    6,856
    
    
    $
    6,528
    
    
    $
    3,482Long term debt
    
    $
    2,262
    
    
    $
    2,255
    
    
    $
    2,235
    
    
    $
    1,688
    
    
    $
    102Preferred members interest
    
    $
    
    
    
    $
    200
    
    
    $
    300
    
    
    $
    300
    
    
    $
    Members equity
    
    $
    2,744
    
    
    $
    2,450
    
    
    $
    2,653
    
    
    $
    2,421
    
    
    
    N/ACash Flow Data:Cash flow from operating activities
    
    $
    475
    
    
    $
    444
    
    
    $
    472
    
    
    $
    713
    
    
    $
    173Cash flow from investing activities
    
    $
    (41
    )
    
    $
    (237
    )
    
    $
    (546
    )
    
    $
    (235
    )
    
    $
    (1,571
    )Cash flow from financing activities
    
    $
    (425
    )
    
    $
    (192
    )
    
    $
    85
    
    
    $
    (478
    )
    
    $
    1,399Other Data:Acquisitions and capital expenditures
    
    $
    129
    
    
    $
    297
    
    
    $
    598
    
    
    $
    371
    
    
    $
    1,570Gas transported and/or processed (TBtu/d)
    
    
    7.7
    
    
    
    8.1
    
    
    
    8.3
    
    
    
    7.3
    
    
    
    4.9NGLs production (MBbl/d)
    
    
    365
    
    
    
    389
    
    
    
    394
    
    
    
    355
    
    
    
    186Market Data:Average NGLs price per gallon (c)
    
    $
    0.53
    
    
    $
    0.38
    
    
    $
    0.45
    
    
    $
    0.53
    
    
    $
    0.34Average natural gas price per MMBtu (d)
    
    $
    5.39
    
    
    $
    3.22
    
    
    $
    4.27
    
    
    $
    3.89
    
    
    $
    2.27
    (a)
    
    Includes the results of operations of ConocoPhillips gas gathering,
processing, marketing and NGL business for the nine months ended December
31, 2000. To the extent that it existed at the time, ConocoPhillips gas
gathering, processing, marketing and NGL business was acquired by the
Predecessor Company on March 31, 2000.  (b)
    
    Includes the results of operations of Union Pacific Fuels for the nine
months ended December 31, 1999. Union Pacific Fuels was acquired by the
Predecessor Company on March 31, 1999.  (c)
    
    Based on index prices from the Mont Belvieu and Conway market hubs that
are weighted by our component and location mix for the periods indicated.  (d)
    
    Based on NYMEX prices for the periods indicated. N/A Not applicable due to change in corporate structure as of March 31, 2000. 19




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##### Table of Contents



ITEM 7.Managements Discussion and Analysis of Financial Condition and Results
of Operations. The following discussion details the material factors that affected our
historical financial condition and results of operations in 2003, 2002 and
2001. This discussion should be read in conjunction with Item 1. Business,
and the consolidated financial statements with the related notes, included
elsewhere in thisForm 10-K. Overview We operate in the two principal business segments of the midstream natural
gas industry:  
    
    Natural gas gathering, processing, transportation and storage, from
which we generate revenues primarily by providing services such as
compression, gathering, treating, processing, transportation of residue
gas, storage and trading and marketing (the Natural Gas Segment). In
2003, approximately 82% of the Companys operating revenues prior to
intersegment revenue elimination and approximately 96% of the Companys
gross margin were derived from this segment.
    
    NGLs fractionation, transportation, marketing and trading, from which
we generate revenues from transportation fees, market center
fractionation and the marketing and trading of NGLs (the NGLs
Segment). In 2003, approximately 18% of the Companys operating
revenues prior to intersegment revenue elimination and approximately 4%
of the Companys gross margin were derived from this segment.
    
    Intersegment activity is primarily related to the sale of NGLs from
the Natural Gas Segment to the NGLs Segment at market based transfer
prices. Our limited liability company agreement limits the scope of our business
to the midstream natural gas industry in the United States and Canada, the
marketing of NGLs in Mexico and the transportation, marketing and storage of
other petroleum products, unless otherwise approved by our board of directors.
This limitation in scope is not currently expected to materially impact the
results of our operations. Effects of Commodity Prices The Company is exposed to commodity prices as a result of being paid for
certain services in the form of commodities rather than cash. For gathering
services, the Company receives fees or commodities from the producers to bring
the raw natural gas from the well head to the processing plant. For processing
services, the Company either receives fees or commodities as payment for these
services, depending on the types of contracts which are described below. Based
on the Companys current contract mix, the Company has a long NGL position and
is sensitive to changes in NGL prices. The Company also has a short gas
position, however, the short gas position is less significant than the long NGL
position. Based upon our portfolio of supply contracts, without giving effect
to hedging activities that would reduce the impact of commodity price
decreases, a decrease of $0.01 per gallon in the price of NGLs and $0.10 per
million Btus in the average price of natural gas would result in changes in
annual pre-tax net income of approximately $(18) million and $1 million,
respectively. In addition, a decrease of $1 per barrel in the average price of
crude oil would result in a change to annual pre-tax net income of
approximately $(5) million. During the year ended December 31, 2003, approximately 80% of our gross
margin was generated by commodity sensitive arrangements and approximately 20%
of our gross margin (excluding hedging and including earnings of unconsolidated
affiliates) was generated by fee-based arrangements. The commodity exposure is
managed by the Company as discussed below. The midstream natural gas industry is cyclical, with the operating results
of companies in the industry significantly affected by the prevailing price of
NGLs, which in turn has been generally correlated to the price of crude oil.
Although the prevailing price of natural gas has less short term significance
to our operating results than the price of NGLs, in the long term, the growth
of our business depends on natural gas prices being at levels sufficient to
provide incentives and capital for producers to increase natural gas
exploration and production. In the past, the prices of NGLs, crude oil and
natural gas have been extremely volatile. We generally expect NGL prices to follow changes in crude oil prices over
the long term, which we believe will in large part be determined by the level
of production from major crude oil exporting countries and the demand generated
by growth in the world economy. However, the relationship or correlation
between crude oil value and NGL prices declined significantly during 2001 and
2002. In late 2002 and throughout 2003, this relationship reverted back toward
historical trends. 20




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##### Table of Contents



We believe that future natural gas prices will be influenced by supply
deliverability, the severity of winter and summer weather and the level of
United States economic growth. The price increases in crude oil, NGLs and
natural gas experienced during 2000 and first half of 2001 spurred increased
natural gas drilling activity. However, a decline in commodity prices in late
2001, continuing into 2002, negatively affected drilling activity. Drilling
activity increased in 2003 due to higher commodity prices. The average number
of active oil and gas rigs drilling in the United States increased to 1,126 at
December 31, 2003 from 862 at December 31, 2002. Recent significant increases
in natural gas prices could result in continued increased drilling activity in
2004. However, energy market uncertainty could negatively impact the United
States drilling activity in the short term. Lower drilling levels over a
sustained period would have a negative effect on natural gas volumes gathered
and processed. To better address the risks associated with volatile commodity prices, we
employ a comprehensive commodity price risk management program. We closely
monitor the risks associated with these commodity price changes on our future
operations and, where appropriate, use various commodity instruments such as
natural gas, crude oil and NGL contracts to hedge a portion of the value of our
assets and operations from such price risks. See Item 7A. Quantitative and
Qualitative Disclosures About Market Risk. We do not realize the full impact
of commodity price changes because some of our sales volumes were previously
hedged at prices different than actual market prices. The settlement of these
hedge transactions reduced the results of operations by $115 million and $27
million in 2003 and 2002, respectively, and increased the results of
operations by $6 million in 2001. Effects of Our Raw Natural Gas Supply Arrangements Our results are affected by the types of arrangements we use to process
raw natural gas. We obtain access to raw natural gas and provide our midstream
natural gas services principally under three types of processing contracts:  
    
    Percentage-of-Proceeds Contracts  Under these contracts we receive
as our fee a negotiated percentage of the residue natural gas and NGLs
value derived from our gathering and processing activities, with the
producer retaining the remainder of the value or product. These types of
contracts permit us and the producers to share proportionately in
commodity price changes. Under these contracts, we share in both the
increases and decreases in natural gas prices and NGL prices. During
2003, approximately 65% of our gross margin (excluding hedging and
including equity earnings of unconsolidated affiliates) from the Natural
Gas Segment was generated from percentage-of-proceeds contracts.
    
    Fee-Based Contracts  Under these contracts we receive a set fee for
gathering, processing and/or treating raw natural gas. Our revenue
stream from these contracts is correlated with our level of gathering
and processing activity and is not directly dependent on commodity
prices. During 2003, approximately 20% of our gross margin (excluding
hedging and including equity earnings of unconsolidated affiliates) from
the Natural Gas Segment was generated from fee-based contracts.
    
    Keep-Whole and Wellhead Purchase Contracts  Under the terms of a
wellhead purchase contract, we purchase raw natural gas from the
producer at the wellhead or defined receipt point for processing and
then market the resulting NGLs and residue gas at market prices. Under
the terms of a keep-whole processing contract, we gather raw natural gas
from the producer for processing and then we market the NGLs and return
to the producer residue natural gas with a Btu content equivalent to the
Btu content of the raw natural gas gathered. This arrangement keeps the
producer whole to the thermal value of the raw natural gas we received.
Under these types of contracts the Company is exposed to the frac
spread. The frac spread is the difference between the value of the NGLs
extracted from processing and the value of the Btu equivalent of the
residue natural gas. We benefit in periods when NGL prices are higher
relative to natural gas prices. During 2003, approximately 5% of our
gross margin (excluding hedging and including equity earnings of
unconsolidated affiliates) from the Natural Gas Segment was generated
from keep-whole and wellhead purchase contracts.
    
    In addition, during 2003 approximately 10% of the gross margin
(excluding hedging and including equity earnings of unconsolidated
affiliates) from the Natural Gas Segment was generated from sales of
condensate, which is low grade crude oil that is produced in association
with natural gas. Our current mix of percentage-of-proceeds contracts (where we are exposed
to decreases in natural gas prices) and keep-whole and wellhead purchase
contracts (where we are exposed to increases in natural gas prices) helps to
mitigate our exposure to changes in natural gas prices. Our exposure to
decreases in NGL prices is partially offset by our hedging program. Our hedging
program reduces the potential negative impact that commodity price changes
could have on our earnings and improves our ability to adequately plan for cash
needed for debt service and capital expenditures. The primary goals of our
hedging program include maintaining minimum cash 21




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##### Table of Contents



flows to fund debt service
and dividends, production replacement and maintenance capital
projects; and retaining a high percentage of potential upside
relating to increases in prices of NGLs Accounting Adjustments Certain prior period amounts have been reclassified in the Consolidated
Financial Statements to conform to the current period presentation. Included in
the reclassified amounts are increases in both Sales of natural gas and
petroleum products and in Purchases of natural gas and petroleum products in
the amount of approximately $805 million and $639 million for the years ended
December 31, 2002 and 2001, respectively. This reclassification resulted from
intersegment trading activities being eliminated twice from the Consolidated
Statements of Operations in the years ended December 31, 2002 and 2001. In
addition, Accounts receivable  Customers, net and Accounts payable  Trade
were increased by $102 million at December 31, 2002 to properly present on a
gross basis balances that were previously presented net in the Consolidated
Balance Sheet. Management has concluded that these reclassifications are not
material to the fair presentation of the Companys financial statements. During 2003, we recorded an $11 million charge ($7 million to Operating
and maintenance expense and $4 million to General and administrative expense)
to properly account for our vacation accrual in accordance with SFAS No. 43,
Accounting for Compensated Absences. We recorded this adjustment, which
related primarily to prior periods, entirely in 2003. Management has
determined that this charge, related to an error correction, is immaterial on
both a quantitative and qualitative basis to the trends in the financial
statements for the periods presented, the prior periods affected and to a fair
presentation of our financial statements. We completed a comprehensive account reconciliation project to review and
analyze our balance sheet accounts in 2002. As a result of this account
reconciliation project, we recorded approximately $53 million of adjustments
that may be related to corrections of accounting errors in prior periods. The
$53 million reduced Gross Margin, as defined under Results of Operations
below, by $33 million, increased costs and expenses by $16 million, increased
depreciation by $2 million, increased other costs and expenses by $4 million
and reduced interest expense by $2 million. Numerous items identified in the
account reconciliation project resulted from system conversions and otherwise
unsupportable balance sheet amounts. Due to the nature of these account
reconciliation adjustments, it would be impractical to determine what periods
such adjustments relate to. Management has determined that the charges related
to error corrections are immaterial both individually and in the aggregate on
both a quantitative and qualitative basis to the trends in the financial
statements for the periods presented, the prior periods affected and to a fair
presentation of our financial statements. See Notes 2 and 20 to the Consolidated Financial Statements included
elsewhere in this Form 10-K and Item 9A. Controls and Procedures. Other Factors That Significantly Affect Our Results Our results of operations are impacted by increases and decreases in the
volume of raw natural gas that we handle through our systems, which we refer to
as throughput volume, and the percentage of capacity at which our processing
facilities operate, which we refer to as our capacity utilization rate.
Throughput volumes and capacity utilization rates generally are driven by well
head production and our competitive position on a regional basis and more
broadly by demand for residue natural gas and NGLs. Our revenues and expenses are significantly dependent on commodity prices
such as NGLs and natural gas. Past and current trends in the price changes of
these commodities may not be indicative of future trends. In addition, revenues
and expenses are impacted by throughput volumes. If negative market conditions
persist over time or throughput volumes decline, estimated cash flows over the
lives of our assets may not exceed the carrying value of those individual
assets, and asset impairments may occur in the future under existing accounting
rules. Furthermore, a change in managements intent about the use of individual
assets (held for use vs. held for sale) could also impact an impairment
analysis. For the years ended December 31, 2003 and 2002, we recorded asset
impairments of approximately $4 million and $8 million, respectively. There
were no asset impairments recorded in 2001. At December 31, 2003, the net book
value of property, plant and equipment was $4,462 million. In 2003, we converted a portion of our keep-whole contracts to
percentage-of-proceeds contracts and we converted a portion of our keep-whole
contracts to add a minimum fee clause. This had the impact of reducing the
Companys exposure to natural gas prices and reducing the exposure to NGL
prices on an unhedged basis. Risk management activities have also affected our results of operations.
We do not realize the full impact of commodity price changes because some of
our sales volumes were previously hedged at prices different than actual market
prices. The settlement of 22




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##### Table of Contents



these hedge transactions reduced the results of operations by $115 million
and $27 million in 2003 and 2002, respectively, and increased the results of
operations by $6 million in 2001. See Item 7A. Quantitative and Qualitative
Disclosure About Market Risk. Results of Operations The following is a discussion of our historical results of operations. 2003
    
    2002
    
    2001(millions)Operating revenues:Sales of natural gas and petroleum products
    
    $
    8,580
    
    
    $
    5,727
    
    
    $
    8,081Transportation, storage and processing
    
    
    263
    
    
    
    238
    
    
    
    178Trading and marketing net margin
    
    
    (24
    )
    
    
    14
    
    
    
    48Total operating revenues
    
    
    8,819
    
    
    
    5,979
    
    
    
    8,307Purchases of natural gas and petroleum products
    
    
    7,544
    
    
    
    4,952
    
    
    
    7,046Gross margin (a)
    
    
    1,275
    
    
    
    1,027
    
    
    
    1,261Costs and expenses
    
    
    941
    
    
    
    903
    
    
    
    758Equity earnings of unconsolidated affiliates
    
    
    49
    
    
    
    38
    
    
    
    30EBIT from continuing operations before cumulative
effect of accounting change (b)
    
    
    383
    
    
    
    162
    
    
    
    533Interest expense, net
    
    
    170
    
    
    
    166
    
    
    
    166Income tax expense
    
    
    8
    
    
    
    10
    
    
    
    3Gain (loss) from discontinued operations
    
    
    32
    
    
    
    (33
    )
    
    
    Cumulative effect of changes in accounting
principles
    
    
    (23
    )
    
    
    
    
    
    
    Net income (loss)
    
    $
    214
    
    
    $
    (47
    )
    
    $
    364
  (a)
    
    Gross margin consists of total operating revenues less purchases of
natural gas and petroleum products. Gross margin is a non-Generally
Accepted Accounting Principles (GAAP) measure under the rules of the
Securities and Exchange Commission (SEC), but is included as a
supplemental disclosure because it is a primary performance measure used
by management as it represents the results of product sales and purchases,
a key component of our operations. As an indicator of our operating
performance, gross margin should not be considered an alternative to, or
more meaningful than, net income or cash flow as determined in accordance
with GAAP. Our gross margin may not be comparable to a similarly titled
measure of another company because other entities may not calculate gross
margin in the same manner.  (b)
    
    EBIT consists of net income from continuing operations before cumulative
effect of accounting change, net interest expense and income tax expense.
EBIT is a non-GAAP measure under the rules of the SEC, but is included as
a supplemental disclosure because it is a primary performance measure used
by management as it represents the results of operations without regard to
financing methods or capital structure. As an indicator of our operating
performance, EBIT should not be considered an alternative to, or more
meaningful than, net income or cash flow as determined in accordance with
GAAP. Our EBIT may not be comparable to a similarly titled measure of
another company because other entities may not calculate EBIT in the same
manner. 2003 compared with 2002 Operating Revenues Total operating revenues increased $2,840 million, or
47%, to $8,819 million in 2003 from $5,979 million in 2002. Approximately
$2,250 million of this increase was attributable to a $2.17 per MMBtu increase
in average natural gas prices and approximately $1,195 million of this increase
was attributable to a $0.15 per gallon increase in average NGL prices. Lower
throughput and NGL production reduced revenues by approximately $120 million
related to natural gas volume and approximately $380 million related to lower
NGL production. We did not realize the full impact of the above increase in
NGL prices because some of our sales volumes were previously hedged at prices
lower than actual market prices. The settlement of these hedge transactions
reduced revenues by $115 million and $27 million in 2003 and 2002,
respectively. These settlements reduced by $88 million the benefit of the 2003
NGL price increases described above. Other increases were attributable to
transportation, storage and processing fees of $25 million which was primarily
due to increased fee revenue associated with our Canadian operations,
intrastate pipelines and storage. Also included in operating revenues was a decrease in trading and
marketing net margin of $38 million, of which $32 million was related to the
Natural Gas Segment and $6 million was related to the NGLs Segment. The
trading and marketing net margin loss of $24 million for 2003 includes $14
million of income related to the NGLs Segment offset by a $38 million loss
related to the Natural 23




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Gas Segment. The Natural Gas Segment experienced losses of approximately
$10 million due to trading activities in 2003. In addition, approximately $25
million of losses in the Natural Gas Segment is attributable to losses on
mark-to-market derivatives for which the results of the related physical asset
based activity is recognized on an accrual basis and not included in trading
and marketing net margin. Prior to the adoption of EITF 02-03 on January 1,
2003, the gains and losses on both the mark-to-market derivatives and the
related physical activity were recorded in trading and marketing net margin
(see Accounting Pronouncements beginning on page 38). Purchases of Natural Gas and Petroleum Products- Purchases of natural gas
and petroleum products increased $2,592 million, or 52%, to $7,544 million in
2003 from $4,952 million in 2002. The increase was due primarily to increased
costs of raw natural gas and natural gas liquids supply of approximately $2,985
million, offset by lower throughput volumes of approximately $440 million.
Additional increases of $48 million were related to non-recurring charges
during 2002 as discussed below. Gross Margin  Gross margin increased $248 million, or 24% to $1,275
million in 2003 from $1,027 million in 2002. This increase was primarily due to
the following factors:  
    
    approximately $290 million (net of hedging) was mainly
the result of higher average NGLs and crude oil prices;
    
    approximately $40 million not included in the pricing impacts was
the result of 2003 elections to reduce levels of keep-whole processing
activities from time to time through operational optionality and
contract renegotiaion due to lower historical and forecasted
processing profit margins; and
    
    $48 million related to accounting adjustments in 2002. $25
million relates to a provisions recorded in 2002 ($12 million relating
to prior periods) recorded as a result of our completion of our
analysis of gas imbalances with suppliers and customers dating back to
1999. This charge was recorded to reflect managements current best
estimate of necessary reserves for uncollectible imbalances,
unrecorded liabilities related to imbalances and incorrectly valued
imbalances. $23 million relates to charges recorded in 2002 related to
completion of our account reconciliation project, including a $6
million write-down for storage inventory. Of the $48 million total of
adjustments, $33 million may be related to corrections of accounting
errors in prior periods (see Accounting Adjustments on page 22). The increase in gross margin was offset by the following factors:  
    
    approximately $130 million was the result of higher average natural gas prices; and
    
    $38 million relates to decreased trading and marketing net margin as discussed above. Gross margin associated with the Natural Gas Segment increased $249
million, or 26%, to $1,221 million in 2003 from $972 million in 2002, mainly as
a result of the following factors:  
    
    approximately $225 million (net of hedging) was the result of
commodity sensitive processing arrangements, mainly due to the
increase in average NGLs and crude oil prices along with our election to reduce
levels of keep-whole processing activities offset by the increase in
average natural gas prices; and
    
    $48 million related to accounting adjustments in 2002 as
discussed above. The increase in gross margin associated with the Natural Gas Segment was
offset by $32 million relating to decreased trading and marketing net margin as
discussed above. Gross margin associated with the NGLs Segment decreased $1 million, or 2%
to $54 million in 2003 from $55 million in 2002. This decrease was comprised of
a $6 million decrease in trading and marketing net margin offset by increases
in the northeast wholesale propane marketing and terminals margin of $2 million
and from the operation of a newly constructed pipeline in south Texas of $1
million. NGL production during 2003 decreased 24,000 barrels per day, or 6%, to
365,000 barrels per day from 389,000 barrels per day during 2002, and natural
gas transported and/or processed during 2003 decreased 0.4 trillion Btus per
day, or 5%, to 7.7 trillion Btus per day from 8.1 trillion Btus per day during
2002. The primary cause of the decrease in NGL production was a reduction in
keep-whole processing activity during 2003 due to marginally economic
processing margins and reduced drilling activity. Costs and Expenses Operating and maintenance expenses increased $17
million, or 4%, to $451 million in 2003 from $434 million in 2002. This
increase was primarily due to the following factors:  
    
    increased facility maintenance and pipeline repair of $10 million;
    
    increased environmental compliance of $7 million;
    
    accretion expense associated with asset retirement obligations of
$3 million related to the implementation of SFAS No. 24




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143
    
    in 2003; and  
    
    a charge from accounting adjustments of $7 million in 2003 offset
by a benefit related to accounting adjustments of $11 million in 2002
(see Accounting Adjustments on page 22). General and administrative expenses increased $17 million, or 10%, to $184
million in 2003 from $167 million in 2002. This increase was primarily due to
the following factors:  
    
    higher bonus and incentive compensation of $19 million; and
    
    severance of $6 million in 2003. The increase in general and administrative expenses was offset by the following factors:  
    
    lower corporate overhead of $10 million; and
    
    a charge from accounting adjustments of $4 million in 2003 offset
by a benefit related to accounting adjustments of $5 million in 2002
(see Accounting Adjustments on page 22). Depreciation and amortization expenses increased $12 million, or 4%, to
$302 million in 2003 from $290 million in 2002. This increase was due primarily
to ongoing capital expenditures for well connections and facility maintenance
and enhancements, and the depreciation of asset retirement costs that were
capitalized in conjunction with the implementation of SFAS No. 143. Asset impairments were $4 million in 2003 compared to $8 million in 2002.
The impairment in 2003 was related to assets located in Onshore and Offshore
Gulf of Mexico. The impairment in 2002 was related to assets located in
Offshore Gulf of Mexico and write-off of a leasehold interest. As part of our
periodic asset performance evaluations, we determined in December 2003 and 2002
that certain gas plants and gathering systems have recently generated cash flow
losses and are expected to continue to generate minimal or negative cash flows
in future years. Accordingly, at December 31, 2003 and 2002, we performed tests
for recoverability on these assets in accordance with the requirements of
applicable accounting standards using probability weighted undiscounted future
cash flow models. Based upon the results of these analyses, we determined that
the carrying value of these assets was impaired and accordingly, wrote them
down to their fair value. Fair value was determined based on managements best
estimates of sales value and/or discounted future cash flow models. The charges
associated with these impairments were recorded in the Natural Gas Segment. Net loss (gain) on sale of assets was a loss of $4 million in 2002 related
to the loss on sale of assets associated with a partnership investment. This
amount relates to accounting corrections (see Accounting Adjustments on page
22). Equity in Earnings of Unconsolidated Affiliates Equity in earnings of
unconsolidated affiliates increased $11 million, or 29%, to $49 million in 2003
from $38 million in 2002. This increase is primarily the result of increased
earnings from our general partnership interest in TEPPCO Partners, L.P.
(TEPPCO) of $7 million and increased earnings from the 2002 acquisition of an
interest in Discovery Producer Services, LLC (Discovery) located in Offshore
Gulf of Mexico of $6 million. Interest Expense, Net Interest expense increased $4 million, or 2%, to
$170 million in 2003 from $166 million in 2002. This increase was primarily the
result of the third quarter 2003 implementation of SFAS No. 150 requiring
prospective reclassification as interest expense disbursements of $6 million
that in previous periods were classified as dividends on our preferred members
interest. Income Tax Expense The Company is a limited liability company, which is
a pass-through entity for U.S. income tax purposes. However, some of its
subsidiaries are tax-paying entities. Income tax expense represents federal,
state and foreign taxes associated with these entities. Income tax expense
decreased $2 million to $8 million in 2003 from $10 million in 2002 due
primarily to decreased earnings associated with tax-paying subsidiaries. Gain (Loss) From Discontinued Operations- Gain (loss) from discontinued
operations was a gain of $32 million in 2003 and a loss of $33 million in 2002.
The 2003 gain is primarily the result of the gain on the sale of various
natural gas gathering and processing assets (see Note 10 to the Consolidated
Financial Statements) and the 2002 loss represents impairment charges
associated with the assets sold in 2003. Cumulative Effect of Changes in Accounting Principles Cumulative effect
of changes in accounting principles was a loss of $23 million in 2003. Of this
amount, $18 million relates to the implementation of SFAS 143, and $5 million
is due to the rescission of EITF 98-10 (see Note 2 to Consolidated Financial
Statements). 25




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2002 compared with 2001 Gross Margin Gross margin decreased $234 million, or 19% to $1,027
million in 2002 from $1,261 million in 2001. This decrease was primarily due to
the following factors:  
    
    approximately $200 million (including hedging) was the result of
a $0.07 per gallon decrease in average NGL prices and volume declines;  
    
    $48 million related to accounting adjustments in 2002 as discussed above; and  
    
    $34 million was the result of decreased trading and marketing net margin. The decrease in gross margin was offset by approximately $45 million
resulting from a $1.05 per million Btu decrease in natural gas prices. Gross margin associated with the Natural Gas Segment decreased $233
million, or 19%, to $972 million in 2002 from $1,205 million in 2001, mainly as
a result of the following factors:  
    
    approximately $155 million (net of hedging) was the result of
commodity sensitive processing arrangements, mainly due to the
decrease in average NGL prices, partially offset by the decrease in
average natural gas prices;  
    
    $25 million was the result of decreased trading and marketing net margin; and  
    
    $48 million related to accounting adjustments in 2002 as discussed above. Gross Margin associated with the NGLs Segment decreased $1 million, or 2%
to $55 million in 2002 from $56 million in 2001. A decrease in trading and
marketing net margin of $9 million was offset by a $10 million increase related to the
2001 acquisition of northeast propane terminal and marketing assets. NGL production during 2002 decreased 5,000 barrels per day, or 1%, to
389,000 barrels per day from 394,000 barrels per day during 2001, and natural
gas transported and/or processed during 2002 decreased 0.2 trillion Btus per
day, or 2%, to 8.1 trillion Btus per day from 8.3 trillion Btus per day during
2001. The primary cause of the decrease in NGL production was periodic
reduction in keep-whole processing activity during 2002 due to marginally
economic processing margins and reduced drilling activity, partially offset by
acquisitions. Costs and Expenses Operating and maintenance expenses increased $74
million, or 21%, to $434 million in 2002 from $360 million in 2001. This
increase was primarily the due to the following factors:  
    
    increased maintenance, equipment overhauls and pipeline integrity projects of approximately $33 million;  
    
    increased labor costs of $7 million;  
    
    result of the full year impact of acquisitions for approximately
$20 million (see Note 3 to the Consolidated Financial Statements); and  
    
    increases of $14 million due to higher spending levels, including
$11 million of accounting adjustments (see Accounting Adjustments on
page 22). General and administrative expenses increased $37 million, or 28%, to $167
million in 2002 from $130 million in 2001. The primary causes of this increase
were $11 million for core business process improvements and $5 million of
accounting adjustments (see Accounting Adjustments on page 22). The remaining
increase was related to higher costs of services provided by Duke Energy of
approximately $7 million and higher labor and outside services resulting from
accounting and technology projects of approximately $9 million. Depreciation and amortization expenses increased $43 million (excluding
$22 million of goodwill amortization in 2001), or 17%, to $290 million in 2002
from $247 million in 2001. This increase was due primarily to acquisitions,
ongoing capital expenditures for well connections and facility maintenance and
enhancements. Asset impairments were $8 million in 2002. The impairment was related to
assets located in Offshore Gulf of Mexico and write-off of a leasehold
interest. As part of our periodic asset performance evaluations, we determined
in December 2002 that certain gas plants and gathering systems have recently
generated cash flow losses and are expected to continue to generate minimal or
negative cash flows in future years. Accordingly, at December 31, 2002, we
performed tests for recoverability on these assets in accordance with the
requirements of applicable accounting standards using probability weighted
undiscounted future cash flow models. Based upon the results of these
analyses, we determined that the carrying value of these assets was impaired
and accordingly, wrote them down to their fair value. Fair value was determined
based on managements best estimates of sales value and/or discounted future
cash 26




