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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549




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Form 10-K

|           |  |                                                                                         
|---------- |  | ----------------------------------------------------------------------------------------
|(Mark One) |  |                                                                                         
|[X]        |  | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934    
|           |  |                                                                                         
|           |  | For the fiscal year ended December 31, 2002                                             
|           |  |                                                                                         
|or        
|           |  |                                                                                         
|[   ]      |  | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
|           |  |                                                                                         
|           |  | For the transition period from              
to                                         

Commission file number 0-31095

Duke Energy Field Services, LLC

(Exact name of registrant as specified in its charter)


|                                                                                     |  |                                                
|------------------------------------------------------------------------------------ |  | -----------------------------------------------
|Delaware
(State or other jurisdiction
of incorporation or organization)              |  | 76-0632293
(I.R.S. Employer
Identification No.)
|                                                                                     |  |                                                
|370 17th Street, Suite 900
Denver, 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:

|                    |  |                                          
|------------------- |  | -----------------------------------------
|Title of Each Class |  | Name of Each Exchange
on Which Registered
|                    |  |                                          
|None                |  | 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, 2003, 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 Business                                                            
|                                                   |                                                                                                | Our Business Strategy                                                   
|                                                   |                                                                                                | Natural Gas Gathering, Processing, Transportation, Marketing and Storage
|                                                   |                                                                                                | Natural Gas Liquids Transportation, Fractionation, Marketing and Trading
|                                                   |                                                                                                | TEPPCO                                                                  
|                                                   |                                                                                                | Natural Gas Suppliers                                                   
|                                                   |                                                                                                | Competition                                                             
|                                                   |                                                                                                | Regulation                                                              
|                                                   |                                                                                                | Environmental Matters                                                   
|                                                   |                                                                                                | Employees                                                               
|                                                   | ITEM 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. 
|PART 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. Controls and Procedures                                                              
|PART IV.                                          
|                                                   | ITEM 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.                    
|SIGNATURES                                        
|CERTIFICATIONS                                    
|EXHIBIT INDEX                                     
|EX-10.4 Second Amendment to Services Agreement    
|EX-10.5 Amendment to Services Agreement           
|EX-12.1 Calculation of Ratio of Earnings          
|EX-21.1 Subsidiaries                              
|EX-23.1 Consent of Deloitte & Touche LLP          
|EX-23.2 Consent of KPMG LLP                       
|EX-99.1 Certification Pursuant to 18 USC Sec. 1350
|EX-99.2 Certification Pursuant to 18 USC Sec. 1350
|EX-99.3 Consolidated Financial Statements         



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DUKE ENERGY FIELD SERVICES, LLC
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2002

TABLE OF CONTENTS

|          |     |  |  |                                                                                       |                                                                             |  |    |    | 
|--------- | --- |  |  | ------------------------------------------------------------------------------------- | --------------------------------------------------------------------------- |  | -- | -- | 
|Item      |     |  |  |                                                                                       | Page                                                                       
|          |     |  |  |                                                                                       |                                                                            
|PART I.   |     |  |  |                                                                                      
|          | 1.  |  |  | Business                                                                              |                                                                             |  | 3  |   
|          |     |  |  |                                                                                       | Our Business                                                                |  |    | 3  | 
|          |     |  |  |                                                                                       | Our Business Strategy                                                       |  |    | 4  | 
|          |     |  |  |                                                                                       | Natural Gas Gathering, Processing, Transportation, Marketing
and Storage    |  |    | 5  | 
|          |     |  |  |                                                                                       | Natural Gas Liquids Transportation, Fractionation and
Marketing and Trading |  |    | 11 | 
|          |     |  |  |                                                                                       | TEPPCO                                                                      |  |    | 12 | 
|          |     |  |  |                                                                                       | Natural Gas Suppliers                                                       |  |    | 13 | 
|          |     |  |  |                                                                                       | Competition                                                                 |  |    | 13 | 
|          |     |  |  |                                                                                       | Regulation                                                                  |  |    | 14 | 
|          |     |  |  |                                                                                       | Environmental Matters                                                       |  |    | 16 | 
|          |     |  |  |                                                                                       | Employees                                                                   |  |    | 17 | 
|          | 2.  |  |  | Properties                                                                            |                                                                             |  | 17 |   
|          | 3.  |  |  | Legal Proceedings                                                                     |                                                                             |  | 17 |   
|          | 4.  |  |  | Submission of Matters to a Vote of Security Holders                                   |                                                                             |  | 17 |   
|PART II.  |     |  |  |                                                                                      
|          | 5.  |  |  | Market for Registrants Common Equity and Related
Stockholder Matters                 |                                                                             |  | 18 |   
|          | 6.  |  |  | Selected Financial Data                                                               |                                                                             |  | 19 |   
|          | 7.  |  |  | Managements Discussion and Analysis of Financial Condition
and Results of Operations |                                                                             |  | 21 |   
|          | 7A. |  |  | Quantitative and Qualitative Disclosures About Market
Risk                            |                                                                             |  | 31 |   
|          | 8.  |  |  | Financial Statements and Supplementary Data                                           |                                                                             |  | 38 |   
|          | 9.  |  |  | Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure  |                                                                             |  | 66 |   
|PART III. |     |  |  |                                                                                      
|          | 10. |  |  | Directors and Executive Officers of the Registrant                                    |                                                                             |  | 66 |   
|          | 11. |  |  | Executive Compensation                                                                |                                                                             |  | 68 |   
|          | 12. |  |  | Security Ownership of Certain Beneficial Owners and
Management                        |                                                                             |  | 72 |   
|          | 13. |  |  | Certain Relationships and Related Transactions                                        |                                                                             |  | 72 |   
|          | 14. |  |  | Controls and Procedures                                                               |                                                                             |  | 73 |   
|PART IV.  |     |  |  |                                                                                      
|          | 15. |  |  | Exhibits, Financial Statement Schedules and Reports
on Form 8-K                       |                                                                             |  | 75 |   
|          |     |  |  | Signatures                                                                            |                                                                             |  | 76 |   
|          |     |  |  | Exhibit Index                                                                         |                                                                             |  | 79 |   

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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;                                                                                                                                                                                                                                                                                                                              
|
| |  |  | the effect of accounting policies issued periodically by accounting standard-setting bodies; and                                                                                                                                                                                                                                                                                                                           
|
| |  |  | general economic conditions.                                                                                                                                                                                                                                                                                                                                                                                               

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.

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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 this Form 10-K as 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 this Form 10-K give 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 this Form 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 900, 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 (NGL
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
2002:



| |  |  | we handled an average of approximately 8.3 trillion British thermal units (Btus) per day of raw natural gas;
| | - |  | --------------------------------------------------------------------------------------------------------------
|
| |  |  | we produced an average of approximately 392,000 barrels per day of NGLs;                                      
|
| |  |  | we marketed and traded an average of approximately 576,000 barrels per day of NGLs; and                       
|
| |  |  | we marketed an average of approximately 2.6 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, 2002, our gathering systems
consisted of approximately 60,000 miles of gathering and transmission pipe,
with approximately 35,000 active receipt points.

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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 60 owned and
operated plants and at 11 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 components. We
fractionate NGL raw mix at our 11 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 Chevron Phillips Chemical Company LLC under an existing
contract which expires December 31, 2014. 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 and
Marketing 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 7.5 billion cubic foot natural gas storage facility.

On March 31, 2000, we combined the gas gathering, processing, marketing
and NGLs businesses of Duke Energy and ConocoPhillips that existed at that
time. In connection with the Combination, Duke Energy and ConocoPhillips
transferred to us all of their respective interests in their subsidiaries that
conducted their midstream natural gas business. Concurrent with the
Combination, on March 31, 2000, we obtained by transfer from Duke Energy
ownership of 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
and provides additional flexibility in pursuing our disciplined acquisition
strategy by providing an alternative acquisition vehicle.

Duke Energy and ConocoPhillips are currently having discussions regarding
possible changes to DEFS ownership. Member interests in DEFS are currently
held 69.7% by Duke Energy and 30.3% by ConocoPhillips. As a result of the
merger between Conoco Inc. (Conoco) and Phillips Petroleum Company that
created ConocoPhillips, ConocoPhillips owns the midstream natural gas assets
that were formerly owned by Conoco. Duke Energy and ConocoPhillips are
currently discussing the possible contribution by ConocoPhillips of certain of
these assets to DEFS. There is no certainty that these discussions will lead
to a transaction in which ConocoPhillips would contribute these assets to DEFS
or what the terms of such a transaction might be.

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 17, Business Segments, of the
Notes to Consolidated Financial Statements included in Item 8. Financial
Statements and Supplemental Data.




Our Business Strategy

We are one of the largest gatherers of raw natural gas, based on wellhead
volume, in North America. We are the largest producer and one of the largest
marketers of NGLs in North America. 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:



| |  |  | 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
significant market presence and asset base generally provide us
opportunities to use our economies of scale to be the 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.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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| |  |  | 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.                                                                                                                                                                                                                                                          
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | Increase our presence in high growth production areas.We intend to
use our strategic asset base in North America and our leading position
in the midstream natural gas industry as a platform for future growth.
We plan to increase our operations by following a disciplined
acquisition strategy, and by expanding existing infrastructure and
constructing new gathering lines and processing facilities.                                                                                                                                                                                                                                                                                                                              
|
| |  |  | Further streamline our low-cost structure.Our economies of scale,
operating efficiency and resulting low cost structure enhance our
ability to attract new raw natural gas supplies and generate current
income. The low-cost provider in any region can more readily attract new
raw natural gas volumes by offering more competitive terms to producers.
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, reviewing our contract structure and ensuring reliability
in our plant operations.




Natural Gas Gathering, Processing, Transportation, Marketing and Storage

Overview

At December 31, 2002, our raw natural gas gathering and processing
operations consisted of:



| |  |  | approximately 60,000 miles of gathering and transmission pipe, with
connections to approximately 35,000 active receipt points; and                                                                
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | 60 owned and operated processing plants and ownership interests in 11
additional third party operated plants, with a combined processing
capacity of approximately 8.0 billion cubic feet per day.

In 2002, we gathered, processed and/or transported approximately 8.3
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 1,600 additional receipt points in 2002.

Our raw natural gas gathering and processing operations are located in 11
contiguous 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. We have a significant presence in the first five of these
producing regions. According to Hart Downstream Energy Services Gas Processors
Report dated November 18, 2002, we are the largest NGL producer in North
America.

Raw Natural Gas Supply Arrangements.Typically, we take ownership, control
or custody of raw natural gas 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 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 Petroleum, Exxon Mobil, EOG Resources, and
Dominion, which together account for approximately 20% 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.

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We believe our significant asset base and scope of our operations provide
us with significant opportunities to add released raw natural gas to our
systems. In addition, we have significant processing capacity in the Offshore
Gulf of Mexico and Rocky Mountain regions, which contain significant 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 the
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 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 6.5 trillion Btus per day of raw natural gas and
produced an average of 392,000 barrels per day of NGLs during 2002.

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 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. We believe there are additional
opportunities to grow our services to our customer base.

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.

The natural gas marketing industry is a highly competitive commodity
business. We provide a full range of natural gas marketing services in
conjunction with the gathering, processing and transportation services we offer
on our facilities, which allows us to use our asset infrastructure to enhance
our revenues across each aspect of the midstream natural gas value chain.

6



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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, 2002.

|                                        |  |           |        |          |  |           |    |             |  |             |    |             |  |  |       |                     |  |  |       |     |  |  |         | 
|--------------------------------------- |  | --------- | ------ | -------- |  | --------- | -- | ----------- |  | ----------- | -- | ----------- |  |  | ----- | ------------------- |  |  | ----- | --- |  |  | ------- | 
|                                        |  |           |        |          |  |           |    |             |  |             |    |             |  |  |       | 2002 Operating Data
|                                        |  | Gas       |        |          |  |           |    |             |  |             |    |             |  |  |       |                    
|                                        |  | Gathering |        | Company  |  | Plants    |    | Net Plant   |  | Plant Inlet |    | NGLs       
|                                        |  | System    |        | Operated |  | Operated  |    | Capacity(1) |  | Volume(1)   |    | Production 
|Region                                  |  | (miles)   |        | Plants   |  | by Others |    | (MMcf/d)(3) |  | (BBtu/d)(3) |    | (Bbls/d)(3)
|                                        |  |           |        |          |  |           |    |             |  |             |    |            
|Permian Basin                           |  |           | 16,664 |          |  |           | 17 |             |  |             | 2  |             |  |  | 1,380 |                     |  |  | 1,364 |     |  |  | 121,559 | 
|Mid-Continent                           |  |           | 30,270 |          |  |           | 13 |             |  |             | 1  |             |  |  | 2,019 |                     |  |  | 1,896 |     |  |  | 123,759 | 
|East Texas-Austin Chalk-North
Louisiana |  |           | 4,614  |          |  |           | 6  |             |  |             |   |             |  |  | 1,185 |                     |  |  | 1,026 |     |  |  | 61,743  | 
|Onshore Gulf of Mexico                  |  |           | 4,561  |          |  |           | 7  |             |  |             | 1  |             |  |  | 1,118 |                     |  |  | 1,015 |     |  |  | 48,053  | 
|Rocky Mountains                         |  |           | 2,756  |          |  |           | 9  |             |  |             |   |             |  |  | 475   |                     |  |  | 399   |     |  |  | 21,294  | 
|Offshore Gulf of Mexico                 |  |           | 685    |          |  |           | 2  |             |  |             | 6  |             |  |  | 1,332 |                     |  |  | 357   | (2) |  |  | 9,265   | 
|Western Canada                          |  |           | 921    |          |  |           | 6  |             |  |             | 1  |             |  |  | 543   |                     |  |  | 401   |     |  |  | 6,240   | 
|                                        |  |           |        |          |  |           |    |             |  |             |    |             |  |  |       |                     |  |  |       |     |  |  |         | 
|Total                                   |  |           | 60,471 |          |  |           | 60 |             |  |             | 11 |             |  |  | 8,052 |                     |  |  | 6,458 |     |  |  | 391,913 | 



---

|(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 335 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. As we develop our regional strategies, we evaluate the
nature of the opportunity that a particular region presents. The attributes
that we evaluate include 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 broad 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

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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,
17 natural gas processing plants in this region. In addition, we own minority
interests in two other natural gas processing plants that are operated by
others. Our natural gas processing plants are strategically located to access
Permian Basin production. Our plants have processing capacity net to our
interest of 1.4 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. Three 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 2002, these plants operated at an overall 81% capacity
utilization rate. On average, the raw natural gas from West Texas and Southeast
New Mexico contains approximately 4.0 gallons of NGLs per thousand cubic feet.

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.

Our key suppliers in this region include ExxonMobil, Occidental, Anadarko
Petroleum, ConocoPhillips, Dominion Resources, Chevron-Texaco, and Yates
Petroleum. Our principal competitors in this region include Dynegy, Sid
Richardson, ConocoPhillips, Western Gas Resources, BP, El Paso Energy Partners, Marathon and Chevron-Texaco.

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 13 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 Arkoma, 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 2002, our plants
operated at an overall 82% capacity utilization rate. On average, the raw
natural gas from this region contains 4.1 gallons of NGLs per thousand cubic
feet.

We also produce approximately 25% of the United States domestic supply of
helium from our Mid-Continent facilities. Annual growth in demand for helium
over the past five years has been approximately 8% per year. Because of its
unique characteristics and use as an industrial gas, we expect demand for
helium to grow well into the future.

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 acreage dedication
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, OXY USA, Dominion
Resources, EOG Resources, Marathon Oil Company, Chesapeake Energy Corporation,
Apache Corporation and Anadarko Petroleum. Our principal competitors in this
region include Oneok Field Services, Enogex Inc., CMS Field Services, 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 six natural gas processing plants in this region. Our plants have
processing capacity net to our interest of 1.2 billion cubic feet of raw
natural gas per day. During 2002, these plants operated at an overall 74%
capacity utilization rate.

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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 currently produces approximately 38,000 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 Petroleum and American Central.
Most of the raw natural gas processed at the complex is contracted under
percent-of-proceeds agreements with an average remaining term of approximately
five years. The complex is adjacent to our Carthage Hub, which delivers residue
gas to interconnects with 12 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 gather and process or gather and transport over 420
billion Btus per day. 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 six
interstate pipelines at or near the Perryville Hub.

Our key suppliers in this region include Anadarko Petroleum, Devon Energy
and ConocoPhillips. Our principal competitors in this region include Gulf
South, El Paso Energy Partners 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 another
entity. Our plants have processing capacity net to our interest of 1.1 billion
cubic feet of raw natural gas per day. During 2002, the plants in this region
ran at an overall 80% capacity utilization rate.

Our Spindletop natural gas storage facility is located near Beaumont,
Texas and has current working natural gas capacity of 7.5 billion cubic feet,
plus expansion potential of up to an additional ten billion cubic feet. We
currently have approximately 3.75 billion cubic feet of the available storage
capacity under lease with third parties with expiration terms out to July 2003.
This high deliverability storage facility interconnects with 10 interstate and
intrastate pipelines and is positioned to meet 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 Corporation, United Oil
and Minerals and El Paso Production Company. Our principal competitors in this
region include El Paso Field Services, Kinder Morgan and Houston Pipe Line
Company.

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 2002, 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 Oil & Gas, BP, Kerr McGee
and Anadarko Petroleum. Our principal competitors in this region include Kerr
McGee, Williams Field Services and Western Gas Resources.

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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 other entities. The plants have processing capacity
net to our interest of 1.3 billion cubic feet of raw natural gas per day.
During 2002, our plants in this region operated at an overall 49% 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 an offshore gathering
and transmission system. 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 Chevron-Texacos Cypress
terminal.

On May 31, 2002, we acquired 33.3% of the outstanding membership interests
in Discovery Producer Services, LLC (DPS). The DPS assets, which were
primarily constructed in 1997, extend from deepwater offshore Louisiana to
onshore delivery points approximately 30 miles south of New Orleans. DPS 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. Based on our broad range of assets in the region, we intend to
capture incremental margins along the natural gas value chain.

Our key suppliers in the Offshore Gulf of Mexico region include El Paso
Production Company, ExxonMobil, Dominion Resources and AGIP. Our principal
competitors in this region include BP Pipelines, Shell Gas Transmission,
Williams Field Services and El Paso Field Services.

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 foothills area of Alberta. In total, the facilities in
this region have processing capacity net to our interest of 543 million cubic
feet of raw sour natural gas per day. Over 900 miles of gathering systems and
100,000 horsepower of compression support these facilities. During 2002, our
processing plants in this area operated at an overall 66% capacity utilization
rate. 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 foreign operations in Canada are subject
to risks inherent in transactions involving foreign currencies.

The Peace River Arch area continues to be an active drilling area with
land widely held among several large and small producers. Multiple residue gas
market outlets can be accessed from our facilities through connections to
TransCanadas NOVA system, the Westcoast system into British Columbia and the
Alliance Pipeline.

We believe that significant growth opportunities exist in this region. We
anticipate that producers in this area may follow the lead of United States
producers and divest their midstream assets over the next few years. We are
positioned to capitalize on this fundamental shift in the Canadian natural gas
processing industry and plan to expand our position in Alberta and British
Columbia through additional acquisitions and greenfield projects.

Our key suppliers in this region include Burlington Resources Canada Ltd.,
Canadian Natural Resources Ltd., Alberta Energy Company and Devon Energy
Canada. Our principal competitors in the area include Gibson Gas Processing
Ltd., BP Amoco, Petro Canada and Keyspan Energy.

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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 2002, we marketed and traded approximately 576,000
barrels per day of NGLs, of which approximately 63% was production for our own
account, ranking us as one of the largest NGL marketers in the country.

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, establishing us as a prominent wholesale
purchaser and seller of propane in the Northeast. Marketing propane from these
rail terminals, along with volume from TEPPCOs Providence, Rhode Island import
facility, accounts for approximately 23,000 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 11 owned and operated fractionators, including two
at the Mont Belvieu market center, and ten pipeline systems. Our current total
fractionation capacity is approximately 177,000 barrels per day.

Strategy

Our strategy is to utilize the size, scope and reliability of supply from
our raw natural gas processing operations and apply our knowledge of NGL market
dynamics to make additional investments in NGL infrastructure. 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 11 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.

Transportation.We will seek additional opportunities to invest in NGL
pipelines and secure favorable third party transportation arrangements. We use
company owned NGL pipelines to transport approximately 49,500 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.

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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 Petroleum Co. Our
largest sales customers are Chevron Phillips Chemical Company, ConocoPhillips,
Dow Hydrocarbons and Eastman Chemical which accounted for approximately 19%,
13%, 5%, and 3%, respectively, of our total NGL transportation, fractionation
and marketing revenues in 2002. Our principal competitors in the marketing of
NGLs are Enterprise Products, Koch, Dynegy and Louis Dreyfus. In 2002, we
marketed and traded an average of approximately 576,000 barrels per day, or
approximately 25% of the available domestic supply, which includes gas plant
production, refinery plant production and imports.




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 4,300 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 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). Marathon Ashland Petroleum LLC owns the other 50%
interest. Centennial owns and operates an interstate refined petroleum products
pipeline extending from the upper Texas Gulf Coast to Illinois.