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flow models. The charges associated with these impairments were recorded
in the Natural Gas Segment. Net loss (gain) on sale of assets changed to a loss of $4 million in 2002
from a gain of $1 million in 2001. The primary reason for the change was the
loss on sale of assets associated with a partnership investment of $5 million
recorded in 2002. This amount relates to accounting corrections (see
Accounting Adjustments on page 22). Equity in Earnings of Unconsolidated Affiliates Equity in earnings of
unconsolidated affiliates increased $8 million, or 27%, to $38 million in 2002
from $30 million in 2001. This increase is primarily the result of increased
earnings from our general partnership interest in TEPPCO of $4 million and
increased earnings from the 2002 acquisition of an interest in Discovery of $2
million. Interest Expense, Net Interest expense remained flat at $166 million
in 2002 and 2001. The Company had slightly higher debt levels in 2002, offset
by lower interest rates and capitalized interest adjustments (see Accounting
Adjustments on page 22). Income Tax Expense Income tax expense represents federal, state and
foreign taxes associated with the Companys tax-paying subsidiaries. Income
tax expense increased $7 million to $10 million in 2002 from $3 million in 2001
due primarily to increased earnings associated with tax-paying subsidiaries
obtained through acquisitions in 2001 and prior. Gain (Loss) From Discontinued Operations- Gain (loss) from discontinued
operations was a loss of $33 million in 2002 which represents impairment
charges associated with assets sold in 2003. Environmental Considerations We have various ongoing remedial matters related to historical operations,
based primarily on state authorities generally described under Item 1.
Business  Environmental Matters. These are typically managed in conjunction
with the relevant state or federal agencies to address specific conditions, and
in some cases is the responsibility of other entities based upon contractual
obligations related to the assets. We make expenditures in connection with environmental matters as part of
our normal operations. We estimate that the aggregate environmental
costs that we will expense or capitalize in 2004 and 2005 to maintain
compliance with environmental reuglations and laws will be approximately $51
million and $42 million, respectively. In addition, at December
31, 2003, we have liabilities of $21 million recorded for
environmental remediation obligations and $45 million recorded for
asset retirement obligations. Critical Accounting Policies The selection and application of accounting policies is an important
process that has developed as our operations mature and accounting guidance
evolves. We have identified certain critical accounting policies that require
the use of material estimates and have a material impact on our consolidated
financial position and results of operations. These policies require
significant estimations and judgment. Management bases its estimates and
judgments on historical experience and on assumptions that it believes are
reasonable at the time of application. The estimations and judgments may change
as more historical experience and information becomes available. If estimations
and judgments are different than actual amounts recorded, adjustments are made
in subsequent periods to take into consideration the new information. We
discuss each of our critical accounting policies with senior members of
management and the audit committee, as appropriate. Our critical accounting
policies include: Risk Management Activities- We use two comprehensive accounting models
for our risk management and trading activities in reporting our consolidated
financial position and results of operations as required by generally accepted
accounting principles  a fair value model and an accrual model. For the three
years ended December 31, 2003, the determination as to which model was
appropriate was primarily based on accounting guidance issued by the Financial
Accounting Standards Board (FASB) and the Emerging Issues Task Force
(EITF). Effective January 1, 2003, we adopted the final consensus reached in
EITF Issue 02-03 (EITF 02-03), Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and for Contracts Involved in Energy
Trading and Risk Management Activities. While the implementation of such
guidance changed which accounting model is used for certain of our
transactions, the overall application of the models remains the same. See Note
2 to the Consolidated Financial Statements for further discussion of EITF
02-03. The fair value model incorporates the use of mark-to-market (MTM)
accounting. Under this method, an asset or liability is recognized at fair
value on the Consolidated Balance Sheet and the change in the fair value of
that asset or liability is recognized in Trading and Marketing Net Margin in
the Consolidated Statements of Operations during the current period. We apply
MTM 27




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accounting to our derivatives unless subject to hedge accounting or the
normal purchase and normal sale exemption (as described below). MTM accounting is applied within the context of an overall valuation
framework. When available, quoted market prices are used to record a contracts
fair value. However, market values for energy commodity contracts may not be
readily determinable because the duration of the contracts exceeds the liquid
activity in a particular market. If no active trading market exists for a
commodity or for a contracts duration, holders and issuers of these contracts
must calculate fair value using internally developed valuation techniques or
models. Key components used in these valuation techniques include price
curves, volatility, correlation, interest rates and tenor. Of these components,
volatility and correlation are the most subjective. Internally developed
valuation techniques include the use of interpolation, extrapolation and
fundamental analysis in the calculation of a contracts fair value. All risk
components for new and existing transactions are valued using the same
valuation technique and market data and discounted using a London Interbank
Offered Rate (LIBOR) based interest rate. Valuation adjustments for
performance, market risk and administration costs are used to adjust the fair
value of the contract to the gain or loss ultimately recognized in the
Consolidated Statements of Operations. Validation of a contracts fair value occurs by an internal group
independent of our trading function. They perform pricing model validation,
back testing and stress testing of valuation techniques and inputs and
valuation of curves against market activity. In addition, we validate a
contracts fair value through collateral negotiation with third parties. While
we use industry best practices to develop our valuation techniques, changes in
our pricing methodologies or the underlying assumptions could result in
significantly different fair values and income recognition. Often for a derivative that is initially subject to MTM accounting, we
apply either hedge accounting or the normal purchase and normal sales
exemption. The use of hedge accounting or the normal purchase and sales
exemption provide effectively for the use of the accrual model. Under this
model, there is no recognition in the Consolidated Statements of Operations for
changes in the fair value of a contract until the service is provided or the
associated delivery period occurs. Hedge accounting treatment may be used when we contract to buy or sell a
commodity such as natural gas at a fixed price for future delivery
corresponding with anticipated physical sales or purchase of natural gas (cash
flow hedge). In addition, hedge accounting treatment may be used when we hold
firm commitments or asset or liability positions and enter into transactions
that hedge the risk that the price of the commodity may change between the
contracts inception and the physical delivery date of the commodity (fair
value hedge). To the extent that the fair value of the hedge instrument is
effective in offsetting the transaction being hedged, there is no impact to the
Consolidated Statements of Operations prior to settlement of the hedge.
However, due to the differences that exist in the energy commodity prices and
the fact that not all of our hedges relate to the exact location and commodity
being hedged, a certain degree of hedge ineffectiveness may be realized in the
Consolidated Statements of Operations. The normal purchase and sales exemption indicates that no recognition of
the contracts fair value in the consolidated financial statements is required
until settlement of the contract. The Company has applied this exemption for
contracts involving the purchase or sale of physical natural gas or NGLs in
future periods. Revenue Recognition We recognize revenues on sales of natural gas and
petroleum products in the period of delivery and transportation revenues in the
period service is provided. For gathering services, we receive fees from the
producers to transport the natural gas from the wellhead to the processing
plant. For processing services, we either receive fees or commodities as
payment for these services, depending on the type of contract. Under the
percentage-of-proceeds contract type, we are paid for our services by keeping a
percentage of the NGLs produced and the residue gas resulting from processing
the natural gas. Under a keep-whole contract, we keep a portion of the NGLs
produced, but return the equivalent Btu content of the gas back to the
producer. We also receive fees for further fractionation of the NGLs produced,
and for transportation and storage of NGLs and residue gas. We recognize revenue for our NGL and residue gas derivative trading
activities net in the Consolidated Statements of Operations as trading and
marketing net margin. These activities include mark-to-market gains and losses
on energy trading contracts and the financial or physical settlement of energy
trading contracts. Revenue for goods and services provided but not invoiced is estimated each
month and recorded along with related purchases of goods and services used but
not invoiced. These estimates are generally based on estimated commodity
prices, preliminary throughput measurements and allocations and contract data.
Actual invoices for the current month are issued in the following month and
differences from estimated amounts are recorded. There are no material
differences from the actual amounts invoiced subsequent to year end relating to
estimated revenues and purchases recorded at December 31, 2003,
2002 and 2001. 28




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Gas Imbalance Accounting Quantities of natural gas over-delivered or
under-delivered related to imbalance agreements with producers or pipelines are
recorded monthly as other receivables or other payables using then current
index prices or the weighted average prices of natural gas at the plant or
system. These imbalances are settled with cash or deliveries of natural gas. Impairment of Long-lived Assets- We evaluate the carrying value of
long-lived assets when circumstances indicate the carrying value of those
assets may not be recoverable. The carrying amount is not recoverable if it
exceeds the undiscounted sum of cash flows expected to result from the use and
eventual disposition of the asset. We consider various factors when determining
if impairment has occurred, including but not limited to:  
    
    Significant adverse change in legal factors or in the business
climate;  
    
    A current-period operating or cash flow loss combined with a history
of operating or cash flow losses or a projection or forecast that
demonstrates continuing losses associated with the use of a long-lived
asset;  
    
    An accumulation of costs significantly in excess of the amount
originally expected for the acquisition or construction of a long-lived
asset;  
    
    Significant adverse changes in the extent or manner in which an asset is used or in its physical condition;  
    
    A significant change in the market value of an asset;  
    
    A current expectation that, more likely than not, an asset will be
sold or otherwise disposed of before the end of its estimated useful
life. If the carrying value is not recoverable, the impairment loss is measured
as the excess of the assets carrying value over its fair value. Fair value is
determined based upon managements best estimates of sales value and/or
discounted future cash flow models. Our revenues and expenses are significantly dependent on commodity prices
such as NGLs and natural gas. Past and current trends in the price changes of
these commodities may not be indicative of future trends. In addition, revenues
and expenses are impacted by throughput volumes. If negative market conditions
persist over time or throughput volumes decline, estimated cash flows over the
lives of our assets may not exceed the carrying value of those individual
assets, and asset impairments may occur in the future under existing accounting
rules. Furthermore, a change in managements intent about the use of individual
assets (held for use vs. held for sale) could also impact an impairment
analysis. Impairment of Goodwill- We perform an annual goodwill impairment test and
update the test if events or circumstances occur that would more likely than
not reduce the fair value of a reporting unit below its carrying amount. We use
a discounted cash flow analysis supported by market valuation multiples to
perform the assessment. Key assumptions in the analysis included the use of an
appropriate discount rate, estimated future cash flows and an estimated run
rate of general and administrative costs. In estimating cash flows, we
incorporate current market information as well as historical factors and
fundamental analysis as well as other factors into its forecasted commodity
prices. We will continue to remain alert for any indicators that the fair value of
a reporting unit could be below book value and assess goodwill for impairment
as appropriate, in addition to performing the annual goodwill impairment
analysis required by SFAS No. 142. Contingencies- We apply SFAS No. 5 (SFAS 5), Accounting for
Contingencies, and related interpretations to determine accounting and
disclosure requirements for contingencies. We operate in a highly regulated
environment. Governmental bodies such as the FERC, the SEC, the Internal
Revenue Service, the Department of Labor, the Environmental Protection Agency
and others have purview over various aspects of our business operations and
public reporting. Reserves are established when, in managements judgment, the
contingency is probable and able to be reasonably estimated. Disclosures
regarding litigation, assessments, and credit worthiness of customers or
counterparties, among others, are made when the contingency is not required to
be reserved for, but there is a reasonable possibility that a liability will be
incurred (see Note 15 to the Consolidated Financial Statements for discussion
of various contingencies). The evaluation of these contingencies is performed
by internal and external specialists. Accounting for contingencies requires
significant judgment by management regarding the estimated probabilities and
ranges of exposure to potential liability. Managements assessment of our
exposure to contingencies could change as new developments occur or more
information becomes available. The outcome of the contingencies could vary
significantly and could materially impact our consolidated results of
operations, cash flows and financial position. Management has applied its best
judgment in applying SFAS 5 to these matters. 29




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Liquidity and Capital Resources As of December 31, 2003, we had $43 million in cash and cash equivalents
compared to $35 million as of December 31, 2002. Current liabilities exceeded
current assets by $73 million and $322 million at December 31, 2003 and 2002,
respectively. We rely upon cash flows from operations to fund our liquidity and
capital requirements. A material adverse change in operations or available
financing may impact our ability to fund our current liquidity and capital
resource requirements. Operating Cash Flows During 2003, cash provided by operating activities was $475 million, an
increase of $31 million from $444 million during 2002. This increase was due
primarily to a $261 million increase in net income, partially offset by changes
in working capital balances, unrealized mark-to-market and hedging activity,
and non-cash charges. The increase in net income is due largely to
higher NGLs and crude oil prices, offset by higher natural gas prices, lower volumes, increased operating
expenses and increased general and administrative expenses. Volatility in crude oil, NGLs and natural gas prices and the structure of
our commodity supply contracts have a direct impact on our generation and use
of cash from operations due to its impact on net income as described in the
Effects of Commodity Prices section above, along with the resulting changes in
working capital. Investing Cash Flows During 2003, cash used in investing activities was $41 million, a decrease
of $196 million from $237 million in 2002. The decrease is partially related to
proceeds of $90 million from sales of discontinued operations. Our capital
expenditures consist of expenditures for acquisitions and construction of
additional gathering systems, processing plants, fractionators and other
facilities and infrastructure in addition to well connections and upgrades to
our existing facilities. For the year ended December 31, 2003, we spent
approximately $129 million on acquisition and capital expenditures of
continuing operations compared to $297 million in 2002. The decrease is due to
reduced plant expansions, well connections and plant upgrades in 2003, as
compared to 2002. Our level of capital expenditures for acquisitions and construction and
other investments depends on many factors, including industry conditions, the
availability of attractive acquisition opportunities and construction projects,
the level of commodity prices and competition. We expect to finance our capital
expenditures with our cash on hand, cash flow from operations, asset sales, our
credit facility or other available sources of financing. Our capital
expenditure forecast for 2004 is approximately $220 million. Depending on cash
flow results, redeployment of capital from divestitures and opportunities in
the marketplace, 2004 acquisition and capital expenditures may vary from the
forecast. Investments in unconsolidated affiliates provided $65 million in cash
distributions to us during 2003 compared with $54 million in 2002. There were
investment expenditures of $85 million in 2003 that were made to repay the
underlying debt of an unconsolidated affiliate. The only remaining debt of an
unconsolidated affiliate at December 31, 2003 was $3 million that was repaid on
January 31, 2004. Financing Cash Flows Bank Financing and Commercial Paper On March 28, 2003, we entered into a credit facility (the Facility). The
Facility replaces a credit facility that matured on March 28, 2003. The
Facility is used to support our commercial paper program and for working
capital and other general corporate purposes. The Facility matures on March 26,
2004; however; any outstanding loans under the Facility at maturity may, at our
option, be converted to a one-year term loan. The Facility is a $350 million
revolving credit facility, of which $100 million can be used for letters of
credit. The Facility requires us to maintain at all times a debt to total
capitalization ratio of less than or equal to 53%; and maintain at the end of
each fiscal quarter an interest coverage ratio (defined to be the ratio of
adjusted EBITDA, as defined by the Facility, for the four most recent quarters
to interest expense for the same period) of at least 2.5 to 1 (adjusted EBITDA
is defined by the Facility to be earnings before interest, taxes and
depreciation and amortization and other adjustments); and contains various
restrictions applicable to dividends and other payments to our members. The
Facility bears interest at a rate equal to, at our option and based on our
current debt rating, either (1) LIBOR plus 1.25% per year or (2) the higher of
(a) the JP Morgan Chase Bank prime rate plus 0.25% per year and (b) the Federal
Funds rate plus 0.75% per year. At December 31, 2003, there were no borrowings
or letters of credit drawn against the Facility. By March 26, 2004, we expect
to refinance the Facility and replace it with an up to $250 million 30




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credit facility which will mature on March 25, 2005 and have similar terms
as the Facility, with the exception that there will no longer be a restriction
applicable to dividends and other payments to our members and we will be able
to request letters of credit up to the full committed amount of the new credit
facility. This new credit facility has been decreased from the Facility due to
reduced liquidity requirements. On March 28, 2003, we also entered into a $100 million funded short-term
loan with a bank (the Short-Term Loan). The Short-Term Loan was used for
working capital and other general corporate purposes. The Short-Term Loan
contained an original maturity of September 30, 2003, but was repaid by August
2003 with funds generated from asset sales and operations. On November 3, 2003, we executed a $32 million irrevocable standby letter
of credit expiring on May 15, 2004 to be used to secure transaction exposure
with a counterparty. At December 31, 2003, we had no outstanding commercial paper. In the
future, our debt levels will vary depending on our liquidity needs, capital
expenditures and cash flow. In April 2002, we filed a shelf registration statement increasing our
ability to issue securities to $500 million. The shelf registration statement
provides for the issuance of senior notes, subordinated notes and trust
preferred securities. Based on current and anticipated levels of operations, we believe that our
cash on hand and cash flow from operations, combined with borrowings available
under the commercial paper program as supported by the Facility, which is
expected to be refinanced, will be sufficient to enable us to meet our current
and anticipated cash operating requirements and working capital needs for the
next year. Actual capital requirements, however, may change, particularly as a
result of any acquisitions or distributions that we may make. Our ability to
meet current and anticipated operating requirements will depend on our future
performance. Preferred Financing In August 2000, we issued $300 million of preferred member interests to
affiliates of Duke Energy and ConocoPhillips in proportion to their ownership
interests. The proceeds from this financing were used to repay a portion of our
outstanding commercial paper. The outstanding preferred member interests are
entitled to cumulative preferential distributions of 9.5% per annum payable,
unless deferred, semiannually. For the years ending December 31, 2003, 2002 and
2001, we paid preferential distributions of $9 million (represents the first half of 2003), $25 million and $29
million, respectively. On September 9, 2002, we redeemed $100 million, on
September 19, 2003, we redeemed $125 million, and on December 31, 2003, we
redeemed the remaining $75 million of our preferred members interest by paying
cash to each member (Duke Energy and ConocoPhillips) in proportion to their
ownership interests. In May 2003, the FASB issued SFAS No. 150 (SFAS 150), Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and
Equity. SFAS 150 requires that certain financial instruments that could
previously be accounted for as equity, be classified as liabilities in the
balance sheets and initially recorded at fair value. Upon adoption on July 1,
2003, we reclassified our preferred members interest, which are mandatorily
redeemable securities, of $200 million from mezzanine equity to long term debt.
During 2003, subsequent to the reclassification, we redeemed the entire
remaining $200 million of the securities. Beginning on July 1, 2003, accrued
or paid distributions previously classified as dividends on the preferred
members interest are prospectively classified as interest expense in the
Consolidated Statements of Operations. Interest expense for 2003 on the
preferred members interest was $6 million (represents the
second half of 2003 preferential distributions). Debt Securities The following series of unsecured senior debt securities were outstanding
at December 31, 2003: Issue
    
    Principal
    
    InterestDate
    
    (millions)
    
    Rate
    
    Due DateAugust 16, 2000
    
    $
    600
    
    
    
    7 1/2
    %
    
    August 16, 2005August 16, 2000
    
    $
    800
    
    
    
    7 7/8
    %
    
    August 16, 2010August 16, 2000
    
    $
    300
    
    
    
    8 1/8
    %
    
    August 16, 2030February 2, 2001
    
    $
    250
    
    
    
    6 7/8
    %
    
    February 1, 2011November 9, 2001
    
    $
    300
    
    
    
    5 3/4
    %
    
    November 15, 2006
 31




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##### Table of Contents



The proceeds from the issuance of debt securities were used to repay a
portion of our outstanding commercial paper. The notes mature and become due
and payable on their respective due dates, and are not subject to any sinking
fund provisions. Interest is payable semiannually. Each series of notes is
redeemable, in whole or in part, at our option. At the respective due dates, we
expect to either refinance the debt with long term debt or a combination of
short term and long term debt or repay a portion of the debt and refinance the
remainder with long term debt or a combination of short term and long term
debt. In October 2001, we entered into an interest rate swap to convert the
fixed interest rate of $250 million of debt securities that were issued in
August 2000 to floating rate debt. The interest rate fair value hedge is at a
floating rate based on a six-month London Interbank Offered Rate (LIBOR),
which is re-priced semiannually through 2005. In August 2003, we entered into
two additional interest rate swaps to convert the fixed interest rate of $100
million of debt securities issued on August 16, 2000 to floating rate debt.
These interest rate fair value hedges also bear a floating rate based on
six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet
conditions which permit the assumption of no ineffectiveness. As such, for the
life of the swaps no ineffectiveness will be recognized. As of December 31,
2003, the fair value of the interest rate swaps of $15 million asset was
included in the Consolidated Balance Sheets as Unrealized Gains or Losses on
Trading and Hedging Transactions with an offset to the underlying debt included
in Long Term Debt. Distributions We are required to make quarterly distributions to Duke Energy and
ConocoPhillips based on allocated taxable income. Our Limited Liability Company
Agreement provides for taxable income to be allocated in accordance with the
Internal Revenue Code Section 704(c). This Code section takes into account the
variation between the adjusted tax basis and the fair market value of assets
contributed to the joint venture. The required distribution is based on the
highest taxable income allocated to either member, with the other member
receiving a proportionate amount to maintain the ownership capital accounts at
69.7% for Duke Energy and 30.3% for ConocoPhillips. As of December 31, 2003 and
2002, there were no distributions payable based on taxable income allocated to
the members. We expect that we will pay tax distributions to our members in
2004. In 2003, our board of directors approved a plan to consider the payment of
a quarterly dividend to our members. Our board of directors may
consider net income, cash flow or any other criteria deemed appropriate for determining the amount of the quarterly dividend to be
paid. Our LLC Agreement restricts making distributions, which would include
these dividends, except with the approval of both members. Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Arrangements As part of our normal business, we are a party to various financial
guarantees, performance guarantees and other contractual commitments to extend
guarantees of credit and other assistance to various subsidiaries, investees
and other third parties. To varying degrees, these guarantees involve elements
of performance and credit risk, which are not included in the Consolidated
Balance Sheets. The possibility of us having to honor our contingencies is
largely dependent upon future operations of various subsidiaries, investees and
other third parties, or the occurrence of certain future events. We would
record a reserve if events occurred that required that one be established. See
Note 18 to the Consolidated Financial Statements for more information on
guarantee obligations. At December 31, 2003, we were the guarantor of approximately $3 million of
debt associated with unconsolidated subsidiaries. Assets of the unconsolidated
subsidiaries are pledged as collateral for the debt. This debt was
subsequently repaid in January 2004. At December 31, 2003, we had no liability
recorded for the guarantees of the debt associated with the unconsolidated
subsidiaries. At December 31, 2003, we have various indemnification agreements
outstanding contained in asset purchase and sale agreements. These
indemnification agreements generally relate to the change in environmental and
tax laws or settlement of outstanding litigation. These indemnification
agreements generally have terms of one to five years, although some are longer.
We cannot estimate the maximum potential amount of future payments under these
indemnification agreements due to the uncertainties related to changes in laws
and regulation with regard to taxes, safety and protection of the environment
or the settlement of outstanding litigation, which are outside our control. At
December 31, 2003, we had a liability of $1 million recorded for these
outstanding indemnification provisions. 32




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##### Table of Contents



The following table summarizes our payments due under material cash
contractual obligations as of December 31, 2003 (in millions): Payments Due By Period (millions)Total
    
    Less than 1 Year
    
    1-3 Years
    
    3-5 Years
    
    More than 5 YearsDebt (a)
    
    $
    3,630
    
    
    $
    172
    
    
    $
    1,194
    
    
    $
    209
    
    
    $
    2,055Capital leases
    
    
    3
    
    
    
    1
    
    
    
    2
    
    
    
    
    
    
    
    Operating leases
    
    
    71
    
    
    
    13
    
    
    
    19
    
    
    
    14
    
    
    
    25Purchase commitments (b)
    
    
    353
    
    
    
    218
    
    
    
    75
    
    
    
    60
    
    
    
    Other long term liabilities (c)
    
    
    62
    
    
    
    1
    
    
    
    2
    
    
    
    2
    
    
    
    57Total
    
    $
    4,119
    
    
    $
    405
    
    
    $
    1,292
    
    
    $
    285
    
    
    $
    2,137
  (a)
    
    Debt includes debt securities of $2,250 million and long term notes payable
of $10 million. Debt also includes interest payments of $1,370 million
($59 million of which is recognized as accrued interest payable on the
2003 Consolidated Balance Sheet) of future interest payments based upon
current outstanding long term debt.  (b)
    
    Purchase commitments include $353 million of various non-cancelable
commitments to purchase physical quantities of commodities in future
periods. Amount includes certain normal purchases, commodity derivatives and
hedges. For contracts where the price paid is based on an index, the
amount is based on the forward market prices at December 31, 2003.
Purchase commitments exclude $906 million of accounts payable and $150
million of other current liabilities recognized on the 2003 Consolidated
Balance Sheet. Purchase commitments also exclude $153 million of current
and $24 million of long term unrealized losses on trading and hedging
transactions included in the Consolidated Balance Sheets. These amounts
represent the current fair value of various derivative contracts and do
not represent future cash purchase commitments. These contracts may be
settled financially at the difference between the future market price and
the contractual price and may result in cash payments or cash receipts in
the future, but generally do not require delivery of physical quantities. In
addition, many of our gas purchase contracts include short and long term
commitments to purchase produced gas at market prices. These contracts,
which have no minimum quantities, are excluded from the table.  (c)
    
    Other long term liabilities include $17 million of deferred income taxes
and $45 million of asset retirement obligations recognized on the 2003
Consolidated Balance Sheet. 
 ITEM 7A.Quantitative and Qualitative Disclosures About Market Risk. Risk and Accounting Policies We are exposed to market risks associated with commodity prices, credit
exposure, interest rates, and, to a limited extent, foreign currency exchange
rates. Management has established comprehensive risk management policies to
monitor and manage these market risks. Duke Energy Field Services Risk
Management Committee is responsible for the overall approval of market risk
management policies and the delegation of approval and authorization levels.
The Risk Management Committee is composed of senior executives who receive
regular briefings on the Companys positions and exposures as well as periodic
updates from and consultations with the Duke Energy Chief Risk Officer (CRO)
and other expert resources at Duke Energy regarding market risk positions and
exposures, credit exposures and overall risk management in the context of
market activities. The Risk Management Committee is responsible for the overall
management of credit risk and commodity price risk, including monitoring
exposure limits. See Critical Accounting Policies beginning on page 27  Risk Management
Activities for further discussion of Risk and Accounting Policies. Commodity Price Risk We are exposed to the impact of market fluctuations primarily in the price
of NGLs that we own as a result of our processing activities. We employ
established policies and procedures to manage our risks associated with these
market fluctuations using various commodity derivatives, including forward
contracts, swaps, futures and options. (See Notes 2 and 13 to the Consolidated
Financial Statements.) 33




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##### Table of Contents



Commodity Derivatives  Mark-to-Market The risk in the commodity
mark-to-market portfolio is measured and monitored on a daily basis utilizing a
Value-at-Risk model to determine the potential one-day favorable or unfavorable
Daily Value at Risk (DVaR) as described below. DVaR is monitored daily in
comparison to established thresholds. Other measures are also used to limit and
monitor the risk in the commodity mark-to-market portfolio (which includes all
trading and non-trading derivatives not designated as hedge positions) on a
monthly and annual basis. These measures include limits on the nominal size of
positions and periodic loss limits. DVaR computations are based on a historical simulation, which uses price
movements over an 11 day period to simulate forward price curves in the energy
markets to estimate the potential favorable or unfavorable impact of one days
price movement on the existing portfolio. The historical simulation emphasizes
the most recent market activity, which is considered the most relevant
predictor of immediate future market movements for crude oil, NGLs, natural gas
and other energy-related products. DVaR computations use several key
assumptions, including a 95% confidence level for the resultant price movement
and the holding period specified for the calculation. The Companys DVaR
amounts for commodity mark-to-market derivatives instruments and related activities are shown in the
following table: Daily Value at Risk (millions) Estimated Average
    
    Estimated Average
    
    High One-Day Impact
    
    Low One-Day ImpactOne-Day Impact on
    
    One-Day Impact on
    
    on EBIT for
    
    on EBIT forEBIT for 2003
    
    EBIT for 2002
    
    2003
    
    2003Calculated DVaR
    
    $
    1
    
    
    $
    2
    
    
    $
    7
    
    
    
    
 DVaR is an estimate based on historical price volatility. Actual
volatility can exceed predicted results. DVaR also assumes a normal
distribution of price changes, thus if the actual distribution is not normal,
the DVaR may understate or overstate actual results. DVaR is used to estimate
the risk of the entire portfolio, and for locations that do not have daily
trading activity, it may not accurately estimate risk due to limited price
information. Stress tests may be employed in addition to DVaR to measure risk
where market data information is limited. In the current DVaR methodology,
options are modeled in a manner equivalent to forward contracts which may
understate the risk. Our exposure to commodity price risk is influenced by a number of factors,
including contract size, length of contract, market liquidity, location and
unique or specific contract terms. Effective January 1, 2003, in connection
with the implementation of EITF 02-03, the Company designates each commodity derivative as either trading or non-trading. Certain non-trading
derivatives are further designated as either a hedge of a forecasted
transaction or future cash flow (cash flow hedge), a hedge of a recognized
asset, liability or firm commitment (fair value hedge), or a normal purchase or
sale contract, while certain non-trading derivatives, which are related to our
asset based marketing, are non-trading mark-to-market derivatives. For each of
the Companys derivatives, the accounting method and presentation of gains and
losses or revenue and expense in the Consolidated Statements of Income are as
follows: Classification of Contract
    
    Accounting Method
    
    Presentation of Gains & Losses or Revenue & ExpenseTrading Derivatives
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net marginNon-Trading Derivatives:Cash Flow Hedge
    
    Hedge methodb
    
    Gross basis in the same income statementcategory as the related hedged itemFair Value Hedge
    
    Hedge methodb
    
    Gross basis in the same income statementcategory as the related hedged itemNormal Purchase orNormal Sale
    
    Accrual methodc
    
    Gross basis upon settlement in theNon-Trading Mark-to-
    
    Mark-to-marketa
    
    corresponding income statement categoryMarket
    
    
    
    based on commodity typeNet basis in Trading and marketing net margin
 a Mark-to-market- An accounting method whereby the change in the fair value of
the asset or liability is recognized in the Consolidated Statements of Income
in Trading and marketing net margin during the current period. b Hedge method- An accounting method whereby the effective portion of the
change in the fair value of the asset or liability is recorded in the
Consolidated Balance Sheets and there is no recognition in the Consolidated
Statements of Income for the effective portion until the service is provided or
the associated delivery period occurs. 34




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##### Table of Contents



c Accrual method- An accounting method whereby there is no recognition in the
Consolidated Statements of Income for normal purchases and sales derivatives
for changes in fair value of a contract until the service is provided or the
associated delivery period occurs. The following table illustrates the movements in the fair value of our
mark-to-market instruments during 2003: Changes in Fair Value of Mark-to-Market Contracts (millions) Trading
    
    Non-Trading
    
    TotalFair value of contracts outstanding at the beginning of the year
    
    ($
    23
    )
    
    ($
    5
    )
    
    ($
    28
    )Contracts realized or otherwise settled during the year
    
    
    11
    
    
    
    35
    
    
    
    46Net premiums paid (received) for new option contracts during the year
    
    
    (5
    )
    
    
    
    
    
    
    (5
    )Net mark-to-market changes in fair values
    
    
    20
    
    
    
    (35
    )
    
    
    (15
    )Fair value of contracts outstanding at the end of the year
    
    $
    3
    
    
    ($
    5
    )
    
    ($
    2
    )
 The fair value of these contracts is expected to be realized in future
periods, as detailed in the following table. The amount of cash ultimately
realized for these contracts will differ from the amounts shown in the
following table due to factors such as market volatility, counterparty default
and other unforeseen events that could impact the amount and/or realization of
these values. When available, quoted market prices are used to record a contracts fair
value. However, market values for energy trading contracts may not be readily
determinable because the duration of the contracts exceeds the liquid activity
in a particular market. If no active trading market exists for a commodity or
for a contracts duration, holders of these contracts must calculate fair value
using internally developed valuation techniques or models. Key components used
in these valuation techniques include price curves, volatility, correlation,
interest rates, and tenor. Of these components, volatility and correlation are
the most subjective. Internally developed valuation techniques include the use
of interpolation, extrapolation, and fundamental analysis in the calculation of
a contracts fair value. All risk components for new and existing transactions
are valued using the same valuation technique and market data and discounted
using a LIBOR based interest rate. Valuation adjustments for performance,
market risk and administration costs are used to adjust the fair value of the
contract to the gain or loss ultimately recognized in the Consolidated
Statements of Operations. 35




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##### Table of Contents



The following table shows the fair value of our mark-to-market portfolio
as of December 31, 2003: Fair Value of Contracts as of December 31, 2003 (millions)Maturity in 2007Sources of Fair Value
    
    Maturity in 2004
    
    Maturity in 2005
    
    Maturity in 2006
    
    and Thereafter
    
    Total Fair ValueTrading:Prices supported by
quoted market prices
and other external
sources
    
    $
    4
    
    
    $
    1
    
    
    $
    (1
    )
    
    $
    
    
    
    $
    4Prices based on
models
and other valuation
methods
    
    
    1
    
    
    
    
    
    
    
    
    
    
    
    (2
    )
    
    
    (1
    )Total
Trading
    
    
    5
    
    
    
    1
    
    
    
    (1
    )
    
    
    (2
    )
    
    
    3Non-Trading:Prices supported by
quoted market prices
and other external
sources
    
    
    (4
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (4
    )Prices based on
models
and other valuation
methods
    
    
    (1
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1
    )Total
Non-Trading
    
    
    (5
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (5
    )Total
Mark-to-Market
    
    $
    
    
    
    $
    1
    
    
    $
    (1
    )
    
    $
    (2
    )
    
    $
    (2
    )
 The Prices supported by quoted market prices and other external sources
category includes our New York Mercantile Exchange (NYMEX) swap positions in
natural gas and crude oil. The NYMEX has currently quoted prices for the next
32 months. In addition, this category includes our forward positions and
options in natural gas and natural gas basis swaps at points for which
over-the-counter (OTC) broker quotes are available. On average, OTC quotes
for natural gas forwards and swaps extend 22 and 32 months into the future,
respectively. OTC quotes for natural gas options extend 12 months into the
future, on average. We value these positions against internally developed
forward market price curves that are validated and recalibrated against OTC
broker quotes. This category also includes strip transactions whose prices
are obtained from external sources and then modeled to daily or monthly prices
as appropriate. The Prices based on models and other valuation methods category includes
(i) the value of options not quoted by an exchange or OTC broker and (ii) the
value of transactions for which an internally developed price curve was
constructed as a result of the long dated nature of the transaction or the
illiquidity of the market point. In certain instances structured transactions
can be decomposed and modeled by us as simple forwards and options based on
prices actively quoted. Although the valuation of the simple structures might
not be different from the valuation of contracts in other categories, the
effective model price for any given period is a combination of prices from two
or more different instruments and therefore has been included in this category
due to the complex nature of these transactions. Hedging Strategies We are exposed to market fluctuations in the prices
of energy commodities related to natural gas gathering, processing and
marketing activities. We closely monitor the risks associated with these
commodity price changes on our future operations and, where appropriate, may
use various commodity instruments such as natural gas, crude oil and NGL
contracts to hedge the value of our assets and operations from such price
risks. Our hedging program reduces the potential negative impact that
commodity price changes could have on our earnings and improves our ability to
adequately plan for cash needed for debt service and capital expenditures. The
primary goals of the hedging program include maintaining minimum cash flows to
fund debt service, production replacement and maintenance capital projects, and
retaining a high percentage of potential upside relating to price increases of
NGLs. 36




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##### Table of Contents



Our primary use of commodity derivatives is to hedge the output and
production of assets we physically own. Current contract
terms are up to one year; however, our risk management guidelines allow
for contract terms up to three years. Since these contracts are designated and
qualify as effective hedge positions of future cash flows, or fair
values of assets, liabilities or firm commitments, to the extent that the hedge relationships are
effective, their market value change impacts are not recognized in current
earnings. The unrealized gains or losses on these contracts are deferred in
Accumulated Other Comprehensive Income (Loss) (AOCI) for cash flow hedges or
included in Other Current or Noncurrent Assets or Liabilities on the
Consolidated Balance Sheets for fair value hedges of firm commitments. Amounts
in AOCI are realized in earnings concurrently with the transaction being
hedged. However, in instances where the hedging contract no longer qualifies
for hedge accounting, amounts included in AOCI through the date of
de-designation remain in AOCI until the underlying transaction actually occurs.
The derivative contract (if continued as an open position) will be marked to
market currently through earnings. Several factors influence the effectiveness
of a hedge contract, including counterparty credit risk and using contracts
with different commodities or unmatched terms. Hedge effectiveness is monitored
regularly and measured each month. The following table shows when gains and losses deferred on the
Consolidated Balance Sheets for derivative instruments qualifying as effective
hedges of firm commitments or anticipated future transactions will be
recognized into earnings. However, as mentioned previously, the effective
portion of the gains and losses for these contracts are not recognized in
earnings until settlement at their future market price. Therefore, assumptions
and valuation techniques for these contracts have no impact on reported
earnings prior to settlement for the effective portion of these hedges. The fair value of our qualifying hedge positions at a point in time is not
necessarily indicative of the results realized when such contracts settle. The
following table show the fair value of our hedging contracts, including both
commodity hedges and interest rate hedges, as of December 31, 2003: Fair Value of Contracts as of December 31, 2003 (millions)Maturity in 2007Sources of Fair Value
    
    Maturity in 2004
    
    Maturity in 2005
    
    Maturity in 2006
    
    and Thereafter
    
    Total Fair ValueQuoted market prices
    
    $
    (18
    )
    
    $
    6
    
    
    $
    2
    
    
    $
    (5
    )
    
    $
    (15
    )Prices based on
models or other
valuation techniques
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    $
    (18
    )
    
    $
    6
    
    
    $
    2
    
    
    $
    (5
    )
    
    $
    (15
    )
 Based upon our portfolio of supply contracts, without giving effect to
hedging activities that would reduce the impact of commodity price decreases, a
decrease of $0.01 per gallon in the price of NGLs and $0.10 per million Btus in
the average price of natural gas would result in changes in annual pre-tax net
income of approximately $(18) million and $1 million, respectively. In
addition, a decrease of $1 per barrel in the average price of crude oil would
result in a change to annual pre-tax net income of approximately $(5) million. Credit Risk Our principle customers in the Natural Gas Segment are large, natural gas
marketing services and industrial end-users. In the NGLs segment, our
principle customers range from large multi-national petrochemical and refining
companies to small regional propane distributors. Substantially all of our
natural gas and NGLs sales are made at index, market-based prices.
Approximately 40% of our NGLs production is committed to ConocoPhillips and
ChevronPhillips, under an existing 15-year contract which expires in 2015. This
concentration of credit risk may affect our overall credit risk in that these
customers may be similarly affected by changes in economic, regulatory or other
factors. Where exposed to credit risk, we analyze the counterparties
financial condition prior to entering into an agreement, establish credit
limits and monitor the appropriateness of these limits on an ongoing basis.
The corporate credit policy prescribes the use of master collateral agreements
to mitigate credit exposure. Collateral agreements provide for a counterparty
to post cash or letters of credit for exposure in excess of the established
threshold. The threshold amount represents an open credit limit, determined in
accordance with the corporate credit policy. The collateral agreements also
provide that the inability to post collateral is sufficient cause to terminate
a contract and liquidate all positions. Substantially all other agreements
contain adequate assurance provisions, which would allow us, at our discretion,
to suspend deliveries, cancel agreements or continue deliveries to the buyer
after the buyer provides security for payment satisfactory to us. 37




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##### Table of Contents



Despite the current credit environment in the energy sector, management
believes that the credit risk management process described above is operating
effectively. As of December 31, 2003, we had cash or letters of credit of $65
million to secure future performance by counterparties, and had deposited with
counterparties $39 million of such collateral to secure our obligations to
provide future services or to perform under financial contracts. Collateral
amounts held or posted may be fixed or may vary depending on the value of the
underlying contracts and could cover normal purchases and sales, trading and
hedging contracts. In many cases, we and our counterparties publicly
disclosed credit ratings impact the amounts of collateral requirements. Interest Rate Risk We enter into debt arrangements that are exposed to market risks related
to changes in interest rates. We periodically utilize interest rate
lock agreements and interest rate swaps to hedge interest rate risk associated with debt. Our primary goals include: (1)
maintaining an appropriate ratio of fixed-rate debt to total debt for our debt
rating; (2) reducing volatility of earnings resulting from interest rate
fluctuations; and (3) locking in attractive interest rates based on historical
averages. As of December 31, 2003, the fair value of our interest rate swaps
was an asset of $15 million. (See Notes 2 and 13 to the Consolidated Financial
Statements.) As of December 31, 2003, we had no outstanding commercial paper. As a
result of our debt and interest rate swaps, we are exposed to market risks
related to changes in interest rates. In the future, we intend to manage our
interest rate exposure using a mix of fixed and floating interest rate debt. An
increase of 0.5% in interest rates would result in an increase in annual
interest expense of approximately $2 million. Foreign Currency Risk Our primary foreign currency exchange rate exposure at December 31, 2003
was the Canadian dollar. Foreign currency risk associated with this exposure
was not material. Accounting Pronouncements In May 2003, the FASB issued SFAS 150 which requires that certain
financial instruments that could previously be accounted for as equity, be
classified as liabilities in the Consolidated Balance Sheets and initially
recorded at fair value. In addition to its requirements for the classification
and measurement of financial instruments in its scope, SFAS 150 also requires
disclosures about the nature and terms of the financial instruments and about
alternative ways of settling the instruments. The provisions of SFAS 150 are
effective for all financial instruments entered into or modified after May 31,
2003, and are otherwise effective at the beginning of the first interim period
beginning after June 15, 2003. Upon adoption on July 1, 2003, we reclassified
our preferred members interest, which are mandatorily redeemable securities,
of $200 million from mezzanine equity to long term debt and prospectively
classified accrued or paid distributions on the preferred members interest,
which had previously been classified as dividends, as interest expense.
Interest expense recorded in 2003 on the preferred members interest was $6
million. During 2003, we redeemed the remaining $200 million of the securities
in cash. In April 2003, the FASB issued SFAS No. 149 (SFAS 149), Amendment of
Statement 133 on Derivative Instruments and Hedging Activities, which amends
and clarifies accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS 133. SFAS 149 clarifies the discussion around initial net
investment, clarifies when a derivative contains a financing component, and
amends the definition of an underlying to conform to language used in FASB
Interpretation No. 45 (FIN 45), Guarantors Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others. In addition, SFAS 149 also incorporates certain of the Derivative
Implementation Group Implementation Issues. The provisions of SFAS 149 are
effective for contracts entered into or modified after June 30, 2003 and for
hedging relationships designated after June 30, 2003. The guidance is to be
applied to hedging relationships on a prospective basis. The adoption of the
new interpretation had no material effect on our consolidated results of
operations, cash flows or financial position. In January 2003, the FASB issued Interpretation No. 46 (FIN 46),
Consolidation of Variable Interest Entities which requires the primary
beneficiary of a variable interest entitys activities to consolidate the
variable interest entity. FIN 46 defines a variable interest entity as an
entity in which the equity investors do not have substantive voting rights and
there is not sufficient equity at risk for the entity to finance its activities
without additional subordinated financial support. The primary beneficiary is
the party that absorbs a majority of the expected losses and/or receives a
majority of the expected residual returns of the variable interest entitys
activities. In December 2003, the FASB issued FIN 46R, which supercedes and
amends certain provisions of FIN 46. While FIN 46R retains many of the concepts
and provisions of FIN 46, it also provides additional guidance related to the
application of FIN 46, 38




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provides for certain additional scope exceptions, and incorporates several
FASB Staff Positions issued related to the application of FIN 46. The provisions of FIN 46 are immediately applicable to variable interest
entities created, or interests in variable interest entities obtained, after
January 31, 2003 and the provisions of FIN 46R are required to be applied to
such entities by the end of the first reporting period ending after March 15,
2004 (March 31, 2004 for us). For variable interest entities created, or
interests in variable interest entities obtained, on or before January 31,
2003, FIN 46 or FIN 46R is required to be applied to special-purpose entities
by the end of the first reporting period ending after December 15, 2003
(December 31, 2003 for calendar-year entities) and is required to be applied to
all other non-special purpose entities by the end of the first reporting period
ending after March 15, 2004 (March 31, 2004 for calendar-year entities). FIN 46
and FIN 46R may be applied prospectively with a cumulative-effect adjustment as
of the date it is first applied, or by restating previously issued financial
statements with a cumulative-effect adjustment as of the beginning of the first
year restated. FIN 46 and FIN 46R also require certain disclosures of an
entitys relationship with variable interest entities. We have not identified any material variable interest entities created, or
interests in variable entities obtained, after January 31, 2003 which require
consolidation or disclosure under FIN 46 and continue to assess the existence
of any interests in variable interest entities created on or prior to January
31, 2003. We currently anticipate one non-special purpose entity, previously
accounted for under the equity method of accounting, will be consolidated by us
in the first quarter of 2004 under the provisions of FIN 46R. This entity,
which is a substantive entity, has total assets of approximately $92 million as
of December 31, 2003 and total revenue of approximately $43 million for the
year ended December 31, 2003. Our maximum exposure to loss as a result of our
involvement with this entity is approximately $82 million as of December 31, 2003. We continue to assess
FIN 46R but do not anticipate that it will have a material impact on our
consolidated results of operations, cash flows or financial position. In November 2002, the FASB issued FIN 45 which elaborates on the
disclosures to be made by a guarantor about its obligations under certain
guarantees issued. It also clarifies that a guarantor is required to recognize,
at the inception of a guarantee, a liability for the fair value of the
obligation undertaken in issuing the guarantee. We adopted the initial
recognition and measurement provisions of FIN 45 effective January 1, 2003. The
adoption of the new interpretation had no material effect on our consolidated
results of operations, cash flows or financial position. In June 2002, the EITF reached a partial consensus on EITF 02-03. EITF
02-03 concluded that, effective for periods ending after July 15, 2002,
mark-to-market gains and losses on energy trading contracts (including those to
be physically settled) must be shown on a net basis in the Consolidated
Statements of Operations. We had previously chosen to report certain energy
trading contracts on a gross basis, as sales in operating revenues and the
associated costs recorded as purchases in costs and expenses, in accordance
with prevailing industry practice. The amounts in the comparative 2001
Consolidated Statements of Operations have been reclassified to conform to the
2003 and 2002 presentation of all amounts on a net basis. Revenues were
adjusted downward by $931 million from the previously reported amount, with
offsetting adjustments made to operating expenses resulting in no impact on net
income. In October 2002, the EITF, as part of their further deliberations on EITF
02-03, rescinded the consensus reached in Issue No. 98-10 (EITF 98-10),
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities, As a result, all energy trading contracts that do not meet the
definition of a derivative under SFAS No. 133, and trading inventories that
previously had been recorded at fair values, must now be recorded at the lower
of cost or market and are reported on an accrual basis resulting in the
recognition of earnings or losses at the time of contract settlement or
termination. New non-derivative energy trading contracts entered into after
October 25, 2002 should be accounted for under the accrual accounting basis.
Non-derivative energy trading contracts on the Consolidated Balance Sheet as of
January 1, 2003 that existed at October 25, 2002 and inventories that were
recorded at fair values have been adjusted to the lower of historical cost or
market, resulting in a $5 million charge recorded in 2003 in Cumulative effect
of accounting change in the Consolidated Statements of Operations. In
connection with the consensus reached on Issue No. 02-03, the FASB staff
observed that, effective July 1, 2002, an entity should not recognize
unrealized gains or losses at the inception of a derivative instrument unless
the fair value of that instrument is evidenced by quoted market prices or
current market transactions. In October 2002, the EITF also reached a consensus on EITF 02-03 that,
effective for periods beginning after December 15, 2002, all gains and losses
on all derivative instruments held for trading purposes should be shown on a
net basis in Consolidated Statements of Operations. Gains and losses on
non-derivative energy trading contracts should similarly be presented on a
gross or net basis in connection with the guidance in Issue No. 99-19,
Reporting Revenue Gross as a Principal versus Net as an Agent. Upon
application of this presentation, comparative financial statements for prior
periods are required to be reclassified to conform to the consensus other than
for energy trading contracts that were shown on a net basis under EITF 98-10.
Accordingly, for 2003, derivative instruments that are held for trading and
marketing purposes and are accounted for under mark-to-market accounting are
included in Trading and 39




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marketing net margin in the Consolidated Statements of Operations. As
noted above, for 2002 and 2001, Trading and marketing net margin also includes
the net margin on non-derivative energy trading contracts (primarily gas
storage inventories and the related physical purchases and sales). The gross
revenue presentation requirements had no impact on gross margin or net income. In July 2003, the EITF reached consensus in EITF Issue No. 03-11 (EITF
03-11), Reporting Realized Gains and Losses on Derivative Instruments that
are Subject to FASB Statement No. 133, Accounting for Derivative Instruments
and Hedging Activities, and Not Held for Trading Purposes, that determining
whether realized gains and losses on derivative contracts not held for trading
purposes should be reported on a net or gross basis is a matter of judgment
that depends on the relevant facts and circumstances. In analyzing the facts
and circumstances, EITF Issue No. 99-19 and Opinion No. 29, Accounting for
Nonmonetary Transactions, should be considered. EITF 03-11 is effective for
transactions or arrangements entered into after September 30, 2003. The
adoption of EITF 03-11 had no material effect on our consolidated results of
operations, cash flows or financial position as we continue to net non-trading
mark-to-market activity. On June 25, 2003, the FASB cleared the guidance contained in DIG Issue
C20, Scope Exceptions: Interpretation of the Meaning of Not Clearly and
Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment
Feature. DIG Issue C20, which applies only to the guidance in paragraph 10(b)
of FASB 133 and not in reference to embedded derivatives, describes three
circumstances in which the underlying in a price adjustment incorporated into a
contract that otherwise satisfies the requirements for the normal purchases and
normal sales exception would be considered to be not clearly and closely
related to the asset being sold or purchased. The guidance in DIG Issue C20
was effective for us on October 1, 2003. The adoption of this Issue had no
material impact on our consolidated results of operations, cash flows or
financial position. We adopted SFAS No. 142 (SFAS 142), Goodwill and Other Intangible
Assets, on January 1, 2002 which requires that goodwill no longer be amortized
over an estimated useful life, as previously required. Instead, goodwill
amounts are subject to a fair-value-based annual impairment assessment. We did
not recognize any impairments due to the implementation of SFAS 142. The
standard also requires certain identifiable intangible assets to be recognized
separately and amortized as appropriate. No adjustments to intangibles were
identified by us at transition. The following table shows what net income (loss) would have been if
amortization related to goodwill that is no longer being amortized had been
excluded from prior periods: For the Year EndedDecember 31,2003
    
    2002
    
    2001(millions)Reported net income (loss)
    
    $
    214
    
    
    $
    (47
    )
    
    $
    364Add: Goodwill amortization
    
    
    
    
    
    
    
    
    
    
    22Adjusted net income (loss)
    
    $
    214
    
    
    $
    (47
    )
    
    $
    386
 We adopted SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, on January 1, 2002. The new rules supersedes but retains
many of the fundamental recognition and measurement provisions of SFAS No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of. The new rules significantly change the criteria for
classifying an asset as held-for-sale. Adoption of the new standard had no
material effect on our consolidated results of operations or financial
position. In June 2001, the FASB issued SFAS No. 143 (SFAS 143), Accounting for
Asset Retirement Obligations, which addresses financial accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. The standard applies to legal
obligations associated with the retirement of long-lived assets that result
from the acquisition, construction, development and/or normal use of the asset.
SFAS 143 requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred, if a reasonable
estimate of fair value can be made. The fair value of the liability is added to
the carrying amount of the associated asset. This additional carrying amount is
then depreciated over the life of the asset. The liability increases due to the
passage of time based on the time value of money until the obligation is
settled. We adopted the provisions of SFAS 143 as of January 1, 2003. In
accordance with the transition provisions of SFAS 143, we recorded an $18
million charge in 2003 in Cumulative effect of accounting change in the
Consolidated Statements of Operations. In May 2003, the EITF reached consensus in EITF Issue No. 01-08 (EITF
01-08), Determining Whether an Arrangement Contains a Lease, to clarify the
requirements of identifying whether an arrangement should be accounted for as a
lease at its 40




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inception. The guidance in the consensus is designed to mandate reporting
revenue as rental or leasing income that otherwise would be reported as part of
product sales or service revenue. EITF 01-08 requires both parties to an
arrangement to determine whether a service contract or similar arrangement is
or includes a lease within the scope of SFAS No. 13, Accounting for Leases.
The consensus is to be applied prospectively to arrangements agreed to,
modified, or acquired in business combinations in fiscal periods beginning on
July 1, 2003. The adoption of EITF 01-08 had no material effect on our
consolidated results of operations, cash flows or financial position. Subsequent Events In August 2003, we entered into a purchase and sale agreement to sell
gas gathering and processing plant assets in West Texas to a third
party purchaser for a sales price of approximately $62 million. The transaction
was to be closed on September 30, 2003; however, the purchaser was unable to
meet the conditions of closing. In October 2003, we entered into a new
purchase and sale agreement for the sale of these assets to a party related to
the original third party purchaser for a sales price of approximately $62
million. The transaction was to be closed in December 2003; however, the
purchaser was again unable to meet the conditions of closing. In February
2004, we entered into a new purchase and sale agreement for the sale of these
assets to a party related to the original third party purchaser for a sales
price of approximately $62 million. The transaction closed in the first
quarter of 2004 with no significant book gain or loss. On March 10, 2004, we entered into an agreement to acquire gathering,
processing and transmission assets in Southeast New Mexico from ConocoPhillips
for approximately $75 million. Pending approvals from
governmental authorities, the transaction is scheduled to close in the
second quarter of 2004. The assets to be acquired include three natural gas
processing plants with capacity of 112 MMcf/d, over 1,000 miles of gathering
lines and associated compression, and a 75 mile intrastate natural gas pipeline. 41




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ITEM 8.Financial Statements and Supplementary Data. DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, 2003, 2002 and 2001
(millions) 2003
    
    2002
    
    2001Operating revenues:Sales of natural gas and petroleum products
    
    $
    6,115
    
    
    $
    3,533
    
    
    $
    5,084Sales of natural gas and petroleum products to
affiliates
    
    
    2,465
    
    
    
    2,194
    
    
    
    2,997Transportation, storage and processing
    
    
    263
    
    
    
    238
    
    
    
    178Trading and marketing net margin
    
    
    (24
    )
    
    
    14
    
    
    
    48Total operating revenues
    
    
    8,819
    
    
    
    5,979
    
    
    
    8,307Costs and expenses:Purchases of natural gas and petroleum products
    
    
    6,862
    
    
    
    4,482
    
    
    
    6,354Purchases of natural gas and petroleum products from
Affiliates
    
    
    682
    
    
    
    470
    
    
    
    692Operating and maintenance
    
    
    451
    
    
    
    434
    
    
    
    360Depreciation and amortization
    
    
    302
    
    
    
    290
    
    
    
    269General and administrative
    
    
    184
    
    
    
    167
    
    
    
    130Asset impairments
    
    
    4
    
    
    
    8
    
    
    
    Net loss (gain) on sale of assets
    
    
    
    
    
    
    4
    
    
    
    (1
    )Total costs and expenses
    
    
    8,485
    
    
    
    5,855
    
    
    
    7,804Operating income
    
    
    334
    
    
    
    124
    
    
    
    503Equity in earnings of unconsolidated affiliates
    
    
    49
    
    
    
    38
    
    
    
    30Interest expense, net
    
    
    170
    
    
    
    166
    
    
    
    166Income (loss) from continuing operations before
income taxes
    
    
    213
    
    
    
    (4
    )
    
    
    367Income tax expense
    
    
    8
    
    
    
    10
    
    
    
    3Income (loss) from continuing operations before
cumulative effect of accounting change
    
    
    205
    
    
    
    (14
    )
    
    
    364Gain (loss) from discontinued operations
    
    
    32
    
    
    
    (33
    )
    
    
    Cumulative effect of accounting change
    
    
    (23
    )
    
    
    
    
    
    
    Net income (loss)
    
    
    214
    
    
    
    (47
    )
    
    
    364Dividends on preferred members interest
    
    
    9
    
    
    
    25
    
    
    
    29Earnings (deficit) available for members interest
    
    $
    205
    
    
    $
    (72
    )
    
    $
    335
 See Notes to Consolidated Financial Statements. 42




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DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Years Ended December 31, 2003, 2002 and 2001
(millions) 2003
    
    2002
    
    2001Net income (loss)
    
    $
    214
    
    
    $
    (47
    )
    
    $
    364Other comprehensive income (loss):Cumulative effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    
    6Foreign currency translation adjustment
    
    
    60
    
    
    
    
    
    
    
    (5
    )Net unrealized gains (losses) on cash flow hedges
    
    
    (92
    )
    
    
    (129
    )
    
    
    52Reclassification into earnings
    
    
    121
    
    
    
    16
    
    
    
    (3
    )Total other comprehensive income (loss)
    
    
    89
    
    
    
    (113
    )
    
    
    50Total comprehensive income (loss)
    
    $
    303
    
    
    $
    (160
    )
    
    $
    414
 See Notes to Consolidated Financial Statements. 43




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DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2003, 2002 and 2001
(millions) 2003
    
    2002
    
    2001Cash flows from operating activities:Net income (loss)
    
    $
    214
    
    
    $
    (47
    )
    
    $
    364Adjustments to reconcile net income (loss) to net cash provided
by operating activities:(Gain) loss on discontinued operations
    
    
    (32
    )
    
    
    33
    
    
    
    Cumulative effect of changes in accounting principles
    
    
    23
    
    
    
    
    
    
    
    Depreciation and amortization
    
    
    302
    
    
    
    290
    
    
    
    269Equity in earnings of unconsolidated affiliates
    
    
    (49
    )
    
    
    (38
    )
    
    
    (30
    )Other, net
    
    
    16
    
    
    
    10
    
    
    
    3Change in operating assets and liabilities (net of effects of
acquisitions) which provided (used) cash:Accounts receivable
    
    
    (148
    )
    
    
    123
    
    
    
    309Accounts receivable from affiliates
    
    
    101
    
    
    
    59
    
    
    
    35Net unrealized losses (gains) on mark-to-market transactions.
    
    
    (33
    )
    
    
    72
    
    
    
    (36
    )Other current assets
    
    
    (14
    )
    
    
    (3
    )
    
    
    35Other noncurrent assets
    
    
    5
    
    
    
    1
    
    
    
    (17
    )Accounts payable
    
    
    51
    
    
    
    (81
    )
    
    
    (407
    )Accounts payable to affiliates
    
    
    (9
    )
    
    
    (1
    )
    
    
    (36
    )Other current liabilities
    
    
    35
    
    
    
    7
    
    
    
    (4
    )Other long term liabilities
    
    
    4
    
    
    
    10
    
    
    
    (23
    )Net cash provided by continuing operations
    
    
    466
    
    
    
    435
    
    
    
    462Net cash provided by discontinued operations
    
    
    9
    
    
    
    9
    
    
    
    10Net cash provided by operating activities
    
    
    475
    
    
    
    444
    
    
    
    472Cash flows from investing activities:Acquisition expenditures
    
    
    (6
    )
    
    
    
    
    
    
    (220
    )Capital expenditures
    
    
    (123
    )
    
    
    (297
    )
    
    
    (378
    )Investment expenditures, net of cash acquired
    
    
    (85
    )
    
    
    
    
    
    
    (5
    )Investment distributions
    
    
    65
    
    
    
    54
    
    
    
    41Proceeds from sales of discontinued operations
    
    
    90
    
    
    
    
    
    
    
    Proceeds from sales of assets
    
    
    21
    
    
    
    11
    
    
    
    22Net cash used in continuing operations
    
    
    (38
    )
    
    
    (232
    )
    
    
    (540
    )Net cash used in discontinued operations
    
    
    (3
    )
    
    
    (5
    )
    
    
    (6
    )Net cash used in investing activities
    
    
    (41
    )
    
    
    (237
    )
    
    
    (546
    )Cash flows from financing activities:Net decreases in advances from members
    
    
    
    
    
    
    (2
    )
    
    
    (11
    )Redemption of preferred members interests/debt
    
    
    (200
    )
    
    
    (100
    )
    
    
    Distributions to members
    
    
    
    
    
    
    (63
    )
    
    
    (236
    )Payment of debt
    
    
    (316
    )
    
    
    (2
    )
    
    
    (184
    )Proceeds from issuing debt, net
    
    
    100
    
    
    
    
    
    
    
    545Payment of dividends
    
    
    (9
    )
    
    
    (25
    )
    
    
    (29
    )Net cash (used in) provided by continuing operations
    
    
    (425
    )
    
    
    (192
    )
    
    
    85Net cash (used in) provided by discontinued operations
    
    
    
    
    
    
    
    
    
    
    Net cash (used in) provided by financing activities
    
    
    (425
    )
    
    
    (192
    )
    
    
    85Effect of foreign exchange rate changes on cash
    
    
    (1
    )
    
    
    
    
    
    
    7Net increase in cash
    
    
    8
    
    
    
    15
    
    
    
    18Cash and cash equivalents, beginning of year
    
    
    35
    
    
    
    20
    
    
    
    2Cash and cash equivalents, end of year
    
    $
    43
    
    
    $
    35
    
    
    $
    20Supplementary cash flow information:Cash paid for interest (net of amounts capitalized)
    
    $
    168
    
    
    $
    167
    
    
    $
    156
 See Notes to Consolidated Financial Statements. 44




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DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED BALANCE SHEETS
As of December 31, 2003 and 2002
(millions) 2003
    
    2002ASSETSCurrent assets:Cash and cash equivalents
    
    $
    43
    
    
    $
    35Accounts receivable:Customers, net of allowance for doubtful accounts
of $8 and $7, respectively
    
    
    872
    
    
    
    710Affiliates
    
    
    57
    
    
    
    158Other
    
    
    29
    
    
    
    41Inventories
    
    
    45
    
    
    
    72Unrealized gains on trading and hedging transactions
    
    
    135
    
    
    
    159Other
    
    
    20
    
    
    
    7Total current assets
    
    
    1,201
    
    
    
    1,182Property, plant and equipment, net
    
    
    4,462
    
    
    
    4,643Investment in affiliates
    
    
    190
    
    
    
    129Intangible assets:Commodity sales and purchases contracts, net
    
    
    80
    
    
    
    84Goodwill, net
    
    
    447
    
    
    
    435Total intangible assets
    
    
    527
    
    
    
    519Unrealized gains on trading and hedging transactions
    
    
    25
    
    
    
    22Other noncurrent assets
    
    
    109
    
    
    
    104Total assets
    
    $
    6,514
    
    
    $
    6,599LIABILITIES AND MEMBERS EQUITYCurrent liabilities:Accounts payable:Trade
    
    $
    857
    
    
    $
    793Affiliates
    
    
    16
    
    
    
    24Other
    
    
    33
    
    
    
    46Short term debt
    
    
    6
    
    
    
    216Accrued interest payable
    
    
    59
    
    
    
    59Unrealized losses on trading and hedging transactions.
    