TEPPCOs Upstream Segment owns and operates approximately 2,600 miles of
crude oil trunk line and gathering pipelines, primarily in Texas and Oklahoma.
It also owns a 50% interest in Seaway Crude Pipeline Company, or Seaway, which
owns an approximately 500 mile, large diameter crude oil pipeline that
transports primarily imported crude oil from the Texas Gulf Coast to the
mid-continent and midwest refining sectors. ConocoPhillips owns the remaining
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 650 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 350 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 970 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

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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. 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.

We believe that our ownership of the general partnership interest of
TEPPCO improves our business position in the gathering and transportation
sector of the midstream natural gas industry and provides us additional
flexibility in pursuing our disciplined acquisition strategy by providing an
alternative acquisition vehicle.

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 2002 per unit distribution level, the general partner received
approximately 25% of the cash distributed by TEPPCO to its partners, which
consisted of 23% from the incentive cash distribution and 2% from the general
partner interest. During 2002, total cash distributions to the general partner
of TEPPCO were $37.7 million. Also during 2002, equity contributions of $7.6
million were paid by the general partner to TEPPCO.




Natural Gas Suppliers

We purchase substantially all of our raw natural gas from producers under
varying term contracts. Typically, we take ownership of raw natural gas 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 2002. 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.




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;                            

13



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| |  |  | 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

Transportation.Historically, the transportation and sale for resale of
natural gas in interstate commerce has been regulated under the Natural Gas Act
of 1938, the Natural Gas Policy Act of 1978, and the regulations promulgated
thereunder by the FERC. In the past, the federal government regulated the
prices at which natural gas could be sold. In 1989, Congress enacted the
Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and
Natural Gas Policy Act price and non-price controls affecting wellhead sales of
natural gas. Congress could, however, reenact field natural gas price controls
in the future, though we know of no current initiative to do so.

As a gatherer, processor and marketer of raw natural gas, we depend on the
natural gas transportation and storage services offered by various interstate
and intrastate pipeline companies to enable the delivery and sale of our
residue gas supplies. In accordance with methods required by the FERC for
allocating the system capacity of open access interstate pipelines, at times
other system users can preempt the availability of interstate natural gas
transportation and storage service necessary to enable us to make deliveries
and sales of residue gas. Moreover, shippers and pipelines may negotiate the
rates charged by pipelines for such services within certain allowed parameters.
These rates will also periodically vary depending upon individual system usage
and other factors. An inability to obtain transportation and storage services
at competitive rates can hinder, in some instances, our processing and
marketing operations and affect our sales margins.

The intrastate pipelines that we own are subject to state regulation and,
to the extent they provide interstate services under Section 311 of the Natural
Gas Policy Act of 1978, also are subject to FERC regulation. Dauphin Island
owns and operates a natural gas gathering system and interstate transmission
system located in offshore waters south of Louisiana and Alabama. The offshore
gathering system does not provide jurisdictional service under the Natural Gas
Act; the interstate offshore transmission system is regulated by the FERC.

14



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Commencing in April 1992 the FERC issued Order No. 636 and a series of
related orders that require interstate pipelines to provide open-access
transportation on a basis that is equal for users of the pipeline services. The
FERC has stated that it intends for Order No. 636 to foster increased
competition within all phases of the natural gas industry. Order No. 636
applies to our activities in Dauphin Island. The courts have largely affirmed
the significant features of Order No. 636 and the numerous related orders
pertaining to individual pipelines, although certain appeals remain pending and
the FERC continues to review and modify its regulations. For example, the FERC
issued Order No. 637 in February 2000 which, among other things:



| |  |  | permits pipelines to charge different maximum cost-based rates for peak and off-peak periods;                                       
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | encourages, but does not mandate, auctions for pipeline capacity;                                                                   
|
| |  |  | requires pipelines to implement imbalance management services;                                                                      
|
| |  |  | restricts the ability of pipelines to impose penalties for
imbalances, overruns and non-compliance with operational flow orders;
and
|
| |  |  | implements a number of new pipeline reporting requirements.                                                                         

Order No. 637 also requires the FERC to analyze whether it should
implement additional fundamental policy changes, including, among other things,
whether to pursue performance-based ratemaking or other non-cost based
ratemaking techniques and whether the FERC should mandate greater
standardization in terms and conditions of service across the interstate
pipeline grid. In addition, the FERC implemented regulations governing the
procedure for obtaining authorization to construct new pipeline facilities and
has issued a policy statement, which it largely affirmed in a recent order on
rehearing, establishing a presumption in favor of requiring owners of new
pipeline facilities to charge rates based solely on the costs associated with
such new pipeline facilities. We cannot predict what further action the FERC
will take on these matters. However, we do not believe that we will be affected
by any action taken previously or in the future on these matters materially
differently than other natural gas gatherers, transporters, processors and
marketers with which we compete.

Some of our interstate natural gas pipelines are subject to the
regulations of the U.S. Department of Transportation (DOT) concerning
pipeline safety. The DOT is developing regulations that will require pipelines
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. The
Pipeline Safety Improvement Act of 2002, which was enacted on December 17,
2002, establishes mandatory inspections of high-consequence areas for all U.S.
oil and natural gas pipelines within 10 years. At this time we cannot estimate
the expected cost of complying with these regulations.

Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC and the courts. The natural gas
industry historically has been heavily regulated; therefore, there is no
assurance that the less stringent and pro-competition regulatory approach
recently pursued by the FERC and Congress will continue.

Gathering.The Natural Gas Act exempts natural gas gathering facilities
from FERC jurisdiction. Interstate natural gas transmission facilities, on the
other hand, remain subject to FERC jurisdiction. The FERC has historically
distinguished between these two types of facilities on a fact-specific basis.
We believe that our gathering facilities and operations meet the current tests
that the FERC uses to grant non-jurisdictional gathering facility status.
However, there is no assurance that the FERC will not modify such tests or that
all of our facilities will remain classified as natural gas gathering
facilities.

Some 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.

In April 2000, the FERC issued Order No. 639, requiring that virtually all
non-proprietary pipeline gatherers of natural gas on the outer-continental
shelf report information on their affiliations, rates and conditions of
service. Among the FERCs purposes in issuing these rules was the desire to
provide shippers on the outer-continental shelf with greater assurance of
open-access services on pipelines located on the outer-continental shelf and
non-discriminatory rates and conditions of service on these pipelines. The FERC

15



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exempted Natural Gas Act-regulated pipelines, like that owned and operated
by Dauphin Island, from the new reporting requirements, reasoning that the
information that these pipelines were already reporting was sufficient to
monitor conformity with existing non-discrimination mandates. The Company and
others challenged the rule, and on January 11, 2002, the U.S. District Court
for the District of Columbia issued a summary judgment in favor of the Company
and the other plaintiffs, and a permanent injunction against the FERC
prohibiting enforcement of Order No. 639. On February 20, 2002, FERC filed its
notice of appeal to the D.C. Circuit Court of Appeals. A ruling in favor of the
FERC could increase our cost of regulatory compliance and place us at a
disadvantage in comparison to companies that are not required to satisfy the
reporting requirements. Order No. 639 may be altered on appeal, and it is not
known at this time what effect these new rules, as they may be altered, will
have on our business. We currently believe that Order No. 639 and the related
reporting requirements will not have a material adverse effect on our existing
business activities.

Processing.The primary functions of our natural gas processing plants are
the extraction of NGLs and the conditioning of natural gas for marketing. The
FERC has traditionally maintained that a processing plant that primarily
extracts NGLs is not a facility for transportation or sale of natural gas for
resale in interstate commerce and therefore is not subject to its jurisdiction
under the Natural Gas Act. We believe that our natural gas processing plants
are primarily involved in removing NGLs and, therefore, are exempt from FERC
jurisdiction.

Transportation and Sales of Natural Gas Liquids.We have non-operating
interests in two pipelines that transport NGLs in interstate commerce. The
rates, terms and conditions of service on these pipelines are subject to
regulation by the FERC under the Interstate Commerce Act. The Interstate
Commerce Act requires, among other things, that petroleum products (including
NGLs) pipeline rates be just and reasonable and non-discriminatory. The FERC
allows petroleum pipeline rates to be set on at least three bases, including
historic cost, historic cost plus an index or market factors.

Sales of Natural Gas Liquids.Our sales of NGLs are not currently
regulated and are made at market prices. In a number of instances, however, the
ability to transport and sell such NGLs is dependent on liquids pipelines whose
rates, terms and conditions of service are subject to the Interstate Commerce
Act. Although certain regulations implemented by the FERC in recent years could
result in an increase in the cost of transporting NGLs on certain pipelines, we
do not believe that these regulations affect us any differently than other
marketers of NGLs with whom we compete.

U.S. Department of Transportation.Some of our pipelines are subject to
regulation by the DOT with respect to their 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.

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. The most significant of these is the Natural Gas
Pipeline Safety Act, which regulates safety requirements in the design,
construction, operation and maintenance of gas pipeline facilities. In
addition, 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. Our West Doe natural gas
gathering pipeline, which crosses the Alberta/British Columbia border, falls
under the jurisdiction of the National Energy Board of Canada and is 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;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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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, 2002, we had approximately 3,800 employees, which
includes approximately 970 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 which covers approximately 65 of
our employees. We believe our relations with our employees are good.




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 14, 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 the resolution
of 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 2002.

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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. Unless otherwise approved by our board of directors,
we are prohibited from making any distributions except in an amount sufficient
to pay certain tax obligations of our members that arise from their ownership
of member interests.

In August 2000, we issued $300.0 million of preferred members 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. We have the right to defer payments of preferential
distributions on the preferred member interests, other than certain tax
distributions, at any time and from time to time, for up to 10 consecutive
semiannual periods. Deferred preferred distributions will accrue additional
amounts based on the preferential distribution rate (plus 0.5% per annum) to
the date of payment. The preferred member interests, together with all accrued
and unpaid preferential distributions, must be redeemed and paid on the earlier
of the thirtieth anniversary date of issuance or consummation of an initial
public offering of the Companys equity securities. At December 31, 2002 there
were no outstanding preferred distributions.

On September 9, 2002, we redeemed $100.0 million of our preferred members
interest by paying cash to each of our members (Duke Energy and ConocoPhillips)
in proportion to their ownership interests.

18



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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, 2002, 2001 and 2000 and for the periods then ended have been
derived from the audited consolidated financial statements of the Company. The
selected historical combined financial data as of December 31, 1999 and 1998
and for the periods then ended have 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.

|                                                                             |                                             |                          |         |                |           |      |         |           |           |         |          |           |           |   |         |           |           |   |        |         |         | 
|---------------------------------------------------------------------------- | ------------------------------------------- | ------------------------ | ------- | -------------- | --------- | ---- | ------- | --------- | --------- | ------- | -------- | --------- | --------- | - | ------- | --------- | --------- | - | ------ | ------- | ------- | 
|                                                                             |                                             |                          |         | 2002           |           | 2001 |         | 2000(1)   |           | 1999(2) |          | 1998     
|                                                                             |                                             |                          |         |                |           |      |         |           |           |         |          |          
|                                                                             |                                             |                          |         | (In thousands)
|Annual Income Statement
Data:                                                |                                             |                          |         |                |           |      |         |           |           |         |          |           |           |   |         |           |           |   |        |        
|Operating revenues:                                                          |                                             |                          |         |                |           |      |         |           |           |         |          |           |           |   |         |           |           |   |        |        
|                                                                             | Sales of natural gas and
petroleum products |                          | $       | 5,185,728      |           |      | $       | 7,695,080 |           |         | $        | 5,983,473 |           |   | $       | 2,105,961 |           |   | $      | 175,947 |        
|                                                                             | Transportation, storage and
processing      |                          |         | 291,431        |           |      |         | 281,744   |           |         |          | 199,851   |           |   |         | 148,050   |           |   |        | 115,187 |        
|                                                                             | Trading and marketing net
margin            |                          |         | 14,397         |           |      |         | 47,870    |           |         |          | 15,100    |           |   |         | 15,368    |           |   |        | 8,232   |        
|                                                                             |                                             |                          |         |                |           |      |         |           |           |         |          |           |           |   |         |           |           |   |        |        
|                                                                             |                                             | Total operating
revenues |         |                | 5,491,556 |      |         |           | 8,024,694 |         |          |           | 6,198,424 |   |         |           | 2,269,379 |   |        |         | 299,366 | 
|Costs and expenses:                                                          |                                             |                          |         |                |           |      |         |           |           |         |          |           |           |   |         |           |           |   |        |        
|                                                                             | Natural gas and petroleum
products          |                          |         | 4,440,371      |           |      |         | 6,740,894 |           |         |          | 4,980,476 |           |   |         | 1,776,366 |           |   |        | 53,175  |        
|                                                                             | Operating and maintenance                   |                          |         | 449,318        |           |      |         | 373,477   |           |         |          | 331,572   |           |   |         | 181,392   |           |   |        | 113,556 |        
|                                                                             | Depreciation and
amortization               |                          |         | 298,953        |           |      |         | 278,930   |           |         |          | 234,862   |           |   |         | 130,788   |           |   |        | 75,573  |        
|                                                                             | General and administrative                  |                          |         | 167,115        |           |      |         | 129,968   |           |         |          | 171,154   |           |   |         | 73,685    |           |   |        | 44,946  |        
|                                                                             | Asset impairments                           |                          |         | 40,440         |           |      |         |          |           |         |          |          |           |   |         |          |           |   |        |        |        
|                                                                             | Net loss (gain) on sale of
assets           |                          |         | 4,256          |           |      |         | (1,277    | )         |         |          | (10,660   | )         |   |         | 2,377     |           |   |        | (33,759 | )      
|                                                                             |                                             |                          |         |                |           |      |         |           |           |         |          |           |           |   |         |           |           |   |        |        
|                                                                             |                                             | Total costs and
expenses |         |                | 5,400,453 |      |         |           | 7,521,992 |         |          |           | 5,707,404 |   |         |           | 2,164,608 |   |        |         | 253,491 | 
|                                                                             |                                             |                          |         |                |           |      |         |           |           |         |          |           |           |   |         |           |           |   |        |        
|Operating income                                                             |                                             |                          | 91,103  |                |           |      | 502,702 |           |           |         | 491,020  |           |           |   | 104,771 |           |           |   | 45,875 |        
|Equity in earnings of
unconsolidated affiliates                              |                                             |                          | 38,196  |                |           |      | 30,069  |           |           |         | 27,424   |           |           |   | 22,502  |           |           |   | 11,845 |        
|Interest expense                                                             |                                             |                          | 165,841 |                |           |      | 165,670 |           |           |         | 149,220  |           |           |   | 52,915  |           |           |   | 52,403 |        
|                                                                             |                                             |                          |         |                |           |      |         |           |           |         |          |           |           |   |         |           |           |   |        |        
|(Loss) income before income
taxes and cumulative effect of
accounting change |                                             |                          | (36,542 | )              |           |      | 367,101 |           |           |         | 369,224  |           |           |   | 74,358  |           |           |   | 5,317  |        
|Income tax expense (benefit)                                                 |                                             |                          | 10,009  |                |           |      | 2,783   |           |           |         | (310,937 | )         |           |   | 31,029  |           |           |   | 3,289  |        
|                                                                             |                                             |                          |         |                |           |      |         |           |           |         |          |           |           |   |         |           |           |   |        |        
|Net (loss) income before
cumulative effect of
accounting change              |                                             |                          | (46,551 | )              |           |      | 364,318 |           |           |         | 680,161  |           |           |   | 43,329  |           |           |   | 2,028  |        
|                                                                             |                                             |                          |         |                |           |      |         |           |           |         |          |           |           |   |         |           |           |   |        |        
|Cumulative effect of accounting
change                                       |                                             |                          |        |                |           |      | 411     |           |           |         |         |           |           |   |        |           |           |   |       |        
|                                                                             |                                             |                          |         |                |           |      |         |           |           |         |          |           |           |   |         |           |           |   |        |        
|Net (loss) income                                                            |                                             | $                        | (46,551 | )              |           | $    | 363,907 |           |           | $       | 680,161  |           |           | $ | 43,329  |           |           | $ | 2,028  |        
|                                                                             |                                             |                          |         |                |           |      |         |           |           |         |          |           |           |   |         |           |           |   |        |        

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|                                            |  |                                                 |           |      |  |         |           |         |  |      |           |   |  |   |            |   |  |   |           |  
|------------------------------------------- |  | ----------------------------------------------- | --------- | ---- |  | ------- | --------- | ------- |  | ---- | --------- | - |  | - | ---------- | - |  | - | --------- | -
|                                            |  | 2002                                            |           | 2001 |  | 2000(1) |           | 1999(2) |  | 1998
|                                            |  |                                                 |           |      |  |         |           |         |  |     
|                                            |  | (In thousands, except ratios and per unit data)
|Balance Sheet Data (end of
period):         |  |                                                 |           |      |  |         |           |         |  |      |           |   |  |   |            |   |  |   |           |  
|Total assets                                |  | $                                               | 6,580,435 |      |  | $       | 6,630,209 |         |  | $    | 6,527,997 |   |  | $ | 3,482,296  |   |  | $ | 1,770,838 |  
|Long term debt                              |  | $                                               | 2,255,508 |      |  | $       | 2,235,034 |         |  | $    | 1,688,157 |   |  | $ | 101,600    |   |  | $ | 101,600   |  
|Preferred members interest                 |  | $                                               | 200,000   |      |  | $       | 300,000   |         |  | $    | 300,000   |   |  | $ |           |   |  | $ |          |  
|Members equity                             |  | $                                               | 2,450,563 |      |  | $       | 2,653,042 |         |  | $    | 2,420,835 |   |  |   | (8         | ) |  |   | (8        | )
|Cash Flow Data:                             |  |                                                 |           |      |  |         |           |         |  |      |           |   |  |   |            |   |  |   |           |  
|Cash flow from operations                   |  | $                                               | 431,075   |      |  | $       | 450,463   |         |  | $    | 713,072   |   |  | $ | 173,136    |   |  | $ | 40,409    |  
|Cash flow from investing
activities         |  |                                                 | (236,860  | )    |  |         | (538,587  | )       |  |      | (234,848  | ) |  |   | (1,571,446 | ) |  |   | (203,625  | )
|Cash flow from financing
activities         |  |                                                 | (191,617  | )    |  |         | 84,981    |         |  |      | (477,578  | ) |  |   | 1,398,934  |   |  |   | 162,514   |  
|Other Data:                                 |  |                                                 |           |      |  |         |           |         |  |      |           |   |  |   |            |   |  |   |           |  
|Acquisitions and other capital
expenditures |  | $                                               | 301,631   |      |  | $       | 597,370   |         |  | $    | 371,063   |   |  | $ | 1,570,083  |   |  | $ | 185,479   |  
|EBITDA(3)                                   |  | $                                               | 428,252   |      |  | $       | 811,701   |         |  | $    | 753,306   |   |  | $ | 258,061    |   |  | $ | 133,293   |  
|Ratio of EBITDA to interest
expense(4)      |  |                                                 | 2.58      |      |  |         | 4.90      |         |  |      | 5.05      |   |  |   | 4.88       |   |  |   | 2.54      |  
|Ratio of earnings to fixed
charges(5)       |  |                                                 | 0.85      |      |  |         | 3.17      |         |  |      | 3.43      |   |  |   | 2.33       |   |  |   | 1.07      |  
|Gas transported and/or processed
(TBtu/d)   |  |                                                 | 8.3       |      |  |         | 8.6       |         |  |      | 7.6       |   |  |   | 5.1        |   |  |   | 3.6       |  
|NGLs production (MBbl/d)                    |  |                                                 | 392       |      |  |         | 397       |         |  |      | 359       |   |  |   | 192        |   |  |   | 110       |  
|Market Data:                                |  |                                                 |           |      |  |         |           |         |  |      |           |   |  |   |            |   |  |   |           |  
|Average NGLs price per
gallon(6)            |  | $                                               | .38       |      |  | $       | .45       |         |  | $    | .53       |   |  | $ | .34        |   |  | $ | .26       |  
|Average natural gas price per
MMBtu(7)      |  | $                                               | 3.22      |      |  | $       | 4.27      |         |  | $    | 3.89      |   |  | $ | 2.27       |   |  | $ | 2.11      |  



---

|(1) |  | 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|   
|(3) |  | EBITDA consists of income from continuing operations before interest
expense, income tax expense, and depreciation and amortization expense.
EBITDA is not a measurement presented in accordance with generally
accepted accounting principles. You should not consider this measure in
isolation from or as a substitute for net income or cash flow measures
prepared in accordance with generally accepted accounting principles or as
a measure of our profitability or liquidity. EBITDA is included as a
supplemental disclosure because it may provide useful information
regarding our ability to service debt and to fund capital expenditures.
However, not all EBITDA may be available to service debt. This measure may
not be comparable to similarly titled measures reported by other
companies.
|   
|(4) |  | The ratio of EBITDA to interest expense represents a ratio that provides
an investor with information as to our companys current ability to meet
our financing costs.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|   
|(5) |  | The ratios of earnings to fixed charges are computed utilizing the
Securities and Exchange Commission (SEC) guidelines. As a result of
losses, earnings were insufficient to cover fixed charges by $25.6 million
for the year ended December 31, 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|   
|(6) |  | 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|   
|(7) |  | Based on the NYMEX Henry Hub prices for the periods indicated.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|   
|(8) |  | Not applicable due to change in corporate structure as of March 31, 2000.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      

20



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##### Table of Contents






ITEM 7. Managements Discussion and Analysis of Financial Condition and Results of Operations.

Duke Energy Field Services, LLC holds the combined North American
midstream natural gas gathering, processing, marketing and NGL business of Duke
Energy and ConocoPhillips that existed at the time of the Combination.