    
    153
    
    
    
    246Other
    
    
    150
    
    
    
    120Total current liabilities
    
    
    1,274
    
    
    
    1,504Deferred income taxes
    
    
    17
    
    
    
    12Long term debt
    
    
    2,262
    
    
    
    2,255Unrealized losses on trading and hedging transactions
    
    
    24
    
    
    
    15Other long term liabilities
    
    
    73
    
    
    
    38Minority interests
    
    
    120
    
    
    
    125Preferred members interest
    
    
    
    
    
    
    200Commitments and contingent liabilitiesMembers equity:Members interest
    
    
    1,709
    
    
    
    1,709Retained earnings
    
    
    1,011
    
    
    
    806Accumulated other comprehensive income (loss)
    
    
    24
    
    
    
    (65
    )Total members equity
    
    
    2,744
    
    
    
    2,450Total liabilities and members equity
    
    $
    6,514
    
    
    $
    6,599
 See Notes to Consolidated Financial Statements. 45




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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF MEMBERS EQUITY

Years Ended December 31, 2003, 2002 and 2001
(millions)


|                                         |  |          |       |          |  |               |       |       |  |             |      |   |  |   |       |  
|---------------------------------------- |  | -------- | ----- | -------- |  | ------------- | ----- | ----- |  | ----------- | ---- | - |  | - | ----- | -
|                                         |  |          |       |          |  |               |       |       |  | Accumulated |      |   |  |  
|                                         |  |          |       |          |  |               |       |       |  | Other       |      |   |  |  
|                                         |  | Members |       | Retained |  | Comprehensive |       |       |  |            
|                                         |  | Interest |       | Earnings |  | Income (Loss) |       | Total
|                                         |  |          |       |          |  |               |       |      
|Balance, January 1,
2001                 |  | $        | 1,709 |          |  | $             | 714   |       |  | $           | (2   | ) |  | $ | 2,421 |  
|Distributions                            |  |          |      |          |  |               | (153  | )     |  |             |     |   |  |   | (153  | )
|Dividends on preferred
members interest |  |          |      |          |  |               | (29   | )     |  |             |     |   |  |   | (29   | )
|Net income                               |  |          |      |          |  |               | 364   |       |  |             |     |   |  |   | 364   |  
|Other                                    |  |          |      |          |  |               |      |       |  |             | 50   |   |  |   | 50    |  
|                                         |  |          |       |          |  |               |       |       |  |             |      |   |  |   |       |  
|Balance, December 31,
2001               |  |          | 1,709 |          |  |               | 896   |       |  |             | 48   |   |  |   | 2,653 |  
|Distributions                            |  |          |      |          |  |               | (18   | )     |  |             |     |   |  |   | (18   | )
|Dividends on preferred
members interest |  |          |      |          |  |               | (25   | )     |  |             |     |   |  |   | (25   | )
|Net loss                                 |  |          |      |          |  |               | (47   | )     |  |             |     |   |  |   | (47   | )
|Other                                    |  |          |      |          |  |               |      |       |  |             | (113 | ) |  |   | (113  | )
|                                         |  |          |       |          |  |               |       |       |  |             |      |   |  |   |       |  
|Balance, December 31,
2002               |  |          | 1,709 |          |  |               | 806   |       |  |             | (65  | ) |  |   | 2,450 |  
|Dividends on preferred
members interest |  |          |      |          |  |               | (9    | )     |  |             |     |   |  |   | (9    | )
|Net income                               |  |          |      |          |  |               | 214   |       |  |             |     |   |  |   | 214   |  
|Other                                    |  |          |      |          |  |               |      |       |  |             | 89   |   |  |   | 89    |  
|                                         |  |          |       |          |  |               |       |       |  |             |      |   |  |   |       |  
|Balance, December 31,
2003               |  | $        | 1,709 |          |  | $             | 1,011 |       |  | $           | 24   |   |  | $ | 2,744 |  
|                                         |  |          |       |          |  |               |       |       |  |             |      |   |  |   |       |  

See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2003, 2002 and 2001


1. General

Basis of Presentation Duke Energy Field Services, LLC (with its
consolidated subsidiaries, the Company or Field Services LLC) operates in
the midstream natural gas gathering, marketing and natural gas liquids
industries. The Company operates in the two principal segments of the midstream
natural gas industry of (1) natural gas gathering, processing, transportation,
marketing and storage; and (2) natural gas liquids (NGLs) fractionation,
transportation, trading and marketing and trading. Field Services LLCs limited
liability company agreement (LLC Agreement) limits the scope of the Companys
business to the midstream natural gas industry in the United States and Canada,
the marketing of NGLs in Mexico and the transportation,
marketing and storage of other petroleum products. Field Services LLC is 69.7%
owned by Duke Energy Corporation (Duke Energy) and 30.3% owned by
ConocoPhillips.

2. Summary of Significant Accounting Policies

Consolidation The Consolidated Financial Statements include the accounts
of the Company and all majority-owned subsidiaries, after eliminating
intercompany transactions and balances. Investments in 20% to 50% owned
affiliates, and investments in less than 20% owned affiliates where the Company
had the ability to exercise significant influence, are accounted for using the
equity method. Investments greater than 50% are consolidated unless the Company
does not have the ability to exercise control, in which case, they are
accounted for using the equity method (see Note10).

Use of Estimates Conformity with accounting principles generally
accepted in the United States of America requires management to make estimates
and assumptions that affect the amounts reported in the financial statements
and notes. Although these estimates are based on managements best available
knowledge of current and expected future events, actual results could be
different from those estimates.

Cash and Cash Equivalents Cash and cash equivalents includes all cash
balances and highly liquid investments with an original maturity of three
months or less.

Inventories Inventories consist primarily of natural gas and NGLs held
in storage for transmission and processing and sales commitments. Inventories
are recorded at the lower of cost or market value using the average cost method
(see Note 6). Prior to 2003, natural gas storage arbitrage volumes were marked
to market. However, effective January 1, 2003, with the Financial Accounting
Standard Boards (FASB) Emerging Issues Task Forces (EITF) rescission of
Issue No. 98-10 (EITF 98-10), Accounting for Contracts Involved in Energy
Trading and Risk Management Activities, all gas storage inventories are
recorded at the lower of cost or market, (see Cumulative Effect of Changes in
Accounting Principles and New Accounting Standards below).

Accounting for Hedges and Commodity Trading and Marketing Activities All
derivatives not qualifying for the normal purchases and sales exception under
Statement of Financial Accounting Standards (SFAS) No. 133 (SFAS 133),
Accounting for Derivative Instruments and Hedging Activities, as amended, are
recorded in the Consolidated Balance Sheets at their fair value as Unrealized
Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. Prior to
the implementation of EITF Issue No. 02-03 (EITF
02-03), Issues Involved in Accounting for Derivative Contracts Held for
Trading Purposes and for Contracts Involved in Energy Trading and Risk
Management Activities, on January 1, 2003, certain non-derivative energy
trading contracts were also recorded on the Consolidated Balance Sheets at
their fair value. See the Cumulative Effect of Changes in Accounting
Principles section below for further discussion of the implementation of the
provisions of EITF 02-03.

Effective January 1, 2003, in connection with the implementation of the
remaining provisions of EITF 02-03, the Company designates each energy
commodity derivative as either trading or non-trading. Certain non-trading
derivatives are further designated as either a hedge of a forecasted
transaction or future cash flow (cash flow hedge), a hedge of a recognized
asset, liability or firm commitment (fair value hedge), or a normal purchase or
sale contract, while certain non-trading derivatives, which are related to

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asset based activity, are non-trading mark-to-market derivatives. For
each of the Companys derivatives, the accounting method and presentation of
gains and losses or revenue and expense in the Consolidated Statements of
Income are as follows:

|                               |  |                   |  |                                                                                                   
|------------------------------ |  | ----------------- |  | --------------------------------------------------------------------------------------------------
|Classification of              |  |                   |  | Presentation of Gains & Losses or Revenue &                                                       
|Contract                       |  | Accounting Method |  | Expense                                                                                           
|                               |  |                   |  |                                                                                                   
|Trading Derivatives            |  | Mark-to-marketa   |  | Net basis in Trading and marketing net margin                                                     
|                              
|Non-Trading Derivatives:       |  |                   |  |                                                                                                   
|                              
|Cash Flow Hedge                |  | Hedge methodb     |  | Gross basis in the same income statement
category as the related hedged item                      
|                              
|Fair Value Hedge               |  | Hedge methodb     |  | Gross basis in the same income statement
category as the related hedged item                      
|                              
|Normal Purchase or
Normal Sale |  | Accrual methodc   |  | Gross basis upon settlement in the
corresponding income statement category
based on commodity type
|                              
|Non-Trading Mark-to-
Market    |  | Mark-to-marketa   |  | Net basis in Trading and marketing net margin                                                     

a Mark-to-market- An accounting method whereby the change in the fair value of
the asset or liability is recognized in the Consolidated Statements of Income
in Trading and marketing net margin during the current period.

b Hedge method- An accounting method whereby the effective portion of the
change in the fair value of the asset or liability is recorded in the
Consolidated Balance Sheets and there is no recognition in the Consolidated
Statements of Income for the effective portion until the service is provided or
the associated delivery period occurs.

c Accrual method- An accounting method whereby there is no recognition in the
Consolidated Statements of Income for normal purchases and sales derivatives
for changes in fair value of a contract until the service is provided or the
associated delivery period occurs.

For hedge contracts, the Company formally assesses, both at the hedge
contracts inception and on an ongoing basis, whether the hedge contract is
highly effective in offsetting changes in fair values or cash flows of hedged
items. The Company excludes the time value of options when assessing hedge
effectiveness.

When available, quoted market prices or prices obtained through external
sources are used to verify a contracts fair value. For contracts with a
delivery location or duration for which quoted market prices are not available,
fair value is determined based on pricing models developed primarily from
historical and expected correlations with quoted market prices.

Values are adjusted to reflect the credit risk inherent in the transaction
as well as the potential impact of liquidating open positions in an orderly
manner over a reasonable time period under current conditions. Changes in
market prices and management estimates directly affect the estimated fair value
of these contracts. Accordingly, it is reasonably possible that such estimates
may change in the near term.

Commodity Trading and Marketing  A favorable or unfavorable price
movement of any derivative contract held for trading and marketing purposes is
reported as Trading and Marketing Net Margin in the Consolidated Statements of
Operations. An offsetting amount is recorded in the Consolidated Balance Sheets
as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging
Transactions. When a contract is settled, the realized gain or loss is
reclassified to a receivable or payable account. Settlement has no revenue
presentation effect on the Consolidated Statements of Operations.

See the New Accounting Standards section below for a discussion of the
implications of EITF 02-03 on the accounting for trading activities subsequent
to October 25, 2002.

Commodity Cash Flow Hedges  The fair value of a derivative designated and
qualified as a cash flow hedge is recorded in the Consolidated Balance Sheets
as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging
Transactions. The effective portion of the change in fair value of a
derivative designated and qualified as a cash flow hedge is included in the
Consolidated Balance Sheets as Accumulated Other Comprehensive Income (Loss)
(AOCI) until earnings are affected by the hedged item. Settlement amounts of
cash flow hedges are removed from AOCI and recorded in the Consolidated
Statements of Operations in the same accounts as the item being hedged. The
Company discontinues hedge accounting prospectively when it is determined that
the derivative no longer qualifies as an effective hedge, or when it is no
longer probable that the hedged transaction will occur. When hedge accounting
is discontinued because the derivative no longer qualifies as an effective
hedge, the derivative continues to be carried on the Consolidated Balance
Sheets at its fair value; however, subsequent changes in its fair value are
recognized in current

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period earnings. Gains and losses related to discontinued hedges that were
previously accumulated in AOCI will remain in AOCI until earnings are affected
by the hedged item, unless it is no longer probable that the hedged transaction
will occur, in which case, the gains and losses that were in AOCI will be
immediately recognized in current period earnings. At December 31, 2003 and
2002, there were losses of $29 million and $58 million, respectively, in AOCI
related to cash flow hedges. At December 31, 2001, there was a gain of $55
million in AOCI related to cash flow hedges.

Commodity Fair Value Hedges  Changes in the fair value of a derivative
that is designated and qualifies as a fair value hedge are included in the
Consolidated Statements of Operations as Sales of Natural Gas and Petroleum
Products and Purchases of Natural Gas and Petroleum Products, as appropriate.
Changes in the fair value of the physical portion of a fair value hedge (i.e.,
the hedged item) are recorded in the Consolidated Statements of Operations in
the same accounts as the changes in the fair value of the derivative, with
offsetting amounts recorded in the Consolidated Balance Sheets as Other Current
Assets, Other Noncurrent Assets, Other Current Liabilities or Other Long Term
Liabilities, as appropriate.

Interest Rate Fair Value Hedges  The Company periodically enters into
interest rate swaps to convert a portion of its fixed-rate long term debt to
floating-rate long term debt. Hedged items in fair value hedges are
marked-to-market with the respective derivative instruments. Accordingly, the
Companys hedged fixed-rate debt is carried at fair value. The terms of the
outstanding swaps match those of the associated debt which permits the
assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life
of the swaps, no ineffectiveness will be recognized.

Intangible Assets Intangible assets consist of goodwill and NGLs sales
and purchases contracts. Goodwill is the cost of an acquisition less the fair
value of the net assets of the acquired business. Prior to January 1, 2002, the
Company amortized goodwill on a straight-line basis over the useful lives of
the acquired assets, ranging from 15 to 20 years. The Company implemented SFAS
No. 142 (SFAS 142), Goodwill and Other Intangible Assets as of January 1,
2002. For information on the impact of SFAS 142 on goodwill and goodwill
amortization see the New Accounting Standards section below. (See Notes 3 and
9 for information on significant goodwill additions.) Commodity sales and purchases
contracts are amortized on a straight-line basis over the term of the contract,
ranging from one to 15 years.

Property, Plant and Equipment Property, plant and equipment are recorded
at original cost. Depreciation is computed using the straight-line method over
the estimated useful lives of the individual assets (see Note 7). The costs of
maintenance and repairs, which are not significant improvements, are expensed
when incurred. Interest totaling $1 million for 2003, $5 million for 2002 and
$1 million for 2001 has been capitalized on construction projects.

Impairment
of Long-Lived Assets,
Assets Held for Sale and Discontinued
Operations The Company reviews the recoverability of long-lived assets and
intangible assets when circumstances indicate that the carrying amount of the
asset may not be recoverable. This evaluation is based on undiscounted cash
flow projections.

The Company primarily uses the criteria in SFAS No. 144 (SFAS 144),
Accounting for the Impairment or Disposal of Long-Lived Assets, to determine
when an asset is classified as held for sale. Upon classification as held for
sale, the long-lived asset is measured at the lower of its carrying amount or
fair value less cost to sell, depreciation is ceased and the asset is
separately presented on the Consolidated Balance Sheets.

If an asset held for sale or sold has clearly distinguishable operations
and cash flows, generally at the plant level, and the Company will not have significant continuing involvement
in the operations after the disposal, then the related results of operations
for the current and prior periods, including any related impairments, and gains
or losses on sales are reflected as Gain (loss) from discontinued operations in
the Consolidated Statements of Operations. If an asset held for sale does not
have clearly distinguishable operations and cash flows, impairments and gains
or losses on sales are recorded as Net loss (gain) on sale of assets in the
Consolidated Statements of Operations. Impairments for all other long-lived
assets, other than goodwill, are recorded as Asset impairments in the
Consolidated Statements of Operations.

Revenue Recognition The Company recognizes revenues on sales of natural
gas and petroleum products in the period of delivery and transportation
revenues in the period service are provided. For gathering services, the
Company receives fees from the producers to transport the natural gas from the
wellhead to the processing plant. For processing services, the Company either
receives fees or commodities as payment for these services, depending on the
type of contract. Under the percentage-of-proceeds contract type, the Company
is paid for its services by keeping a percentage of the NGLs produced and the
residue gas resulting from processing the natural gas. Under a keep-whole
contract, the Company keeps a portion of the NGLs produced, but returns the
equivalent energy

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content of the gas back to the producer. The Company also receives fees
for further fractionation of the NGLs produced, and for transportation and for
storage of NGLs and residue gas.

The Company recognizes revenue for its NGL and residue gas derivative
trading activities net in the Consolidated Statements of Operations as trading
and marketing net margin. These activities include mark-to-market gains and
losses on energy trading contracts and the financial or physical settlement of
energy trading contracts.

Revenue for goods and services provided but not invoiced is estimated each
month and recorded along with related purchases of goods and services used but
not invoiced. These estimates are generally based on estimated commodity
prices, preliminary throughput measurements and allocations and contract data.
Actual invoices for the current month are issued in the following month and
differences from estimated amounts are recorded. There are no material
differences from the actual amounts invoiced subsequent to year end relating to
estimated revenues and purchases recorded at December 31, 2003,
2002 and 2001.

Significant Customers Duke Energy, an affiliated company, was a
significant customer in each of the past three years. Sales to Duke Energy,
primarily residue gas, totaled approximately $799 million during 2003, $1,122
million during 2002 and $1,637 million during 2001. Effective February 28,
2003, the Companys Master Natural Gas Sales and Purchase Agreement with Duke
Energy Trading and Marketing, L.L.C. (DETM), a subsidiary of Duke Energy,
terminated. DETM provided a thirty-day notice of termination on January 30,
2003. The Company will continue to conduct business with DETM on a
transactional basis in the future at a reduced volume level.

ConocoPhillips, an affiliated company, was also a significant customer in
each of the past three years. Sales to ConocoPhillips, including its affiliate,
ChevronPhillips Chemical Company LLC (CP Chem.) totaled approximately $1,500
million during 2003, $934 million during 2002 and $1,188 million during 2001.

Unamortized Debt Premium, Discount and Expense Premiums, discounts and
expenses incurred with the issuance of long term debt are amortized over the
terms of the debt using the effective interest method.

Environmental Expenditures Environmental expenditures are expensed or
capitalized as appropriate, depending upon the future economic benefit.
Expenditures that relate to an existing condition caused by past operations,
and that do not generate current or future revenue, are expensed. Liabilities
for these expenditures are recorded on an undiscounted basis when environmental
assessments and/or clean-ups are probable and the costs can be reasonably
estimated. Recorded environmental liabilities were $21 million and $26 million
at December 31, 2003 and 2002, respectively.

Gas Imbalance Accounting Quantities of natural gas over-delivered or
under-delivered related to imbalance agreements with producers or pipelines are
recorded monthly as other receivables or other payables using then current
index prices or the weighted average prices of natural gas at the plant or
system. These balances are settled with cash or deliveries of natural gas.

Foreign Currency Translation The Company translates assets and
liabilities of its Canadian operations, where the Canadian dollar is the
functional currency, at the year-end exchange rates. Revenues and expenses are
translated using average monthly exchange rates during the year, which
approximates the exchange rates at the time of each transaction during the
year. Foreign currency translation adjustments are included in the
Consolidated Statements of Comprehensive Income (Loss). At December 31, 2003,
there was a translation gain of $53 million in AOCI. At December 31, 2002 and
2001, there were translation losses of $7 million in each period in AOCI.

Income TaxesThe Company is structured as a limited liability company
which is a pass-through entity for U.S. income tax purposes. The Company owns
corporations who file their own respective federal, foreign and state corporate
income tax returns. The income tax expense related to these corporations is
included in the income tax expense of the Company, along with other
miscellaneous state, local and franchise taxes of the limited liability company
and other subsidiaries. In addition, the Company has Canadian subsidiaries
which are subject to Canadian taxes.

The Company follows the asset and liability method of accounting for
income taxes. Under the asset and liability method, deferred income taxes are
recognized for the tax consequences of temporary differences between the
financial statement carrying amounts and the tax basis of the assets and
liabilities (see Note 11).

Under the terms of the LLC Agreement, the Company is required to make
quarterly distributions to Duke Energy and ConocoPhillips based on allocated
taxable income. The LLC Agreement, as amended, provides for taxable income to
be allocated in

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accordance with Internal Revenue Code Section 704(c). This Code Section
accounts for the variation between the adjusted tax basis and the fair market
value of assets contributed to the joint venture. The distribution is based on
the highest taxable income allocated to either member, with the other member
receiving a proportionate amount to maintain the ownership capital accounts at
69.7% for Duke Energy and 30.3% for ConocoPhillips. As of December 31, 2003 and
2002, no distributions were due the members.

Stock Based Compensation Under Duke Energys 1998 Long Term Incentive
Plan, stock options for Duke Energys common stock may be granted to the
Companys key employees. The Company accounts for stock based compensation
using the intrinsic value recognition and measurement principles of Accounting
Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to
Employees, and FASB Interpretation No. 44, Accounting for Certain
Transactions Involving Stock Compensation (an Interpretation of APB Opinion No.
25). Under this method, any compensation cost is measured as the quoted market
price of stock at the date of the grant less the amount an employee must pay to
acquire the stock. Since the exercise price for all options granted under the
plan was equal to the market value of the underlying common stock on the date
of grant, no compensation cost is recognized in the accompanying Consolidated
Statements of Operations. Restricted stock grants, phantom stock awards and
stock-based performance awards are recorded over the required vesting period as
compensation cost, based on the market value on the date of grant. All
outstanding common stock amounts and compensation awards have been adjusted to
reflect Duke Energys two-for-one common stock split effected January 26, 2001.
The following disclosures reflect the provisions of SFAS No. 148, Accounting
for Stock-Based Compensation  Transition and Disclosure  an amendment of FASB
Statement No. 123.

The following table shows what earnings available for members interest
would have been if the Company had applied the fair value recognition
provisions of SFAS No. 123, Accounting for Stock-Based Compensation, to all
stock-based compensation awards.

Pro Forma Stock-Based Compensation(millions)

|                                                                                                       |  |                                  |     |      |  |      |     |   |  |   |     |  
|------------------------------------------------------------------------------------------------------ |  | -------------------------------- | --- | ---- |  | ---- | --- | - |  | - | --- | -
|                                                                                                       |  | For the years ended December 31,
|                                                                                                       |  |                                 
|                                                                                                       |  | 2003                             |     | 2002 |  | 2001
|                                                                                                       |  |                                  |     |      |  |     
|Earnings (deficit) available for members interest,
as reported                                        |  | $                                | 205 |      |  | $    | (72 | ) |  | $ | 335 |  
|Add: stock-based compensation expense included in
reported net income (loss)                           |  |                                  | 1   |      |  |      | 1   |   |  |   | 1   |  
|Deduct: total stock-based compensation expense
determined under fair value based method
for all awards |  |                                  | (6  | )    |  |      | (4  | ) |  |   | (3  | )
|                                                                                                       |  |                                  |     |      |  |      |     |   |  |   |     |  
|Pro forma earnings (deficit) available for members
interest                                           |  | $                                | 200 |      |  | $    | (75 | ) |  | $ | 333 |  
|                                                                                                       |  |                                  |     |      |  |      |     |   |  |   |     |  

Cumulative Effect of Changes in Accounting Principles The Company
adopted the provisions of EITF 02-03 that required new non-derivative energy
trading contracts entered into after October 25, 2002 to be accounted for under
the accrual accounting basis. Non-derivative energy trading contracts recorded
in the Consolidated Balance Sheet as of January 1, 2003 that existed at October
25, 2002 and inventories that were recorded at fair values were adjusted to
historical cost via a cumulative effect adjustment of $5 million as a reduction
to 2003 earnings.

The Company adopted the provisions of SFAS No. 143 (SFAS 143),
Accounting for Asset Retirement Obligations, as of January 1, 2003 which
addresses financial accounting and reporting for obligations associated with
the retirement of tangible long-lived assets and the associated asset
retirement costs. In accordance with the transition provisions of SFAS 143, the
Company recorded a cumulative-effect adjustment of $18 million as a reduction
in 2003 earnings.

The Company adopted SFAS 133 on January 1, 2001. In accordance with the
transition provisions of SFAS 133, the Company recorded an immaterial
cumulative-effect adjustment as a reduction in 2001 earnings and a
cumulative-effect adjustment increasing OCI and members equity by $6 million.
For the years ended December 31, 2002 and 2001, the Company reclassified into
earnings $1 million and $12 million of losses, respectively, from OCI for
derivatives included in the transition adjustment related to hedge transactions
that settled. All hedge transactions in the transition adjustment had been
settled as of December 31, 2002. The amounts reclassified out of OCI were
different from the amounts included in the transition adjustment due to market
price changes since January 1, 2001.

New Accounting Standards In May 2003, the FASB issued SFAS No. 150
(SFAS 150), Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity. SFAS 150 requires that certain
financial instruments that could previously be accounted for as equity, be
classified as liabilities in the Consolidated Balance Sheets and initially
recorded at fair value.

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In addition to its requirements for the classification and measurement of
financial instruments in its scope, SFAS 150 also requires disclosures about
the nature and terms of the financial instruments and about alternative ways of
settling the instruments. The provisions of SFAS 150 are effective for all
financial instruments entered into or modified after May 31, 2003, and are
otherwise effective at the beginning of the first interim period beginning
after June 15, 2003. Upon adoption on July 1, 2003, the Company reclassified
its preferred members interest, which are mandatorily redeemable securities,
of $200 million from mezzanine equity to long term debt and prospectively
classified accrued or paid distributions on the preferred members interest,
which had previously been classified as dividends, as interest expense.
Interest expense recorded in 2003 on the preferred members interest was $6
million. During 2003, the Company redeemed the remaining $200 million of the
securities in cash.

In April 2003, the FASB issued SFAS No. 149 (SFAS 149), Amendment of
Statement 133 on Derivative Instruments and Hedging Activities, which amends
and clarifies accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS 133. SFAS 149 clarifies the discussion around initial net
investment, clarifies when a derivative contains a financing component, and
amends the definition of an underlying to conform to language used in FASB
Interpretation No. 45 (FIN 45), Guarantors Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others. In addition, SFAS 149 also incorporates certain of the Derivative
Implementation Group Implementation Issues. The provisions of SFAS 149 are
effective for contracts entered into or modified after June 30, 2003 and for
hedging relationships designated after June 30, 2003. The guidance is to be
applied to hedging relationships on a prospective basis. The adoption of the
new interpretation had no material effect on the Companys consolidated results
of operations, cash flows or financial position.

In January 2003, the FASB issued Interpretation No. 46 (FIN 46),
Consolidation of Variable Interest Entities which requires the primary
beneficiary of a variable interest entitys activities to consolidate the
variable interest entity. FIN 46 defines a variable interest entity as an
entity in which the equity investors do not have substantive voting rights and
there is not sufficient equity at risk for the entity to finance its activities
without additional subordinated financial support. The primary beneficiary is
the party that absorbs a majority of the expected losses and/or receives a
majority of the expected residual returns of the variable interest entitys
activities. In December 2003, the FASB issued FIN 46R, which supercedes and
amends certain provisions of FIN 46. While FIN 46R retains many of the concepts
and provisions of FIN 46, it also provides additional guidance related to the
application of FIN 46, provides for certain additional scope exceptions, and
incorporates several FASB Staff Positions issued related to the application of
FIN 46.

The provisions of FIN 46 are immediately applicable to variable interest
entities created, or interests in variable interest entities obtained, after
January 31, 2003 and the provisions of FIN 46R are required to be applied to
such entities by the end of the first reporting period ending after March 15,
2004 (March 31, 2004 for the Company). For variable interest entities created,
or interests in variable interest entities obtained, on or before January 31,
2003, FIN 46 or FIN 46R is required to be applied to special-purpose entities
by the end of the first reporting period ending after December 15, 2003
(December 31, 2003 for calendar-year entities) and is required to be applied to
all other non-special purpose entities by the end of the first reporting period
ending after March 15, 2004 (March 31, 2004 for calendar-year entities). FIN 46
and FIN 46R may be applied prospectively with a cumulative-effect adjustment as
of the date it is first applied, or by restating previously issued financial
statements with a cumulative-effect adjustment as of the beginning of the first
year restated. FIN 46 and FIN 46R also require certain disclosures of an
entitys relationship with variable interest entities.

The Company has not identified any material variable interest entities
created, or interests in variable entities obtained, after January 31, 2003
which require consolidation or disclosure under FIN 46 and continues to assess
the existence of any interests in variable interest entities created on or
prior to January 31, 2003. The Company currently anticipates one non-special
purpose entity, previously accounted for under the equity method of accounting,
will be consolidated by the Company in the first quarter of 2004 under the
provisions of FIN 46R. This entity, which is a substantive entity, has total
assets of approximately $92 million as of December 31, 2003 and total revenue
of approximately $43 million for the year ended December 31, 2003. The
Companys maximum exposure to loss as a result of its involvement with this
entity is approximately $82 million as of December 31, 2003. The Company continues to assess FIN 46R
but does not anticipate that it will have a material impact on the Companys
consolidated results of operations, cash flows or financial position.

In November 2002, the FASB issued FIN 45 which elaborates on the
disclosures to be made by a guarantor about its obligations under certain
guarantees issued. It also clarifies that a guarantor is required to recognize,
at the inception of a guarantee, a liability for the fair value of the
obligation undertaken in issuing the guarantee. The Company adopted the initial
recognition and measurement provisions of FIN 45 effective January 1, 2003. The
adoption of the new interpretation had no material effect on the Companys
consolidated results of operations, cash flows or financial position.

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In June 2002, the EITF reached a partial consensus on EITF 02-03, Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities. EITF
02-03 concluded that, effective for periods ending after July 15, 2002,
mark-to-market gains and losses on energy trading contracts (including those to
be physically settled) must be shown on a net basis in the Consolidated
Statements of Operations. The Company had previously chosen to report certain
energy trading contracts on a gross basis, as sales in operating revenues and
the associated costs recorded as purchases in costs and expenses, in accordance
with prevailing industry practice. The amounts for 2001 in the comparative
Consolidated Statements of Operations have been reclassified to conform to the
2003 and 2002 presentation of all amounts on a net basis. Revenues for 2001
were adjusted downward by $931 million from the previously reported amount,
with offsetting adjustments made to operating expenses resulting in no impact
on net income.

In October 2002, the EITF, as part of their further deliberations on EITF
02-03, rescinded the consensus reached in EITF 98-10. As a result, all energy
trading contracts that do not meet the definition of a derivative under SFAS
133, and trading inventories that previously had been recorded at fair values,
must now be recorded at the lower of cost or market and are reported on an
accrual basis resulting in the recognition of earnings or losses at the time of
contract settlement or termination. New non-derivative energy trading contracts
entered into after October 25, 2002 should be accounted for under the accrual
accounting basis. Non-derivative energy trading contracts on the Consolidated
Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and
inventories that were recorded at fair values have been adjusted to the lower
of historical cost or market resulting in a $5 million charge recorded in 2003
in Cumulative effect of accounting change in the Consolidated Statements of
Operations. In connection with the consensus reached on EITF 02-03, the FASB
staff observed that, effective July 1, 2002, an entity should not recognize
unrealized gains or losses at the inception of a derivative instrument unless
the fair value of that instrument is evidenced by quoted market prices or
current market transactions.

In October 2002, the EITF also reached a consensus on EITF 02-03 that,
effective for periods beginning after December 15, 2002, all gains and losses
on all derivative instruments held for trading purposes should be shown on a
net basis in the Consolidated Statements of Operations. Gains and losses on
non-derivative energy trading contracts should similarly be presented on a
gross or net basis in connection with the guidance in Issue No. 99-19 (EITF
99-19), Reporting Revenue Gross as a Principal versus Net as an Agent. Upon
application of this presentation, comparative financial statements for prior
periods are required to be reclassified to conform to the consensus other than
for energy trading contracts that were shown on a net basis under EITF 98-10.
Accordingly, for 2003, derivative instruments that are held for trading and
marketing purposes and are accounted for under mark-to-market accounting are
included in Trading and Marketing Net Margin in the Consolidated Statements of
Operations. As noted above, for 2002 and 2001, Trading and Marketing Net Margin
also includes the net margin on non-derivative energy trading contracts
(primarily gas storage inventories and the related physical purchases and
sales). The gross revenue presentation requirements had no impact on operating
income or net income.

In July 2003, the EITF reached consensus in EITF Issue No. 03-11 (EITF
03-11), Reporting Realized Gains and Losses on Derivative Instruments that
are Subject to FASB Statement No. 133, Accounting for Derivative Instruments
and Hedging Activities, and Not Held for Trading Purposes, that determining
whether realized gains and losses on derivative contracts not held for trading
purposes should be reported on a net or gross basis is a matter of judgment
that depends on the relevant facts and circumstances. In analyzing the facts
and circumstances, EITF 99-19 and Opinion No. 29, Accounting for Nonmonetary
Transactions, should be considered. EITF 03-11 is effective for transactions
or arrangements entered into after September 30, 2003. The adoption of EITF
03-11 had no material effect on the Companys consolidated results of
operations, cash flows or financial position, as the Company continues to net
non-trading mark-to-market activity.

On June 25, 2003, the FASB cleared the guidance contained in DIG Issue
C20, Scope Exceptions: Interpretation of the Meaning of Not Clearly and
Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment
Feature. DIG Issue C20, which applies only to the guidance in paragraph 10(b)
of FASB 133 and not in reference to embedded derivatives, describes three
circumstances in which the underlying in a price adjustment incorporated into a
contract that otherwise satisfies the requirements for the normal purchases and
normal sales exception would be considered to be not clearly and closely
related to the asset being sold or purchased. The guidance in DIG Issue C20
was effective for the Company on October 1, 2003. The adoption of this Issue
had no material impact on the Companys consolidated results of operations,
cash flows or financial position.

The Company adopted SFAS 142 which requires that goodwill no longer be
amortized over an estimated useful life, as previously required. Instead,
goodwill amounts are subject to a fair-value-based annual impairment
assessment. The Company did not recognize any impairments due to the
implementation of SFAS 142. The standard also requires certain identifiable
intangible assets to be recognized separately and amortized as appropriate. No
adjustments to intangibles were identified at transition.

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The following table shows what net income (loss) would have been if
amortization related to goodwill that is no longer being amortized had been
excluded from prior periods:

|                           |                            |   |                    |     |      |   |      |     |   |   |     |     | 
|-------------------------- | -------------------------- | - | ------------------ | --- | ---- | - | ---- | --- | - | - | --- | --- | 
|                           |                            |   | For the Year Ended
|                           |                            |   | December 31,      
|                           |                            |   |                   
|                           |                            |   | 2003               |     | 2002 |   | 2001
|                           |                            |   |                    |     |      |   |     
|                           |                            |   | (millions)        
|Reported net (loss) income |                            | $ | 214                |     |      | $ | (47  | )   |   | $ | 364 |    
|Add: Goodwill amortization |                            |   |                   |     |      |   |     |     |   |   | 22  |    
|                           |                            |   |                    |     |      |   |      |     |   |   |     |    
|                           | Adjusted net (loss) income |   | $                  | 214 |      |   | $    | (47 | ) |   | $   | 386 | 
|                           |                            |   |                    |     |      |   |      |     |   |   |     |    

The Company adopted SFAS 144 on January 1, 2002 which supersedes but
retains many of the fundamental recognition and measurement provisions of SFAS
No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of. The new rules significantly change the criteria for
classifying an asset as held-for-sale. Adoption of the new standard had no
material effect on the Companys consolidated results of operations or
financial position.

In June 2001, the FASB issued SFAS 143 which addresses financial
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. The
standard applies to legal obligations associated with the retirement of
long-lived assets that result from the acquisition, construction, development
and/or normal use of the asset. SFAS 143 requires that the fair value of a
liability for an asset retirement obligation be recognized in the period in
which it is incurred, if a reasonable estimate of fair value can be made. The
fair value of the liability is added to the carrying amount of the associated
asset. This additional carrying amount is then depreciated over the life of the
asset. The liability increases due to the passage of time based on the time
value of money until the obligation is settled. The Company adopted the
provisions of SFAS 143 as of January 1, 2003. In accordance with the transition
provisions of SFAS 143, the Company recorded an $18 million charge in 2003 in
Cumulative effect of accounting change in the Consolidated Statements of
Operations.

In May 2003, the EITF reached consensus in EITF Issue No. 01-08 (EITF
01-08), Determining Whether an Arrangement Contains a Lease, to clarify the
requirements of identifying whether an arrangement should be accounted for as a
lease at its inception. The guidance in the consensus is designed to mandate
reporting revenue as rental or leasing income that otherwise would be reported
as part of product sales or service revenue. EITF 01-08 requires both parties
to an arrangement to determine whether a service contract or similar
arrangement is or includes a lease within the scope of SFAS No. 13, Accounting
for Leases. The consensus is to be applied prospectively to arrangements
agreed to, modified, or acquired in business combinations in fiscal periods
beginning on July 1, 2003. The adoption of EITF 01-08 had no material effect on
the Companys consolidated results of operations, cash flows or financial
position.

Reclassifications Certain prior period amounts have been reclassified in
the Consolidated Financial Statements to conform to the current period
presentation. Included in the reclassified amounts are increases in both Sales
of natural gas and petroleum products and in Purchases of natural gas and
petroleum products in the amount of approximately $805 million and $639 million
for the years ended December 31, 2002 and 2001, respectively. This
reclassification resulted from intersegment trading activities being eliminated
twice from the Consolidated Statements of Operations in the years ended
December 31, 2002 and 2001. In addition, Accounts receivable  Customers, net
and Accounts payable  Trade were increased by $102 million at December 31,
2002 to properly present on a gross basis balances that were previously
presented net in the Consolidated Balance Sheet. Management has concluded that
these reclassifications are not material to the fair presentation of the
Companys financial statements.

3. Acquisitions and Dispositions

Disposition of Various Gathering, Transmission and Processing Assets On
June 30, 2003, the Company sold various gathering, transmission and processing
assets to two separate buyers for a combined sales price of approximately $90
million. These assets were included in the Companys Natural Gas Segment as
disclosed in Note 18. These assets comprised a component of the Company for
purposes of reporting discontinued operations. All prior period operations
have been revised to reflect these assets as discontinued operations.

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The following table sets forth selected financial information associated
with these assets accounted for as discontinued operations.

|                        |                                          |   |      |    |      |   |              |     |   |   |     |   | 
|----------------------- | ---------------------------------------- | - | ---- | -- | ---- | - | ------------ | --- | - | - | --- | - | 
|                        |                                          |   |      |    |      |   | Year Ended   |     |   |   |    
|                        |                                          |   |      |    |      |   | December 31, |     |   |   |    
|                        |                                          |   |     
|                        |                                          |   | 2003 |    | 2002 |   | 2001        
|                        |                                          |   |      |    |      |   |             
|                        |                                          |   |      |    |      |   | (millions)   |     |   |   |    
|Revenues                |                                          | $ | 160  |    |      | $ | 194          |     |   | $ | 240 |  
|Operating income (loss) |                                          | $ | 6    |    |      | $ | (33          | )   |   | $ |    |  
|Gain on sale            |                                          |   | 26   |    |      |   |             |     |   |   |    |  
|                        |                                          |   |      |    |      |   |              |     |   |   |     |  
|                        | Gain (loss) from discontinued operations |   | $    | 32 |      |   | $            | (33 | ) |   | $   |  | 
|                        |                                          |   |      |    |      |   |              |     |   |   |     |  

Included in the 2002 loss from discontinued operations of $33 million are
asset impairments of $32 million.

Disposition of Vehicles In July 2003, the Company entered into an
agreement to sell approximately 900 vehicles for approximately $14 million.
This is a sale-leaseback transaction whereby the Company sold the vehicles but
will lease them back over a one-year lease term. The lease expires in July
2004, with subsequent annual extensions exercisable at the Companys option.
The future minimum lease payments under the lease are approximately $3 million.
The Company does not have an option to purchase the leased vehicles at the end
of the minimum lease term. As the proceeds from the sale of the vehicles were
equal to the net book value of the vehicles, no gain or loss was recognized.

Acquisition of Discovery Producer Services On May 31, 2002, the Company
acquired 33.3% of the outstanding membership interests in Discovery Producer
Services, LLC (DPS). The base purchase price of $71 million was adjusted for
working capital and certain capital expenditures. This adjusted purchase price
was then reduced by approximately $85 million of DPS debt guaranteed by the
Company, resulting in the Company receiving cash of approximately $15 million
on the closing date of the transaction. This investment is accounted for under
the equity method of accounting. The pro forma impact of the acquisition on the
Companys results of operations was not material.

Acquisition of Additional Equity Interests On July 10, 2001, the Company
acquired additional interests in Mobile Bay Processing Partners, Gulf Coast NGL
Pipeline, L.L.C. and Dauphin Island Gathering Partners from MCNIC Energy
Enterprise Inc. (MCNIC) for approximately $66 million. This acquisition of
additional interests has been accounted for under the purchase method of
accounting. As a result, the Company has controlling interests in each of these
entities, and the assets and liabilities and results of operations of the three
affiliates have been consolidated in the Companys financial statements since
the date of the purchases with an offsetting amount recorded as minority
interest. The pro forma impact of the acquisition on the Companys results of
operations was not material.

Acquisition of Canadian Midstream Services, Ltd. On May 1, 2001, the
Company acquired the outstanding shares of Canadian Midstream Services, Ltd.
(CMSL) for a purchase price of approximately $162 million. The purchase price
included assumed debt of approximately $49 million. The acquisition was
accounted for under the purchase method of accounting, and the assets and
liabilities and results of operations of CMSL have been consolidated in the
Companys financial statements since the date of purchase. On an unaudited pro
forma basis, revenues and net income for the year ended December 31, 2001 would
have increased $8 million and $1 million, respectively, if the acquisition of
CMSL had occurred on January 1, 2001. The following is a summary of the
allocated purchase price (millions):

|                              |                      |   |     |     | 
|----------------------------- | -------------------- | - | --- | --- | 
|Property, plant and equipment |                      | $ | 139 |    
|Goodwill                      |                      |   | 54  |    
|Current assets                |                      |   | 14  |    
|Current liabilities           |                      |   | (57 | )  
|Other noncurrent liabilities  |                      |   | (36 | )  
|                              |                      |   |     |    
|                              | Total purchase price |   | $   | 114 | 
|                              |                      |   |     |    

Acquisition of Gas Supply Resources, Inc. On April 30, 2001, the Company
acquired in a purchase transaction, Gas Supply Resources, Inc. (GSRI), a
propane wholesaler located in the northeast, for approximately $45 million. The
pro forma impact of the acquisition on the Companys results of operations was
not material. Goodwill of $28 million has been recorded as a result of
allocating the purchase price to the individual assets and liabilities
acquired.

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4. Agreements and Transactions with Duke Energy Services Agreements with Duke Energy Under a services agreement dated
March 14, 2000, Duke Energy and certain of its subsidiaries provide the Company
with various staff and support services, including information technology
products and services, payroll, employee benefits, insurance, cash management,
treasury, media relations, printing, records management, legal functions and
investor services. These services are priced on the basis of a monthly charge.
Additionally, the Company may use other Duke Energy services subject to hourly
rates, including legal, insurance, internal audit, tax planning, human
resources and security departments. This agreement, as amended, expired on
December 31, 2003; however, the parties anticipate renewing the
agreement. Included in Other Current Assets at December 31, 2003 are prepaid
insurance premiums of $5 million and included in Other Current
Liabilities at December 31, 2002 are accrued insurance premiums of $2
million that were paid or payable to an insurance provider that is a
subsidiary of Duke Energy. Included in Accounts receivable  Affiliates are insurance recovery receivables of $4 million at
December 31, 2003 from an insurance provider that is a subsidiary of
Duke Energy. The Company also entered into an IT Consolidation and Operations Services
Agreement, dated July 30, 2003, with a subsidiary of Duke Energy. Under this
Agreement, Duke Energy agreed to assist the Company in transferring and
consolidating its information technology operations into Duke Energys
information technology operations and provide future ongoing information
technology services to the Company. These services are priced on the basis of a
monthly charge. This agreement expires on December 31, 2005, but automatically
renews each year thereafter unless terminated by either party as provided for
in the agreement. Total expenditures resulting from these agreements were $27 million, $16
million and $7 million in 2003, 2002 and 2001, respectively. The total
expenditures include expenditures for capital spending of $1 million and $2
million in 2003 and 2002, respectively. License Agreement Duke Energy has licensed to the Company a
non-exclusive right to use the phrase Duke Energy and its logo and certain
other trademarks in identifying the Companys businesses. This right may be
terminated by Duke Energy at its sole option any time after Duke Energys
direct or indirect ownership interest in the Company is less than or equal to
35%; or Duke Energy no longer controls, directly or indirectly, the management
and policies of the Company. Transactions between Duke Energy and the Company The Company sells a
portion of its residue gas and NGLs to, purchases raw natural gas and other
petroleum products from, and provides gathering and transportation services to
Duke Energy and its subsidiaries. The Company anticipates continuing to
purchase and sell these commodities and provide these services to Duke Energy
in the ordinary course of business (see Note 2, Significant Customers). The
Companys total revenues from these activities were approximately $799 million,
$1,122 million and $1,637 million for 2003, 2002 and 2001, respectively. The
Companys total purchases from these activities were approximately $137
million, $108 million and $262 million for 2003, 2002 and 2001, respectively. 5. Agreements and Transactions with ConocoPhillips Long Term NGLs Purchases Contract with ConocoPhillips Under the NGL
Output Purchase and Sale Agreement (the ConocoPhillips NGL Agreement) between
ConocoPhillips and the Company, a wholly-owned subsidiary of ConocoPhillips,
has the right to purchase at index-based prices substantially all NGLs produced
by various processing plants of the Company located in the Mid-Continent and
Permian Basin regions, and the Austin Chalk area which include approximately
40% of the Companys total NGLs production. The ConocoPhillips NGL Agreement
also grants ConocoPhillips, and subsequently CP Chem, the right to purchase at
index-based prices certain quantities of NGLs produced at processing plants
that are acquired and/or constructed by the Company in the future in various
counties in the Mid-Continent and Permian Basin regions, and the Austin Chalk
area. The primary term of the agreement is effective until January 1, 2015. Transactions with ConocoPhillips The Company sells a portion of its
residue gas and other by-products to ConocoPhillips and CP Chem. In addition,
the Company purchases raw natural gas from ConocoPhillips. The Companys total
revenues from these activities were approximately $1,500 million, $934 million
and $1,188 million for 2003, 2002 and 2001, respectively (see Note 2,
Significant Customers.) The Companys total purchases from these activities
were approximately $447 million, $280 million, and $327 million for 2003, 2002
and 2001, respectively. 56




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6. Inventories A summary of inventories by category follows: December 31,2003
    
    2002(millions)Gas held for resale
    
    $
    21
    
    
    $
    30NGLs
    
    
    24
    
    
    
    42Total inventories
    
    $
    45
    
    
    $
    72
 7. Property, Plant and Equipment A summary of property, plant and equipment by classification follows: December 31,DepreciationRates
    
    2003
    
    2002(millions)Gathering
    
    
    4% - 6
    %
    
    $
    2,468
    
    
    $
    2,437Processing
    
    
    4
    %
    
    
    2,087
    
    
    
    1,996Transmission
    
    
    4
    %
    
    
    1,223
    
    
    
    1,240Underground storage
    
    
    2% - 5
    %
    
    
    102
    
    
    
    93General plant
    
    
    20% - 33
    %
    
    
    133
    
    
    
    193Construction work in progress
    
    
    
    
    
    
    28
    
    
    
    616,041
    
    
    
    6,020Accumulated depreciation
    
    
    
    
    
    
    (1,579
    )
    
    
    (1,377
    )Property, plant and equipment, net
    
    
    
    
    
    $
    4,462
    
    
    $
    4,643
 Asset Impairments As part of the Companys periodic asset performance
evaluations, it was determined in December 2003 and 2002 that certain gas
plants and gathering systems have recently generated cash flow losses and are
expected to continue to generate minimal or negative cash flows in future
years. Accordingly, at December 31, 2003 and 2002, the Company performed tests
for recoverability on these assets in accordance with the requirements of SFAS
144 using probability weighted undiscounted future cash flow models. Based
upon the results of these analyses, the Company determined that the carrying
value of these assets was impaired and, accordingly, wrote them down to their
fair value. Fair value was determined based on managements best estimates of
sales value and/or discounted future cash flow models. The charge associated
with these impairments was $4 million and $8 million for 2003 and 2002,
respectively, relating to the natural gas gathering, processing,
transportation, marketing and storage segment. There were no asset impairments
recorded in 2001. The Companys revenues and expenses are significantly dependent on
commodity prices such as NGLs and natural gas. Past and current trends in the
price changes of these commodities may not be indicative of future trends. In
addition, revenues and expenses are impacted by throughput volumes. If negative
market conditions persist over time or throughput volumes decline, estimated
cash flows over the lives of assets may not exceed the carrying value of those
individual assets, and asset impairments may occur in the future under existing
accounting rules. Furthermore, a change in managements intent about the use of
individual assets (held for use vs. held for sale) could also impact an
impairment analysis. 8. Asset Retirement Obligations In June 2001, the FASB issued SFAS 143 which addresses financial
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs and
applies to legal obligations associated with the retirement of long-lived
assets that result from the acquisition, construction, development and/or
normal use of the asset. The Companys asset retirement obligations relate
primarily to the retirement of various gathering pipelines and processing
facilities, obligations related to right-of-way easement agreements and
contractual leases for land use. SFAS 143 requires that the fair value of a liability for an asset
retirement obligation be recognized in the period in which it is incurred, if a
reasonable estimate of fair value can be made. The fair value of the liability
is added to the carrying amount of the 57




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associated asset. This additional carrying amount is then depreciated over
the life of the asset. The liability increases due to the passage of time based
on the time value of money until the obligation is settled. The Company identified various assets as having an indeterminate life in
accordance with SFAS 143, which do not trigger a requirement to establish a
fair value for future retirement obligations associated with such assets. These
assets include certain pipelines, gathering systems and processing facilities.
These assets may have obligations associated with them, but a liability for
these asset retirement obligations will only be recorded if and when a future
retirement obligation with a determinable life is identified. SFAS 143 was effective for fiscal years beginning after June 15, 2002, and
was adopted by the Company on January 1, 2003. At January 1, 2003, the
implementation of SFAS 143 resulted in a net increase in total assets of $25
million, consisting of an increase in net property, plant and equipment. Long
term liabilities increased by $43 million, which represents the establishment
of an asset retirement obligation liability. A cumulative-effect of a change in
accounting principle adjustment of $18 million was recorded on January 1, 2003,
as a reduction in earnings. On an unaudited pro forma basis, net income (loss)
would not have been materially different if SFAS 143 had been applied during
each of the periods presented. The following table shows the asset retirement obligation liability as
though SFAS 143 had been in effect for the prior three years. Pro forma Asset Retirement Obligation (millions)January 1, 2000
    
    $
    13December 31, 2000
    
    
    32December 31, 2001
    
    
    39December 31, 2002
    
    
    43
 The asset retirement obligation is adjusted each quarter for any
liabilities incurred or settled during the period, accretion expense and any
revisions made to the estimated cash flows. The following table rolls forward
the asset retirement obligation from the balance at January 1, 2003 through
December 31, 2003. Reconciliation of Asset Retirement Obligation (millions)Balance as of January 1, 2003
    
    $
    43Accretion expense
    
    
    3Liabilities incurred
    
    
    1Liabilities settled
    
    
    (3
    )Other
    
    
    1Balance as of December 31, 2003
    
    $
    45
 9. Goodwill and Other Intangibles The changes in the carrying amount of goodwill for the years ended
December 31, 2003 and December 31, 2002 are as follows: ForeignPurchase
    
    CurrencyBalance
    
    Price
    
    Exchange
    
    BalanceDecember 31, 2002
    
    Adjustments
    
    Adjustments
    
    December 31, 2003(millions)Natural gas gathering, processing, transportation,
marketingand storage
    
    $
    395
    
    
    $
    
    
    
    $
    12
    
    
    $
    407NGL fractionation, transportation, marketing and trading
    
    
    40
    
    
    
    
    
    
    
    
    
    
    
    40Total consolidated
    
    $
    435
    
    
    $
    
    
    
    $
    12
    
    
    $
    447
 ForeignPurchase
    
    CurrencyBalance
    
    Price
    
    Exchange
    
    BalanceDecember 31, 2001
    
    Adjustments
    
    Adjustments
    
    December 31, 2002(millions)Natural gas gathering, processing, transportation, marketing
and storage
    
    $
    394
    
    
    $
    
    
    
    $
    1
    
    
    $
    395NGL fractionation, transportation, marketing and trading
    
    
    27
    
    
    
    13
    
    
    
    
    
    
    
    40Total consolidated
    
    $
    421
    
    
    $
    13
    
    
    $
    1
    
    
    $
    435
 58




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There were no impairments of goodwill for the years ended December 31,
2003, 2002 and 2001. The
gross carrying amount and accumulated amortization for commodity sales and
purchases contracts are as follows: For the Year EndedDecember 31,2003
    
    2002(millions)Commodity sales and purchases contracts
    
    $
    127
    
    
    $
    121Accumulated amortization
    
    
    (47
    )
    
    
    (37
    )Commodity sales and purchases contracts, net
    
    $
    80
    
    
    $
    84
 During the years ended December 31, 2003, 2002 and 2001, the Company
recorded amortization expense associated with commodity sales and purchases
contracts of $11 million, $10 million and $9 million, respectively. The average
remaining amortization period for these contracts is 4.5 years. Estimated
amortization for these contracts for the next five years is as follows: Estimated Amortization(millions)2004
    
    $
    92005
    
    
    82006
    
    
    82007
    
    
    82008
    
    
    8Thereafter
    
    
    39Total
    
    $
    80
 10. Investments in Affiliates The Company has investments in the following businesses (included in the
Natural Gas Segment) accounted for using the equity method: 2003
    
    December 31,Ownership
    
    2003
    
    2002(millions)Discovery Producer Services, LLC
    
    
    33.33
    %
    
    $
    78
    
    
    $
    Mont Belvieu I
    
    
    20.00
    %
    
    
    33
    
    
    
    35Sycamore Gas System General Partnership.
    
    
    48.45
    %
    
    
    16
    
    
    
    17Main Pass Oil Gathering
    
    
    33.33
    %
    
    
    14
    
    
    
    15Tri-States NGL Pipeline, LLC
    
    
    9.65
    %
    
    
    13
    
    
    
    14MidTexas Pipeline Company
    
    
    50.00
    %
    
    
    2
    
    
    
    3TEPPCO Partners, L.P
    
    
    2.00
    %
    
    
    
    
    
    
    12Black Lake Pipeline
    
    
    50.00
    %
    
    
    10
    
    
    
    10Fox Plant LLC
    
    
    50.00
    %
    
    
    9
    
    
    
    8Other affiliates
    
    Various
    
    
    15
    
    
    
    15Total investments in affiliates
    
    
    
    
    
    $
    190
    
    
    $
    129Discovery Producer Services, LLC
    
    
    33.33
    %
    
    $
    
    
    
    $
    (15
    )TEPPCO Partners, L.P
    
    
    2.00
    %
    
    
    (7
    )
    
    
    Total investments in affiliates
included in other long term
liabilities
    
    
    
    
    
    $
    (7
    )
    
    $
    (15
    )
 Discovery Producer Services, LLC  Discovery Producer Services, LLC
(Discovery) owns and operates a 600 MMcf/d interstate pipeline, a condensate
handling facility, a cryogenic gas processing plant, and other gathering assets
in deepwater offshore Louisiana. The Company received approximately $15 million
to purchase this interest in 2002. The negative purchase price was related to
the underlying debt of Discovery of $85 million which was repaid during 2003
through a capital contribution made by the 59




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members. The deficit between the carrying amount of the investment and the
underlying equity of Discovery of $48 million at December 31, 2003 is
associated with and is being depreciated over the life of the underlying
long-lived assets of Discovery. Mont Belvieu I Mont Belvieu I operates a 200 MBbl/d fractionation
facility in the Mont Belvieu, Texas Market Center. The excess of the carrying
amount of the investment over the underlying equity of Mont Belvieu I of $6
million at December 31, 2003 is associated with and is being depreciated over
the life of the underlying long-lived assets of Mont Belvieu I. Sycamore Gas System General Partnership Sycamore Gas System General
Partnership (Sycamore) is a partnership formed for the purpose of
constructing, owning and operating a gas gathering and compression system in
Carter County, Oklahoma. The excess of the carrying amount of the investment
over the underlying equity of Sycamore of $12 million at December 31, 2003 is
associated with and is being depreciated over the life of the underlying
long-lived assets of Sycamore. Main Pass Oil Gathering Main Pass Oil Gathering is a joint venture
whose primary operation is a crude oil gathering pipeline system of 81 miles in
the Main Pass East and Viosca Knoll Block areas in the Gulf of Mexico. Tri-States NGL Pipeline, LLC Tri-States NGL Pipeline, LLC owns 169
miles of NGL pipeline, extending from a point near Mobile Bay, Alabama to a
point near Kenner, Louisiana. Black Lake Pipeline Black Lake Pipeline (Black Lake) owns a 317 mile
long NGL pipeline, with a current capacity of approximately 40 MBbl/d. The
pipeline receives NGLs from a number of gas plants in Louisiana and Texas. The
NGLs are transported to Mont Belvieu fractionators. The deficit between the
carrying amount of the investment and the underlying equity of Black Lake of $4
million at December 31, 2003 is associated with and is being depreciated over
the life of the underlying long-lived assets of Black Lake. Fox Plant LLC Fox Plant LLC is a limited liability company formed for
the purpose of constructing, owning and operating a gathering facility and gas
processing plant in Carter County, Oklahoma. MidTexas Pipeline Company MidTexas Pipeline Company (MidTexas) is a
company formed for the purpose of constructing, owning and operating a gas
utility. The deficit between the carrying amount of the investment and the
underlying equity of MidTexas of $31 million at December 31, 2003 is associated
with and is being depreciated over the life of the underlying long-lived assets
of MidTexas. TEPPCO Partners, L.P. The Company owns a 2% general partner interest
in TEPPCO Partners, L.P. (TEPPCO), a publicly traded master limited
partnership. TEPPCO owns and operates assets for the transportation and storage
of refined products, liquefied petroleum gases and petrochemicals; the
gathering, transportation, marketing and storage of crude oil, and distribution
of lubrication oils and specialty chemicals; and the gathering of natural gas,
fractionation of NGLs and transportation of NGLs. The general partner of TEPPCO manages and directs TEPPCO under the TEPPCO
partnership agreement and the partnership agreements of its operating
partnerships. Under these partnership agreements, the general partner of TEPPCO
is reimbursed for all direct and indirect expenses it incurs and payments it
makes on behalf of TEPPCO. TEPPCO makes quarterly cash distributions of its
available cash, which consists generally of all cash receipts less
disbursements and cash reserves necessary for working capital, anticipated
capital expenditures and contingencies and debt payments, the amounts of which
are determined by the general partner of TEPPCO. The partnership agreements
provide for incentive distributions payable to the general partner of TEPPCO
out of TEPPCOs available cash in the event quarterly distributions to its
unitholders exceed certain specified targets. In general, subject to certain
limitations, if a quarterly distribution exceeds a target of $0.275 per limited
partner unit, the general partner of TEPPCO will receive incentive
distributions equal to: 
    
    15% of that portion of the distribution per limited partner unit
which exceeds the minimum quarterly distribution amount of $0.275 but is
not more than $0.325, plus
    
    25% of that portion of the quarterly distribution per limited partner
unit which exceeds $0.325 but is not more than $0.45, plus
    
    50% of that portion of the quarterly distribution per limited partner
unit which exceeds $0.45. 60




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At TEPPCOs 2003 per unit distribution level, the general partner received
approximately 27% of the cash distributed by TEPPCO to its partners, which
consisted of 25% from the incentive cash distribution and 2% from the general
partner interest. During 2003, total cash distributions to the general partner
of TEPPCO were $55 million. As of December 31, 2003, the Company has a negative investment balance of
$7 million in TEPPCO. This negative balance represents deferred income, but
does not represent any liability or commitment by the Company
to contribute cash to TEPPCO. The Companys investment in TEPPCO consists of
its capital contributions, increased by its cumulative share of net income and
decreased by cash distributions received from TEPPCO. Cash distributions that
TEPPCO pays during a period may exceed their net income for that same period.
Cumulative cash distributions in excess of net income allocations and capital
contributions resulted in a negative investment amount at December 31, 2003.
Future cash distributions which exceed net income will result in an increase in
the negative investment amount. According to the partnership agreement, in the
event of TEPPCOs dissolution, its assets and liabilities would be divided
among the limited partners and general partner in the same proportion as
available cash. After all allocations are made between the partners, if a
deficit balance still remains for the general partner, the general partner
would not be required to make whole any deficits in its equity account. Under the terms of the partnership agreement, the general partner is
required to maintain a 2% interest in the sum of the general partner and the
limited partners capital accounts. Compliance with the requirement is
calculated in accordance with the rules of Treasury Regulations Section
1.704-1(b), and the tax accounting definition of a capital account thereunder.
As of December 31, 2003, the general partners capital account balance was in
excess of this 2% minimum investment requirement, as calculated under the tax
accounting rules. Equity in earnings amounted to the following for the years ended December
31: 2003
    
    2002
    
    2001(millions)Discovery Producer Services, LLC
    
    $
    8
    
    
    $
    2
    
    
    $
    Mont Belvieu I
    
    
    (1
    )
    
    
    (1
    )
    
    
    (1
    )Sycamore Gas System General
Partnership
    
    
    (1
    )
    
    
    
    
    
    
    Main Pass Oil Gathering
    
    
    6
    
    
    
    5
    
    
    
    4Tri-States NGL Pipeline, LLC
    
    
    
    
    
    
    1
    
    
    
    1MidTexas Pipeline Company
    
    
    (1
    )
    
    
    
    
    
    
    TEPPCO Partners, L.P.
    