On March 31, 2000, we combined the gas gathering, processing, marketing
and NGLs businesses of Duke Energy and ConocoPhillips. In connection with the
Combination, Duke Energy and ConocoPhillips transferred all of their then
existing respective interests in their subsidiaries that conducted their
midstream natural gas business 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. Concurrently with the Combination, we obtained by
transfer from Duke Energy the general partner of TEPPCO. In exchange for the
asset contribution, ConocoPhillips received 30.3% of the member interests in
our company, with Duke Energy holding the remaining 69.7% of the outstanding
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. This debt was subsequently refinanced through
the issuance of unsecured senior debt securities. See Liquidity and Capital
Resources.

The Combination was accounted for as a purchase business combination in
accordance with Accounting Principles Board Opinion (APB) No. 16, Accounting
for Business Combinations. The Predecessor Company was the acquirer of
ConocoPhillips midstream natural gas business in the Combination.

The following discussion details the material factors that affected our
historical financial condition and results of operations in 2002, 2001 and
2000. This discussion should be read in conjunction with Item 1. Business,
and the consolidated financial statements with the related notes, included
elsewhere in this Form 10-K.

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.

Unless the context otherwise requires, the discussion of our business
contained in this section for periods ending on or prior to March 31, 2000
relates solely to the Predecessor Company on a historical basis and does not
give effect to the Combination, the transfer to our company of additional
midstream natural gas assets acquired by Duke Energy or ConocoPhillips prior to
consummation of the Combination or the transfer to our company of the general
partner of TEPPCO from Duke Energy.

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
2002, approximately 80% of the Companys operating revenues prior to
intersegment revenue elimination and approximately 95% 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 2002, approximately 20% of the Companys operating
revenues prior to intersegment revenue elimination and approximately 5%
of the Companys gross margin were derived from this segment.                                                                       

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.

21



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##### Table of Contents



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 contract 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.

During the three years ended December 31, 2002, approximately 75% of our
gross margin was generated by commodity sensitive arrangements and
approximately 25% of our gross margin was generated by fee-based arrangements.
The commodity exposure is actively 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 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, this relationship strengthened moving back toward
historical trends.

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. The average
number of active rigs drilling in North America declined to 1,204 at December
31, 2002 from 1,282 at December 31, 2001. Recent significant increases in
natural gas prices could result in increased drilling activity in 2003.
However, energy market uncertainty could negatively impact North American
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 the value of our assets and
operations from such price risks. See Item 7A. Quantitative and Qualitative
Disclosures About Market Risk. Our 2002 and 2001 results of operations include
a hedging loss of $27.1 million and a gain of $6.0 million, respectively.

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 type of
contracts permit us and the producers to share proportionately in price
changes. Under these contracts, we share in both the increases and
decreases in natural gas prices and NGL prices. During 2002
approximately 55% of our gross margin 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 2002, approximately 25% of our gross margin from the
Natural Gas Segment was generated from fee-based contracts including our
general partnership interest in TEPPCO.                                                                                                                                                 

22



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##### Table of Contents





| |  |  | 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 2002, approximately 10% of our
gross margin from the Natural Gas Segment was generated from wellhead
and keep-whole contracts.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | In addition, during 2002 approximately 10% of the gross margin 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, dividends and capital expenditures. The primary goals
of our hedging program include maintaining minimum cash flows to fund debt
service, dividends, production replacement and maintenance capital projects;
avoiding disruption of our growth capital and value creation process; and
retaining a high percentage of potential upside relating to price increases of
NGLs.

Accounting Adjustments

The Company has completed a comprehensive account reconciliation project
to review and analyze its balance sheet accounts. As a result of this account
reconciliation project, the Company recorded approximately $53.0 million of
adjustments that may be related to corrections of accounting errors in prior
periods. The $53.0 million reduced Gross Margin, as defined under Results of
Operations below, by $32.8 million, increased costs and expenses by $16.0
million, increased depreciation by $2.3 million, increased other costs and
expenses by $4.1 million and reduced interest expense by $2.2 million. Numerous
items identified in the account reconciliation project resulted from system
conversions and otherwise unsupportable balance sheet amounts. Due to the
nature of certain 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 the Companys financial
statements.

See Note 19 to the Consolidated Financial Statements included elsewhere in
this Form 10-K and Item 14. Controls and Procedures.

Other Factors That Have Significantly Affected Our Results

Our results of operations are impacted by increases and decreases in the
volume of raw natural gas that we handle through our system, 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.

Risk management activities have also affected our results of operations.
Our 2002, 2001 and 2000 results of operations include a hedging loss of $27.1
million, a gain of $6.0 million, and a loss of $127.7 million respectively. See
Item 7A. Quantitative and Qualitative Disclosure About Market Risk.

23



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##### Table of Contents



Results of Operations

The following is a discussion of our historical results of operations. The
discussion for periods ending on or prior to the Combination on March 31, 2000
relates solely to the Predecessor Company and does not give effect to the
Combination, the transfer to our company of additional midstream natural gas
assets acquired by Duke Energy or ConocoPhillips prior to consummation of the
Combination or the transfer to our company of the general partner of TEPPCO
from Duke Energy.

|                                                                        |                                                 |                          |           |                |           |      |           |           |           |   |           |           |           | 
|----------------------------------------------------------------------- | ----------------------------------------------- | ------------------------ | --------- | -------------- | --------- | ---- | --------- | --------- | --------- | - | --------- | --------- | --------- | 
|                                                                        |                                                 |                          |           | 2002           |           | 2001 |           | 2000     
|                                                                        |                                                 |                          |           |                |           |      |           |          
|                                                                        |                                                 |                          |           | (In thousands)
|Operating revenues:                                                     |                                                 |                          |           |                |           |      |           |           |           |   |           |          
|                                                                        | Sales of natural gas and petroleum products     |                          | $         | 5,185,728      |           |      | $         | 7,695,080 |           |   | $         | 5,983,473 |          
|                                                                        | Transportation, storage and processing          |                          |           | 291,431        |           |      |           | 281,744   |           |   |           | 199,851   |          
|                                                                        | Trading and marketing net margin                |                          |           | 14,397         |           |      |           | 47,870    |           |   |           | 15,100    |          
|                                                                        |                                                 |                          |           |                |           |      |           |           |           |   |           |          
|                                                                        |                                                 | Total operating revenues |           |                | 5,491,556 |      |           |           | 8,024,694 |   |           |           | 6,198,424 | 
|                                                                        | Purchases of natural gas and petroleum products |                          |           | 4,440,371      |           |      |           | 6,740,894 |           |   |           | 4,980,476 |          
|                                                                        |                                                 |                          |           |                |           |      |           |           |           |   |           |          
|Gross margin                                                            |                                                 |                          | 1,051,185 |                |           |      | 1,283,800 |           |           |   | 1,217,948 |          
|Equity earnings of unconsolidated affiliates                            |                                                 |                          | 38,196    |                |           |      | 30,069    |           |           |   | 27,424    |          
|                                                                        |                                                 |                          |           |                |           |      |           |           |           |   |           |          
|Total gross margin and equity earnings of
unconsolidated affiliates (1) |                                                 | $                        | 1,089,381 |                |           | $    | 1,313,869 |           |           | $ | 1,245,372 |          
|                                                                        |                                                 |                          |           |                |           |      |           |           |           |   |           |          



---

|(1) |  | Gross margin and equity in earnings (Gross Margin) consists of income
from continuing operations before operating and general and administrative
expense, interest expense, income tax expense, and depreciation and
amortization expense. Gross margin as defined is not a measurement
presented in accordance with generally accepted accounting principles. You
should not consider this measure in isolation from or as a substitute for
net income or cash flow measures prepared in accordance with generally
accepted accounting principles or as an isolated measure of our
profitability or liquidity. Gross margin is included as a supplemental
disclosure because it may provide useful information regarding the impact
of key drivers such as commodity prices and supply contract mix on the
Companys earnings.
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

2002 compared with 2001

Gross Margin.Gross Margin decreased $224.5 million, or 17% to $1,089.4
million from $1,313.9 million in 2001. This decrease was primarily the result
of lower NGL prices of approximately $199.0 million (including hedging) due to
a $.07 per gallon decrease in average NGL prices and volume declines. These
decreases were partially offset by approximately $44.0 million due to a $1.05
per million Btu decrease in natural gas prices. Average prices for 2002 were
$.38 per gallon for NGLs and $3.22 per million Btu for natural gas,
respectively, as compared with $.45 per gallon and $4.27 per million Btu during
2001. NGL and natural gas trading contributed another $8.7 million, and $24.8
million to the Gross Margin decrease, respectively. Natural gas trading
includes derivative settlements associated with our trading and marketing
efforts around our natural gas intrastate pipelines and storage.

Gross Margin was also negatively impacted in 2002 by a $25 million
provision ($12 million relating to prior periods) recorded as a result of the
Companys completion of its 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, and unrecorded liabilities related to imbalances and incorrectly
valued imbalances. Gross Margin was further reduced by $23 million of charges
recorded in 2002 related to completion of the Companys account reconciliation
project, including a $6 million writedown for storage inventory. See
Accounting Adjustments above.

Gross Margin associated with the Natural Gas Segment decreased $232.3
million, or 19%, to $996.0 million in 2002 from $1,228.3 million in 2001,
primarily as a result of lower NGL prices. Commodity sensitive processing
arrangements accounted for approximately $154.0 million (net of hedging) of
this decrease mainly due to the $.07 per gallon decrease in average NGL prices,
partially offset by a $1.05 per million Btu decrease in natural gas prices.
This reduction was the result of the interaction of our gas supply
arrangements. Natural gas trading and natural gas trading and marketing
associated with our natural gas intrastate pipeline and storage assets
contributed approximately $24 million to this decrease. Gross Margin
associated with this segment was also negatively affected by the charges
related to reserves for gas imbalances with suppliers and customers, a
writedown of storage inventory and charges related to completion of the
Companys account reconciliation project.

Gross Margin associated with the NGLs Segment decreased $.4 million, or 1%
to $55.1 million during 2002 from $55.5 million in 2001. Decreases in NGL
trading margins during 2002 were offset by the 2001 acquisition of northeast
propane terminal and marketing assets.

24



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##### Table of Contents



NGL production during 2002 decreased 5,300 barrels per day, or 1%, to
391,900 barrels per day from 397,200 barrels per day during 2001, and natural
gas transported and/or processed during 2002 decreased .3 trillion Btus per
day, or 3%, to 8.3 trillion Btus per day from 8.6 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 $75.8
million, or 20%, to $449.3 million in 2002 from $373.5 million in 2001. This
increase was primarily the result of the full year impact of acquisitions for
approximately $20 million, accrual increases of $14.0 million due to higher
spending levels, and increased maintenance, equipment overhauls, cost of labor
and pipeline integrity projects. Included in the $14.0 million is $11 million
of accounting adjustments (see Accounting Adjustments above). General and
administrative expenses increased $37.1 million, or 29%, to $167.1 million in
2002 from $130.0 million in 2001. The primary causes of this increase were $11
million for core business process improvements, increased allocated costs from
Duke Energy due to increased service levels, expanded business activity
resulting from acquisitions and outside services for accounting and technology
projects and accounting adjustments of $5 million (see Accounting Adjustments
above).

Depreciation and amortization increased $42.1 million (excluding $22.0
million of goodwill amortization in 2001), or 16%, to $299.0 million in 2002
from $256.9 million in 2001. This increase was due primarily to acquisitions,
ongoing capital expenditures for well connections and facility maintenance and
enhancements.

Asset impairments were $40.4 million in 2002 compared to none in 2001. The
impairment was related to certain assets located in Eastern Oklahoma, Offshore
Gulf of Mexico, Northern Louisiana and Alabama and writeoff of a leasehold
interest. As part of the Companys periodic asset performance evaluations, it
was 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, the Company 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, 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 $40.4 million for 2002 relating to the Natural Gas
Segment.

Other costs and expenses increased to a loss of $4.3 million in 2002 from
a gain of $1.3 million in 2001. The primary reason for the increase was the
loss on sale of assets associated with a partnership investment of $5.2
million. This amount relates to accounting corrections (see Accounting
Adjustments above).

Interest.Interest expense increased $0.1 million, or less than 1%, to
$165.8 million in 2002 from $165.7 million in 2001. This increase was primarily
the result of slightly higher debt levels, offset by lower interest rates and
capitalized interest adjustments (see Accounting Adjustments above).

Income Taxes.The Company is a limited liability company, which is a
pass-through entity for U.S. income tax purposes. Income tax expense
represents federal, state and foreign taxes associated with tax-paying
subsidiaries. Income tax expense increased $7.2 million to $10.0 million in
2002 from $2.8 million in 2001 due primarily to increased earnings associated
with tax-paying subsidiaries obtained through acquisitions in 2001 and prior.

Net (Loss) Income.Net (loss) income decreased $410.5 million to a loss of
($46.6) million in 2002 from income of $363.9 million in 2001. This decrease
was partly the result of decreased NGL prices and increases in operating and
maintenance, and general and administrative expenses, partially offset by lower
natural gas prices and acquisition activity. Net income was also negatively
affected by charges related to asset impairments, reserves for imbalances,
storage inventory write-offs, loss on asset sale, charges related to completion
of the Companys account reconciliation project and increases in our accrual
for unrecorded liabilities.

2001 compared with 2000

Gross Margin.Gross Margin increased $68.5 million, or 6% to $1,313.9
million in 2001 from $1,245.4 million in 2000. Of this increase, approximately
$183.0 million was related to the addition of the ConocoPhillips midstream
natural gas business to our operations in the Combination on March 31, 2000.
Additional increases of approximately $28.0 million were attributable to the
combination of our acquisition of Canadian midstream facilities, Texas
intrastate pipelines, northeast propane terminal and marketing assets, and the
acquisition of the general partnership interest in TEPPCO. These increases were
offset by approximately $130.0 million (net of hedging) due to an $.08 per
gallon decrease in average NGL prices, and approximately $12.0 million due to a
$.38 per

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million Btu increase in natural gas prices. Average prices for 2001 were
$.45 per gallon for NGLs and $4.27 per million Btus for natural gas,
respectively, as compared with $.53 per gallon and $3.89 per million Btus
during 2000. NGL trading contributed another $13.9 million to the Gross Margin
increase.

Gross Margin associated with the Natural Gas Segment increased $59.0
million, or 5%, to $1,228.3 million in 2001 from $1,169.3 million in 2000,
mainly as a result of the Combination. Commodity sensitive processing
arrangements offset this increase by approximately $130.0 million (net of
hedging) due to the $.08 per gallon decrease in average NGL prices. This
reduction was the result of the interaction of commodity prices and our gas
supply arrangements.

Gross Margin associated with the NGL Segment increased $6.9 million to
$55.5 million in 2001 from $48.6 million in 2000. This increase was primarily
the result of NGL trading, the acquisition of northeast propane terminal and
marketing assets, offset by the sale of an East Texas NGL pipeline.

NGL production during 2001 increased 38,700 barrels per day, or 11%, to
397,200 barrels per day from 358,500 barrels per day in 2000, and natural gas
transported and/or processed during 2001 increased 1.0 trillion Btus per day,
or 13%, to 8.6 trillion Btus per day from 7.6 trillion Btus per day during
2000. The primary cause of the increase in NGL production was the addition of
the ConocoPhillips midstream natural gas business in the Combination partially
offset by reduced recoveries at certain facilities resulting from tightened
fractionation spreads driven by high natural gas prices experienced during the
first two quarters and low NGL prices experienced during the fourth quarter of
2001.

Costs and Expenses.Operating and maintenance expenses increased $41.9
million, or 13%, to $373.5 million in 2001 from $331.6 million in 2000. Of this
increase, approximately $35.6 million was related to the addition of the
ConocoPhillips midstream natural gas business in the Combination. The
remainder was primarily the result of acquisitions partially offset by plant
consolidation and cost reduction efforts. General and administrative expenses
decreased $41.2 million, or 24%, to $130.0 million in 2001 from $171.2 million
in 2000. This decrease was primarily the result of decreased allocated overhead
from our parents, decreased incentive compensation accruals and focused cost
reduction efforts partially offset by the addition of the ConocoPhillips
midstream natural gas business in the Combination.

Depreciation and amortization increased $44.0 million, or 19%, to $278.9
million in 2001 from $234.9 million in 2000. Of this increase, $21.8 million
was due to the addition of the ConocoPhillips midstream natural gas business
in the Combination. The remainder was due to acquisitions, ongoing capital
expenditures for well connections and facility maintenance and enhancements.

Interest.Interest expense increased $16.5 million, or 11%, to $165.7
million in 2001 from $149.2 million in 2000. This increase was primarily the
result of higher outstanding debt levels, partially offset by lower interest
rates.

Income Taxes.The Company is a limited liability company, which is a
pass-through entity for U.S. income tax purposes. As a result of the March 31,
2000 Predecessor Company conversion to a limited liability company,
substantially all of the Predecessor Companys existing net deferred tax
liability ($327.0 million) was eliminated and a corresponding income tax
benefit was recorded. The 2001 income tax expense of $2.8 million is mainly the
result of foreign and other miscellaneous taxes.

Net Income.Net income decreased $316.3 million to $363.9 million in 2001
from $680.2 million in 2000. This decrease was largely the result of the tax
benefit recognition discussed above, offset by the addition of the
ConocoPhillips midstream natural gas business in the Combination and cost
reduction efforts. Lower NGL prices and higher gas prices also contributed to
this decrease.

Environmental Considerations

We have various ongoing remedial matters related to historical operations
similar to others in the industry, 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 are 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 and as capital expenses. For each of 2003 and 2004, we
estimate that our aggregate expensed and capital-related environmental costs
will be approximately $29 million.

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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 various 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 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, 2002, 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 EITF Issue 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 will change which accounting model is used for certain of our
transactions, the overall application of the model remains the same. See Note 2
to the Consolidated Financial Statements for further discussion of EITF Issue
02-03 and its expected impact on our 2003 financial position and results of
operations.

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. Through
December 31, 2002, we applied MTM accounting to our derivatives, unless subject
to hedge accounting or the normal purchase and normal sale exemption (as
described below), and energy trading contracts, as defined by EITF Issue 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities.

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 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 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 and 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 area. 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 sale exemption in
accordance with SFAS No. 133. 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 is 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 is used when we hold firm
commitments or asset 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 locational
differences that exist in the

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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, as provided in SFAS No. 133 and
interpreted by Derivative Implementation Group Issue C15, indicates that no
recognition of the contracts fair value in the consolidated financial
statements is required until settlement of the contract (in the Companys case,
the purchase or delivery of natural gas or NGLs). The Company has applied this
exemption for contracts involving the purchase or sale of natural gas or NGLs
in future periods.

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 is provided. For gathering services, the Company
receives fees from the producers to bring 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
British thermal unit (Btu) content of the gas back to the producer. The
Company also receives fees for further fractionation of the NGLs produced, for
transportation and storage of NGLs and residue gas. In addition, the Company
recognizes revenue for its NGL and residue gas marketing activities. Revenue
for goods and services provided but not billed is estimated each month based on
estimated commodity prices, preliminary throughput measurements and contract
data.

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 measure. 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. If negative market
conditions persist over time and estimated cash flows over the lives of our
assets do not exceed the carrying value of those individual assets, asset
impairments may occur in the future under existing accounting rules.
Furthermore, a change in managements intent about the use of individual assets
could also impact an impairment analysis. At this time, management has not
determined any asset impairments for 2003 and beyond. At December 31, 2002, we
had property, plant and equipment of $4,642 million.

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Liquidity and Capital Resources

Operating Cash Flows

During 2002, funds of $431.1 million were provided by operating
activities, a decrease of $19.4 million from $450.5 million during 2001. This
decrease was due primarily to a $410.5 million decrease in net income,
partially offset by changes in working capital balances, unrealized
mark-to-market and hedging activity, and non-cash charges, including asset
impairments. The decrease in net income is due largely to lower NGLs prices
and increased operating expenses and general and administrative expenses.

Price volatility in crude oil, NGLs and natural gas prices have a direct
impact on our generation of cash from operations.

Investing Cash Flows

During 2002, funds of $236.9 million were used in investing activities, a
decrease of $301.7 million from $538.6 million in 2001. 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, 2002, we spent
approximately $301.6 million on capital expenditures compared to $597.4 million
in 2001.

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 and borrowings
available under our commercial paper program, our credit facilities or other
available sources of financing.

Investments in unconsolidated affiliates provided $53.9 million in cash
distributions to us during 2002.

Financing Cash Flows

Bank Financing and Commercial Paper

In March 2002, we entered into a $650 million credit facility (the
Facility), of which $150.0 million can be used for letters of credit. The
Facility is used to support our commercial paper program and for working
capital and other general corporate purposes. The Facility matures on March 28,
2003, however, any outstanding loans under the Facility at maturity may, at our
option, be converted to a one-year term loan. The Facility requires us to
maintain at all times a debt to total capitalization ratio of less than or
equal to 53%. The Company entered into an amendment to the Facility on November
13, 2002. The Facility, as amended, bears interest at a rate equal to, at our
option, either (1) LIBOR plus 1.25% per year or (2) the higher of (a) the Bank
of America prime rate and (b) the Federal Funds rate plus 0.50% per year. At
December 31, 2002, there were no borrowings or letters of credit outstanding
against the Facility. We plan to replace the existing facility with a new $350
million credit facility (the New Facility). We expect to close on the New
Facility on March 28, 2003. The New Facility is expected to have similar terms
as the Facility being replaced, except it is likely to include an interest
coverage ratio and a new restriction on dividends to our members. In addition,
we plan to put into place a $100 million funded short-term facility (the
Funded Facility) with a six month term. The Funded Facility is expected to
have similar terms as the New Facility and is expected to close on or before
March 28, 2003.