    
    36
    
    
    
    29
    
    
    
    25Black Lake Pipeline
    
    
    
    
    
    
    2
    
    
    
    1Fox Plant LLC
    
    
    
    
    
    
    
    
    
    
    Other affiliates
    
    
    2
    
    
    
    
    
    
    
    Total equity earnings
    
    $
    49
    
    
    $
    38
    
    
    $
    30
 Distributions in excess of earnings were $23 million, $16 million and $11
million in 2003, 2002 and 2001, respectively. The following summarizes combined financial information of unconsolidated
affiliates for the years ended December 31: 2003
    
    2002
    
    2001(millions)Income statement:Operating revenues
    
    $
    4,532
    
    
    $
    3,509
    
    
    $
    3,744Operating expenses
    
    $
    4,295
    
    
    $
    3,301
    
    
    $
    3,572Net income
    
    $
    159
    
    
    $
    144
    
    
    $
    127Balance sheet:Current assets
    
    $
    558
    
    
    $
    459Noncurrent assets
    
    
    3,293
    
    
    
    3,132Current liabilities
    
    
    513
    
    
    
    434Noncurrent liabilities
    
    
    1,431
    
    
    
    1,701Net assets
    
    $
    1,907
    
    
    $
    1,456
 61




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The Company sells a portion of its residue gas and NGLs to, purchases raw
natural gas and other petroleum products from, and provides gathering and
transportation services to unconsolidated affiliates (primarily TEPPCO). The
Company anticipates continuing to purchase and sell these commodities and
provide these services to unconsolidated affiliates in the ordinary course of
business. The Companys total revenues from these activities were approximately
$166 million, $138 million and $172 million for 2003, 2002 and 2001,
respectively. The Companys total purchases from these activities were
approximately $98 million, $82 million and $103 million for 2003, 2002 and
2001, respectively. 11. Income Taxes The Company is a limited liability company which is a pass-through entity
for U.S. income tax purposes. The Company owns corporations who file their own
respective federal and state corporate income tax returns. The income tax
expense related to these corporations is included in the income tax expense of
the Company, along with other miscellaneous state, local and franchise taxes of
the limited liability company and other subsidiaries. In addition, the Company
has Canadian subsidiaries that are levied certain foreign taxes. Income tax as presented in the Statements of Operations is summarized as
follows: Years Ended December 31,2003
    
    2002
    
    2001(millions)Current:Federal
    
    $
    4
    
    
    $
    6
    
    
    $
    State
    
    
    1
    
    
    
    1
    
    
    
    1Foreign
    
    
    1
    
    
    
    1
    
    
    
    1Total current
    
    
    6
    
    
    
    8
    
    
    
    2Deferred:Federal
    
    
    1
    
    
    
    1
    
    
    
    State
    
    
    
    
    
    
    1
    
    
    
    1Foreign
    
    
    1
    
    
    
    
    
    
    
    Total deferred
    
    
    2
    
    
    
    2
    
    
    
    1Total income tax
expense
    
    $
    8
    
    
    $
    10
    
    
    $
    3
 The Companys temporary differences primarily relate to depreciation on
property, plant and equipment. Cash paid for income taxes was not material for
the years ended December 31, 2003, 2002 and 2001. 12. Financing Credit Facility with Financial Institutions On March 28, 2003, the
Company entered into a credit facility (the Facility). The Facility replaces
a credit facility that matured on March 28, 2003. The Facility is used to
support the Companys commercial paper program and for working capital and
other general corporate purposes. The Facility matures on March 26, 2004;
however; any outstanding loans under the Facility at maturity may, at the
Companys option, be converted to a one-year term loan. The Facility is a $350
million revolving credit facility, of which $100 million can be used for
letters of credit. The Facility requires the Company to maintain at all times a
debt to total capitalization ratio of less than or equal to 53%; and maintain
at the end of each fiscal quarter an interest coverage ratio (defined to be the
ratio of adjusted EBITDA, as defined by the Facility, for the four most recent
quarters to interest expense for the same period) of at least 2.5 to 1
(adjusted EBITDA is defined by the Facility to be earnings before interest,
taxes and depreciation and amortization and other adjustments); and contains
various restrictions applicable to dividends and other payments to the
Companys members. The Facility bears interest at a rate equal to, at the
Companys option and based on our current debt rating, either (1) LIBOR plus
1.25% per year or (2) the higher of (a) the JP Morgan Chase Bank prime rate
plus 0.25% per year and (b) the Federal Funds rate plus 0.75% per year. At
December 31, 2003, there were no borrowings or letters of credit drawn against
the Facility and the Company had no outstanding commercial paper. At December
31, 2002, the Company had $215 million in outstanding commercial paper, with
maturities ranging from three to 30 days and annual interest rates ranging from
1.83% to 1.90%. The weighted average interest rate on the outstanding
commercial paper was 1.89% as of December 31, 2002. The amount of the Companys
outstanding commercial paper never exceeded the available amount under the
Facility. By March 26, 2004, the Company expects to refinance the Facility and
replace it with an up to $250 million credit facility which will mature on
March 25, 2005 and have similar terms as the Facility, with the exception that
there will no longer be a restriction applicable to dividends and other
payments to the Companys members and the Company will be able to request
letters of credit up to the full committed amount of the new credit facility. 62




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On March 28, 2003, the Company also entered into a $100 million funded
short-term loan with a bank (the Short-Term Loan). The Short-Term Loan was
used for working capital and other general corporate purposes. The Short-Term
Loan contained an original maturity of September 30, 2003, but was repaid by
August 2003 with funds generated from asset sales and operations. On November 3, 2003, the Company executed a $32 million irrevocable
standby letter of credit expiring on May 15, 2004 to be used to secure
transaction exposure with a counterparty. In April 2002, the Company filed a shelf registration statement increasing
its ability to issue securities to $500 million. The shelf registration
statement provides for the issuance of senior notes, subordinated notes and
trust preferred securities. Preferred Financing In August 2000, the Company issued $300 million of
preferred member interests to affiliates of Duke Energy and ConocoPhillips in
proportion to their ownership interests. The proceeds from this financing were
used to repay a portion of the Companys outstanding commercial paper. The
outstanding preferred member interests are entitled to cumulative preferential
distributions of 9.5% per annum payable, unless deferred, semiannually. For the
years ending December 31, 2003, 2002 and 2001, the Company paid preferential
distributions of $9 million (representing the first half of 2003), $25 million and $29 million, respectively. On
September 9, 2002, the Company redeemed $100 million, on September 19, 2003,
the Company redeemed $125 million, and on December 31, 2003, the Company
redeemed the remaining $75 million of its preferred members interest by paying
cash to each member (Duke Energy and ConocoPhillips) in proportion to their
ownership interests. Upon adoption of SFAS 150 on July 1, 2003, the Company reclassified its
preferred members interest, which are mandatorily redeemable securities, of
$200 million from mezzanine equity to long term debt. During 2003, subsequent
to the reclassification, the Company redeemed the remaining $200 million.
Beginning on July 1, 2003, accrued or paid distributions previously classified
as dividends on the preferred members interest are prospectively classified as
interest expense in the Consolidated Statements of Operations. Interest
expense for 2003 on the preferred members interest was
$6 million (representing the second half of 2003 preferential
distributions). Debt Securities Long term debt at December 31, 2003 and 2002 was as
follows (millions): Principal/Discount
    
    
    
    
    
    Interest2003
    
    2002
    
    Issue Date
    
    Rate
    
    Due DateDebt Securities
    
    $
    600
    
    
    $
    600
    
    
    August 16, 2000
    
    
    7 1/2
    %
    
    August 16, 2005800
    
    
    
    800
    
    
    August 16, 2000
    
    
    7 7/8
    %
    
    August 16, 2010300
    
    
    
    300
    
    
    August 16, 2000
    
    
    8 1/8
    %
    
    August 16, 2030250
    
    
    
    250
    
    
    February 2, 2001
    
    
    6 7/8
    %
    
    February 1, 2011300
    
    
    
    300
    
    
    November  9, 2001
    
    
    5 3/4
    %
    
    November 15, 2006Interest rate swap
    
    
    15
    
    
    
    14Note payable
    
    
    5
    
    
    
    Capitalized leases
    
    
    2
    
    
    
    2Unamortized discount
    
    
    (10
    )
    
    
    (11
    )Long term debt
    
    $
    2,262
    
    
    $
    2,255
 63




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##### Table of Contents



The debt securities mature and become payable on the respective due dates,
and are not subject to any sinking fund provisions. Interest is payable
semiannually. The debt securities are unsecured and are redeemable at the
option of the Company. Approximate future maturities of long term debt in the
year indicated are as follows at December 31, 2003: Debt Maturities(millions)2004
    
    $
    62005
    
    
    6172006
    
    
    3012007
    
    
    2008
    
    
    Thereafter
    
    
    1,3542,278Short term debt
    
    
    (6
    )2,272Unamortized discount
    
    
    (10
    )Long term debt
    
    $
    2,262
 In October 2001, the Company entered into an interest rate swap to convert
the fixed interest rate of $250 million of debt securities that were issued in
August 2000 to floating rate debt. The interest rate fair value hedge is at a
floating rate based on a six-month LIBOR, which is re-priced semiannually
through 2005. In August 2003, the Company entered into two additional interest
rate swaps to convert the fixed interest rate of $100 million of debt
securities issued on August 16, 2000 to floating rate debt. These interest
rate fair value hedges also bear a floating rate based on six-month LIBOR,
which is re-priced semiannually through 2030. 13. Derivative Instruments, Hedging Activities and Credit Risk Commodity price risk The Companys principal operations of gathering,
processing, transportation and storage of natural gas, and the accompanying
operations of fractionation, transportation, trading and marketing of NGLs
create commodity price risk exposure due to market fluctuations in commodity
prices, primarily with respect to the prices of NGLs, natural gas and crude
oil. As an owner and operator of natural gas processing and other midstream
assets, the Company has an inherent exposure to market variables and commodity
price risk. The amount and type of price risk is dependent on the underlying
natural gas contracts entered into to purchase and process raw natural gas.
Risk is also dependent on the types and mechanisms for sales of natural gas and
NGLs and related products produced, processed, transported or stored. Energy trading (market) risk Certain of the Companys subsidiaries are
engaged in the business of trading energy related products and services
including managing purchase and sales portfolios, storage contracts and
facilities, and transportation commitments for products. These energy trading
operations are exposed to market variables and commodity price risk with
respect to these products and services, and may enter into physical contracts
and financial instruments with the objective of realizing a positive margin
from the purchase and sale of commodity-based instruments. Corporate economic risks The Company enters into debt arrangements that
are exposed to market risks related to changes in interest rates. The Company
periodically uses interest rate lock agreements and interest rate swaps to hedge interest rate risk associated
with new debt issuances. The Companys primary goals include (1) maintaining an
appropriate ratio of fixed-rate debt to total debt for the Companys debt
rating; (2) reducing volatility of earnings resulting from interest rate
fluctuations; and (3) locking in attractive interest rates based on historical
rates. Counterparty risks The Company sells various commodities (i.e., natural
gas, NGLs and crude oil) to a variety of customers. The natural gas customers
include local utilities, industrial consumers, independent power producers and
merchant energy trading organizations. The NGLs customers range from large,
multi-national petrochemical and refining companies to small regional retail
propane distributors. Substantially all of the Companys NGLs sales are made at
market-based prices, including approximately 40% of NGLs production that is
committed to ConocoPhillips and CP Chem, under a contract with a primary term
that expires on January 1, 2015. This concentration of credit risk may affect
the Companys overall credit risk in that these customers may be similarly
affected by changes in economic, regulatory or other factors. On all
transactions where the Company is exposed to credit risk, the Company analyzes
the counterparties financial condition prior to entering into an agreement,
establishes credit limits and monitors the appropriateness of these limits on
an ongoing basis. The corporate credit policy prescribes the use of master
collateral agreements to mitigate credit exposure. The collateral agreements
provide for a counterparty to post cash or letters of credit for exposure in
excess of the established threshold. The threshold amount represents an open
credit limit, determined in accordance with the corporate credit 64




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policy. The collateral agreements also provide that the inability to post
collateral is sufficient cause to terminate a contract and liquidate all
positions. Physical forward contracts and financial derivatives are generally cash
settled at the expiration of the contract term. These transactions are
generally subject to specific credit provisions within the contracts that would
allow the seller, at its discretion, to suspend deliveries, cancel agreements
or continue deliveries to the buyer after the buyer provides security for
payment satisfactory to the seller. Commodity cash flow hedges The Company uses cash flow hedges, as
specifically defined by SFAS 133, to reduce the potential negative impact that
commodity price changes could have on the Companys earnings, and its ability
to adequately plan for cash needed for debt service, dividends, capital
expenditures and tax distributions. The Companys primary corporate hedging
goals include maintaining minimum cash flows to fund debt service, dividends,
production replacement, maintenance capital projects and tax distributions; and
retaining a high percentage of potential upside relating to price increases of
NGLs. The Company uses natural gas, crude oil and NGLs swaps and options to
hedge the impact of market fluctuations in the price of NGLs, natural gas and
other energy-related products. For the year ended December 31, 2003, the
Company recognized a net loss of $115 million, of which, a $6 million gain
represented the total ineffectiveness of all cash flow hedges and a $121
million loss represented the total derivative settlements. For the year ended
December 31, 2002, the Company recognized a net loss of $27 million, of which,
a $10 million loss represented the total ineffectiveness of all cash flow
hedges and a $16 million loss represented the total derivative settlements. The
time value of options was excluded in the assessment of hedge effectiveness and
totaled a $1 million loss in 2002 which is included in Sales of natural gas and
petroleum products in the Consolidated Statements of Operations. No derivative
gains or losses were reclassified from AOCI to current period earnings as a
result of the discontinuance of cash flow hedges related to certain forecasted
transactions that are not probable of occurring. Gains and losses on derivative contracts that are reclassified from AOCI
to current period earnings are included in the line item in which the hedged
item is recorded. As of December 31, 2003, the entire $29 million of deferred
net losses on derivative instruments in AOCI are expected to be reclassified
into earnings during the next 12 months as the hedge transactions occur;
however, due to the volatility of the commodities markets, the corresponding
value in AOCI is subject to change prior to its reclassification into earnings.
The maximum term over which the Company is hedging its exposure to the
variability of future cash flows is one year. Commodity fair value hedges The Company uses fair value hedges to hedge
exposure to changes in the fair value of an asset or a liability (or an
identified portion thereof) that is attributable to price risk. The Company may
hedge producer price locks (fixed price gas purchases) and market locks (fixed
price gas sales) to reduce the Companys exposure to fixed price risk via
swapping out the fixed price risk for a floating price position (New York
Mercantile Exchange or index based). For the years ended December 31, 2003, 2002 and 2001, the gains or losses
representing the ineffective portion of the Companys fair value hedges were
not material. All components of each derivatives gain or loss are included in
the assessment of hedge effectiveness, unless otherwise noted. The Company did
not have any firm commitments that no longer qualified as fair value hedge
items and therefore, did not recognize an associated gain or loss. Interest rate fair value hedges In October 2001, the Company entered
into an interest rate swap to convert the fixed interest rate of $250 million
of debt securities that were issued in August 2000 to floating rate debt. The
interest rate fair value hedge is at a floating rate based on a six-month
LIBOR, which is re-priced semiannually through 2005. In August 2003, the
Company entered into two additional interest rate swaps to convert the fixed
interest rate of $100 million of debt securities issued on August 16, 2000 to
floating rate debt. These interest rate fair value hedges are also at a
floating rate based on six-month LIBOR, which is re-priced semiannually through
2030. The swaps meet conditions which permit the assumption of no
ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps no
ineffectiveness will be recognized. As of December 31, 2003 and 2002, the fair
value of the interest rate swaps were a $15 million asset and a $14 million
asset, respectively. These amounts are included in the Consolidated Balance
Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions with
an offset to the underlying debt included in Long Term Debt. Commodity Derivatives  Mark-to-Market The trading and marketing of
energy related products and services exposes the Company to the fluctuations in
the market values of traded instruments. The Company manages its trading and
marketing portfolio with strict policies which limit exposure to market risk
and require daily reporting to management of potential financial exposure.
These policies include statistical risk tolerance limits using historical price
movements to calculate daily earnings at risk measurement. 65




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##### Table of Contents



14. Estimated Fair Value of Financial Instruments

The following fair value amounts have been determined by the Company using
available market information and appropriate valuation methodologies. However,
considerable judgment is required in interpreting market data to develop the
estimates of fair value. Accordingly, the estimates presented herein are not
necessarily indicative of the amounts that the Company could realize in a
current market exchange. The use of different market assumptions and/or
estimation methods may have a material effect on the estimated fair value
amounts.

|                                                           |  |                   |                |                   |                |   |        |   |  |        |  |       |  |   |        |   |  |   |        |  
|---------------------------------------------------------- |  | ----------------- | -------------- | ----------------- | -------------- | - | ------ | - |  | ------ |  | ----- |  | - | ------ | - |  | - | ------ | -
|                                                           |  | December 31, 2003 |                | December 31, 2002
|                                                           |  |                   |                |                  
|                                                           |  | Carrying          | Estimated Fair | Carrying          | Estimated Fair
|                                                           |  | Amount            |                | Value             |                |   |        |   |  | Amount |  | Value
|                                                           |  |                   |                |                   |                |   |        |   |  |        |  |      
|                                                           |  | (millions)       
|Accounts receivable                                        |  | $                 | 958            |                   |                | $ | 958    |   |  |        |  |       |  | $ | 909    |   |  | $ | 909    |  
|Accounts payable                                           |  |                   | (906           | )                 |                |   | (906   | ) |  |        |  |       |  |   | (863   | ) |  |   | (863   | )
|Unrealized gains (losses) on
trading and hedging
contracts |  |                   | (17            | )                 |                |   | (17    | ) |  |        |  |       |  |   | (80    | ) |  |   | (80    | )
|Short term debt                                            |  |                   | (6             | )                 |                |   | (6     | ) |  |        |  |       |  |   | (216   | ) |  |   | (216   | )
|Long term debt                                             |  |                   | (2,262         | )                 |                |   | (2,578 | ) |  |        |  |       |  |   | (2,255 | ) |  |   | (2,464 | )

The fair value of accounts receivable, accounts payable and short term
debt are not materially different from their carrying amounts because of the
short term nature of these instruments or the stated rates approximating market
rates.

The estimated fair value of the natural gas, NGLs and crude oil hedge
contracts is determined by multiplying the difference between the quoted
termination prices for natural gas, NGLs and crude oil and the hedge contract
prices by the quantities under contract. The estimated fair value of options is
determined by the Black-Scholes options valuation model.

The estimated fair value of long term debt is determined by prices
obtained from market quotes.

15. Commitments and Contingent Liabilities

Litigation The midstream industry has seen a number of class action
lawsuits involving royalty disputes, mismeasurement and mispayment allegations.
Although the industry has seen these types of cases before, they were typically
brought by a single plaintiff or small group of plaintiffs. A number of these
cases are now being brought as class actions. The Company and its subsidiaries
are currently named as defendants in some of these cases. Management believes
the Company and its subsidiaries have meritorious defenses to these cases, and
therefore will continue to defend them vigorously. However, these class actions
can be costly and time consuming to defend. Management believes that,
based on currently known information, these proceedings will not have a material adverse effect on the
consolidated results of operations or financial position of the Company.

General Insurance The Company carries insurance coverage that management
believes is consistent with companies engaged in similar commercial operations
with similar type properties. The Companys insurance coverage includes (1)
commercial general public liability insurance for liabilities arising to third
parties for bodily injury and property damage resulting from our operations;
(2) workers compensation liability coverage to required statutory limits; (3)
automobile liability insurance for all owned, non-owned and hired vehicles
covering liabilities to third parties for bodily injury and property damage,
and (4) property insurance covering the replacement value of all real and
personal property damage, excluding electric transmission and distribution
lines, including damages arising from boiler and machinery breakdowns,
earthquake, flood damage and business interruption/extra expense. All coverages
are subject to certain deductibles, terms and conditions common for companies
with similar types of operations.

The Company also maintains excess liability insurance coverage above the
established primary limits for commercial general liability and automobile
liability insurance. Limits, terms, conditions and deductibles are comparable
to those carried by other energy companies of similar size. The cost of the
Companys general insurance coverages continued to fluctuate over the past year
reflecting the changing conditions of the insurance markets.

Severance Program On October 30, 2003, the Company communicated a
company-wide voluntary and involuntary severance program to its employees to
reduce approximately 6% of the Companys workforce. The plan was completed on
December 8, 2003
and includes the reduction of 160 employees over the period of December
2003 to June 2004. The Company has expensed $6 million

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related to this
severance program in the fourth quarter of 2003 in the General and
administrative expense. An additional $1 million of expense will be recognized
in the first and second quarters of 2004, which is the remaining future service
period. The severance liability that was recorded in the fourth quarter of 2003
is $6 million at December 31, 2003, as the majority of the severance payouts
will occur in the first and second quarters of 2004. The severance liability is
recorded in Other current liabilities.

Other Commitments and Contingencies The Company utilizes assets under
operating leases in several areas of operation. Combined rental expense,
including leases with no continuing commitment, amounted to $20 million, $20
million and $24 million in 2003, 2002 and 2001, respectively. Rental expense
for leases with escalation clauses is recognized on a straight line basis over
the initial lease term. Minimum rental payments under the Companys various
operating leases in the year indicated are as follows at December 31, 2003:

|                        |  |   |    |  
|----------------------- |  | - | -- | -
|Minimum Rental Payments
|                       
|(millions)             
|2004                    |  | $ | 13 |  
|2005                    |  |   | 10 |  
|2006                    |  |   | 9  |  
|2007                    |  |   | 8  |  
|2008                    |  |   | 6  |  
|Thereafter              |  |   | 25 |  
|                        |  |   |    |  
|Total gross payments    |  |   | 71 |  
|Sublease receipts       |  |   | (5 | )
|                        |  |   |    |  
|Total net payments      |  | $ | 66 |  

16. Stock-Based Compensation

Under Duke Energys 1998 Long Term Incentive Plan, stock options for Duke
Energys common stock may be granted to the Companys key employees. Under the
plan, the exercise price of each option granted cannot be less than the market
price of Duke Energys common stock on the date of grant. Vesting periods range
from immediate to five years with a maximum option term of 10 years.

The following tables show information regarding options to purchase Duke
Energys common stock granted to employees of the Company.

Stock Option Activity

|                                 |  |           |       |             |                  |   |    |  |    | 
|-------------------------------- |  | --------- | ----- | ----------- | ---------------- | - | -- |  | -- | 
|                                 |  |           |       | Options     | Weighted-Average
|                                 |  |           |       | (thousands) | Exercise Price  
|                                 |  |           |       |             |                 
|Outstanding at December 31, 2000 |  |           | 2,568 |             |                  | $ | 31 | 
|                                 |  | Granted   |       |             | 815              |   |    |  | 38 | 
|                                 |  | Exercised |       |             | (251             | ) |    |  | 27 | 
|                                 |  | Forfeited |       |             | (144             | ) |    |  | 32 | 
|                                 |  |           |       |             |                  |   |    | 
|Outstanding at December 31, 2001 |  |           | 2,988 |             |                  |   | 33 | 
|                                 |  | Granted   |       |             | 68               |   |    |  | 37 | 
|                                 |  | Exercised |       |             | (79              | ) |    |  | 25 | 
|                                 |  | Forfeited |       |             | (108             | ) |    |  | 35 | 
|                                 |  |           |       |             |                  |   |    | 
|Outstanding at December 31, 2002 |  |           | 2,869 |             |                  |   | 33 | 
|                                 |  | Granted   |       |             | 985              |   |    |  | 14 | 
|                                 |  | Exercised |       |             | (6               | ) |    |  | 11 | 
|                                 |  | Forfeited |       |             | (683             | ) |    |  | 29 | 
|                                 |  |           |       |             |                  |   |    | 
|Outstanding at December 31, 2003 |  |           | 3,165 |             |                  |   | 28 | 
|                                 |  |           |       |             |                  |   |    | 

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Stock Options at December 31, 2003

|           |       |                |     |                |       |             |     |                |     |           |    |    |  |         |     |           |       |   |    |    |    | 
|---------- | ----- | -------------- | --- | -------------- | ----- | ----------- | --- | -------------- | --- | --------- | -- | -- |  | ------- | --- | --------- | ----- | - | -- | -- | -- | 
|           |       |                |     | Outstanding    |       | Exercisable
|           |       |                |     |                |       |            
|           |       |                |     |                |       |             |     | Weighted-      |     | Weighted- |    |    |  |         |     | Weighted-
|Range of   |       |                |     |                |       | Average     |     | Average        |     |           |    |    |  | Average
|Exercise   |       | Number         |     | Remaining Life |       | Exercise    |     | Number         |     | Exercise 
|Prices     |       | (in thousands) |     | (in years)     |       | Price       |     | (in thousands) |     | Price    
|           |       |                |     |                |       |             |     |                |     |          
|$8 to $10  |       |                | 8   |                |       |             | 1.1 |                |     | $         | 10 |    |  |         | 8   |           |       | $ | 10 |   
|$11 to $16 |       |                | 788 |                |       |             | 9.0 |                |     |           | 14 |    |  |         | 15  |           |       |   | 12 |   
|$17 to $22 |       |                | 55  |                |       |             | 8.6 |                |     |           | 18 |    |  |         | 55  |           |       |   | 18 |   
|$23 to $28 |       |                | 985 |                |       |             | 5.4 |                |     |           | 26 |    |  |         | 985 |           |       |   | 26 |   
|$29 to $34 |       |                | 90  |                |       |             | 5.7 |                |     |           | 30 |    |  |         | 86  |           |       |   | 30 |   
|$35 to $40 |       |                | 696 |                |       |             | 8.0 |                |     |           | 38 |    |  |         | 361 |           |       |   | 38 |   
|           | > $40 |                |     | 543            |       |             |     | 7.0            |     |           |    | 43 |  |         |     | 409       |       |   |    | 43 |   
|           |       | Total          |     |                | 3,165 |             |     |                | 7.2 |           |    |    |  |         |     |           | 1,919 |   |    |    | 32 | 
|           |       |                |     |                |       |             |     |                |     |           |    |    |  |         |     |           |       |   |    |   

On December 31, 2002, there were 1.6 million exercisable options with a
$31 weighted-average exercise price. On December 31, 2001, there were 0.8
million exercisable options with a $29 weighted-average exercise price.

The weighted-average fair value per option granted was $4 for 2003, $10
for 2002 and 2001. The fair value of each option grant was estimated on the
date of grant using the Black-Scholes option-pricing model.

Weighted-Average Assumptions for Option-Pricing

|                                |  |        |      |        |  |        |      |   |  |  |      |  
|------------------------------- |  | ------ | ---- | ------ |  | ------ | ---- | - |  |  | ---- | -
|                                |  | 2003   |      | 2002   |  | 2001  
|                                |  |        |      |        |  |       
|Stock dividend yield            |  |        | 3.4  | %      |  |        | 3.3  | % |  |  | 3.4  | %
|Expected stock price volatility |  |        | 37.5 | %      |  |        | 30.5 | % |  |  | 29.7 | %
|Risk-free interest rates        |  |        | 3.6  | %      |  |        | 5.1  | % |  |  | 5.0  | %
|Expected option lives           |  | 7years |      | 7years |  | 7years
|                                |  |        |      |        |  |        |      |   |  |  |      |  

Duke Energy granted stock-based performance awards of Duke Energy common
stock to key employees of the Company under the 1998 Long Term Incentive Plan.
Stock-based performance awards under the 1998 plan vest over periods ranging
from three to seven years. Vesting can occur in year three, at the earliest if
performance is met. Compensation expense for stock-based performance awards is
charged to the Companys earnings over the vesting period and amounted to less
than $1 million in 2003, 2002, and 2001.

Duke Energy granted phantom shares of Duke Energy common stock to
employees of the Company under the 1998 Plan. Phantom stock awards under the
1998 Plan vest over periods ranging from one to four years. Duke awarded 34,190
shares (fair value of approximately $1 million at grant dates) in 2001.
Compensation expense for phantom awards is charged to the Companys earnings
over the vesting period and amounted to less than $1 million in 2003,
approximately $1 million in 2002 and less than $1 million in 2001.

Duke Energy granted restricted shares of Duke Energy common stock to
employees of the Company under the 1998 Plan. Restricted stock awards under
the 1998 Plan vest over periods from one to five years. Duke Energy awarded
3,000 shares (fair value was not significant) in 2003. Duke Energy did not award any restricted awards in 2002 or 2001.
Compensation expense for restricted awards is charged to the Companys earnings
over the vesting period and amounted to less than $1 million in 2003.

In addition, Duke Energy granted restricted shares of Duke Energy common
stock to key employees of the Company under the 1996 Stock Incentive Plan.
Restricted stock grants under the 1996 plan vest over periods ranging from one
to five years. No restricted shares were awarded in 2003, 2002 or 2001.
Compensation expense for restricted awards is charged to the Companys earnings
over the vesting period, and amounted to less than $1 million in 2003, 2002,
and 2001.

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17. Pension and Other Benefits

All Company employees who are 18 years old and work at least 20 hours per
week are eligible for participation in the Companys 401(k) and retirement plan
in which the Company contributes 4% of each eligible employees qualified
earnings. Additionally, the Company matches employees contributions in the
plan up to 6% of qualified earnings. During 2003, 2002 and 2001, the Company
expensed plan contributions of $14 million each year.

The Company offers certain eligible executives the opportunity to
participate in the Duke Energy Field Services, LP Non-Qualified Executive
Deferred Compensation Plan. This plan allows participants to defer current
compensation on a pre-tax basis and to receive tax deferred earnings on such
contributions. The plan also has make-whole provisions for plan participants
who may otherwise be limited in the amount that the Company can contribute to
the 401(k) plan on the participants behalf. All amounts contributed to or
earned by the plans investments are held in a trust account for the benefit of
the participants. The trust and the liability to the participants are part of
the general assets and liabilities, respectively, of the Company. Additionally,
certain executives of the Company participate in restricted stock and other
compensatory plans. Total expense for the Company for all executive
compensatory plans was $1 million, $2 million and $2 million in 2003, 2002 and
2001, respectively.

18. Business Segments

The Company operates in two principal business segments:

(1)  natural gas gathering, processing, transportation and storage, from
which the Company generates revenues primarily by providing services such as
compression, gathering, treating, processing, transportation of residue gas,
storage and trading and marketing (the Natural Gas Segment), and

(2)  NGLs fractionation, transportation, marketing and trading, from which
the Company generates revenues from transportation fees, market center
fractionation and the marketing and trading of NGLs (the NGLs Segment).

Intersegment activity is primarily related to the sale of NGLs from the
Natural Gas Segment to the NGLs Segment at market based transfer prices.

These segments are monitored separately by management for performance
against its internal forecast and are consistent with the Companys internal
financial reporting. These segments have been identified based on the differing
products and services, regulatory environment and the expertise required for
these operations. Margin is a performance measure utilized by management to
monitor the business of each segment. The accounting policies for the segments
are the same as those described in Note 2. Foreign operations are not material
and are therefore not separately identified.