At December 31, 2002, we had $215.1 million in outstanding commercial
paper, with maturities ranging from three to 30 days and annual interest rates
ranging from 1.83% to 1.90%. At no time did the amount of our outstanding
commercial paper exceed the available amount under the Facility. 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.

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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 and the expected New Facility and Funded
Facility, 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. On September 9, 2002, we redeemed $100.0 million
of our preferred members interest by paying cash to each member (Duke Energy
and ConocoPhillips) in proportion to their ownership interests. The outstanding
preferred member interests are entitled to cumulative preferential
distributions of 9.5% per annum payable, unless deferred, semiannually. We have
the right to defer payments of preferential distributions on the preferred
member interests, other than certain tax distributions, at any time and from
time to time, for up to 10 consecutive semiannual periods. Deferred preferred
distributions will accrue additional amounts based on the preferential
distribution rate (plus 0.5% per annum) to the date of payment. At December 31,
2002 there were no outstanding deferred distributions. The preferred member
interests, together with all accrued and unpaid preferential distributions,
must be redeemed and paid on the earlier of the thirtieth anniversary date of
issuance or consummation of an initial public offering of equity securities.
For the years ending December 31, 2002 and 2001, we paid preferential
distributions of $25.5 million and $28.5 million, respectively.

Debt Securities

During 2000 and 2001, we issued the following series of unsecured senior
debt securities:

|                 |  |           |         |          |  |          |       |   |  |                   |  | 
|---------------- |  | --------- | ------- | -------- |  | -------- | ----- | - |  | ----------------- |  | 
|Issue            |  | Principal |         | Interest |  |          |       |  
|Date             |  | ($000s)   |         | Rate     |  | Due Date
|                 |  |           |         |          |  |         
|August 16, 2000  |  | $         | 600,000 |          |  |          | 7 1/2 | % |  | August 16, 2005  
|August 16, 2000  |  | $         | 800,000 |          |  |          | 7 7/8 | % |  | August 16, 2010  
|August 16, 2000  |  | $         | 300,000 |          |  |          | 8 1/8 | % |  | August 16, 2030  
|February 2, 2001 |  | $         | 250,000 |          |  |          | 6 7/8 | % |  | February 1, 2011 
|November 9, 2001 |  | $         | 300,000 |          |  |          | 5 3/4 | % |  | November 15, 2006

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. The proceeds from the issuance of debt securities were used to repay a
portion of our outstanding commercial paper.

In October 2001, the Company entered into an interest rate swap to convert
the fixed interest rate on $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 6-month LIBOR rates, which is re-priced semiannually
through 2005. The terms of the swap match the associated debt which permits the
assumption of no ineffectiveness, as defined by Statement of Financial
Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments
and Hedging Activities. As such, for the life of the swap no ineffectiveness
will be recognized. As of December 31, 2002, the fair value of the interest
rate swap of $14.3 million 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, 2002,
there were no distributions payable based on taxable income allocated to the
members.

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Contractual Obligations and Commercial Commitments

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 on 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, 2002, we were the guarantor of approximately $100.5
million of debt associated with unconsolidated subsidiaries, of which $84.5
million is related to our 33.3% ownership interest in Discovery Producer
Services, LLC. These guarantees expire December 31, 2003. The debt related to
Discovery Producer Services, LLC is due December 31, 2003, and is expected to
be refinanced. In the event that the unconsolidated subsidiaries default on the
debt payments, we would be required to pay the debt. Assets of the
unconsolidated subsidiaries are pledged as collateral for the debt. At
December 31, 2002, we had no liability recorded for the guarantees of the debt
associated with the unconsolidated subsidiaries.

At December 31, 2002, 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, 2002, we had no liability recorded for these outstanding
indemnification agreements.




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  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 and options for non-trading activity (primarily hedge
strategies). (See Notes 2 and 12 to the Consolidated Financial Statements.)

Commodity
Derivatives  Trading  The risk in the commodity trading
portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk
model to determine the potential one-day favorable or unfavorable Daily
Earnings at Risk (DER) as described below. DER is monitored daily in
comparison to established thresholds. Other measures are also used to limit and
monitor the risk in the commodity trading portfolio (which includes all trading
contracts 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.

DER computations are based on a historical simulation, which uses price
movements over a specified period (generally ranging from seven to 14 days) to
simulate forward price curves in the energy markets to estimate the potential
favorable or unfavorable impact of one days price movement on the existing
portfolio. The historical simulation emphasizes the most recent market
activity, which is considered the most relevant predictor of immediate future
market movements for crude oil, NGLs, gas and other energy-

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related products. DER 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 DER amounts for commodity
derivatives instruments held for trading purposes are shown in the following
table.

Daily Earnings at Risk (in thousands)

|               |  |                   |       |                   |  |                     |       |                    |  |   |       |  |  |   |     | 
|-------------- |  | ----------------- | ----- | ----------------- |  | ------------------- | ----- | ------------------ |  | - | ----- |  |  | - | --- | 
|               |  | Estimated Average |       | Estimated Average |  |                     |       |                    |  |   |       | 
|               |  | One-Day Impact on |       | One-Day Impact on |  | High One-Day Impact |       | Low One-Day Impact
|               |  | EBIT for 2002     |       | EBIT for 2001     |  | on EBIT for 2002    |       | on EBIT for 2002  
|               |  |                   |       |                   |  |                     |       |                   
|Calculated DER |  | $                 | 2,102 |                   |  | $                   | 1,630 |                    |  | $ | 4,840 |  |  | $ | 441 | 

DER is an estimate based on historical price volatility. Actual volatility
can exceed predicted results. DER also assumes a normal distribution of price
changes, thus if the actual distribution is not normal, the DER may understate
or overstate actual results. DER is used to estimate the risk of the entire
portfolio, and for locations that do not have daily trading activity, it may
not accurately estimate risk due to limited price information. Stress tests may
be employed in addition to DER to measure risk where market data information is
limited. In the current DER methodology, options are modeled in a manner
equivalent to forward contracts which may understate the risk.

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. The following table illustrates the
movements in the fair value of our trading instruments during 2002.

Changes in Fair Value of Trading Contracts (in thousands)

|                                                                 |  |   |          |  
|---------------------------------------------------------------- |  | - | -------- | -
|Fair value of contracts outstanding at the beginning of the year |  | $ | 33,242   |  
|Contracts realized or otherwise settled during the year          |  |   | (67,516  | )
|Net premiums received for new option contracts during the year   |  |   | (4,919   | )
|Net mark-to-market changes in fair values                        |  |   | 11,206   |  
|                                                                 |  |   |          |  
|Fair value of contracts outstanding at the end of the year       |  |   | ($27,987 | )
|                                                                 |  |   |          |  

The fair value of these contracts is expected to be realized in future
periods, as detailed in the following table. The amount of cash ultimately
realized for these contracts will differ from the amounts shown in the
following table due to factors such as market volatility, counterparty default
and other unforeseen events that could impact the amount and/or realization of
these values. At December 31, 2002, we held cash or letters of credit of $33.7
million to secure such future performance, and had $9.3 million deposited with
counterparties.

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 and
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.

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The following table shows the fair value of our trading portfolio as of
December 31, 2002.

|                                                                    |       |                  |                                                                |                  |   |                  |       |                |  |                  |      |     |   |   |                  |    |   |   |         |         |  
|------------------------------------------------------------------- | ----- | ---------------- | -------------------------------------------------------------- | ---------------- | - | ---------------- | ----- | -------------- |  | ---------------- | ---- | --- | - | - | ---------------- | -- | - | - | ------- | ------- | -
|                                                                    |       |                  | Fair Value of Contracts as of December 31, 2002 (in thousands)
|                                                                    |       |                  |                                                               
|                                                                    |       |                  |                                                                |                  |   |                  |       |                |  |                  |      |     |   |   | Maturity in 2006 |    |   |   |        
|Sources of Fair Value                                               |       | Maturity in 2003 |                                                                | Maturity in 2004 |   | Maturity in 2005 |       | and Thereafter |  | Total Fair Value
|                                                                    |       |                  |                                                                |                  |   |                  |       |                |  |                 
|Prices supported by
quoted market prices
and other external
sources |       | $                | (23,700                                                        | )                |   | $                | 1,052 |                |  | $                | 331  |     |   | $ |                 |    |   | $ | (22,317 | )      
|Prices based on
models
and other valuation
methods                  |       |                  | (5,791                                                         | )                |   |                  | 513   |                |  |                  | (384 | )   |   |   | (8               | )  |   |   | (5,670  | )      
|                                                                    |       |                  |                                                                |                  |   |                  |       |                |  |                  |      |     |   |   |                  |    |   |   |         |        
|                                                                    | Total |                  | $                                                              | (29,491          | ) |                  | $     | 1,565          |  |                  | $    | (53 | ) |   | $                | (8 | ) |   | $       | (27,987 | )
|                                                                    |       |                  |                                                                |                  |   |                  |       |                |  |                  |      |     |   |   |                  |    |   |   |         |        

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, (ii) the
value of transactions for which an internally developed price curve was
constructed as a result of the long dated nature of the transaction or the
illiquidity of the market point, and (iii) the value of structured
transactions. 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 have 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, 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. In
accordance with SFAS No. 133, our primary use of commodity derivatives is to
hedge the output and production of assets we physically own. Contract terms are
up to three years, however, since these contracts are designated and qualify as
effective hedge positions of future cash flows, or fair values of assets owned
by us, to the extent that the hedge relationships are effective, their market
value change impacts are not recognized in current earnings. The unrealized
gains or losses on these contracts are deferred in Other Comprehensive (Loss)
Income (OCI) 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, in accordance with SFAS No. 133. Amounts deferred in OCI
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 OCI through the date of de-designation remain
in OCI until the underlying transaction actually occurs. The derivative
contract (if continued as an open position) will be marked to market currently
through earnings. Several factors influence the effectiveness of a hedge
contract, including counterparty credit risk 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. Contracts with terms extending several years are
generally valued using models and assumptions developed internally or by
industry standards. However, as mentioned previously, the effective portion of
the gains and losses for these contracts are not recognized in earnings until

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settlement at their then 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.

|                                                     |       |                  |                                                                |                  |   |                  |       |                |  |                  |       |       |  |   |                  |   |  |   |         |         |  
|---------------------------------------------------- | ----- | ---------------- | -------------------------------------------------------------- | ---------------- | - | ---------------- | ----- | -------------- |  | ---------------- | ----- | ----- |  | - | ---------------- | - |  | - | ------- | ------- | -
|                                                     |       |                  | Fair Value of Contracts as of December 31, 2002 (in thousands)
|                                                     |       |                  |                                                               
|                                                     |       |                  |                                                                |                  |   |                  |       |                |  |                  |       |       |  |   | Maturity in 2006 |   |  |   |        
|Sources of Fair Value                                |       | Maturity in 2003 |                                                                | Maturity in 2004 |   | Maturity in 2005 |       | and Thereafter |  | Total Fair Value
|                                                     |       |                  |                                                                |                  |   |                  |       |                |  |                 
|Quoted market prices                                 |       | $                | (56,794                                                        | )                |   | $                | 2,767 |                |  | $                | 2,079 |       |  | $ |                 |   |  | $ | (51,948 | )      
|Prices based on
models or other
valuation techniques |       |                  | (292                                                           | )                |   |                  |      |                |  |                  |      |       |  |   |                 |   |  |   | (292    | )      
|                                                     |       |                  |                                                                |                  |   |                  |       |                |  |                  |       |       |  |   |                  |   |  |   |         |        
|                                                     | Total |                  | $                                                              | (57,086          | ) |                  | $     | 2,767          |  |                  | $     | 2,079 |  |   | $                |  |  |   | $       | (52,240 | )
|                                                     |       |                  |                                                                |                  |   |                  |       |                |  |                  |       |       |  |   |                  |   |  |   |         |        

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 $.01 per gallon in the price of NGLs and $.10 per million Btus in
the average price of natural gas would result in changes in annual pre-tax net
income of approximately $(25) million and $5 million, respectively.

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 are 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
Chevron Phillips Chemical LLC, under an existing 15-year contract which expires
in 2014. 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.

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, 2002, we had cash or letters of credit of
$33.7 million to secure future performance by counterparties, and had deposited
with counterparties $9.3 million of such collateral to secure our obligations
to provide future services. 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.

Generally speaking, all physical and financial derivative contracts are
settled in cash at the expiration of the contract term.

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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
new debt issuances. Our 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 averages. As of
December 31, 2002, the fair value of our interest rate swap was an asset of
$14.3 million. (See Notes 2 and 12 to the Consolidated Financial Statements.)

As of December 31, 2002, we had approximately $215.1 million outstanding
under a commercial paper program. As a result, 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 .5% in interest rates would result in an increase in annual
interest expense of approximately $2.3 million.

Foreign Currency Risk

Our primary foreign currency exchange rate exposure at December 31, 2002
was the Canadian dollar. Foreign currency risk associated with this exposure
was not material.

Accounting Pronouncements

In January 2003, the FASB issued Interpretation No. 46 (FIN 46),
Consolidation of Variable Interest Entities. FIN 46 requires an entity to
consolidate a variable interest entity if it is the primary beneficiary of the
variable interest entitys activities. The primary beneficiary is the party
that absorbs a majority of the expected losses, receives a majority of the
expected residual returns, or both, of the variable interest entitys
activities. FIN 46 is applicable immediately to variable interest entities
created, or interests in variable interest entities obtained, after January 31,
2003. For those variable interest entities created, or interests in variable
interest entities obtained, on or before January 31, 2003, FIN 46 is required
to be applied in the first fiscal year or interim period beginning after June
15, 2003. FIN 46 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 also requires certain disclosures
of an entitys relationship with variable interest entities. The Company is
currently assessing FIN 46 but has not yet determined the impact that it will
have on its consolidated results of operations, cash flows or financial
position.

In December 2002, the FASB issued SFAS No. 148, Accounting for
Stock-Based Compensation  Transition and Disclosure  an amendment of FASB
Statement No. 123. SFAS No. 148 amends SFAS No. 123, Accounting for
Stock-Based Compensation, to provide alternative methods of transition for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation. In addition, SFAS No. 148 amends the disclosure
requirements of SFAS No. 123 to require prominent disclosures in both annual
and interim financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on reported results. We
adopted the disclosure only provisions of SFAS No. 148 as of December 31, 2002.
Adoption of the new standard had no material effect on our consolidated results
of operations or financial position.

In November 2002, the FASB issued Interpretation No. 45, Guarantors
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others, 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 will adopt the initial recognition and measurement
provisions of Interpretation No. 45 on a prospective basis to guarantees issued
or modified after December 31, 2002. We adopted the disclosure only provisions
of Interpretation No. 45 as of December 31, 2002. Adoption of the new
interpretation had no material effect on our consolidated results of operations
or financial position.

In June 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities, which addresses accounting for
restructuring and similar costs. SFAS No. 146 supersedes previous accounting
guidance, principally EITF No. 94-3. We will adopt the provisions of SFAS No.
146 for restructuring activities initiated after December 31, 2002. SFAS No.
146 requires that the liability for costs associated with an exit or disposal
activity be recognized when the liability is incurred. Under EITF No. 94-3, a
liability for an exit cost was recognized at the date of the Companys
commitment to an exit plan. SFAS No. 146 also establishes that the liability
should initially be measured and recorded at fair value. Accordingly, SFAS No.
146 may affect the timing of recognizing future restructuring costs as well as
the amounts recognized.

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

|                                 |  |                    |            |      |  |   |            |  
|-------------------------------- |  | ------------------ | ---------- | ---- |  | - | ---------- | -
|                                 |  | For the Year Ended
|                                 |  | December 31,      
|                                 |  | 2001               |            | 2000
|                                 |  |                    |            |     
|                                 |  | (In thousands)    
|Total revenues before adjustment |  | $                  | 9,597,665  |      |  | $ | 9,093,366  |  
|Adjustment                       |  |                    | (1,572,971 | )    |  |   | (2,894,942 | )
|                                 |  |                    |            |      |  |   |            |  
|Revenue as reported              |  | $                  | 8,024,694  |      |  | $ | 6,198,424  |  
|                                 |  |                    |            |      |  |   |            |  

In October 2002, the EITF, as part of their further deliberations on Issue
No. 02-03, rescinded the consensus reached in Issue No. 98-10. 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, will be recorded at their historical cost and 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 are accounted for under the accrual
accounting basis. Non-derivative energy trading contracts and trading
inventories that were recorded at fair values were adjusted to historical cost
via a cumulative effect adjustment of $5.4 million as a reduction to 2003
earnings.

In October 2002, the EITF also reached a consensus in Issue No. 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 income statement. 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. Therefore, the Companys trading
revenue presentation on the Consolidated Statements of Operations may be
revised again in 2003 based on the final consensus of the EITF.

We adopted SFAS No. 142, Goodwill and Other Intangible Assets, on
January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized
over an estimated useful life, as previously required. Instead, goodwill
amounts are subject to a fair-value-based annual impairment assessment. We did
not recognize any impairments due to the implementation of SFAS No. 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 (loss) income 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,      
|                           |                            |   | 2002               |         | 2001 |   | 2000   
|                           |                            |   |                    |         |      |   |        
|                           |                            |   | (In thousands)    
|Reported net (loss) income |                            | $ | (46,551            | )       |      | $ | 363,907 |         |  | $ | 680,161 |        
|Add: Goodwill amortization |                            |   |                   |         |      |   | 21,989  |         |  |   | 17,859  |        
|                           |                            |   |                    |         |      |   |         |         |  |   |         |        
|                           | Adjusted net (loss) income |   | $                  | (46,551 | )    |   | $       | 385,896 |  |   | $       | 698,020 | 
|                           |                            |   |                    |         |      |   |         |         |  |   |         |        

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The changes in the carrying amount of goodwill for the years ended
December 31, 2002 and December 31, 2001 are as follows (in thousands):

|                                                                         |                    |   |                   |         |          |   |             |   |                   |   |        |        |  |   |          |         | 
|------------------------------------------------------------------------ | ------------------ | - | ----------------- | ------- | -------- | - | ----------- | - | ----------------- | - | ------ | ------ |  | - | -------- | ------- | 
|                                                                         |                    |   |                   |         |          |   |             |   |                   |   |        |        |  |   | Purchase
|                                                                         |                    |   | Balance           |         | Acquired |   | Price       |   | Balance          
|                                                                         |                    |   | December 31, 2001 |         | Goodwill |   | Adjustments |   | December 31, 2002
|                                                                         |                    |   |                   |         |          |   |             |   |                  
|Natural gas gathering, processing, transportation,
marketing
and storage |                    | $ | 394,054           |         |          | $ |            |   |                   | $ | 521    |        |  | $ | 394,575  |        
|NGL fractionation, transportation, marketing and trading                 |                    |   | 27,122            |         |          |   |            |   |                   |   | 13,418 |        |  |   | 40,540   |        
|                                                                         |                    |   |                   |         |          |   |             |   |                   |   |        |        |  |   |          |        
|                                                                         | Total consolidated |   | $                 | 421,176 |          |   | $           |  |                   |   | $      | 13,939 |  |   | $        | 435,115 | 
|                                                                         |                    |   |                   |         |          |   |             |   |                   |   |        |        |  |   |          |        

|                                                                         |                    |   |                   |         |          |   |                  |        |                   |   |         |         |   |   |         |         | 
|------------------------------------------------------------------------ | ------------------ | - | ----------------- | ------- | -------- | - | ---------------- | ------ | ----------------- | - | ------- | ------- | - | - | ------- | ------- | 
|                                                                         |                    |   | Balance           |         | Acquired |   | Amortization and |        | Balance          
|                                                                         |                    |   | December 31, 2000 |         | Goodwill |   | Other            |        | December 31, 2001
|                                                                         |                    |   |                   |         |          |   |                  |        |                  
|Natural gas gathering, processing, transportation, marketing
and storage |                    | $ | 376,195           |         |          | $ | 53,799           |        |                   | $ | (35,940 | )       |   | $ | 394,054 |        
|NGL fractionation, transportation, marketing and trading                 |                    |   |                  |         |          |   | 28,053           |        |                   |   | (931    | )       |   |   | 27,122  |        
|                                                                         |                    |   |                   |         |          |   |                  |        |                   |   |         |         |   |   |         |        
|                                                                         | Total consolidated |   | $                 | 376,195 |          |   | $                | 81,852 |                   |   | $       | (36,871 | ) |   | $       | 421,176 | 
|                                                                         |                    |   |                   |         |          |   |                  |        |                   |   |         |         |   |   |         |        

We adopted SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, on January 1, 2002. The new rules supersede SFAS No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of. The new rules retain many of the fundamental recognition
and measurement provisions of SFAS No. 121, but 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, 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 No. 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
is increased due to the passage of time based on the time value of money until
the obligation is settled.

We adopted the provisions of SFAS No. 143 as of January 1, 2003. In
accordance with the transition provisions of SFAS No. 143, we recorded a
cumulative-effect adjustment of $17.4 million as a reduction in 2003 earnings.

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ITEM 8. Financial Statements and Supplementary Data.