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The following table sets forth the Companys segment information.

|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |       | 
|------------------------------------------------------------- | ------------------------------------------------------- | ------------------------------------------------------------------ | - | ------------------------ | ----- | ---- | - | ----- | ----- | - | - | ------ | ----- | 
|                                                              |                                                         |                                                                    |   | Years Ended December 31,
|                                                              |                                                         |                                                                    |   |                         
|                                                              |                                                         |                                                                    |   | 2003                     |       | 2002 |   | 2001 
|                                                              |                                                         |                                                                    |   |                          |       |      |   |      
|                                                              |                                                         |                                                                    |   | (millions)              
|Operating revenues:                                           |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |       
|                                                              | Natural gas, including trading and marketing net margin |                                                                    | $ | 8,097                    |       |      | $ | 5,219 |       |   | $ | 7,404  |      
|                                                              | NGLs, including trading and marketing net margin        |                                                                    |   | 1,782                    |       |      |   | 1,288 |       |   |   | 2,536  |      
|                                                              | Intersegment (a)                                        |                                                                    |   | (1,060                   | )     |      |   | (528  | )     |   |   | (1,633 | )    
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|                                                              |                                                         | Total operating revenues                                           |   | $                        | 8,819 |      |   | $     | 5,979 |   |   | $      | 8,307 | 
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|Gross margin: (b)                                             |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |       
|                                                              | Natural gas, including trading and marketing net margin |                                                                    | $ | 1,221                    |       |      | $ | 972   |       |   | $ | 1,205  |      
|                                                              | NGLs, including trading and marketing net margin        |                                                                    |   | 54                       |       |      |   | 55    |       |   |   | 56     |      
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|                                                              |                                                         | Total
gross margin                                                 |   | $                        | 1,275 |      |   | $     | 1,027 |   |   | $      | 1,261 | 
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|Other operating and administrative costs:                     |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |       
|                                                              | Natural gas                                             |                                                                    | $ | 444                      |       |      | $ | 444   |       |   | $ | 352    |      
|                                                              | NGLs                                                    |                                                                    |   | 8                        |       |      |   | 9     |       |   |   | 7      |      
|                                                              | Corporate                                               |                                                                    |   | 187                      |       |      |   | 160   |       |   |   | 130    |      
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|                                                              |                                                         | Total other operating and administrative costs                     |   | $                        | 639   |      |   | $     | 613   |   |   | $      | 489   | 
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|Depreciation and amortization:                                |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |       
|                                                              | Natural gas                                             |                                                                    | $ | 267                      |       |      | $ | 275   |       |   | $ | 255    |      
|                                                              | NGLs                                                    |                                                                    |   | 13                       |       |      |   | 11    |       |   |   | 10     |      
|                                                              | Corporate                                               |                                                                    |   | 22                       |       |      |   | 4     |       |   |   | 4      |      
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|                                                              |                                                         | Total depreciation and amortization                                |   | $                        | 302   |      |   | $     | 290   |   |   | $      | 269   | 
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|Equity in earnings of unconsolidated affiliates:              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |       
|                                                              | Natural gas                                             |                                                                    | $ | 49                       |       |      | $ | 37    |       |   | $ | 29     |      
|                                                              | NGLs                                                    |                                                                    |   |                         |       |      |   | 1     |       |   |   | 1      |      
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|                                                              |                                                         | Total equity in earnings of unconsolidated affiliates              |   | $                        | 49    |      |   | $     | 38    |   |   | $      | 30    | 
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|                                                              |                                                         | Total corporate interest expense                                   |   | $                        | 170   |      |   | $     | 166   |   |   | $      | 166   | 
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|Income (loss) from continuing operations before income taxes: |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |       
|                                                              | Natural gas                                             |                                                                    | $ | 559                      |       |      | $ | 290   |       |   | $ | 627    |      
|                                                              | NGLs                                                    |                                                                    |   | 33                       |       |      |   | 36    |       |   |   | 40     |      
|                                                              | Corporate                                               |                                                                    |   | (379                     | )     |      |   | (330  | )     |   |   | (300   | )    
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|                                                              |                                                         | Total income (loss) from continuing operations
before income taxes |   | $                        | 213   |      |   | $     | (4    | ) |   | $      | 367   | 
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|Acquisition and Capital Expenditures:                         |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |       
|                                                              | Natural gas                                             |                                                                    | $ | 119                      |       |      | $ | 275   |       |   | $ | 566    |      
|                                                              | NGLs                                                    |                                                                    |   | 1                        |       |      |   | 9     |       |   |   | 11     |      
|                                                              | Corporate                                               |                                                                    |   | 9                        |       |      |   | 13    |       |   |   | 21     |      
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      
|                                                              |                                                         | Total Acquisition and Capital Expenditures                         |   | $                        | 129   |      |   | $     | 297   |   |   | $      | 598   | 
|                                                              |                                                         |                                                                    |   |                          |       |      |   |       |       |   |   |        |      

|              |               |              |   |                    |       |      |   |       |       | 
|------------- | ------------- | ------------ | - | ------------------ | ----- | ---- | - | ----- | ----- | 
|              |               |              |   | As of December 31,
|              |               |              |   |                   
|              |               |              |   | 2003               |       | 2002
|              |               |              |   |                    |       |     
|              |               |              |   | (millions)        
|Total assets: |               |              |   |                    |       |      |   |      
|              | Natural gas   |              | $ | 5,074              |       |      | $ | 5,139 |      
|              | NGLs          |              |   | 271                |       |      |   | 293   |      
|              | Corporate (c) |              |   | 1,169              |       |      |   | 1,167 |      
|              |               |              |   |                    |       |      |   |      
|              |               | Total assets |   | $                  | 6,514 |      |   | $     | 6,599 | 
|              |               |              |   |                    |       |      |   |      



---

|(a) |  | Intersegment sales represent sales of NGLs from the Natural Gas Segment to the NGLs Segment at either index prices or weighted average prices of NGLs. Both measures
of intersegment sales are effectively based on current economic market conditions.                                  
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | Gross margin consists of total operating revenues less purchases of natural gas and petroleum products. Gross margin is viewed as a non-Generally Accepted Accounting
Principles (GAAP) measure under the rules of the Securities and Exchange Commission (SEC), but is included as a

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|    |  | supplemental disclosure because it is a primary
performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross
margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be
comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(c) |  | Includes items such as unallocated working capital, intercompany accounts and intangible and other assets.                                                                                                                                                                                                                                                                                                                                                                                                                     

19. Guarantors Obligations Under Guarantees

At December 31, 2003, the Company was the guarantor of $3 million of debt
associated with unconsolidated subsidiaries. The guaranteed debt was repaid in
full in January of 2004. Assets of the unconsolidated subsidiaries were pledged
as collateral for the debt. At December 31, 2003, the Company had no liability
recorded for the guarantees of the debt associated with the unconsolidated
subsidiaries.

The Company periodically enters into agreements for the acquisition or
divestiture of assets. These agreements contain indemnification provisions that
may provide indemnity for environmental, tax, employment, outstanding
litigation, breaches of representations, warranties and covenants, or other
liabilities related to the assets being acquired or divested. Typically, claims
may be made by third parties under these indemnification agreements for various
periods of time depending on the nature of the claim. The effective periods on
these indemnification provisions generally have terms of one to five years,
although some are longer. The Companys maximum potential exposure under these
indemnification agreements can range depending on the nature of the claim and
the particular transaction. The Company is unable to estimate the total
maximum potential amount of future payments under indemnification agreements
due to several factors, including uncertainty as to whether claims will be made
under these indemnities. At December 31, 2003, the Company had a liability of
$1 million recorded for these outstanding indemnification provisions.

Management believes that it is not probable that the Company would be
required to perform or incur any significant losses associated with the
guarantees and indemnities discussed above and has, therefore, not recorded any
liabilities for contingent losses at December 31, 2003.

20. Accounting Adjustments

During 2003, the Company recorded an $11 million charge to properly
account for its vacation accrual in accordance with SFAS No. 43, Accounting
for Compensated Absences. The Company recorded this adjustment, which related
primarily to prior periods, entirely in 2003. Management has determined that
this charge, related to an error correction, is immaterial on both a
quantitative and qualitative basis to the trends in the financial statements
for the periods presented, the prior periods affected and to a fair
presentation of the Companys financial statements.

The Company completed a comprehensive account reconciliation project to
review and analyze its balance sheet accounts in 2002. This account
reconciliation project identified the following five categories where account
adjustments were necessary: operating expense accruals; gas inventory
adjustments; gas imbalances; joint venture and investment account
reconciliation; and other balance sheet accounts. As a result of this account
reconciliation project, the Company recorded numerous adjustments in 2002.
Adjustments totaling approximately $53 million may be related to corrections of
accounting errors in prior periods. However, management has determined that the
charges related to error corrections are immaterial both individually and in
the aggregate on both a quantitative and qualitative basis to the trends in the
financial statements for the periods presented, the prior periods affected and
to a fair presentation of the Companys financial statements. In addition,
numerous items identified in the account reconciliation project resulted from
system conversions and otherwise unsupportable balance sheet amounts. Due to
the nature of certain of these account reconciliation adjustments, it would be
impractical to determine what periods such adjustments relate to. Accordingly,
the corrections have been made for the year ended December 31, 2002.

21. Subsequent Events

In August 2003, the Company entered into a purchase and sale agreement to
sell gas gathering and processing plant assets in West Texas to a third
party purchaser for a sales price of approximately $62 million. The transaction
was to be closed on September 30, 2003; however, the purchaser was unable to
meet the conditions of closing. In October 2003, the Company entered into a
new purchase and sale agreement for the sale of these assets to a party related
to the original third party purchaser for a sales price of approximately $62
million. The transaction was to be closed in December 2003; however, the
purchaser was again unable to meet the conditions of closing. In February
2004, the Company entered into a new purchase and sale agreement for the sale
of these assets to a

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party related to the original third party purchaser for a sales price of
approximately $62 million. The transaction closed in the first quarter of 2004
with no significant book gain or loss.

On March 10, 2004, the Company entered into an agreement to acquire
gathering, processing and transmission assets in Southeast New Mexico from
ConocoPhillips for approximately $75 million. Pending approvals
from governmental authorities, the transaction is scheduled to
close in the second quarter of 2004.

22.     Quarterly Financial Data (Unaudited)

Certain quarterly amounts have been reclassified to conform to the current
presentation as disclosed in Note 2.

|     |                   |  |         |       |         |  |         |       |         |  |            |       |  |  |   |       |   |  |   |       |  
|---- | ----------------- |  | ------- | ----- | ------- |  | ------- | ----- | ------- |  | ---------- | ----- |  |  | - | ----- | - |  | - | ----- | -
|     |                   |  | First   |       | Second  |  | Third   |       | Fourth  |  |            |       | 
|     |                   |  | Quarter |       | Quarter |  | Quarter |       | Quarter |  | Total     
|     |                   |  |         |       |         |  |         |       |         |  |           
|     |                   |  |         |       |         |  |         |       |         |  | (millions) |       |  |  |   |       |   |  |  
|2003 |                   |  |         |       |         |  |         |       |         |  |            |       |  |  |   |       |   |  |   |      
|     | Operating revenue |  | $       | 2,612 |         |  | $       | 2,087 |         |  | $          | 2,117 |  |  | $ | 2,003 |   |  | $ | 8,819 |  
|     | Operating income  |  |         | 80    |         |  |         | 84    |         |  |            | 90    |  |  |   | 80    |   |  |   | 334   |  
|     | Net income        |  |         | 28    |         |  |         | 83    |         |  |            | 56    |  |  |   | 47    |   |  |   | 214   |  
|2002 |                   |  |         |       |         |  |         |       |         |  |            |       |  |  |   |       |   |  |   |      
|     | Operating revenue |  | $       | 1,216 |         |  | $       | 1,387 |         |  | $          | 1,231 |  |  | $ | 2,145 |   |  | $ | 5,979 |  
|     | Operating income  |  |         | 23    |         |  |         | 17    |         |  |            | 38    |  |  |   | 46    |   |  |   | 124   |  
|     | Net income (loss) |  |         | (17   | )       |  |         | (21   | )       |  |            | 12    |  |  |   | (21   | ) |  |   | (47   | )

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DUKE ENERGY FIELD SERVICES, LLC

Schedule II  Consolidated Valuation and Qualifying Accounts and Reserves (millions)

|                   |                                 |   |            |    |            |   |              |    |                   |   |                |     |            |   |     |     |   |   |    |    | 
|------------------ | ------------------------------- | - | ---------- | -- | ---------- | - | ------------ | -- | ----------------- | - | -------------- | --- | ---------- | - | --- | --- | - | - | -- | -- | 
|                   |                                 |   | Additions  |    |            |   |              |    |                   |   |               
|                   |                                 |   |            |    |            |   |              |    |                   |   |               
|                   |                                 |   | Balance at |    |            |   |              |    | Charged to        |   | Principal Cash |     | Balance at
|                   |                                 |   | Beginning  |    | Charged to |   | Other        |    | Payments and      |   | End of        
|                   |                                 |   | of
Period  |    | Expenses   |   | Accounts (b) |    | Reserve Reversals |   | Period        
|                   |                                 |   |            |    |            |   |              |    |                   |   |               
|December 31, 2003: |                                 |   |            |    |            |   |              |    |                   |   |                |     |            |   |     |     |   |   |    |   
|                   | Allowance for doubtful accounts |   | $          | 8  |            |   | $            | 1  |                   |   | $              | (2  | )          |   | $   |    |   |   | $  | 7  | 
|                   | Environmental                   |   |            | 26 |            |   |              | 7  |                   |   |                | 1   |            |   |     | (13 | ) |   |    | 21 | 
|                   | Asset retirement obligations    |   |            |   |            |   |              | 22 |                   |   |                | 26  |            |   |     | (3  | ) |   |    | 45 | 
|                   | Litigation                      |   |            | 4  |            |   |              | 4  |                   |   |                |    |            |   |     | (3  | ) |   |    | 5  | 
|                   | Other (a)                       |   |            | 10 |            |   |              | 9  |                   |   |                | 1   |            |   |     | (9  | ) |   |    | 11 | 
|                   |                                 |   |            |    |            |   |              |    |                   |   |                |     |            |   |     |     |   |   |    |   
|                   |                                 | $ | 48         |    |            | $ | 43           |    |                   | $ | 26             |     |            | $ | (28 | )   |   | $ | 89 |   
|December 31, 2002: |                                 |   |            |    |            |   |              |    |                   |   |                |     |            |   |     |     |   |   |    |   
|                   | Allowance for doubtful accounts |   | $          | 6  |            |   | $            |   |                   |   | $              | 2   |            |   | $   |    |   |   | $  | 8  | 
|                   | Environmental                   |   |            | 40 |            |   |              |   |                   |   |                | 1   |            |   |     | (15 | ) |   |    | 26 | 
|                   | Litigation                      |   |            | 8  |            |   |              | 1  |                   |   |                |    |            |   |     | (5  | ) |   |    | 4  | 
|                   | Other (a)                       |   |            | 12 |            |   |              | 31 |                   |   |                | (11 | )          |   |     | (22 | ) |   |    | 10 | 
|                   |                                 |   |            |    |            |   |              |    |                   |   |                |     |            |   |     |     |   |   |    |   
|                   |                                 | $ | 66         |    |            | $ | 32           |    |                   | $ | (8             | )   |            | $ | (42 | )   |   | $ | 48 |   
|December 31, 2001: |                                 |   |            |    |            |   |              |    |                   |   |                |     |            |   |     |     |   |   |    |   
|                   | Allowance for doubtful accounts |   | $          | 4  |            |   | $            | 3  |                   |   | $              |    |            |   | $   | (1  | ) |   | $  | 6  | 
|                   | Environmental                   |   |            | 39 |            |   |              |   |                   |   |                | 9   |            |   |     | (8  | ) |   |    | 40 | 
|                   | Litigation                      |   |            | 29 |            |   |              |   |                   |   |                | 1   |            |   |     | (22 | ) |   |    | 8  | 
|                   | Other (a)                       |   |            | 19 |            |   |              |   |                   |   |                | 16  |            |   |     | (23 | ) |   |    | 12 | 
|                   |                                 |   |            |    |            |   |              |    |                   |   |                |     |            |   |     |     |   |   |    |   
|                   |                                 | $ | 91         |    |            | $ | 3            |    |                   | $ | 26             |     |            | $ | (54 | )   |   | $ | 66 |   



---



|(a) |  | Principally consists of other contingency reserves which are included in Other Current Liabilities or Other Long Term Liabilities.                           
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | Principally consists of environmental, litigation and other contingency reserves reclassified to other non-reserves accounts or assumed in business acquisitions.

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INDEPENDENT AUDITORS REPORT

To the Board of Directors and Members of
Duke Energy Field Services, LLC

We have audited the accompanying consolidated balance sheets of Duke
Energy Field Services, LLC and subsidiaries as of December 31, 2003 and 2002,
and the related consolidated statements of operations, comprehensive income
(loss), members equity, and cash flows for each of the three years in the
period ended December 31, 2003. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial
statements and financial statement schedule are the responsibility of the
Companys management. Our responsibility is to express an
opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Duke Energy Field Services,
LLC and subsidiaries at December 31, 2003 and 2002, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2003 in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such consolidated
financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.

As
discussed in Note 2 to the Consolidated Financial Statements, in 2003,
the Company changed its method of accounting for asset retirement
obligations to conform to Statement of Financial Accounting Standards
(SFAS) No. 143, Accounting for Asset Retirement Obligations
and changed its method of accounting for energy trading contracts
that do not meet the definition of a derivative under SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities,
and trading inventories that previously had been recorded at fair
value to conform to Emerging Issues Task Force Issue 02-03, Issues
Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities. In 2002, the Company changed it method of accounting
for goodwill to conform to SFAS No. 142, Goodwill and Other
Intangible Assets. In 2001, the Company changed its method of
accounting for derivative instruments and hedging activities to
conform to SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities.

DELOITTE & TOUCHE LLP

Denver, Colorado
March 15, 2004

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ITEM 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.




None.

ITEM 9A.Controls and Procedures




Our
management, with the participation of our Chief Executive Officer and Chief Financial
Officer, has evaluated the effectiveness of our disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))
(Disclosure Controls Evaluation) and concluded that, as of the end of the
period covered by this report, the disclosure controls and procedures are
effective in ensuring that all material information required to be filed in
this annual report has been made known to them in a timely fashion.
Our disclosure controls and procedures are designed to provide
reasonable assurance that the
required information was effectively recorded, processed, summarized and
reported within the time period necessary to prepare this annual report. Our
disclosure controls and procedures include, without limitation,
controls and procedures designed to ensure that all information
required to be disclosed in our reports under the Exchange Act are accumulated
and communicated to management, including the Chief Executive Officer and the
Chief Financial Officer, as appropriate to allow timely decisions regarding
required disclosure.

In performing its audit of our Consolidated Financial Statements for the
year ended December 31, 2003, our independent auditors, Deloitte & Touche LLP
("Deloitte"), noted certain matters involving our internal controls that it
considered to be a reportable condition under the standards established by the
American Institute of Certified Public Accountants. A reportable condition
involves matters relating to significant deficiencies in the design or
operation of internal controls that, in Deloittes judgment, could adversely
affect our ability to record, process, summarize and report financial data
consistent with the assertions of management on the financial statements. The
reportable condition noted by Deloitte related to the elimination of
intercompany transactions in our consolidation process and the
resulting effect on the Consolidated Financial Statements. The reportable condition was not
considered by Deloitte to be a material weakness under the applicable auditing
standards and had no material effect on our financial statements. Management
has discussed the reportable condition with our Audit Committee and is
implementing additional internal procedures and controls to address the identified deficiency and
enhance the reliability of our internal control procedures.

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PART III.




ITEM 10.Directors and Executive Officers of the Registrant.




Audit Committee of the Board of Directors

The
Company is a majority-owned subsidiary of Duke Energy and we have no
equity securities listed on a national securities exchange. Therefore, we
are not required to have an Audit Committee. However, we voluntarily
established an Audit Committee which is made up of one Director from each of
the Companys members. Both members of the audit committee, Richard J. Osborne
and John E. Lowe, qualify as financial experts as defined in Item 401(h) of
Regulation S-K. The Audit Committee provides independent oversight with
respect to our financial reporting practices, internal controls, internal audit
function, accounting policies and the independent auditors.

Code of Business Ethics

We have adopted a Code of Business Ethics which is applicable to all the
employees of the Company including both the principal executive officer and
principal financial officer. A copy of the Code of Business Ethics is
available on our web site at www.defs.com under the "About DEFS" link.

Directors and Executive Officers

The following table provides information regarding our directors and executive officers:

|                       |  |     |    |          |  |                                                              
|---------------------- |  | --- | -- | -------- |  | -------------------------------------------------------------
|Name                   |  | Age |    | Position
|                       |  |     |    |         
|W. H. Easter III       |  |     | 54 |          |  | Director and Chairman of the Board, President and Chief      
|                       |  |     |    |          |  | Executive Officer                                            
|Mark A. Borer          |  |     | 49 |          |  | Executive Vice President, Marketing and Corporate Development
|Michael J. Bradley     |  |     | 49 |          |  | Executive Vice President, Gathering and Processing           
|Robert F. Martinovich  |  |     | 46 |          |  | Senior Vice President, Northern Division                     
|Rose M. Robeson        |  |     | 43 |          |  | Vice President and Chief Financial Officer                   
|Brent L. Backes        |  |     | 44 |          |  | Vice President, General Counsel and Secretary                
|Philip L. Frederickson |  |     | 47 |          |  | Director                                                     
|Fred J. Fowler         |  |     | 58 |          |  | Director                                                     
|John E. Lowe           |  |     | 45 |          |  | Director                                                     
|Richard J. Osborne     |  |     | 53 |          |  | Director                                                     

W. H. Easter IIIis Chairman of the Board, President and Chief Executive
Officer of our company. Prior to joining our company on January 5, 2004, Mr.
Easter served as Vice President of State Government Affairs for ConocoPhillips
from 2002 through 2003. From 1998 to 2002, Mr. Easter served as General
Manager of Gulf Coast businesses unit for Conoco Inc. and from 1992 to 1998 he
served as Managing Director and CEO of Conoco Jet Nordic in Stockholm, Sweden.
Mr. Easter has been in the energy industry since 1971.

Fred J. Fowler, a Director of our company, is President and Chief
Operating Officer of Duke Energy and has held that position since November
2002. Mr. Fowler previously served as Group President  Energy Transmission of
Duke Energy from 1997 to 2002. From 1996 to 1997, Mr. Fowler served as Group
Vice President of Pan Energy. From 1994 until 1996, Mr. Fowler served as
President of Texas Eastern Transmission Corporation. Mr. Fowler has been in the
energy industry since 1968.

Richard J. Osborne,a Director of our company, is the Group Vice
President, Public and Regulatory Policy of Duke Energy. Mr. Osborne served as
the Executive Vice President and Chief Risk Officer of Duke Energy from 2000 to
2003. From 1997 to 2000, Mr. Osborne served as Executive Vice President and
Chief Financial Officer of Duke Energy. From 1994 to 1997, Mr. Osborne served
as Senior Vice President and Chief Financial Officer of Duke Power. Mr. Osborne
is a member of our Audit Committee. Mr. Osborne has been in the energy industry
since 1975.

Philip L. Frederickson,a Director of our company, is the Executive Vice
President, Commercial for ConocoPhillips. Mr. Frederickson previously served
as Senior Vice President of Corporate Strategy and Business Development of
Conoco Inc. from 2001 to 2002. From 1998 to 2001, Mr. Frederickson served as
Vice President, Business Development of Conoco Inc. From 1997 to 1998, he
served as General Manager, Strategy and Portfolio Management, Upstream of
Conoco Inc.

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John E. Lowe,a Director of our company, is the Executive Vice President,
Planning, Strategy and Corporate Affairs for ConocoPhillips. Mr. Lowe
previously served as the Senior Vice President of Corporate Strategy and
Development of Phillips Petroleum Company from 2001 to 2002 and as Senior Vice
President of Planning and Strategic Transactions of Phillips Petroleum Company
from 2000 to 2001. From 1999 to 2000, Mr. Lowe served as Vice President of
Planning and Strategic Transactions of Phillips Petroleum Company. During 1999
before being appointed Vice President, Planning & Strategic Transactions, Mr.
Lowe served as Manager, Strategic Growth Projects. From 1997 to 1999, Mr. Lowe
served as Supply Chain Manager for Refining, Marketing and Transportation of
Phillips Petroleum Company. From 1993 to 1997 he served as either Director or
Manager of Finance for Phillips Petroleum Company. Mr. Lowe is a member of our
Audit Committee. Mr. Lowe has been in the energy industry since 1981.

Rose M. Robesonwas named Vice President and Chief Financial Officer of
our company in January 2002. Ms. Robeson joined the Company in May 2000 as Vice
President and Treasurer. She was previously Vice President and Treasurer of
Kinder Morgan, Inc. (formerly KN Energy, Inc.) from April 1998 to April 2000
and Assistant Treasurer of Kinder Morgan, Inc. from August 1996 to April 1998.
Ms. Robeson has been in the energy industry since 1987.

Robert F. Martinovichwas named Senior Vice President, Northern Division
of our Company in July 2002. Mr. Martinovich joined the Company in April 2000
as Senior Vice President, Western Division. He was Senior Vice President of GPM
Gas Corporation, a subsidiary of Phillips Petroleum Company, from 1999 until
the Combination. From 1996 until 1999, Mr. Martinovich was Vice President,
Oklahoma Region for GPM Gas Corporation, and from 1994 until 1996, he was
Business Development Manager for GPM Gas Corporation. Mr. Martinovich has been
in the energy industry since 1980.

Michael J. Bradleywas named Executive Vice President, Gathering and
Processing of our company in April 2002. He was previously Senior Vice
President, Northern Division since 1999. Mr. Bradley is also a director of the
general partner of TEPPCO. Mr. Bradley has been in the energy industry since
1979.

Mark A. Borerwas named Executive Vice President, Marketing and Corporate
Development of our company in April 2002. Mr. Borer joined the Predecessor
Company in April 1999 as Senior Vice President, Southern Division. From 1992
until 1999, Mr. Borer served as Vice President of Natural Gas Marketing for
Union Pacific Fuels, Inc. Mr. Borer is also a director of the general partner
of TEPPCO. Mr. Borer has been in the energy industry since 1978.

Brent L. Backeswas named Vice President, General Counsel and Secretary of
our company in January 2002. Mr. Backes joined the Predecessor Company in April
1998 as Senior Attorney. He was previously an attorney at LeBoeuf, Lamb, Greene
& MacRae, LLP with a focus on mergers and acquisitions. Mr. Backes has been in
the energy industry since 1998 and prior to that represented energy companies
in various capacities while in private practice.

Pursuant to our limited liability company agreement, we have five
directors, two of which are appointed by ConocoPhillips and three of which are
appointed by Duke Energy.

There are no family relationships between any of the executive officers
nor any arrangement or understanding between any executive officer and any
other person pursuant to which the officer was selected.

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ITEM 11.Executive Compensation. The following table sets forth compensation information for the years
ended December 31, 2001, December 31, 2002 and December 31, 2003 for the Chief
Executive Officer and each of our next four most highly compensated executive
officers of our company. These five individuals are referred to as the Named
Executive Officers. Long Term CompensationAnnual Compensation
    
    Restricted
    
    SecuritiesUnderlyingOther Annual
    
    Stock
    
    Stock
    
    LTIP
    
    All OtherSalary
    
    Bonus
    
    Compensation
    
    Awards
    
    Options
    
    Payouts
    
    CompensationName and Principal Position
    
    Year
    
    ($)
    
    ($)
    
    ($)(4)
    
    ($)(5)(6)
    
    (#)(7)
    
    ($)
    
    ($)(8)Jim W. Mogg (1)
    
    
    2003
    
    
    
    450,000
    
    
    
    365,985
    
    
    
    
    
    
    
    393,134
    
    
    
    93,000
    
    
    
    
    
    
    
    49,018Chairman of the Board,
    
    
    2002
    
    
    
    450,000
    
    
    
    40,072
    
    
    
    
    
    
    
    
    
    
    
    7,500
    
    
    
    319,560
    
    
    
    93,225President and Chief
    
    
    2001
    
    
    
    419,231
    
    
    
    201,482
    
    
    
    
    
    
    
    337,990
    
    
    
    74,800
    
    
    
    
    
    
    
    91,825Executive OfficerMark A. Borer
    
    
    2003
    
    
    
    280,000
    
    
    
    197,848
    
    
    
    
    
    
    
    151,745
    
    
    
    34,700
    
    
    
    
    
    
    
    31,741Executive Vice President,
    
    
    2002
    
    
    
    269,615
    
    
    
    59,531
    
    
    
    
    
    
    
    
    
    
    
    6,100
    
    
    
    
    
    
    
    41,057Marketing and Corporate
    
    
    2001
    
    
    
    219,230
    
    
    
    65,500
    
    
    
    
    
    
    
    116,431
    
    
    
    25,800
    
    
    
    
    
    
    
    39,457DevelopmentMichael J. Bradley
    
    
    2003
    
    
    
    280,000
    
    
    
    198,800
    
    
    
    
    
    
    
    151,745
    
    
    
    34,700
    
    
    
    
    
    
    
    33,410Executive Vice President,
    
    
    2002
    
    
    
    269,615
    
    
    
    59,501
    
    
    
    
    
    
    
    
    
    
    
    2,300
    
    
    
    
    
    
    
    41,367Gathering and
    
    
    2001
    
    
    
    219,230
    
    
    
    61,800
    
    
    
    
    
    
    
    116,431
    
    
    
    25,800
    
    
    
    
    
    
    
    27,587ProcessingRobert F. Martinovich
    
    
    2003
    
    
    
    250,000
    
    
    
    178,975
    
    
    
    
    
    
    
    135,497
    
    
    
    31,000
    
    
    
    
    
    
    
    32,030Senior Vice President,
    
    
    2002
    
    
    
    250,000
    
    
    
    54,687
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    87,246Northern Division
    
    
    2001
    
    
    
    219,230
    
    
    
    55,800
    
    
    
    
    
    
    
    116,431
    
    
    
    25,800
    
    
    
    
    
    
    
    38,632William W. Slaughter (2)
    
    
    2003
    
    
    
    270,652
    
    
    
    186,564
    (3)
    
    
    
    
    
    
    142,217
    
    
    
    51,500
    
    
    
    
    
    
    
    61,763Executive Vice President
    
    
    2002
    
    
    
    236,304
    
    
    
    102,824
    (3)
    
    
    
    
    
    
    
    
    
    
    57,492
    
    
    
    
    
    
    
    58,2942001
    
    
    
    198,261
    
    
    
    89,217
    (3)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    68,658
    (1)
    
    Mr. Mogg resigned as Chairman of the Board, President and Chief
Executive Officer effective December 31, 2003.(2)
    
    Mr. Slaughter provided services to our company pursuant to a
Consulting Agreement, which provided for the terms of his compensation
as Executive Vice President. The Consulting Agreement ended on December
31, 2003 and Mr. Slaughter resigned as Executive Vice President of the
Company effective that date. For a description of his agreement, see the
disclosure below under the heading Consulting Agreement. For the year
ended December 31, 2001, Mr. Slaughter received compensation that
included allocations for base salary, bonus and supplemental payments to
offset his ineligibility for company benefits. In addition, he received
phantom restricted stock and phantom stock options from the Company.
The agreement was amended on June 28, 2002. The amended agreement
provided for allocations for base salary, bonus, supplemental payments
to offset his ineligibility for company benefits and phantom stock
options, but no other benefits. The agreement was further amended on
April 16, 2003 to provide for the granting of phantom stock options and
phantom performance shares for 2003, but otherwise remained the same.(3)
    
    The bonus paid to Mr. Slaughter for fiscal year 2001, and the first
half of 2002, was an allocation of his billing rate under his Consulting
Agreement. The Consulting Agreement was amended in June 2002, and under
the amended agreement Mr. Slaughters bonus is based on Company and
personal performance similar to other executive officers of the Company.(4)
    
    Perquisites and other personal benefits received by each Named
Executive Officer did not exceed the lesser of $50,000 or 10% of any
such officers salary and bonus disclosed in the table. 78




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##### Table of Contents



(5)
    
    Awards made in 2003 to Messrs. Mogg, Borer, Bradley and Martinovich
are performance shares granted under the Duke Energy 1998 Long-Term
Incentive Plan. The awards were made on February 25, 2003. Performance shares are represented by units denominated in shares of Duke Energy
Common Stock. Each performance share represented the right to receive,
upon vesting, one share of Duke Energy Common Stock. Between fifty
percent (50%) to one hundred percent (100%) of the shares awarded were
eligible for vesting based upon achievement of Duke Energy 2003 earnings
per share (EPS) within a specified range. Based on 2003 EPS, all
performance shares in each award were forfeited. Mr. Slaughter was also
granted performance shares for 2003 under his Consulting Agreement that
were identical to the performance shares of the other executive officers
except they provided for receipt of phantom common stock. However,
based on 2003 EPS, all of Mr. Slaughters performance shares were
forfeited.(6)
    
    Messrs. Mogg, Borer, Bradley and Martinovich elected to receive a
portion of the value of the long-term incentive component of their 2002
compensation in the form of phantom stock. The awards were granted under
the Duke Energy 1998 Long Term Incentive Plan. The awards for Messrs.
Mogg, Borer, Bradley and Martinovich were made on December 19, 2001.
Phantom stock is represented by units denominated in shares of Duke
Energy common stock. Each phantom stock unit represents the right to
receive, upon vesting, one share of Duke Energy common stock. One
quarter of each award vests on each of the first four anniversaries of
the grant date provided the recipient continues to be employed by the
Company or his or her employment terminates on account of retirement.
The awards fully vest in the event of the recipients death or
disability or a change in control as specified in the plan. If the
recipients employment terminates other than on account of retirement,
death or disability, any unvested shares remaining on the termination
date are forfeited. The phantom stock awards also grant an equal number
of dividend equivalents, which represent the right to receive cash
payments equivalent to the cash dividends paid on the number of shares
of Duke Energy common stock represented by the phantom stock units
awarded, until the related phantom stock units vest or are forfeited.The aggregate number of phantom stock units held by Messrs. Mogg, Borer,
Bradley and Martinovich at December 31, 2003 and their values on that date
are as follows: Number of
    
    Value AtPhantom Stock
    
    December 31,Units
    
    2003J. Mogg
    
    
    5,616
    
    
    $
    114,847M. Borer
    
    
    1,826
    
    
    
    37,342M. Bradley
    
    
    1,826
    
    
    
    37,342R. Martinovich
    
    
    1,826
    
    
    
    37,342
  (7)
    
    Represents options granted by Duke Energy to purchase shares of Duke
Energy common stock, except for Mr. Slaughter,
who received phantom stock options that track the performance of Duke
Energy common stock.(8)
    
    Represents the following for 2003:  
    
    Matching contributions under the Companys 401(k) and Retirement
Plan as follows: J. Mogg, $20,000; M. Borer, $20,000; M. Bradley,
$20,000; R. Martinovich, $20,000.
    
    Make-whole contributions under the Companys Executive Deferred
Compensation Plan as follows: J. Mogg, $28,208; M. Borer,
$11,237; M. Bradley, $12,906; R. Martinovich, $11,580.
    
    Life Insurance premiums paid by the Company as follows: J. Mogg,
$810; M. Borer, $504; M. Bradley, $504; R.
Martinovich, $450.
    
    Supplemental payment to offset ineligibility for Company benefit
plan as follows: W. Slaughter, $61,763. 79




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Board Compensation Our Directors do not receive a retainer or fees for service on our Board
of Directors or any committees. All of our directors are reimbursed for
reasonable out-of-pocket expenses incurred in attending meetings of our Board
of Directors or committees and for other reasonable expenses related to the
performance of their duties as directors. Consulting Agreement We entered into a contract for consulting services with Mr. Slaughter that
terminated on December 31, 2003. The agreement was amended on June 28, 2002 and
again on April 16, 2003. The amended agreement provides for a billing rate of
$1,272 per day for 2002 and a billing rate of $1,335 per day for 2003 until the
agreement terminates. In addition, the amended agreement provides that Mr.
Slaughter is eligible for a bonus award with a target of 55% of his base annual
compensation. In addition, under the terms of the amended agreement, Mr.
Slaughter was awarded a long term incentive award for 2002 that tracks the
performance of Duke Energy common stock. The award, valued at $387,500 at the
time of grant, vested on December 31, 2003 and is exercisable for three years
following vesting. The agreement also provided that Mr. Slaughter be awarded a
long term incentive award for 2003 split evenly between phantom stock options and
phantom performance shares. This award, valued at $406,875 at the time of
grant, vested on December 31, 2003 and the phantom stock options are
exercisable for three years following vesting. The phantom performance shares
were forfeited because Duke Energy did not meet certain performance targets for
2003. Mr. Slaughter is not eligible for any other benefits under the Companys
compensation plans. Option Grants in Last Fiscal Year None of the Named Executive Officers has received options to purchase
members interests in our company. None of the Named Executive Officers held
options to purchase member interests in our company at December 31, 2003. This table shows options granted of Duke Energy common stock to the Named
Executive Officers during 2003, along with the present value of the options on
the date they were granted, calculated as described in the footnote to the
table. Option/SAR Grants in Last Fiscal Year Individual GrantsNumber ofShares
    
    % of TotalUnderlying
    
    Options/SARS
    
    Exercise or
    
    
    
    
    
    Grant DateOptions/SARS
    
    Granted to
    
    Base
    
    Expiration
    
    PresentName
    
    Granted(1)(#)
    
    Employees(2)
    
    Price ($/Sh)
    
    Date
    
    Value(3)($)J. W. Mogg
    
    
    3,000
    
    
    
    0.04
    
    
    
    17.10
    
    
    
    1/28/2013
    
    
    
    16,260J. W. Mogg
    
    
    90,000
    
    
    
    1.09
    
    
    
    13.77
    
    
    
    2/25/2013
    
    
    
    393,300M. A. Borer
    
    
    34,700
    
    
    
    0.42
    
    
    
    13.77
    
    
    
    2/25/2013
    
    
    
    151,639M. J. Bradley
    
    
    34,700
    
    
    
    0.42
    
    
    
    13.77
    
    
    
    2/25/2013
    
    
    
    151,639R. F. Martinovich
    
    
    31,000
    
    
    
    0.38
    
    
    
    13.77
    
    
    
    2/25/2013
    
    
    
    135,470W. W. Slaughter (4)
    
    
    51,500
    
    
    
    
    
    
    
    13.77
    
    
    
    12/31/2006
    
    
    
    203,438
    (1)
    
    Neither the Company nor Duke Energy has granted any SARs to the Named
Executive Officers or any other persons except for Mr. Slaughter who
received phantom stock options.(2)
    
    Reflects percentage that the grant represents of the total options
granted to employees of Duke Energy and its subsidiaries during 2003. 80




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##### Table of Contents



(3)
    
    Based on the Black-Scholes option valuation model except for Mr.
Slaughter, which was based on his Consulting Agreement (See above under
the heading Consulting Agreement). The following table lists key input
variables used in valuing the options: Input Variable:Risk-free Interest Rate
    
    
    4.42
    %Dividend Yield
    
    
    3.38
    %Stock Price Volatility
    
    
    37.71
    %Option Term
    
    10 years
  With respect to all option grants listed in the table, the volatility
variable reflected historical monthly stock price trading data with respect
to Duke Energy Common Stock from November 30, 1999 through November 30, 2002.
An adjustment was made with respect to each valuation for a risk of
forfeiture during any applicable vesting period. The actual value, if any,
that a grantee may realize will depend on the excess of the stock price over
the exercise price on the date the option is exercised, so that there is no
assurance the value realized will be at or near the value estimated based
upon the Black-Scholes model.  (4)
    
    Mr. Slaughter was not an employee at the time of grant but provided
services to the Company under a Consulting Agreement (See above under the
heading Consulting Agreement). OPTION EXERCISES AND YEAR-END VALUES This table shows aggregate exercises of options for Duke Energy common
stock during 2003 by the Named Executive Officers, and the aggregate year-end
value of the unexercised options held by them. The value assigned to each
unexercised in-the-money stock option is based on the positive spread between
the exercise price of the stock option and the fair market value of Duke Energy
common stock on December 31, 2003, which was $20.45. The fair market value is
the closing price of a share of Duke Energy Common Stock on that date as
reported on the New York Stock Exchange Composite Transactions Tape. The
ultimate value of a stock option will depend on the market value of the
underlying shares on a future date. Aggregated Option/SAR Exercises in Last Fiscal Year
and Fiscal Year-End Option/SAR Values Number ofSecuritiesUnderlying
    
    Value of UnexercisedUnexercised
    
    In-the-MoneyOptions/SARS at
    
    Options/SARS atFY-End*(#)
    
    FY-End($)Shares Acquired
    
    
    
    
    
    Exercisable/
    
    Exercisable/Name
    
    on Exercise(#)
    
    Value Realized($)
    
    Unexercisable
    
    UnexercisableJ. W. Mogg
    
    
    0
    
    
    
    0
    
    
    
    286,938 / 146,050
    
    
    
    10,050 / 601,200M. A. Borer
    
    
    0
    
    
    
    0
    
    
    
    61,550 / 52,250
    
    
    
    0 / 231,796M. J. Bradley
    
    
    860
    
    
    
    3,535
    
    
    
    53,940 / 52,250
    
    
    
    1,238 / 231,796R. F. Martinovich
    
    
    0
    
    
    
    0
    
    
    
    44,850 / 48,550
    
    
    
    0 / 207,080W. W. Slaughter
    
    
    0
    
    
    
    0
    
    
    
    157,712/0
    
    
    
    344,020 / 0
    *
    
    Neither the Company nor Duke Energy has granted any SARs to the Named
Executive Officers or any other persons except for Mr. Slaughter who
received phantom stock options. 81




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##### Table of Contents



ITEM 12.Security Ownership of Certain Beneficial Owners and Management. The following table sets forth information regarding the beneficial
ownership of the member interests in our company by:  
    
    each holder of more than 5% of our member interests;
    
    the Named Executive Officers;
    
    each director; and
    
    all directors and executive officers as a group. Name of Beneficial Owners
    
    Beneficial OwnershipDuke Energy Corporation
526 South Church Street
Charlotte, North Carolina 28201-1006
    
    
    69.7
    %ConocoPhillips 
600 N. Dairy Ashford
Houston, TX 77079
    
    
    30.3
    %W.H. Easter
    
    
    Brent L. Backes
    
    
    Mark A. Borer
    
    
    Michael J. Bradley
    
    
    Robert F. Martinovich
    
    
    Rose M. Robeson
    
    
    Philip L. Frederickson
    
    
    Fred J. Fowler
    
    
    John E. Lowe
    
    
    Richard J. Osborne
    
    
    All directors and executive officers as a group
(10 persons)
    
    
    
 In August 2000, we issued $300 million of preferred member interests to
affiliates of Duke Energy and ConocoPhillips. Duke Energy Field Services
Investment Corp. was issued a preferred member interest representing 69.7% of
the outstanding preferred member interests in our company and Phillips Gas
Investment Company was issued a preferred member interest representing a 30.3%
of the outstanding preferred member interests in our company. See Note 11 to
the Notes to Consolidated Financial Statements. The preferred member interests
have no voting rights in the election of our directors. On
September 9, 2002,
we redeemed $100 million, on September 19, 2003, we redeemed $125 million, and
on December 31, 2003, we redeemed the remaining $75 million of our preferred
members interest by paying cash to each of our members (Duke Energy and
ConocoPhillips) in proportion to their ownership interests. The Company does not have any equity compensation plans. However,
employees of the Company receive stock options, restricted stock and
performance shares of Duke Energy under the Duke Energy 1998 Long Term
Incentive Plan. 
 ITEM 13.Certain Relationships and Related Transactions. On March 31, 2000, we combined the then existing midstream natural gas
businesses of Duke Energy and ConocoPhillips. In connection with the
Combination, Duke Energy and ConocoPhillips transferred all of their respective
interests in their subsidiaries that conducted their midstream natural gas
business at that time to us. In connection with the Combination, Duke Energy
and ConocoPhillips also transferred to us additional midstream natural gas
assets acquired by Duke Energy or ConocoPhillips prior to consummation of the
Combination, including the Mid-Continent gathering and processing assets of
Conoco and Mitchell Energy. In addition, concurrently with the Combination, we
obtained by transfer from Duke Energy the general partner of TEPPCO. In
exchange for the asset contributions, ConocoPhillips received 30.3% of the
outstanding non-preferred member interests in our company, with Duke Energy
holding the remaining 69.7% of the outstanding non-preferred member interests
in our company. In connection with the closing of the Combination, we borrowed
approximately $2.8 billion in the commercial paper market and made one-time
cash distributions (including reimbursements for acquisitions) of approximately
$1.5 billion to Duke Energy and approximately $1.2 billion to ConocoPhillips. There are significant transactions and relationships between us, Duke
Energy and ConocoPhillips. For purposes of governing these ongoing
relationships and transactions, we will continue in effect the agreements
described below. We intend that the terms of any 82




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future transactions and agreements between us and Duke Energy or
ConocoPhillips will be at least as favorable to us as could be obtained from
third parties. Depending on the nature and size of the particular transaction,
in any such reviews, our Board of Directors may rely on our managements
knowledge, use outside experts or consultants, secure appropriate appraisals,
refer to industry statistics or prices, or take other actions as are
appropriate under the circumstances. Transactions with Duke Energy Services Agreement We entered into a services agreement with Duke Energy and some of its
subsidiaries, dated as of March 14, 2000. Under this agreement, Duke Energy and
those subsidiaries provide us with various staff and support services,
including information technology products and services, payroll, employee
benefits, insurance, cash management, ad valorem taxes, treasury, media
relations, printing, records management, and legal functions. These services
are priced on the basis of a monthly charge approximating market prices.
Additionally, we may use other Duke Energy services subject to hourly rates,
including legal, insurance, internal audit, tax planning, human resources and
security departments. This agreement, as amended, expires on December 31, 2003,
however, we intend to renew this agreement. We believe that the overall charges
under this agreement will not exceed charges we would have incurred had we
obtained similar services from outside sources. In addition, we entered into an IT Consolidation and Operations Services
Agreement, dated as of July 30, 2003, with a subsidiary of Duke Energy. Under
this Agreement, Duke Energy agreed to assist us in transferring and
consolidating our information technology operations into Duke Energys
information technology operations and provide future ongoing information
technology services to us. These services are priced on the basis of a monthly
charge. This agreement expires on December 31, 2005, but automatically renews
each year thereafter unless terminated by either party as provided for in the
agreement. License Agreement In connection with the Combination, Duke Energy has licensed to us a
non-exclusive right to use the phrase Duke Energy and its logo and certain
other trademarks in identifying our businesses. This right may be terminated by
Duke Energy at its sole option any time after:  
    
    Duke Energys direct or indirect ownership interest in our company is less than or equal to 35%; or
    
    Duke Energy no longer controls, directly or indirectly, the management and policies of our company. Following the receipt of Duke Energys notice of termination, we have
agreed to amend our organizational documents and those of our subsidiaries to
remove the Duke name and to phase out within 180 days of the date of the
notice the use of existing signage, printed literature, sales and other
materials bearing a name, phrase or logo incorporating Duke. Other Transactions Prior to the Combination, Duke Energy and its subsidiaries engaged in a
number of transactions with the Predecessor Company. This included sales of
residue gas and NGLs, the purchase of raw natural gas and other petroleum
products and providing natural gas gathering and transportation services to
Duke Energy and its subsidiaries. We continue to engage in such activities with
Duke Energy and its subsidiaries in the ordinary course of business. In 2003,
2002 and 2001, our total revenues from such activities, including amounts
netted in trading and marketing net margin, with Duke Energy and its
subsidiaries were approximately $799 million, $1,122 million, and $1,637
million, respectively. Transactions with ConocoPhillips Prior to the Combination, ConocoPhillips engaged in a number of
transactions with GPM Gas Corporation, the subsidiary of ConocoPhillips that
owned its midstream natural gas assets that were transferred to us as part of
the Combination. This included the sale of residue gas, NGLs and sulfur, and
the purchase of raw natural gas. In addition, it included a long term agreement
with ConocoPhillips, and subsequently its affiliate CP Chem, for the sale of
NGLs at index-based prices. This agreement expires January 1, 2015. We
anticipate that we will continue to engage in such activities with
ConocoPhillips and its subsidiaries and CP Chem in the ordinary course of
business. For the years ended December 31, 2003, 2002 and 2001, our total
revenues from such activities, including 83




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##### Table of Contents



amounts netted in trading and marketing net margin, with ConocoPhillips
and its subsidiaries, and CP Chem were approximately $1,500 million, $934
million and $1,188 million, respectively. 
 ITEM 14.Principal Accounting Fees and Services The following table presents fees for professional services rendered by
Deloitte & Touche LLP (Deloitte), our principal accountant, for the audit of
our financial statements for the years ended December 31, 2003 and 2002, and
the fees billed for other services rendered by Deloitte during those periods: Type of Fees
    
    FY 2003
    
    FY 2002(millions)Audit Fees (a)
    
    $
    1.0
    
    
    $
    1.4Audit-Related Fees (b)
    
    
    0.2
    
    
    
    0.4Tax Fees
    
    
    
    
    
    
    0.3All Other Fees (c)
    
    
    
    
    
    
    Total Fees:
    
    $
    1.2
    
    
    $
    2.1
    (a)
    
    Audit Fees are fees billed by Deloitte for professional services for
the audit of the Companys consolidated financial statements included in
the Companys Annual Report on Form 10-K and review of financial
statements included in the Companys Quarterly Reports on Form 10-Q,
services that are normally provided by Deloitte in connection with
statutory and regulatory filings or engagements or any other service
performed by Deloitte to comply with generally accepted auditing
standards and include comfort and consent letters in connection with
Securities and Exchange Commission filings and financing transactions.(b)
    
    Audit-Related Fees are fees billed by Deloitte for assurance and
related services that are reasonably related to the performance of an
audit or review of the Companys financial statements, including
assistance with acquisitions and divestitures, internal control reviews,
and employee benefit plan audits.(e)
    
    All Other Fees are fees billed by Deloitte for any services not
included in the first three categories. The Company is a majority-owned subsidiary of Duke Energy and we have no
equity securities listed on a national securities exchange. Therefore, we are
not required to have an Audit Committee. However, we voluntarily established
an Audit Committee which is made up of one Director from each of the Companys
members. Both members of the audit committee, Richard J. Osborne and John E.
Lowe, qualify as financial experts as defined in Item 401(h) of Regulation S-K.
The charter of the Audit Committee provides that the Audit Committee is
responsible for reviewing fees paid to the Companys external auditors. At the
beginning of each fiscal year all audit services to be provided by the
independent auditors during that fiscal year are approved by the Audit
Committee. 84




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##### Table of Contents



PART IV. 
 ITEM 15.Exhibits, Financial Statement Schedules, and Reports on Form 8-K. (a) Consolidated Financial Statements, Supplemental Financial Data and
Supplemental Schedule included in Part II of this annual report are as follows: Consolidated Financial Statements  Consolidated Statements of Operations for the Years Ended December 31,
2003, 2002 and 2001Consolidated Statements of Comprehensive Income (Loss) for the Years
Ended December 31, 2003, 2002 and 2001Consolidated Statements of Cash Flows for the Years Ended December 31,
2003, 2002 and 2001Consolidated Balance Sheets as of December 31, 2003 and 2002Consolidated Statements of Members Equity for the Years Ended December
31, 2003, 2002 and 2001  Notes to Consolidated Financial StatementsQuarterly Financial Data (unaudited) (included in Note 20 of the Notes to
Consolidated Financial Statements)Consolidated Financial Statement Schedule II  Valuation and Qualifying
Accounts and Reserves for the Years Ended
December 31, 2003, 2002 and 2001 All other schedules are omitted because of the absence of the conditions
under which they are required or because the required information is included
in the financial statements or notes thereto. (b) Reports on Form 8-K None. (c) Exhibits  See Exhibit Index immediately following the signature
page. 85




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##### Table of Contents



SIGNATURES Pursuant to the requirements of Section 13 or 15(d) the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized. DUKE ENERGY FIELD SERVICES, LLCBy:
    
    /s/ W. H. Easter IIIW. H. Easter IIIChairman of the Board, President andChief Executive Officer
 March 15, 2004 Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated. Signature
    
    Title/s/ W. H. Easter III
W. H. Easter III
    
    Chairman of the Board, President and Chief
Executive Officer (Principal Executive
Officer)/s/ROSE M ROBESON
Rose M. Robeson
    
    Chief Financial Officer (Principal Financial
and Accounting Officer)/s/ PHILIP L. FREDRICKSON
Philip L. Frederickson
    
    Director/s/ FRED J. FOWLER
Fred J. Fowler
    
    Director/s/ JOHN E. LOWE
John E. Lowe
    
    Director/s/ RICHARD J. OSBORNE
Richard J. Osborne
    
    Director
 Date: March 15, 2004 86




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EXHIBIT INDEX Exhibits filed herewith are designated by an asterisk(*). All exhibits not
so designated are incorporated by reference to a prior filing, as indicated.
Items constituting management contracts or compensatory plans or arrangements
are designated by a double asterisk (**). Exhibit Number
    
    Description3.1
    
    
    
    Amended and Restated Limited Liability Company
Agreement of Duke Energy Field Services, LLC by and between
Phillips Gas Company and Duke Energy Field Services
Corporation, dated as of March 31, 2000 (incorporated by
reference to Exhibit 3.1 to Form 10 (Registration No.
000-31095) of registrant filed on July 20, 2000).3.2
    
    
    
    First Amendment to Amended and Restated Limited
Liability Company Agreement of Duke Energy Field Services,
LLC dated as of August 4, 2000 (incorporated by reference
to Exhibit 3.1 to Current Report on Form 8-K of registrant
filed on August 16, 2000).4.1
    
    
    
    Form of Indenture (incorporated by reference to Exhibit
4.1 to Registration Statement on Form S-3/A (Registration
No. 333-41854) of registrant filed on August 2, 2000).4.2
    
    
    
    First Supplemental Indenture between Duke Energy Field
Services, LLC and The Chase Manhattan Bank, as trustee,
dated as of August 16, 2000 (incorporated by reference to
Exhibit 4.1 to Current Report on Form 8-K of registrant
filed on August 16, 2000).4.3
    
    
    
    Second Supplemental Indenture between Duke Energy Field
Services, LLC and The Chase Manhattan Bank, as trustee,
dated as of February 2, 2001 (incorporated by reference to
Exhibit 4.1 to Current Report on Form 8-K of registrant
filed on February 1, 2001).4.4
    
    
    
    Third Supplemental Indenture between Duke Energy Field
Services, LLC and The Chase Manhattan Bank, as trustee,
dated as of November 9, 2001 (incorporated by reference to
Exhibit
4.1 to Current Report on Form 8-K of registrant filed on
November 9, 2002.10.1
    
    
    
    Second Amendment to Parent Company Agreement among
Phillips Petroleum Company, Duke Energy Corporation, Duke
Energy Field Services, LLC and Duke Energy Field Services
Corporation dated as of August 4, 2000 (incorporated by
reference to Exhibit 10.1 to Current Report on Form 8-K of
registrant filed on August 16, 2000).10.2
    
    
    
    Services Agreement dated as of March 14, 2000 by and
between Duke Energy Corporation, Duke Energy Business
Services, LLC, Pan Service Company, Duke Energy Gas
Transmission Corporation and Duke Energy Field Services,
LLC (incorporated by reference to Exhibit 10.3 to
Registration Statement on Form S-1/A (Registration No.
333-32502) of Duke Energy Field Services Corporation, filed
on March 27, 2000).10.3
    
    
    
    First Amendment to Services Agreement dated as of
December 15, 2000 between Duke Energy Corporation, Duke
Energy Business Services, LLC, Pan Service Company, Duke
Energy Gas Transmission Corporation and Duke Energy Field
Services, LLC. (incorporated by reference to Exhibit 10.5 to
Annual Report on Form 10-K of registrant filed on March 30,
2001).10.4
    
    
    
    Second Amendment to Services Agreement effective January 1,
2002 between Duke Energy Corporation, Duke Energy Business
Services, LLC, Pan Service Company, Duke Energy Gas
Transmission Corporation and Duke Energy Field Services, LLC.10.5
    
    
    
    Amendment to Services Agreement effective January 1, 2003
between Duke Energy Corporation, Duke Energy Business
Services, LLC, Pan Service Company, Duke Energy Gas
Transmission Corporation and Duke Energy Field Services, LLC.10.6
    
    
    
    Transition Services Agreement dated as of March 17,
2000 among Phillips Petroleum Company and Duke Energy Field
Services, LLC (incorporated by reference to Exhibit 10.4 to
Registration Statement on Form S-1/A (Registration No.
333-32502) of Duke Energy Field Services Corporation, filed
on March 27, 2000).10.7
    
    
    
    Trademark License Agreement dated as of March 31, 2000
among Duke Energy Corporation and Duke Energy Field
 87




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##### Table of Contents



Exhibit Number
    
    DescriptionServices, LLC (incorporated by reference to Exhibit 10.5 to
Registration Statement on Form S-1/A (Registration No.
333-32502) of Duke Energy Field Services Corporation, filed
on May 4, 2000).10.8
    
    
    
    Contribution Agreement dated as of December 16, 1999
among Duke Energy Corporation, Phillips Petroleum Company
and Duke Energy Field Services, LLC (incorporated by
reference to Exhibit 2.1 to Duke Energy Corporations Form
8-K filed on December 30, 1999).10.9
    
    
    
    First Amendment to Contribution and Governance
Agreement dated as of March 23, 2000 among Phillips
Petroleum Company, Duke Energy Corporation and Duke Energy
Field Services, LLC (incorporated by reference to Exhibit
10.7(b) to Registration Statement on Form S-1/A
(Registration No. 333-32502) of Duke Energy Field Services
Corporation, filed on March 27, 2000).10.10
    
    
    
    NGL Output Purchase and Sale Agreement
effective as of January 1, 2000 between GPM
Gas Corporation and Phillips 66 Company, a
division of Phillips Petroleum Company, as
amended by Amendment No. 1 dated December 16,
1999 (incorporated by reference to Exhibit
10.8 to Registration Statement on Form S-1/A
(Registration No. 333-32502) of Duke Energy
Field Services Corporation, filed on March 15,
2000).10.11
    
    
    
    Sulfur Sales Agreement effective as of
January 1, 1999 between Phillips 66 Company, a
division of Phillips Petroleum Company, and
GPM Gas Corporation (incorporated by reference
to Exhibit 10.9 to Registration Statement on
Form S-1/A (Registration No. 333-32502) of
Duke Energy Field Services Corporation, filed
on March 27, 2000).10.12
    
    
    
    Parent Company Agreement dated as of March
31, 2000 among Phillips Petroleum Company,
Duke Energy Corporation, Duke Energy Field
Services, LLC and Duke Energy Field Services
Corporation (incorporated by reference to
Exhibit 10.10 to Registration Statement on
Form S-1/A (Registration No. 333-32502) of
Duke Energy Field Services Corporation, filed
on May 4, 2000).10.13
    
    
    
    First Amendment to the Parent Company
Agreement dated as of May 25, 2000 among
Phillips Petroleum Company, Duke Energy
Corporation, Duke Energy Field Services, LLC
and Duke Energy Field Services Corporation
(incorporated by reference to Exhibit 10.8(b)
to Form 10 (Registration No. 333-41854) of
registrant filed on July 20, 2000).10.14**
    
    
    
    Contract for Services dated as of April 1,
2000 between Duke Energy Field Services
Assets, LLC and William W. Slaughter
(incorporated by reference to Exhibit 10.11 to
Registration Statement on Form S-1/A
(Registration No. 333-32502) of Duke Energy
Field Services Corporation, filed on May 4,
2000).10.15**
    
    
    
    First Amendment to Contract for Services
dated as of June 29, 2000 between Duke Energy
Field Services Assets, LLC and William W.
Slaughter (incorporated by reference to
Exhibit 10.9(b) to Form 10/A (Registration No.
333- 41854) of registrant filed on August 2,
2000).10.16**
    
    
    
    Second Amendment to Contract for Services
between Duke Energy Field Services, LP and
William W. Slaughter (incorporated by
Reference to Exhibit 10.1 to Quarterly Report
on Form 10-Q of registrant filed on August
14,2002).10.17**
    
    
    
    Third Amendment to Contract for Services
between Duke Energy Field Services, LP and
William W. Slaughter (incorporated by
reference to Exhibit 10.1 to Quarterly Report
on Form 10-Q of the registrant filed on August
14, 2003).10.18
    
    
    
    364-Day Credit Facility among Duke Energy
Field Services, LLC, Duke Energy Field
Services Corporation, JPMorgan Chase Bank, as
Agent and the Lenders named therein, dated
March 28, 2003 (incorporated by reference to
Exhibit 10.01 to Quarterly Report on Form 10-Q
of the registrant filed on May 15, 2003).10.19
    
    
    
    Letter Agreement between Duke Energy Field
Services, LLC and Bank One, NA for funded
short-term loan facility dated March 28, 2003
(incorporated by reference to Exhibit 10.02 to
Quarterly Report on Form 10-Q of registrant
filed on May 15, 2003).10.20
    
    
    
    IT Consolidation and Operations Services
Agreement between Duke Energy Business
Services, LLC and Duke Energy Field Services,
LP, dated as of July 30, 2003 (incorporated by
reference
 88




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##### Table of Contents



Exhibit Number
    
    Descriptionto Exhibit 10.1 to Quarterly Report
on Form 10-Q of the registrant filed on
November 12, 2003).*23.1
    
    
    
    Consent of Deloitte & Touche LLP.*31.1
    
    
    
    Certification of the Chief Financial
Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.*31.2
    
    
    
    Certification of the Chief Executive
Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.*32.1
    
    
    
    Certification Pursuant to 18 U.S.C. Section
1350, as Adopted Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2003.*32.2
    
    
    
    Certification Pursuant to 18 U.S.C. Section
1350, as Adopted Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2003.
 89