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, 2002, 2001 and 2000
(In thousands)

|                                                                             |                                                              |                          |                          |           |           |           |         |           |           |           |          |           |           |           | 
|---------------------------------------------------------------------------- | ------------------------------------------------------------ | ------------------------ | ------------------------ | --------- | --------- | --------- | ------- | --------- | --------- | --------- | -------- | --------- | --------- | --------- | 
|                                                                             |                                                              |                          |                          |           | 2002      |           | 2001    |           | 2000     
|                                                                             |                                                              |                          |                          |           |           |           |         |           |          
|OPERATING REVENUES:                                                          |                                                              |                          |                          |           |           |           |         |           |           |           |          |          
|                                                                             | Sales of natural gas and petroleum products                  |                          | $                        | 3,025,554 |           |           | $       | 4,766,449 |           |           | $        | 3,609,775 |          
|                                                                             | Sales of natural gas and petroleum products  affiliates     |                          |                          | 2,160,174 |           |           |         | 2,928,631 |           |           |          | 2,373,698 |          
|                                                                             | Transportation, storage and processing                       |                          |                          | 291,431   |           |           |         | 281,744   |           |           |          | 188,501   |          
|                                                                             | Transportation, storage and processing  affiliates          |                          |                          |          |           |           |         |          |           |           |          | 11,350    |          
|                                                                             | Trading and marketing net margin                             |                          |                          | 14,397    |           |           |         | 47,870    |           |           |          | 15,100    |          
|                                                                             |                                                              |                          |                          |           |           |           |         |           |           |           |          |          
|                                                                             |                                                              |                          | Total operating revenues |           |           | 5,491,556 |         |           |           | 8,024,694 |          |           |           | 6,198,424 | 
|                                                                             |                                                              |                          |                          |           |           |           |         |           |           |           |          |          
|COSTS AND EXPENSES:                                                          |                                                              |                          |                          |           |           |           |         |           |           |           |          |          
|                                                                             | Purchases of natural gas and petroleum products              |                          |                          | 3,935,943 |           |           |         | 6,049,010 |           |           |          | 4,236,098 |          
|                                                                             | Purchases of natural gas and petroleum products  affiliates |                          |                          | 504,428   |           |           |         | 691,884   |           |           |          | 744,378   |          
|                                                                             | Operating and maintenance                                    |                          |                          | 449,318   |           |           |         | 373,477   |           |           |          | 331,572   |          
|                                                                             | Depreciation and amortization                                |                          |                          | 298,953   |           |           |         | 278,930   |           |           |          | 234,862   |          
|                                                                             | General and administrative                                   |                          |                          | 149,316   |           |           |         | 118,249   |           |           |          | 140,557   |          
|                                                                             | General and administrative  affiliates                      |                          |                          | 17,799    |           |           |         | 11,719    |           |           |          | 30,597    |          
|                                                                             | Asset impairments                                            |                          |                          | 40,440    |           |           |         |          |           |           |          |          |          
|                                                                             | Net loss (gain) on sale of assets                            |                          |                          | 4,256     |           |           |         | (1,277    | )         |           |          | (10,660   | )        
|                                                                             |                                                              |                          |                          |           |           |           |         |           |           |           |          |          
|                                                                             |                                                              | Total costs and expenses |                          |           | 5,400,453 |           |         |           | 7,521,992 |           |          |           | 5,707,404 |          
|                                                                             |                                                              |                          |                          |           |           |           |         |           |           |           |          |          
|OPERATING INCOME                                                             |                                                              |                          | 91,103                   |           |           |           | 502,702 |           |           |           | 491,020  |          
|EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES                              |                                                              |                          | 38,196                   |           |           |           | 30,069  |           |           |           | 27,424   |          
|INTEREST EXPENSE:                                                            |                                                              |                          |                          |           |           |           |         |           |           |           |          |          
|                                                                             | Interest expense                                             |                          |                          | 165,841   |           |           |         | 165,670   |           |           |          | 134,016   |          
|                                                                             | Interest expense  affiliates                                |                          |                          |          |           |           |         |          |           |           |          | 15,204    |          
|                                                                             |                                                              |                          |                          |           |           |           |         |           |           |           |          |          
|                                                                             |                                                              | Total interest expense   |                          |           | 165,841   |           |         |           | 165,670   |           |          |           | 149,220   |          
|                                                                             |                                                              |                          |                          |           |           |           |         |           |           |           |          |          
|(LOSS) INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF ACCOUNTING CHANGE |                                                              |                          | (36,542                  | )         |           |           | 367,101 |           |           |           | 369,224  |          
|INCOME TAX EXPENSE (BENEFIT)                                                 |                                                              |                          | 10,009                   |           |           |           | 2,783   |           |           |           | (310,937 | )        
|                                                                             |                                                              |                          |                          |           |           |           |         |           |           |           |          |          
|(LOSS) INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE                  |                                                              |                          | (46,551                  | )         |           |           | 364,318 |           |           |           | 680,161  |          
|CUMULATIVE EFFECT OF ACCOUNTING CHANGE                                       |                                                              |                          |                         |           |           |           | 411     |           |           |           |         |          
|                                                                             |                                                              |                          |                          |           |           |           |         |           |           |           |          |          
|NET (LOSS) INCOME                                                            |                                                              |                          | (46,551                  | )         |           |           | 363,907 |           |           |           | 680,161  |          
|DIVIDENDS ON PREFERRED MEMBERS INTEREST                                     |                                                              |                          | 25,544                   |           |           |           | 28,500  |           |           |           | 11,717   |          
|                                                                             |                                                              |                          |                          |           |           |           |         |           |           |           |          |          
|(DEFICIT) EARNINGS AVAILABLE FOR MEMBERS INTEREST                           |                                                              | $                        | (72,095                  | )         |           | $         | 335,407 |           |           | $         | 668,444  |          
|                                                                             |                                                              |                          |                          |           |           |           |         |           |           |           |          |          

See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
Years Ended December 31, 2002, 2001 and 2000
(In thousands)

|                                   |                                                     |                                         |          |          |          |      |         |        |        |   |         |        |        |  
|---------------------------------- | --------------------------------------------------- | --------------------------------------- | -------- | -------- | -------- | ---- | ------- | ------ | ------ | - | ------- | ------ | ------ | -
|                                   |                                                     |                                         |          | 2002     |          | 2001 |         | 2000  
|                                   |                                                     |                                         |          |          |          |      |         |       
|NET (LOSS) INCOME                  |                                                     | $                                       | (46,551  | )        |          | $    | 363,907 |        |        | $ | 680,161 |       
|OTHER COMPREHENSIVE (LOSS) INCOME: |                                                     |                                         |          |          |          |      |         |        |        |   |         |       
|                                   | Cumulative effect of change in accounting principle |                                         |          |         |          |      |         | 6,626  |        |   |         |       |       
|                                   | Foreign currency translation adjustment             |                                         |          | 161      |          |      |         | (4,460 | )      |   |         | (2,717 | )     
|                                   | Net unrealized (losses) gains on cash flow hedges   |                                         |          | (129,015 | )        |      |         | 51,621 |        |   |         |       |       
|                                   | Reclassification into earnings                      |                                         |          | 15,963   |          |      |         | (3,313 | )      |   |         |       |       
|                                   |                                                     |                                         |          |          |          |      |         |        |        |   |         |       
|                                   |                                                     | Total other comprehensive (loss) income |          |          | (112,891 | )    |         |        | 50,474 |   |         |        | (2,717 | )
|                                   |                                                     |                                         |          |          |          |      |         |        |        |   |         |       
|TOTAL COMPREHENSIVE (LOSS) INCOME  |                                                     | $                                       | (159,442 | )        |          | $    | 414,381 |        |        | $ | 677,444 |       
|                                   |                                                     |                                         |          |          |          |      |         |        |        |   |         |       

See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2002, 2001 and 2000
(In thousands)

|                                                                                                       |                                                                                                         |                                                            |                                                     |          |         |          |         |          |          |          |        |            |          |          |  
|------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------------- | ---------------------------------------------------------- | --------------------------------------------------- | -------- | ------- | -------- | ------- | -------- | -------- | -------- | ------ | ---------- | -------- | -------- | -
|                                                                                                       |                                                                                                         |                                                            |                                                     |          | 2002    |          | 2001    |          | 2000    
|                                                                                                       |                                                                                                         |                                                            |                                                     |          |         |          |         |          |         
|CASH FLOWS FROM OPERATING ACTIVITIES:                                                                  |                                                                                                         |                                                            |                                                     |          |         |          |         |          |          |          |        |           
|                                                                                                       | Net (loss) income                                                                                       |                                                            | $                                                   | (46,551  | )       |          | $       | 363,907  |          |          | $      | 680,161    |         
|                                                                                                       | Adjustments to reconcile net (loss) income to net cash provided
by operating activities:                |                                                            |                                                     |          |         |          |         |          |          |          |        |            |         
|                                                                                                       |                                                                                                         | Depreciation and amortization                              |                                                     |          | 298,953 |          |         |          | 278,930  |          |        |            | 234,862  |         
|                                                                                                       |                                                                                                         | Deferred income taxes (benefit)                            |                                                     |          | 1,951   |          |         |          | 2,783    |          |        |            | (308,001 | )       
|                                                                                                       |                                                                                                         | Equity in earnings of unconsolidated affiliates            |                                                     |          | (38,196 | )        |         |          | (30,069  | )        |        |            | (27,424  | )       
|                                                                                                       |                                                                                                         | Asset impairments                                          |                                                     |          | 40,440  |          |         |          |         |          |        |            |         |         
|                                                                                                       |                                                                                                         | Loss on asset sales and other                              |                                                     |          | 1,401   |          |         |          | 91       |          |        |            | (10,653  | )       
|                                                                                                       | Change in operating assets and liabilities (net of effects
of acquisitions) which provided (used) cash: |                                                            |                                                     |          |         |          |         |          |          |          |        |            |         
|                                                                                                       |                                                                                                         | Accounts receivable                                        |                                                     |          | 893     |          |         |          | 533,109  |          |        |            | (492,475 | )       
|                                                                                                       |                                                                                                         | Accounts receivable  affiliates                           |                                                     |          | 43,944  |          |         |          | 22,756   |          |        |            | (189,300 | )       
|                                                                                                       |                                                                                                         | Inventories                                                |                                                     |          | (3,624  | )        |         |          | 9,856    |          |        |            | (73,348  | )       
|                                                                                                       |                                                                                                         | Net unrealized loss (gains) on mark-to-market transactions |                                                     |          | 71,778  |          |         |          | (35,744  | )        |        |            | 5,376    |         
|                                                                                                       |                                                                                                         | Other current assets                                       |                                                     |          | 3,097   |          |         |          | 1,013    |          |        |            | 41,324   |         
|                                                                                                       |                                                                                                         | Other noncurrent assets                                    |                                                     |          | (1,917  | )        |         |          | 76       |          |        |            | (9,414   | )       
|                                                                                                       |                                                                                                         | Accounts payable                                           |                                                     |          | (9,662  | )        |         |          | (633,599 | )        |        |            | 808,980  |         
|                                                                                                       |                                                                                                         | Accounts payable  affiliates                              |                                                     |          | 51,389  |          |         |          | (35,844  | )        |        |            | (906     | )       
|                                                                                                       |                                                                                                         | Accrued interest payable                                   |                                                     |          | 1,877   |          |         |          | 7,807    |          |        |            | 49,641   |         
|                                                                                                       |                                                                                                         | Other current liabilities                                  |                                                     |          | 4,031   |          |         |          | (11,868  | )        |        |            | 51,036   |         
|                                                                                                       |                                                                                                         | Other long term liabilities                                |                                                     |          | 11,271  |          |         |          | (22,741  | )        |        |            | (46,787  | )       
|                                                                                                       |                                                                                                         |                                                            |                                                     |          |         |          |         |          |          |          |        |           
|                                                                                                       |                                                                                                         |                                                            | Net cash provided by operating activities           |          |         | 431,075  |         |          |          | 450,463  |        |            |          | 713,072  |  
|                                                                                                       |                                                                                                         |                                                            |                                                     |          |         |          |         |          |          |          |        |           
|CASH FLOWS FROM INVESTING ACTIVITIES:                                                                  |                                                                                                         |                                                            |                                                     |          |         |          |         |          |          |          |        |           
|                                                                                                       | Expenditures for acquisitions                                                                           |                                                            |                                                     |         |         |          |         | (220,097 | )        |          |        | (163,565   | )       
|                                                                                                       | Other capital expenditures                                                                              |                                                            |                                                     | (301,631 | )       |          |         | (377,273 | )        |          |        | (207,498   | )       
|                                                                                                       | Investment expenditures, net of cash acquired                                                           |                                                            |                                                     | 392      |         |          |         | (4,795   | )        |          |        | (5,323     | )       
|                                                                                                       | Investment distributions                                                                                |                                                            |                                                     | 53,878   |         |          |         | 41,278   |          |          |        | 43,557     |         
|                                                                                                       | Proceeds from sales of assets                                                                           |                                                            |                                                     | 10,501   |         |          |         | 22,300   |          |          |        | 97,981     |         
|                                                                                                       |                                                                                                         |                                                            |                                                     |          |         |          |         |          |          |          |        |           
|                                                                                                       |                                                                                                         |                                                            | Net cash used in investing activities               |          |         | (236,860 | )       |          |          | (538,587 | )      |            |          | (234,848 | )
|                                                                                                       |                                                                                                         |                                                            |                                                     |          |         |          |         |          |          |          |        |           
|CASH FLOWS FROM FINANCING ACTIVITIES:                                                                  |                                                                                                         |                                                            |                                                     |          |         |          |         |          |          |          |        |           
|                                                                                                       | Net decreases in advances from members                                                                  |                                                            |                                                     | (2,498   | )       |          |         | (11,347  | )        |          |        | (55,509    | )       
|                                                                                                       | Redemption of preferred members interests                                                               |                                                            |                                                     | (100,000 | )       |          |         |         |          |          |        |           |         
|                                                                                                       | Distributions to members                                                                                |                                                            |                                                     | (63,165  | )       |          |         | (235,564 | )        |          |        | (2,744,319 | )       
|                                                                                                       | Proceeds from issuing preferred members interest                                                       |                                                            |                                                     |         |         |          |         |         |          |          |        | 300,000    |         
|                                                                                                       | Short term debt  net                                                                                   |                                                            |                                                     | 2,139    |         |          |         | (133,455 | )        |          |        | 346,410    |         
|                                                                                                       | Proceeds from issuing debt  net                                                                        |                                                            |                                                     |         |         |          |         | 546,918  |          |          |        | 1,691,114  |         
|                                                                                                       | Debt issuance costs                                                                                     |                                                            |                                                     | (1,959   | )       |          |         | (2,034   | )        |          |        | (3,557     | )       
|                                                                                                       | Payment of debt                                                                                         |                                                            |                                                     | (590     | )       |          |         | (51,037  | )        |          |        |           |         
|                                                                                                       | Payment of dividends                                                                                    |                                                            |                                                     | (25,544  | )       |          |         | (28,500  | )        |          |        | (11,717    | )       
|                                                                                                       |                                                                                                         |                                                            |                                                     |          |         |          |         |          |          |          |        |           
|                                                                                                       |                                                                                                         |                                                            | Net cash (used in) provided by financing activities |          |         | (191,617 | )       |          |          | 84,981   |        |            |          | (477,578 | )
|                                                                                                       |                                                                                                         |                                                            |                                                     |          |         |          |         |          |          |          |        |           
|EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH                                                        |                                                                                                         |                                                            | (21                                                 | )        |         |          | 6,496   |          |          |          | 115    |           
|NET INCREASE IN CASH                                                                                   |                                                                                                         |                                                            | 2,577                                               |          |         |          | 3,353   |          |          |          | 761    |           
|CASH, BEGINNING OF YEAR                                                                                |                                                                                                         |                                                            | 4,906                                               |          |         |          | 1,553   |          |          |          | 792    |           
|                                                                                                       |                                                                                                         |                                                            |                                                     |          |         |          |         |          |          |          |        |           
|CASH, END OF YEAR                                                                                      |                                                                                                         | $                                                          | 7,483                                               |          |         | $        | 4,906   |          |          | $        | 1,553  |           
|                                                                                                       |                                                                                                         |                                                            |                                                     |          |         |          |         |          |          |          |        |           
|SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION  Cash
paid for interest (net of amounts capitalized) |                                                                                                         | $                                                          | 167,266                                             |          |         | $        | 155,946 |          |          | $        | 95,805 |           

See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED BALANCE SHEETS
As of December 31, 2002 and 2001
(In thousands)

|                                                        |                                                        |                |                           |           |         |           |           |           |         |           | 
|------------------------------------------------------- | ------------------------------------------------------ | -------------- | ------------------------- | --------- | ------- | --------- | --------- | --------- | ------- | --------- | 
|                                                        |                                                        |                |                           |           | 2002    |           | 2001     
|                                                        |                                                        |                |                           |           |         |           |          
|ASSETS                                                  |                                                        |                |                           |          
|CURRENT ASSETS:                                         |                                                        |                |                           |           |         |           |           |          
|                                                        | Cash                                                   |                | $                         | 7,483     |         |           | $         | 4,906     |        
|                                                        | Accounts receivable:                                   |                |                           |           |         |           |           |           |        
|                                                        |                                                        | Customers, net |                           |           | 599,116 |           |           |           | 520,118 |          
|                                                        |                                                        | Affiliates     |                           |           | 186,577 |           |           |           | 230,521 |          
|                                                        |                                                        | Other          |                           |           | 50,466  |           |           |           | 136,810 |          
|                                                        | Inventories                                            |                |                           | 86,559    |         |           |           | 82,935    |        
|                                                        | Unrealized gains on trading and hedging transactions   |                |                           | 187,000   |         |           |           | 180,809   |        
|                                                        | Other                                                  |                |                           | 6,713     |         |           |           | 9,060     |        
|                                                        |                                                        |                |                           |           |         |           |           |          
|                                                        |                                                        |                | Total current assets      |           |         | 1,123,914 |           |           |         | 1,165,159 | 
|                                                        |                                                        |                |                           |           |         |           |           |          
|PROPERTY, PLANT AND EQUIPMENT, NET                      |                                                        |                | 4,642,204                 |           |         |           | 4,711,960 |          
|INVESTMENT IN AFFILIATES                                |                                                        |                | 179,684                   |           |         |           | 132,252   |          
|INTANGIBLE ASSETS:                                      |                                                        |                |                           |           |         |           |           |          
|                                                        | Natural gas liquids sales and purchases contracts, net |                |                           | 84,304    |         |           |           | 94,019    |        
|                                                        | Goodwill, net                                          |                |                           | 435,115   |         |           |           | 421,176   |        
|                                                        |                                                        |                |                           |           |         |           |           |          
|                                                        |                                                        |                | Total intangible assets   |           |         | 519,419   |           |           |         | 515,195   | 
|                                                        |                                                        |                |                           |           |         |           |           |          
|UNREALIZED GAINS ON TRADING AND HEDGING
TRANSACTIONS    |                                                        |                | 25,710                    |           |         |           | 19,095    |          
|OTHER NONCURRENT ASSETS                                 |                                                        |                | 89,504                    |           |         |           | 86,548    |          
|                                                        |                                                        |                |                           |           |         |           |           |          
|                                                        |                                                        |                | TOTAL ASSETS              |           | $       | 6,580,435 |           |           | $       | 6,630,209 | 
|                                                        |                                                        |                |                           |           |         |           |           |          
|LIABILITIES AND MEMBERS EQUITY                         |                                                        |                |                           |          
|CURRENT LIABILITIES:                                    |                                                        |                |                           |           |         |           |           |          
|                                                        | Accounts payable:                                      |                |                           |           |         |           |           |           |        
|                                                        |                                                        | Trade          |                           | $         | 638,826 |           |           | $         | 620,094 |          
|                                                        |                                                        | Affiliates     |                           |           | 77,009  |           |           |           | 25,620  |          
|                                                        |                                                        | Other          |                           |           | 45,786  |           |           |           | 76,914  |          
|                                                        | Short term debt                                        |                |                           | 215,094   |         |           |           | 212,955   |        
|                                                        | Accrued taxes other than income                        |                |                           | 31,059    |         |           |           | 24,646    |        
|                                                        | Distributions payable to members                       |                |                           |          |         |           |           | 45,672    |        
|                                                        | Accrued interest payable                               |                |                           | 59,294    |         |           |           | 57,417    |        
|                                                        | Unrealized losses on trading and hedging transactions  |                |                           | 273,578   |         |           |           | 89,032    |        
|                                                        | Other                                                  |                |                           | 88,370    |         |           |           | 98,473    |        
|                                                        |                                                        |                |                           |           |         |           |           |          
|                                                        |                                                        |                | Total current liabilities |           |         | 1,429,016 |           |           |         | 1,250,823 | 
|                                                        |                                                        |                |                           |           |         |           |           |          
|DEFERRED INCOME TAXES                                   |                                                        |                | 11,740                    |           |         |           | 14,362    |          
|LONG TERM DEBT                                          |                                                        |                | 2,255,508                 |           |         |           | 2,235,034 |          
|UNREALIZED LOSSES ON TRADING AND
HEDGING TRANSACTIONS   |                                                        |                | 19,361                    |           |         |           | 25,188    |          
|OTHER LONG TERM LIABILITIES                             |                                                        |                | 89,427                    |           |         |           | 15,845    |          
|MINORITY INTERESTS                                      |                                                        |                | 124,820                   |           |         |           | 135,915   |          
|PREFERRED MEMBERS INTEREST                             |                                                        |                | 200,000                   |           |         |           | 300,000   |          
|COMMITMENTS AND CONTINGENT LIABILITIES
MEMBERS EQUITY: |                                                        |                |                           |           |         |           |           |          
|                                                        | Members interest                                      |                |                           | 1,709,290 |         |           |           | 1,709,290 |        
|                                                        | Retained earnings                                      |                |                           | 806,119   |         |           |           | 895,707   |        
|                                                        | Accumulated other comprehensive (loss) income          |                |                           | (64,846   | )       |           |           | 48,045    |        
|                                                        |                                                        |                |                           |           |         |           |           |          
|                                                        |                                                        |                | Total members equity     |           |         | 2,450,563 |           |           |         | 2,653,042 | 
|                                                        |                                                        |                |                           |           |         |           |           |          
|TOTAL LIABILITIES AND MEMBERS EQUITY                   |                                                        | $              | 6,580,435                 |           |         | $         | 6,630,209 |          
|                                                        |                                                        |                |                           |           |         |           |           |          

See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF MEMBERS EQUITY
Years Ended December 31, 2002, 2001 and 2000
(In thousands)

|                                            |                                                     |   |        |    |         |   |            |          |          |   |               |            |       |   |          |          |       |   |             |   |  |   |           |            |  
|------------------------------------------- | --------------------------------------------------- | - | ------ | -- | ------- | - | ---------- | -------- | -------- | - | ------------- | ---------- | ----- | - | -------- | -------- | ----- | - | ----------- | - |  | - | --------- | ---------- | -
|                                            |                                                     |   |        |    |         |   |            |          |          |   |               |            |       |   |          |          |       |   | Accumulated |   |  |   |          
|                                            |                                                     |   |        |    |         |   | Additional |          |          |   |               |            |       |   |          |          | Other |   |             |   | 
|                                            |                                                     |   | Common |    | Paid-In |   | Members   |          | Retained |   | Comprehensive |            |       |   |         
|                                            |                                                     |   | Stock  |    | Capital |   | Interest   |          | Earnings |   | (Loss) Income |            | Total
|                                            |                                                     |   |        |    |         |   |            |          |          |   |               |            |      
|Balance, January 1,
2000                    |                                                     |   | 1      |    |         |   | 213,091    |          |          |   |              |            |       |   | 173,091  |          |       |   | 288         |   |  |   | 386,471   |           
|Combination at March 31,
2000  see Note 2: |                                                     |   |        |    |         |   |            |          |          |   |               |            |       |   |          |          |       |   |             |   |  |   |           |           
|                                            | Contribution of TEPPCO
general partnership
interest |   |        |   |         |   |            | 2,148    |          |   |               |           |       |   |          |         |       |   |             |  |  |   |           | 2,148      |  
|                                            | Contribution of DEFS Inc.
and DEFSCL to DEFS,
LLC   |   |        | (1 | )       |   |            | (215,239 | )        |   |               | 215,240    |       |   |          |         |       |   |             |  |  |   |           |           |  
|                                            | Contribution of notes and
advances payable          |   |        |   |         |   |            |         |          |   |               | 2,318,569  |       |   |          |         |       |   |             |  |  |   |           | 2,318,569  |  
|                                            | Contribution of GPM
assets and
liabilities          |   |        |   |         |   |            |         |          |   |               | 1,919,800  |       |   |          |         |       |   |             |  |  |   |           | 1,919,800  |  
|                                            | Distributions                                       |   |        |   |         |   |            |         |          |   |               | (2,744,319 | )     |   |          | (127,561 | )     |   |             |  |  |   |           | (2,871,880 | )
|Dividends on preferred
members interest    |                                                     |   |       |    |         |   |           |          |          |   |              |            |       |   | (11,717  | )        |       |   |            |   |  |   | (11,717   | )         
|Net Income                                  |                                                     |   |       |    |         |   |           |          |          |   |              |            |       |   | 680,161  |          |       |   |            |   |  |   | 680,161   |           
|Other                                       |                                                     |   |       |    |         |   |           |          |          |   |              |            |       |   |         |          |       |   | (2,717      | ) |  |   | (2,717    | )         
|                                            |                                                     |   |        |    |         |   |            |          |          |   |               |            |       |   |          |          |       |   |             |   |  |   |           |           
|Balance, December 31,
2000                  |                                                     |   |       |    |         |   |           |          |          |   | 1,709,290     |            |       |   | 713,974  |          |       |   | (2,429      | ) |  |   | 2,420,835 |           
|Distributions                               |                                                     |   |       |    |         |   |           |          |          |   |              |            |       |   | (153,674 | )        |       |   |            |   |  |   | (153,674  | )         
|Dividends on preferred
members interest    |                                                     |   |       |    |         |   |           |          |          |   |              |            |       |   | (28,500  | )        |       |   |            |   |  |   | (28,500   | )         
|Net Income                                  |                                                     |   |       |    |         |   |           |          |          |   |              |            |       |   | 363,907  |          |       |   |            |   |  |   | 363,907   |           
|Other                                       |                                                     |   |       |    |         |   |           |          |          |   |              |            |       |   |         |          |       |   | 50,474      |   |  |   | 50,474    |           
|                                            |                                                     |   |        |    |         |   |            |          |          |   |               |            |       |   |          |          |       |   |             |   |  |   |           |           
|Balance, December 31,
2001                  |                                                     |   |       |    |         |   |           |          |          |   | 1,709,290     |            |       |   | 895,707  |          |       |   | 48,045      |   |  |   | 2,653,042 |           
|Distributions                               |                                                     |   |       |    |         |   |           |          |          |   |              |            |       |   | (17,493  | )        |       |   |            |   |  |   | (17,493   | )         
|Dividends on preferred
members interest    |                                                     |   |       |    |         |   |           |          |          |   |              |            |       |   | (25,544  | )        |       |   |            |   |  |   | (25,544   | )         
|Net loss                                    |                                                     |   |       |    |         |   |           |          |          |   |              |            |       |   | (46,551  | )        |       |   |            |   |  |   | (46,551   | )         
|Other                                       |                                                     |   |       |    |         |   |           |          |          |   |              |            |       |   |         |          |       |   | (112,891    | ) |  |   | (112,891  | )         
|                                            |                                                     |   |        |    |         |   |            |          |          |   |               |            |       |   |          |          |       |   |             |   |  |   |           |           
|Balance, December 31,
2002                  |                                                     | $ |       |    |         | $ |           |          |          | $ | 1,709,290     |            |       | $ | 806,119  |          |       | $ | (64,846     | ) |  | $ | 2,450,563 |           
|                                            |                                                     |   |        |    |         |   |            |          |          |   |               |            |       |   |          |          |       |   |             |   |  |   |           |           

See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2002, 2001 and 2000

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 limits the scope of the Companys business to the
midstream natural gas industry in the United States and Canada, the marketing
of natural gas liquids in Mexico and the transportation, marketing and storage
of other petroleum products.

The Company is the successor to Duke Energy Corporations (Duke Energy)
North American midstream natural gas business that existed at the time of the
Combination (see Note 3). The subsidiaries of Duke Energy that conducted this
business were contributed to the Company immediately prior to the Combination
(see Note 3). For periods prior to the Combination, the Company and these
subsidiaries of Duke Energy are collectively referred to herein as the
Predecessor Company.

2. Summary of Significant Accounting Policies

Consolidation  The Consolidated Financial Statements include the accounts
of the Company and all majority-owned subsidiaries, after eliminating
significant intercompany transactions and balances. Investments in 20% to 50%
owned affiliates are accounted for using the equity method. Investments greater
than 50% are consolidated unless the Company does not operate these investments
and as a result does not have the ability to exercise control (see Note 9).

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.

Inventories  Inventories consist primarily of materials and supplies and
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 7). Historically, natural gas storage
arbitrage volumes were marked to market. However, effective with the Financial
Accounting Standard Boards (FASB) Emerging Issues Task Forces (EITF)
rescission of Issue No. 98-10, Accounting for Contracts Involved in Energy
Trading and Risk Management Activities, all gas storage inventory will be
recorded at the lower of cost or market, (see New Accounting Standards
below).

Accounting for Hedges and Commodity Trading Activities All derivatives
not qualifying for the normal purchases and sales exemption under Statement of
Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative
Instruments and Hedging Activities are recorded in the Consolidated Balance
Sheets at their fair value as Unrealized Gains or Unrealized Losses on Trading
and Hedging Transactions. On the date that derivative contracts are entered
into, the Company designates the derivative as either held for trading (trading
instruments); as a hedge of a recognized asset, liability or firm commitment
(fair value hedges); as a hedge of a forecasted transaction or future cash
flows (cash flow hedges); as a normal purchase or sale contract; or leaves the
derivative undesignated and marks it to market.

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 time value of the 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.

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Values are adjusted to reflect the potential impact of liquidating the
positions held in an orderly manner over a reasonable time period under current
conditions. Changes in market price 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  A favorable or unfavorable price movement of any
derivative contract held for trading 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 Trading 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 Issue 02-03, Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading
and Risk Management Activities, on the accounting for trading activities
subsequent to October 25, 2002.

Commodity Cash Flow Hedges  The effective portion of the change in fair
value of a derivative designated and qualified as a cash flow hedge are
included in the Consolidated Statements of Comprehensive (Loss) Income as Other
Comprehensive (Loss) Income (OCI) until earnings are affected by the hedged
item. Settlement amounts of cash flow hedges are removed from OCI 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, with subsequent changes in its fair value
recognized in current-period earnings. Gains and losses related to discontinued
hedges that were previously accumulated in OCI will remain in OCI 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 accumulated in OCI will be immediately recognized in current-period
earnings.

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 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 enters into interest rate
swaps to convert some 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 swap match those of
the associated debt which permits the assumption of no ineffectiveness, as
defined by SFAS No. 133. As such, for the life of the swap 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, Goodwill and Other Intangible Assets as of January 1, 2002. For
information on the impact of SFAS No. 142 on goodwill and goodwill amortization
see the New Accounting Standards section of this footnote. (See Notes 3 and 4
for information on significant goodwill additions.) NGLs 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 8). The costs of
maintenance and repairs, which are not significant improvements, are expensed
when incurred. Interest totaling $4.7 million for 2002, $0.8 million for 2001
and $0.3 million for 2000 has been capitalized on construction projects.

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Impairment of Long-Lived Assets  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. For the year ended December 31, 2002,
the Company recorded an impairment charge for certain assets of $40.4 million.
For the years ended December 31, 2001 and 2000, there was no impairment.

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 is provided. For gathering services, the Company
receives fees from the producers to bring 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
British thermal unit (Btu) content of the gas back to the producer. The
Company also receives fees for further fractionation of the NGLs produced, for
transportation and storage of NGLs and residue gas. In addition, the Company
recognizes revenue for its NGL and residue gas marketing activities. Revenue
for goods and services provided but not billed is estimated each month based
upon estimated commodity prices, preliminary throughput measurements and
contract data.

Significant Customers  Duke Energy Trading and Marketing, L.L.C.
(DETM), an affiliated company, was a significant customer in each of the past
three years. Sales to DETM, primarily residue gas, totaled approximately
$1,119.1 million during 2002, $1,628.8 million during 2001 and $1,444.0 million
during 2000. Effective February 28, 2003, the Companys Master Natural Gas
Sales and Purchase Agreement with DETM terminated. DETM provided a thirty-day
notice of termination on January 30, 2003. The Company expects to continue to
conduct business with DETM on a transactional basis in the future at a reduced
volume level. Given the Companys extensive gas marketing experience for the
remainder of its business, management does not expect the termination of this
contract to have any material impact on the Companys financial position or its
results of operations.

ConocoPhillips, an affiliated company, was also a significant customer.
Sales to ConocoPhillips, including its affiliate, Chevron Phillips Chemical
Company LLC (CP Chem) totaled approximately $1,022.6 million during 2002,
$1,309.5 million during 2001 and $942.3 million during 2000.

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 issues.

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 $26.0 million at the end of
2002 and $40.0 million at the end of 2001.

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 exchange rates during the year. Foreign currency
translation adjustments are included in the Consolidated Statements of
Comprehensive (Loss) Income.

Income Taxes  The Company follows the asset and liability method of
accounting for income taxes. Deferred taxes are provided for temporary
differences in the tax and financial reporting basis of assets and liabilities
(see Note 10). At March 31, 2000, the Company converted to a limited liability
company which is a pass-through entity for U.S. income tax purposes. As a
result, substantially all of the existing net deferred tax liability of $327.0
million was eliminated and a corresponding income tax benefit recorded.

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.

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In connection with the Combination (see Note 3), the Company is required
to make quarterly distributions to Duke Energy and ConocoPhillips based on
allocated taxable income. The limited liability company agreement, as amended,
provides for taxable income to be allocated in 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, 2002, no additional 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 method of accounting. 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. Restricted stock
grants and Company performance awards are recorded as compensation cost over
the requisite vesting period based on the market value on the date of the
grant. (See Note 15 for pro forma disclosures using the fair value accounting
method.) 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. (See Note 15 for additional information on the stock split.)

Cumulative Effect of Change in Accounting Principle The Company adopted
SFAS No. 133 on January 1, 2001. In accordance with the transition provisions
of SFAS No. 133, the Company recorded a cumulative-effect adjustment of $0.4
million as a reduction in earnings and a cumulative-effect adjustment
increasing OCI and members equity by $6.6 million. For the years ended
December 31, 2002 and 2001, the Company reclassified as earnings $0.9 million
and $12.1 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 January 2003, the FASB issued Interpretation
No. 46 (FIN 46), Consolidation of Variable Interest Entities. FIN 46 requires
an entity to consolidate a variable interest entity if it is the primary
beneficiary of the variable interest entitys activities. The primary
beneficiary is the party that absorbs a majority of the expected losses,
receives a majority of the expected residual returns, or both, of the variable
interest entitys activities. FIN 46 is applicable immediately to variable
interest entities created, or interests in variable interest entities obtained,
after January 31, 2003. For those variable interest entities created, or
interests in variable interest entities obtained, on or before January 31,
2003, FIN 46 is required to be applied in the first fiscal year or interim
period beginning after June 15, 2003. FIN 46 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 also requires
certain disclosures of an entitys relationship with variable interest
entities. The Company is currently assessing FIN 46 but has not yet determined
the impact that it will have on its consolidated results of operations, cash
flows or financial position.

In December 2002, the FASB issued SFAS No. 148, Accounting for
Stock-Based Compensation  Transition and Disclosure  an amendment of FASB
Statement No. 123. SFAS No. 148 amends SFAS No. 123, Accounting for
Stock-Based Compensation, to provide alternative methods of transition for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation. In addition, SFAS No. 148 amends the disclosure
requirements of SFAS No. 123 to require prominent disclosures in both annual
and interim financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on reported results.
The Company adopted the disclosure only provisions of SFAS No. 148 as of
December 31, 2002. Adoption of the new standard had no material effect on the
Companys consolidated results of operations or financial position.

In November 2002, the FASB issued Interpretation No. 45, Guarantors
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others, 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 will adopt the initial recognition and
measurement provisions of Interpretation No. 45 on a prospective basis to
guarantees issued or modified after December 31, 2002. The Company adopted the
disclosure only provisions of Interpretation No. 45 as of December 31, 2002.
Adoption of the new interpretation had no material effect on the Companys
consolidated results of operations or financial position.

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In June 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities, which addresses accounting for
restructuring and similar costs. SFAS No. 146 supersedes previous accounting
guidance, principally EITF No. 94-3. The Company will adopt the provisions of
SFAS No. 146 for restructuring activities initiated after December 31, 2002.
SFAS No. 146 requires that the liability for costs associated with an exit or
disposal activity be recognized when the liability is incurred. Under EITF No.
94-3, a liability for an exit cost was recognized at the date of the Companys
commitment to an exit plan. SFAS No. 146 also establishes that the liability
should initially be measured and recorded at fair value. Accordingly, SFAS No.
146 may affect the timing of recognizing future restructuring costs as well as
the amounts recognized.

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

|                                 |  |                    |            |      |  |   |            |  
|-------------------------------- |  | ------------------ | ---------- | ---- |  | - | ---------- | -
|                                 |  | For the Year Ended
|                                 |  | December 31,      
|                                 |  | 2001               |            | 2000
|                                 |  |                    |            |     
|                                 |  | (In thousands)    
|Total revenues before adjustment |  | $                  | 9,597,665  |      |  | $ | 9,093,366  |  
|Adjustment                       |  |                    | (1,572,971 | )    |  |   | (2,894,942 | )
|                                 |  |                    |            |      |  |   |            |  
|Revenue as reported              |  | $                  | 8,024,694  |      |  | $ | 6,198,424  |  
|                                 |  |                    |            |      |  |   |            |  

In October 2002, the EITF, as part of their further deliberations on Issue
No. 02-03, rescinded the consensus reached in Issue No. 98-10. 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, will be recorded at the lower of cost or market and 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 will 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 were adjusted to historical cost
via a cumulative effect adjustment of $5.4 million as a reduction to 2003
earnings. 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 in Issue No. 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 income statement. 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 should be reclassified to
conform to the consensus. Therefore, the Companys trading revenue presentation
on the Consolidated Statements of Operations may be restated again in 2003
based on the final consensus of the EITF. All gains and losses on all energy
trading contracts are currently presented on a net basis in the Consolidated
Statement of Operations. The new gross versus net revenue presentation
requirements will have no impact on operating income or net income.

The Company adopted SFAS No. 141, Business Combinations, as of July 1,
2001. SFAS No. 141 required that all business combinations initiated after June
30, 2001 be accounted for using the purchase method. Companies may no longer
use the pooling method of accounting for future combinations.

The Company adopted SFAS No. 142, Goodwill and Other Intangible Assets,
on January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized
over an estimated useful life, as previously required. Instead, goodwill
amounts are subject to a fair-value-based annual impairment assessment. The
Company did not recognize any impairments due to the implementation of SFAS No.
142. The standard also requires certain identifiable intangible assets to be
recognized separately and amortized as appropriate. No adjustments to
intangibles were identified by the Company at transition.

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The following table shows what net (loss) income 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,      
|                           |                            |   | 2002               |         | 2001 |   | 2000   
|                           |                            |   |                    |         |      |   |        
|                           |                            |   | (In thousands)    
|Reported net (loss) income |                            | $ | (46,551            | )       |      | $ | 363,907 |         |  | $ | 680,161 |        
|Add: Goodwill amortization |                            |   |                   |         |      |   | 21,989  |         |  |   | 17,859  |        
|                           |                            |   |                    |         |      |   |         |         |  |   |         |        
|                           | Adjusted net (loss) income |   | $                  | (46,551 | )    |   | $       | 385,896 |  |   | $       | 698,020 | 
|                           |                            |   |                    |         |      |   |         |         |  |   |         |        

The changes in the carrying amount of goodwill for the year ended December
31, 2002 and December 31, 2001 are as follows:

|                                                                         |  |                    |         |                   |         |          |   |             |   |                   |        |          |        |   |         |   |         | 
|------------------------------------------------------------------------ |  | ------------------ | ------- | ----------------- | ------- | -------- | - | ----------- | - | ----------------- | ------ | -------- | ------ | - | ------- | - | ------- | 
|                                                                         |  |                    |         |                   |         |          |   |             |   |                   |        | Purchase |        |   |         |  
|                                                                         |  |                    |         | Balance           |         | Acquired |   | Price       |   | Balance          
|                                                                         |  |                    |         | December 31, 2001 |         | Goodwill |   | Adjustments |   | December 31, 2002
|                                                                         |  |                    |         |                   |         |          |   |             |   |                  
|                                                                         |  |                    |         | (In thousands)   
|Natural gas gathering, processing, transportation,
marketing and storage |  | $                  | 394,054 |                   |         | $        |  |             |   | $                 | 521    |          |        | $ | 394,575 |  
|NGL fractionation, transportation, marketing and trading                 |  |                    | 27,122  |                   |         |          |  |             |   |                   | 13,418 |          |        |   | 40,540  |  
|                                                                         |  |                    |         |                   |         |          |   |             |   |                   |        |          |        |   |         |  
|                                                                         |  | Total consolidated |         | $                 | 421,176 |          |   | $           |  |                   |        | $        | 13,939 |   |         | $ | 435,115 | 
|                                                                         |  |                    |         |                   |         |          |   |             |   |                   |        |          |        |   |         |  

|                                                                         |                    |   |                   |         |          |   |              |        |                   |   |         |         |   |   |         |         | 
|------------------------------------------------------------------------ | ------------------ | - | ----------------- | ------- | -------- | - | ------------ | ------ | ----------------- | - | ------- | ------- | - | - | ------- | ------- | 
|                                                                         |                    |   | Balance           |         | Acquired |   | Amortization |        | Balance          
|                                                                         |                    |   | December 31, 2000 |         | Goodwill |   | and Other    |        | December 31, 2001
|                                                                         |                    |   |                   |         |          |   |              |        |                  
|                                                                         |                    |   | (In thousands)   
|Natural gas gathering, processing, transportation, marketing
and storage |                    | $ | 376,195           |         |          | $ | 53,799       |        |                   | $ | (35,940 | )       |   | $ | 394,054 |        
|NGL fractionation, transportation, marketing and trading                 |                    |   |                  |         |          |   | 28,053       |        |                   |   | (931    | )       |   |   | 27,122  |        
|                                                                         |                    |   |                   |         |          |   |              |        |                   |   |         |         |   |   |         |        
|                                                                         | Total consolidated |   | $                 | 376,195 |          |   | $            | 81,852 |                   |   | $       | (36,871 | ) |   | $       | 421,176 | 
|                                                                         |                    |   |                   |         |          |   |              |        |                   |   |         |         |   |   |         |        

The gross carrying amount and accumulated amortization for NGLs sales and
purchases contracts are as follows:

|                                   |                                         |   |                    |        |      |   |         |        | 
|---------------------------------- | --------------------------------------- | - | ------------------ | ------ | ---- | - | ------- | ------ | 
|                                   |                                         |   | For the Year Ended
|                                   |                                         |   | December 31,      
|                                   |                                         |   | 2002               |        | 2001
|                                   |                                         |   |                    |        |     
|                                   |                                         |   | (In thousands)    
|NGLs sales and purchases contracts |                                         | $ | 121,124            |        |      | $ | 121,124 |       
|Less: Accumulated amortization     |                                         |   | (36,820            | )      |      |   | (27,105 | )     
|                                   |                                         |   |                    |        |      |   |         |       
|                                   | NGLs sales and purchases contracts, net |   | $                  | 84,304 |      |   | $       | 94,019 | 
|                                   |                                         |   |                    |        |      |   |         |       

During the years ended December 31, 2002 and 2001, the Company recorded
amortization expense associated with NGLs sales and purchases contracts of $9.7
million and $9.0 million, respectively. Estimated amortization for these
contracts for the next five years is as follows:

|           |  |                        |        | 
|---------- |  | ---------------------- | ------ | 
|           |  | Estimated Amortization
|           |  |                       
|           |  | (in thousands)        
|2003       |  | $                      | 9,701  | 
|2004       |  |                        | 8,128  | 
|2005       |  |                        | 7,192  | 
|2006       |  |                        | 7,192  | 
|2007       |  |                        | 7,186  | 
|Thereafter |  |                        | 44,905 | 
|           |  |                        |        | 
|Total      |  | $                      | 84,304 | 
|           |  |                        |        | 

The Company adopted SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, on January 1, 2002. The new rules supersede
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of. The new rules retain many of the
fundamental recognition and measurement provisions of SFAS No. 121, but

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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 No. 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 No. 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
is increased 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 No. 143
as of January 1, 2003. In accordance with the transition provisions of SFAS No.
143, the Company recorded a cumulative-effect adjustment of $17.4 million as a
reduction in 2003 earnings.

Reclassifications  Certain prior period amounts have been reclassified in
the Consolidated Financial Statements to conform to the current presentation.

3. Combination

On March 31, 2000, the natural gas gathering, processing and NGL assets,
operations, and subsidiaries of Duke Energy that existed at the time were
contributed to Field Services LLC. In connection with the contribution of
assets and subsidiaries at March 31, 2000, notes and advances payable to
subsidiaries of Duke Energy were eliminated and contributed to equity. Also on
March 31, 2000, ConocoPhillips contributed its then existing midstream natural
gas gathering, processing and NGL operations to Field Services LLC. This
contribution and Duke Energys contribution to Field Services LLC are referred
to as the Combination. In connection with the Combination, the Company made
one-time distributions to ConocoPhillips of $1,219.8 million and to Duke Energy
of $1,524.5 million. In exchange for the contributions, and after the one-time
distributions, Duke Energy received a 69.7% member interest in Field Services
LLC, with ConocoPhillips holding the remaining 30.3% member interest.

TEPPCO General Partner  On March 31, 2000, and in connection with the
Combination, Duke Energy contributed the general partner of TEPPCO Partners,
L.P. (TEPPCO) to Field Services LLC. In connection with the contribution of
the general partner of TEPPCO, the Company recorded an investment in TEPPCO of
$2.1 million and increased equity by $2.1 million.

TEPPCO is a publicly traded master limited partnership that owns and
operates a network of pipelines and storage and terminal facilities for refined
products, liquefied petroleum gases, petrochemicals, natural gas gathering and
crude oil. The general partner is responsible for TEPPCOs management and
operations. Because Field Services LLC owns the general partner of TEPPCO, it
has the right to receive incentive cash distributions from TEPPCO in addition
to a 2% share of distributions based on the general partner interest. At
TEPPCOs 2002 per unit distribution level, the general partner received
approximately 25% of the cash distributed by TEPPCO to its partners. Due to the
general partners share of unit distributions and degree of control exercised
through its management of the partnership and other partnership governance
issues, the Companys investment in TEPPCO is accounted for under the equity
method.

4. Acquisitions and Dispositions

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 $71.0 million was adjusted
for working capital and certain capital expenditures. This adjusted purchase
price was then reduced by approximately $84.6 million of DPS debt guaranteed by
the Company, resulting in the Company receiving cash of approximately $11.5
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.

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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 $66.2 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.

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 $162.0 million. The purchase price included
assumed debt of approximately $49.3 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 a pro forma basis, revenues and net
income for the year ended December 31, 2001 would have increased $7.8 million
and $1.4 million, respectively, if the acquisition of CMSL had occurred on
January 1, 2001. The following is a summary of the allocated purchase price (in
millions):

|                              |                      |   |       |       | 
|----------------------------- | -------------------- | - | ----- | ----- | 
|Property, plant and equipment |                      | $ | 139.0 |      
|Goodwill                      |                      |   | 53.7  |      
|Current assets                |                      |   | 14.0  |      
|Current liabilities           |                      |   | (57.3 | )    
|Other noncurrent liabilities  |                      |   | (35.9 | )    
|                              |                      |   |       |      
|                              | Total purchase price |   | $     | 113.5 | 
|                              |                      |   |       |      

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 $45.0 million. The pro forma impact
of the acquisition on the Companys results of operations was not material.
Goodwill of $28.1 million has been recorded as a result of allocating the
purchase price to the individual assets and liabilities acquired.

Disposition of NGL Pipeline Assets  On December 31, 2000, the Company
sold NGL pipeline assets to TEPPCO for $91.0 million. The NGL pipeline assets
sold included the Panola Pipeline and the San Jacinto Pipeline. TEPPCO also
assumed the lease of a 34-mile condensate pipeline. A $12.0 million gain and a
$3.2 million deferred gain were recorded in connection with the sale.

Conoco and Mitchell Assets  On March 31, 2000, Field Services LLC
acquired gathering and processing facilities located in central Oklahoma from
Conoco, Inc. and Mitchell Energy & Development Corp. Field Services LLC paid
cash of $99.8 million, and exchanged its interests in certain gathering and
marketing joint ventures located in southeast Texas having a total fair value
of $42.0 million as consideration for these facilities. The pro forma impact of
the acquisition on the Companys results of operations was not material.

5. Agreements and Transactions with Duke Energy

Services Agreement with Duke Energy  In connection with the Combination,
the Company entered into a services agreement with Duke Energy and some of its
subsidiaries, dated March 14, 2000. Under this agreement, Duke Energy and those
subsidiaries provide the Company 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, legal functions and investor services.
These services are priced on the basis of a monthly charge which management
believes approximates market prices. 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, expires on December 31, 2003. Total expenditures,
including capital spending, resulting from this agreement were $17.7 million,
$10.0 million and $7.4 million in 2002, 2001 and 2000, respectively.

License Agreement  In connection with the Combination, 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.

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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, including TEPPCO, at contractual prices that
management believes approximated market prices in the ordinary course of the
Companys business. 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, including amounts netted in trading and
marketing net margin, were approximately $1,167.1 million, $1,648.5 million and
$1,459.2 million for 2002, 2001 and 2000, respectively. The Companys total
purchases from these activities were approximately $161.6 million, $327.5
million and $420.6 million for 2002, 2001 and 2000, respectively.

6. Agreements and Transactions with ConocoPhillips

Long Term NGLs Purchases Contract with ConocoPhillips  In connection with
the Combination, the Company agreed to maintain the NGL Output Purchase and
Sale Agreement (the ConocoPhillips NGL Agreement) between ConocoPhillips and
the midstream natural gas assets that were contributed by ConocoPhillips to the
Company in the Combination. Under the ConocoPhillips NGL Agreement, Phillips 66
Company, a wholly-owned subsidiary of ConocoPhillips, has the right to purchase
at index-based prices substantially all NGLs produced by the processing plants
which were contributed to the Company from ConocoPhillips in the Combination.
The ConocoPhillips NGL Agreement also grants Phillips 66 Company, and
subsequently Chevron Phillips Chemical Company, 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 December 31, 2014.

Transactions between ConocoPhillips and the Midstream Business Acquired
from ConocoPhillips  Through March 31, 2000, the ConocoPhillips businesses
(the ConocoPhillips Combined Subsidiaries) that owned the midstream natural
gas assets that were contributed to the Company in the Combination had
conducted a series of transactions with ConocoPhillips in which the
ConocoPhillips Combined Subsidiaries sold a portion of their residue gas and
other by-products to ConocoPhillips and its affiliate, CP Chem at contractual
prices that the Company believes approximated market prices. In addition, the
ConocoPhillips Combined Subsidiaries purchased raw natural gas from
ConocoPhillips at contractual prices that the Company believes approximated
market prices. The Company is continuing these transactions in the ordinary
course of business. The Companys total revenues from these activities,
including amounts netted in trading and marketing net margin, were
approximately $1,022.6 million, $1,309.5 million and $942.3 million for 2002,
2001 and 2000, respectively (see Note 2, Summary of Significant Accounting
Policies  Significant Customers.) The Companys total purchases from these
activities, including amounts netted in trading and marketing net margin, were
approximately $423.1 million, $491.1 million, and $340.7 million for 2002, 2001
and 2000, respectively.

7. Inventories

A summary of inventories by category follows:

|                       |                   |   |                |        |      |   |        |        | 
|---------------------- | ----------------- | - | -------------- | ------ | ---- | - | ------ | ------ | 
|                       |                   |   | December 31,  
|                       |                   |   |               
|                       |                   |   | 2002           |        | 2001
|                       |                   |   |                |        |     
|                       |                   |   | (In thousands)
|Gas held for resale    |                   | $ | 29,827         |        |      | $ | 32,553 |       
|NGLs                   |                   |   | 53,186         |        |      |   | 44,310 |       
|Materials and supplies |                   |   | 3,546          |        |      |   | 6,072  |       
|                       |                   |   |                |        |      |   |        |       
|                       | Total inventories |   | $              | 86,559 |      |   | $      | 82,935 | 
|                       |                   |   |                |        |      |   |        |       

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8. Property, Plant and Equipment

A summary of property, plant and equipment by classification follows:

|                              |                                    |  |                |   |              |   |           |            |   |   |           |            |  
|----------------------------- | ---------------------------------- |  | -------------- | - | ------------ | - | --------- | ---------- | - | - | --------- | ---------- | -
|                              |                                    |  |                |   | December 31,
|                              |                                    |  | Depreciation   |   |             
|                              |                                    |  | Rates          |   | 2002         |   | 2001     
|                              |                                    |  |                |   |              |   |          
|                              |                                    |  | (In thousands)
|Gathering                     |                                    |  | 4% - 6         | % |              | $ | 2,437,487 |            |   | $ | 2,308,905 |           
|Processing                    |                                    |  | 4              | % |              |   | 1,995,743 |            |   |   | 1,786,431 |           
|Transmission                  |                                    |  | 4              | % |              |   | 1,240,057 |            |   |   | 1,241,408 |           
|Underground storage           |                                    |  | 2% - 5         | % |              |   | 91,951    |            |   |   | 91,205    |           
|General plant                 |                                    |  | 20% - 33       | % |              |   | 192,707   |            |   |   | 126,125   |           
|Construction work in progress |                                    |  |                |   |              |   | 61,372    |            |   |   | 253,831   |           
|                              |                                    |  |                |   |              |   |           |            |   |   |           |           
|                              |                                    |  |                |   |              |   | 6,019,317 |            |   |   | 5,807,905 |           
|                              | Accumulated depreciation           |  |                |   |              |   |           | (1,377,113 | ) |   |           | (1,095,945 | )
|                              |                                    |  |                |   |              |   |           |            |   |   |           |           
|                              | Property, plant and equipment, net |  |                |   |              |   | $         | 4,642,204  |   |   | $         | 4,711,960  |  
|                              |                                    |  |                |   |              |   |           |            |   |   |           |           

Asset Impairments  As part of the Companys periodic asset performance
evaluations, it was 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, the Company performed tests for
recoverability on these assets in accordance with the requirements of SFAS No.
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 $40.4 million for 2002 relating to the natural gas
gathering, processing, transportation, marketing and storage segment.

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. If
negative market conditions persist over time and estimated cash flows over the
lives of assets do not exceed the carrying value of those individual assets,
asset impairments may occur in the future under existing accounting rules.
Furthermore, a change in managements intent about the use of individual assets
could also impact an impairment analysis.

9. Investments in Affiliates

The Company has investments in the following businesses accounted for
using the equity method:

|                                        |                                 |         |                |   |              |   |        |         |        |   |        |         | 
|--------------------------------------- | ------------------------------- | ------- | -------------- | - | ------------ | - | ------ | ------- | ------ | - | ------ | ------- | 
|                                        |                                 |         |                |   | December 31,
|                                        |                                 |         | 2002           |   |             
|                                        |                                 |         | Ownership      |   | 2002         |   | 2001  
|                                        |                                 |         |                |   |              |   |       
|                                        |                                 |         | (In thousands)
|Discovery Producer Services, LLC        |                                 |         | 33.33          | % |              | $ | 50,737 |         |        | $ |       |        
|Mont Belvieu I                          |                                 |         | 20.00          | % |              |   | 34,521 |         |        |   | 37,706 |        
|Sycamore Gas System General Partnership |                                 |         | 48.45          | % |              |   | 17,051 |         |        |   | 18,803 |        
|Main Pass Oil Gathering                 |                                 |         | 33.33          | % |              |   | 15,041 |         |        |   | 16,817 |        
|Tri-States NGL Pipeline, LLC            |                                 |         | 10.00          | % |              |   | 13,735 |         |        |   | 13,971 |        
|TEPPCO Partners, L.P.                   |                                 |         | 2.00           | % |              |   | 12,177 |         |        |   | 13,401 |        
|Black Lake Pipeline                     |                                 |         | 50.00          | % |              |   | 10,085 |         |        |   | 8,996  |        
|Fox Plant LLC                           |                                 |         | 50.00          | % |              |   | 8,572  |         |        |   | 8,247  |        
|Other affiliates                        |                                 | Various |                |   | 17,765       |   |        |         | 14,311 |  
|                                        |                                 |         |                |   |              |   |        |         |        |   |        |        
|                                        | Total investments in affiliates |         |                |   |              |   | $      | 179,684 |        |   | $      | 132,252 | 
|                                        |                                 |         |                |   |              |   |        |         |        |   |        |        

Discovery Producer Services, LLC  Discovery Producer Services, LLC 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.

Mont Belvieu I  Mont Belvieu I operates a 200 MBbl/d fractionation
facility in the Mont Belvieu, Texas Market Center.

Sycamore Gas System General Partnership  Sycamore Gas System General
Partnership is a partnership formed for the purpose of constructing, owning and
operating a gas gathering and compression system in Carter County, Oklahoma.

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.

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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 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.

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.

Equity in earnings amounted to the following for the years ended December
31:

|                                        |                       |   |                |        |      |   |        |        |  |   |        |        | 
|--------------------------------------- | --------------------- | - | -------------- | ------ | ---- | - | ------ | ------ |  | - | ------ | ------ | 
|                                        |                       |   | 2002           |        | 2001 |   | 2000  
|                                        |                       |   |                |        |      |   |       
|                                        |                       |   | (In thousands)
|Discovery Producer Services, LLC        |                       | $ | 2,119          |        |      | $ |       |        |  | $ |       |       
|Mont Belvieu I                          |                       |   | (1,422         | )      |      |   | (766   | )      |  |   | (501   | )     
|Sycamore Gas System General Partnership |                       |   | (299           | )      |      |   | (302   | )      |  |   | 44     |       
|Main Pass Oil Gathering                 |                       |   | 5,134          |        |      |   | 3,768  |        |  |   | 2,973  |       
|TEPPCO Partners, L.P.                   |                       |   | 28,750         |        |      |   | 24,517 |        |  |   | 10,589 |       
|Tri-States NGL Pipeline, LLC            |                       |   | 1,287          |        |      |   | 554    |        |  |   |       |       
|Black Lake Pipeline                     |                       |   | 1,639          |        |      |   | 1,322  |        |  |   | 1,833  |       
|Fox Plant LLC                           |                       |   | 324            |        |      |   | 202    |        |  |   | 508    |       
|Dauphin Island Gathering Partners (1)   |                       |   |               |        |      |   | 1,287  |        |  |   | 3,835  |       
|Mobile Bay Processing Partners (1)      |                       |   |               |        |      |   | (971   | )      |  |   | 2,413  |       
|Other affiliates                        |                       |   | 664            |        |      |   | 458    |        |  |   | 5,730  |       
|                                        |                       |   |                |        |      |   |        |        |  |   |        |       
|                                        | Total equity earnings |   | $              | 38,196 |      |   | $      | 30,069 |  |   | $      | 27,424 | 
|                                        |                       |   |                |        |      |   |        |        |  |   |        |       

(1) On July 10, 2001, the Company acquired additional interests in Mobile
Bay Processing Partners and Dauphin Island Gathering Partners. As a result of
these acquisitions, the assets and liabilities and results of operations of
these affiliates have been consolidated in the Companys Consolidated Financial
Statements since the date of the purchase (see Note 4).

Distributions in excess of earnings were $15.7 million, $11.2 million and
$16.1 million in 2002, 2001 and 2000, respectively.

The following summarizes combined financial information of unconsolidated
affiliates for the years ended December 31:

|                  |                        |            |   |                |         |      |   |          |         |  |   |          |   | 
|----------------- | ---------------------- | ---------- | - | -------------- | ------- | ---- | - | -------- | ------- |  | - | -------- | - | 
|                  |                        |            |   | 2002           |         | 2001 |   | 2000    
|                  |                        |            |   |                |         |      |   |         
|                  |                        |            |   | (In thousands)
|Income statement: |                        |            |   |                |         |      |   |          |         |  |   |         
|                  | Operating revenues     |            | $ | 295,946        |         |      | $ | 211,792  |         |  | $ | 242,900  |  
|                  | Operating expenses     |            |   | (229,100       | )       |      |   | (167,289 | )       |  |   | (216,334 | )
|                  | Net income             |            |   | 55,282         |         |      |   | 40,352   |         |  |   | 27,278   |  
|Balance sheet:    |                        |            |   |                |         |      |   |          |         |  |   |         
|                  | Current assets         |            | $ | 154,723        |         |      | $ | 73,466   |         |  |   |          |  
|                  | Noncurrent assets      |            |   | 745,207        |         |      |   | 599,727  |         |  |   |          |  
|                  | Current liabilities    |            |   | (69,327        | )       |      |   | (35,014  | )       |  |   |          |  
|                  | Noncurrent liabilities |            |   | (190,455       | )       |      |   | (260,583 | )       |  |   |          |  
|                  |                        |            |   |                |         |      |   |          |         |  |   |         
|                  |                        | Net assets |   | $              | 640,148 |      |   | $        | 377,596 |  |   |          |   | 
|                  |                        |            |   |                |         |      |   |          |         |  |   |         

10. Income Taxes

At March 31, 2000, the Company converted to a limited liability company
which is a pass-through entity for U.S. income tax purposes. As a result,
substantially all of the existing net deferred tax liability of $327.0 million
was eliminated and a corresponding income tax benefit was recorded.

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The Predecessor Companys taxable income was included in a consolidated
U.S. federal income tax return with Duke Energy until conversion to a limited
liability company. Therefore, income tax for 2000 has been provided in
accordance with Duke Energys tax allocation policy, which requires
subsidiaries to calculate federal income tax as if separate taxable income, as
defined, was reported.

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,
|                         |         |                |        |                         
|                         |         |                |        | 2002                     |       | 2001 |       | 2000 
|                         |         |                |        |                          |       |      |       |      
|                         |         |                |        | (In thousands)          
|Current:                 |         |                |        |                          |       |      |       |       |       |   |          |         
|                         | Federal |                | $      | 6,249                    |       |      | $     |      |       |   | $        | (5,066   | )       
|                         | State   |                |        | 989                      |       |      |       | 480   |       |   |          | 2,130    |         
|                         | Foreign |                |        | 820                      |       |      |       | 1,324 |       |   |          |         |         
|                         |         |                |        |                          |       |      |       |       |       |   |          |         
|                         |         | Total current  |        |                          | 8,058 |      |       |       | 1,804 |   |          |          | (2,936   | )
|                         |         |                |        |                          |       |      |       |       |       |   |          |         
|Deferred:                |         |                |        |                          |       |      |       |       |       |   |          |         
|                         | Federal |                |        | 944                      |       |      |       |      |       |   |          | (268,911 | )       
|                         | State   |                |        | 1,007                    |       |      |       | 979   |       |   |          | (39,090  | )       
|                         |         |                |        |                          |       |      |       |       |       |   |          |         
|                         |         | Total deferred |        |                          | 1,951 |      |       |       | 979   |   |          |          | (308,001 | )
|                         |         |                |        |                          |       |      |       |       |       |   |          |         
|Total income tax expense |         | $              | 10,009 |                          |       | $    | 2,783 |       |       | $ | (310,937 | )       
|                         |         |                |        |                          |       |      |       |       |       |   |          |         

11. Financing

Credit Facility with Financial Institutions  In March 2000, Field
Services LLC entered into a $2,800.0 million credit facility with several
financial institutions. No amounts were ever borrowed under this facility. On
April 3, 2000, Field Services LLC borrowed $2,790.9 million in the commercial
paper market to fund one-time cash distributions of $1,524.5 million to Duke
Energy and $1,219.8 million to ConocoPhillips, and to meet working capital
requirements. These borrowings were subsequently paid down with proceeds from
the issuance of debt securities and preferred financing (see below). The credit
facility has since been replaced by a new $650.0 million revolving credit
facility (the Facility), of which $150.0 million can be used for letters of
credit. 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 28, 2003, 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 requires the Company to maintain at all times a debt to total
capitalization ratio of less than or equal to 53%. The Company entered into an
amendment to the Facility on November 13, 2002. The Facility, as amended, bears
interest at a rate equal to, at the Companys option, either (1) London
Interbank Borrowing Rate (LIBOR) plus 1.25% per year or (2) the higher of (a)
the Bank of America prime rate and (b) the Federal Funds rate plus 0.50% per
year. At December 31, 2002, there were no borrowings or letters of credit
outstanding against the Facility. At December 31, 2002 and 2001, the Company
had $215.1 million and $213.0 million in outstanding commercial paper,
respectively, 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% and 2.53% as of December 31, 2002 and
2001, respectively. The amount of the Companys outstanding commercial paper
never exceeded the available amount under the Facility.

Preferred Financing  In August 2000, the Company issued $300.0 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
preferred member interests are entitled to cumulative preferential
distributions of 9.5% per annum payable, unless deferred, semi-annually. The
Company has the right to defer payments of preferential distributions on the
preferred member interests, other than certain tax distributions, at any time,
for up to 10 consecutive semiannual periods. Deferred preferred distributions
will accrue additional amounts based on the preferential distribution rate
(plus 0.5% per annum) to the date of payment. The preferred member interests,
together with all accrued and unpaid preferential distributions, must be
redeemed and paid on the earlier of the thirtieth anniversary date of issuance
or consummation of an initial public offering of equity securities. On
September 9, 2002, the Company redeemed $100.0 million of its preferred member
interests by paying cash to each member in proportion to their ownership
interests. For the years ended December 31, 2002 and 2001, the Company has paid
preferential distributions of $25.5 million and $28.5 million, respectively.
There are no outstanding deferred preferential distributions.

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Debt Securities  Long term debt at December 31, 2002 and 2001 was as follows
(in thousands):

|                     |  |                    |           |      |  |            |           |          |  |                  |  |  |       |   |  |                   |  |  |  | 
|-------------------- |  | ------------------ | --------- | ---- |  | ---------- | --------- | -------- |  | ---------------- |  |  | ----- | - |  | ----------------- |  |  |  | 
|                     |  | Principal/Discount |           |      |  |            |           |          |  |                  |  |  |       |  
|                     |  |                    |           |      |  |            |           | Interest |  |                  |  | 
|                     |  | 2002               |           | 2001 |  | Issue Date |           | Rate     |  | Due Date        
|                     |  |                    |           |      |  |            |           |          |  |                 
|Debt Securities      |  | $                  | 600,000   |      |  | $          | 600,000   |          |  | August 16, 2000  |  |  | 7 1/2 | % |  | August 16, 2005  
|                     |  |                    | 800,000   |      |  |            | 800,000   |          |  | August 16, 2000  |  |  | 7 7/8 | % |  | August 16, 2010  
|                     |  |                    | 300,000   |      |  |            | 300,000   |          |  | August 16, 2000  |  |  | 8 1/8 | % |  | August 16, 2030  
|                     |  |                    | 250,000   |      |  |            | 250,000   |          |  | February 2, 2001 |  |  | 6 7/8 | % |  | February 1, 2011 
|                     |  |                    | 300,000   |      |  |            | 300,000   |          |  | November 9, 2001 |  |  | 5 3/4 | % |  | November 15, 2006
|Interest rate swap   |  |                    | 14,258    |      |  |            | (4,659    | )        |  |                  |  |  |       |   |  |                   |  |  |  | 
|Capitalized leases   |  |                    | 2,697     |      |  |            | 3,288     |          |  |                  |  |  |       |   |  |                   |  |  |  | 
|Unamortized discount |  |                    | (11,447   | )    |  |            | (13,595   | )        |  |                  |  |  |       |   |  |                   |  |  |  | 
|                     |  |                    |           |      |  |            |           |          |  |                  |  |  |       |   |  |                   |  |  |  | 
|Net long term debt   |  | $                  | 2,255,508 |      |  | $          | 2,235,034 |          |  |                  |  |  |       |   |  |                   |  |  |  | 
|                     |  |                    |           |      |  |            |           |          |  |                  |  |  |       |   |  |                   |  |  |  | 

The notes mature and become payable on the respective due dates, and are
not subject to any sinking fund provisions. Debt securities maturing over the
next five years include $600.0 million in 2005 and $300.0 million in 2006.
Interest is payable semiannually. The notes are redeemable at the option of the
Company. The Company used the proceeds from the issuance of the debt securities
to repay short term commercial paper borrowings.

In October 2001, the Company entered into an interest rate swap to convert
the fixed interest rate on $250.0 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 6-month LIBOR rates, which is re-priced semiannually
through 2005.

12. 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 Chevron Phillips Chemical LLC, 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

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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.

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 No. 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, 2002, the
Company recognized a net loss of $27.2 million, of which $9.7 million
represented the total ineffectiveness of all cash flow hedges and $16.1 million
represented the total derivative settlements. The time value of options was
excluded in the assessment of hedge effectiveness.For the year ended December
31, 2002, a $1.4 million loss related to the time value of options is included
in Sales of Natural Gas and Petroleum Products in the Consolidated Statements
of Operations. No derivative gains or losses were reclassified from OCI 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
accumulated OCI to current period earnings are included in the line item in
which the hedged item is recorded. As of December 31, 2002, $57.1 million of
deferred net losses on derivative instruments accumulated in OCI 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 OCI 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 three years.

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 year ended December 31, 2002, 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 hedge  In October 2001, the Company entered into
an interest rate swap to convert the fixed interest rate on $250.0 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. The swap meets conditions
which permit the assumption of no ineffectiveness, as defined by SFAS 133. As
such, for the life of the swap no ineffectiveness will be recognized. As of
December 31, 2002, the fair value of the interest rate swap of $14.3 million
gain 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.

Commodity Derivatives  Trading  The trading of energy related products
and services exposes the Company to the fluctuations in the market values of
traded instruments. The Company manages its traded instrument 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
a daily earnings at risk measurement.

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13. 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, 2002 |            | December 31, 2001
|                                                      |  |                   |            |                  
|                                                      |  | Carrying          |            | Estimated Fair    |  | Carrying |            | Estimated Fair
|                                                      |  | Amount            |            | Value             |  | Amount   |            | Value         
|                                                      |  |                   |            |                   |  |          |            |               
|                                                      |  | (In thousands)   
|Accounts receivable                                   |  | $                 | 836,159    |                   |  | $        | 836,159    |                |  | $ | 887,449    |   |  | $ | 887,449    |  
|Accounts payable                                      |  |                   | (761,621   | )                 |  |          | (761,621   | )              |  |   | (722,628   | ) |  |   | (722,628   | )
|Natural gas, NGLs and
oil hedge
and trading contracts |  |                   | (80,229    | )                 |  |          | (80,229    | )              |  |   | 85,684     |   |  |   | 85,684     |  
|Short term debt                                       |  |                   | (215,094   | )                 |  |          | (215,094   | )              |  |   | (212,955   | ) |  |   | (212,955   | )
|Long term debt                                        |  |                   | (2,255,508 | )                 |  |          | (2,447,511 | )              |  |   | (2,235,034 | ) |  |   | (2,342,795 | )

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.

Notes receivable are carried in the accompanying balance sheet at cost.

The estimated fair value of the natural gas, NGLs and oil hedge contracts
is determined by multiplying the difference between the quoted termination
prices for natural gas, NGLs and 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.

14. Commitments and Contingent Liabilities

Litigation  The midstream natural gas 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 the final disposition of these proceedings will
not have a material adverse effect on the consolidated results of operations or
financial position of the Company.

Other Commitments and Contingencies  The Company utilizes assets under
operating leases in several areas of operation. Combined rental expense
amounted to $9.2 million, $11.1 million and $13.8 million in 2002, 2001 and
2000, respectively. Minimum rental payments under the Companys various
operating leases for the years 2003 through 2007 are $7.9 million, $5.7
million, $5.5 million, $3.6 million and $2.0 million, respectively. Thereafter,
payments aggregate $4.8 million through 2011.

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15. Stock-Based Compensation

Duke Energy applies APB Opinion No. 25, Accounting for Stock Issued to
Employeesand related Interpretations in accounting for the stock-based
compensation plans described below. Accordingly, no compensation expense has
been recognized for stock options. The following table illustrates the effect
on (deficit) earnings available for members interest if Duke Energy had
applied the fair value recognition provisions of FASB Statement No. 123,
Accounting for Stock-Based Compensationto all stock-based compensation
awards.

|                                                                                                                                   |  |                        |         |      |  |      |         |   |  |   |         |  
|---------------------------------------------------------------------------------------------------------------------------------- |  | ---------------------- | ------- | ---- |  | ---- | ------- | - |  | - | ------- | -
|                                                                                                                                   |  | Year Ended December 31
|                                                                                                                                   |  | (In thousands)        
|                                                                                                                                   |  | 2002                   |         | 2001 |  | 2000
|                                                                                                                                   |  |                        |         |      |  |     
|(Deficit) Earnings Available
for Members Interest, as
reported                                                                    |  | $                      | (72,095 | )    |  | $    | 335,407 |   |  | $ | 668,444 |  
|Add: stock-based compensation
expense included in reported
net income, net of related
tax effects                                  |  |                        | 750     |      |  |      | 591     |   |  |   | 1,137   |  
|Deduct: Total stock-based
compensation expense determined under fair value based method for all
awards, net of related tax effects |  |                        |         |      |  |      |         |   |  |   |         |  
|Pro forma (Deficit) Earnings                                                                                                       |  |                        | (3,593  | )    |  |      | (2,909  | ) |  |   | (2,975  | )
|                                                                                                                                   |  |                        |         |      |  |      |         |   |  |   |         |  
|Available for Members                                                                                                             |  |                        |         |      |  |      |         |   |  |   |         |  
|Interest, net of tax effects                                                                                                       |  | $                      | (74,938 | )    |  | $    | 333,089 |   |  | $ | 666,606 |  
|                                                                                                                                   |  |                        |         |      |  |      |         |   |  |   |         |  

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 one to five years with a maximum term of 10 years.

On December 20, 2000, Duke Energy announced a two-for-one common stock
split effective January 26, 2001, to shareholders of record on January 3, 2001.
The following option information has been restated to reflect the stock split,
and appropriate adjustments have been made in the exercise price and number of
shares subject to stock options.

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

Stock Option Activity

|                                 |           |  |                |      |          |   |           |    | 
|-------------------------------- | --------- |  | -------------- | ---- | -------- | - | --------- | -- | 
|                                 |           |  |                |      |          |   | Weighted-
|                                 |           |  |                |      |          |   | Average  
|                                 |           |  | Options        |      | Exercise
|                                 |           |  | (in thousands) |      | Price   
|                                 |           |  |                |      |         
|Outstanding at December 31, 1999 |           |  | 2,522          |      |          | $ | 26        |   
|                                 | Granted   |  |                | 837  |          |   |           | 41 | 
|                                 | Exercised |  |                | (568 | )        |   |           | 22 | 
|                                 | Forfeited |  |                | (223 | )        |   |           | 27 | 
|                                 |           |  |                |      |          |   |           |   
|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        |   
|                                 |           |  |                |      |          |   |           |   

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Stock Options at December 31, 2002

|                |       |                |       |              |       |             |     |                |     |           |    |    |    |  |     |           |       |   |    |    |    | 
|--------------- | ----- | -------------- | ----- | ------------ | ----- | ----------- | --- | -------------- | --- | --------- | -- | -- | -- |  | --- | --------- | ----- | - | -- | -- | -- | 
|                |       |                |       | Outstanding  |       | Exercisable
|                |       |                |       |              |       |            
|                |       |                |       |              |       |             |     | Weighted-      |     | Weighted- |    |    |    |  |     | Weighted-
|                |       |                |       |              |       |             |     | Average        |     | Average   |    |    |    |  |     | Average  
|Range of        |       | Number         |       | Remaining    |       | Exercise    |     | Number         |     | Exercise 
|Exercise Prices |       | (in thousands) |       | Life (Years) |       | Price       |     | (in thousands) |     | Price    
|                |       |                |       |              |       |             |     |                |     |          
|$8 to $10       |       |                | 9     |              |       |             | 2.1 |                |     | $         | 10 |    |    |  | 9   |           |       | $ | 10 |   
|$11 to $16      |       |                | 20    |              |       |             | 2.4 |                |     |           | 12 |    |    |  | 20  |           |       |   | 12 |   
|$17 to $22      |       |                | 16    |              |       |             | 4.1 |                |     |           | 22 |    |    |  | 16  |           |       |   | 22 |   
|$23 to $28      |       |                | 1,153 |              |       |             | 6.4 |                |     |           | 26 |    |    |  | 855 |           |       |   | 26 |   
|$29 to $34      |       |                | 190   |              |       |             | 6.9 |                |     |           | 30 |    |    |  | 120 |           |       |   | 30 |   
|$35 to $40      |       |                | 825   |              |       |             | 9.0 |                |     |           | 38 |    |    |  | 227 |           |       |   | 38 |   
|                | > $40 |                |       | 656          |       |             |     | 8.0            |     |           |    | 43 |    |  |     | 328       |       |   |    | 43 |   
|                |       |                |       |              |       |             |     |                |     |           |    |    |    |  |     |           |       |   |    |   
|                |       | Total          |       |              | 2,869 |             |     |                | 7.5 |           |    |    | 33 |  |     |           | 1,575 |   |    |    | 31 | 
|                |       |                |       |              |       |             |     |                |     |           |    |    |    |  |     |           |       |   |    |   

On December 31, 2002, there were approximately 1,575,000 exercisable
options outstanding with a $31 weighted-average exercise price. On December 31,
2001, there were approximately 813,000 outstanding options exercisable with a
weighted-average exercise price of $29 per option.

The weighted-average fair value of options granted was $10 per option
during 2002, 2001 and 2000. The fair value of each option granted was estimated
on the date of grant using the Black-Scholes options valuation model.

Weighted-Average Assumptions for Option-Pricing

|                                |  |         |      |         |  |         |      |   |  |  |      |  
|------------------------------- |  | ------- | ---- | ------- |  | ------- | ---- | - |  |  | ---- | -
|                                |  | 2002    |      | 2001    |  | 2000   
|                                |  |         |      |         |  |        
|Stock dividend yield            |  |         | 3.3  | %       |  |         | 3.4  | % |  |  | 3.7  | %
|Expected stock price volatility |  |         | 30.5 | %       |  |         | 29.7 | % |  |  | 25.1 | %
|Risk-free interest rates        |  |         | 5.1  | %       |  |         | 5.0  | % |  |  | 5.3  | %
|Expected option lives           |  | 7 years |      | 7 years |  | 7 years

Duke Energy granted performance awards of Duke Energy common stock to key
employees of the Predecessor Company under the 1998 Long Term Incentive Plan
(the 1998 Plan). 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. Duke Energy did not award any performance
awards in 2002, 2001 or 2000. Compensation expense for the performance grants
is charged to the Companys earnings over the vesting period and amounted to
approximately $216,000, $217,000, and $1.2 million, in 2002, 2001, and 2000,
respectively.

Duke Energy granted phantom shares of Duke Energy common stock to
employees of the Predecessor Company under the 1998 Plan. Phantom stock awards
under the 1998 Plan vest over periods ranging from one to four years. Duke
Energy did not award any phantom awards in 2002. Duke awarded 34,190 shares
(fair value of approximately $1.3 million at grant dates) in 2001 and 13,100
shares (fair value of approximately $0.6 million at grant date) in 2000.
Compensation expense for the stock grants is charged to the Companys earnings
over the vesting period, and amounted to approximately $750,000 and $300,000 in
2002 and 2001, respectively. Compensation expense for the stock grants in 2000
was immaterial.

In addition, Duke Energy granted restricted shares of Duke Energy common
stock to key employees of the Predecessor 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 2002 or
2001. Duke Energy awarded 28,526 restricted shares (fair value of approximately
$822,000 at grant dates) in 2000. Compensation expense for the stock grants is
charged to the Companys earnings over the vesting period, and amounted to
approximately $191,000, $418,000 and $402,000 in 2002, 2001 and 2000,
respectively.

16. Pension and Other Benefits

Effective April 1, 2000, the Companys employees began 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
2002, 2001 and 2000, the Company expensed plan contributions of $13.8 million,
$14.1 million and $8.9 million, respectively.

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Prior to April 1, 2000, employees of the Predecessor Company participated
in Duke Energys non-contributory trustee pension plan, which covered eligible
employees with minimum service requirements using a cash balance formula. Duke
Energys policy is to fund amounts, as necessary, on an actuarial basis to meet
benefits to be paid to plan members. Aspects of the plan specific to the
Predecessor Company are as follows:

Components of Net Periodic Pension Costs

|                                              |  |                   |      |  
|--------------------------------------------- |  | ----------------- | ---- | -
|                                              |  | Year Ended       
|                                              |  | December 31, 2000
|                                              |  |                  
|                                              |  | (In thousands)   
|Service cost benefit earned during year       |  | $                 | 480  |  
|Interest cost on projected benefit obligation |  |                   | 460  |  
|Expected return on plan assets                |  |                   | (674 | )
|Amortization of net transition asset          |  |                   | (21  | )
|Amortization of prior service cost            |  |                   | 8    |  
|Recognized actuarial loss                     |  |                   |     |  
|                                              |  |                   |      |  
|Net periodic pension cost                     |  |                   | 253  |  
|Impact of terminating plan participation      |  |                   | 483  |  
|                                              |  |                   |      |  
|Total pension cost                            |  | $                 | 736  |  
|                                              |  |                   |      |  

Assumptions Used for Pension Benefit Accounting

|                                                 |  |                   |      |  
|------------------------------------------------ |  | ----------------- | ---- | -
|                                                 |  | Year Ended       
|                                                 |  | December 31, 2000
|                                                 |  |                  
|Discount rate                                    |  |                   | 7.50 | %
|Rate of increase in compensation levels          |  |                   | 4.53 | %
|Expected long term rate of return on plan assets |  |                   | 9.25 | %

Duke Energy also sponsored, and the Predecessor Company participated in,
an employee savings plan. Predecessor Company employees became ineligible to
participate in the plan on March 31, 2000 in connection with the Combination.

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 is part of the general assets of the Company. Total
Company expense for this plan was $1.3 million, $1.9 million and $1.5 million
in 2002, 2001 and 2000, respectively.

17. Business Segments

The Company operates in two principal business segments: (1) natural gas
gathering, treatment, processing, transportation, trading and marketing and
storage, and (2) NGL fractionation, transportation, marketing and trading.
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, earnings before interest, taxes, depreciation and
amortization (EBITDA) and earnings before interest and taxes (EBIT) are the
performance measures 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,
|                                                 |                                                         |                                                       |         |                         
|                                                 |                                                         |                                                       |         | 2002                     |           | 2001 |         | 2000      
|                                                 |                                                         |                                                       |         |                          |           |      |         |           
|                                                 |                                                         |                                                       |         | (In thousands)          
|Operating revenues:                              |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 | Natural gas, including trading and marketing net margin |                                                       | $       | 5,498,640                |           |      | $       | 7,760,535  |           |   | $       | 7,036,003  |          
|                                                 | NGLs, including trading and marketing net margin        |                                                       |         | 1,399,975                |           |      |         | 2,536,171  |           |   |         | 757,178    |          
|                                                 | Intersegment(a)                                         |                                                       |         | (1,407,059               | )         |      |         | (2,272,012 | )         |   |         | (1,594,757 | )        
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 |                                                         | Total operating revenues                              |         | $                        | 5,491,556 |      |         | $          | 8,024,694 |   |         | $          | 6,198,424 | 
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|Margin:                                          |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 | Natural gas, including trading and marketing net margin |                                                       | $       | 996,046                  |           |      | $       | 1,228,344  |           |   | $       | 1,169,286  |          
|                                                 | NGLs, including trading and marketing net margin        |                                                       |         | 55,139                   |           |      |         | 55,456     |           |   |         | 48,662     |          
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 |                                                         | Total margin                                          |         | $                        | 1,051,185 |      |         | $          | 1,283,800 |   |         | $          | 1,217,948 | 
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|Other operating costs:                           |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 | Natural gas                                             |                                                       | $       | 484,201                  |           |      | $       | 364,664    |           |   | $       | 329,054    |          
|                                                 | NGLs                                                    |                                                       |         | 9,813                    |           |      |         | 7,536      |           |   |         | (8,142     | )(c)     
|                                                 | Corporate                                               |                                                       |         | 167,115                  |           |      |         | 129,968    |           |   |         | 171,154    |          
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 |                                                         | Total other operating costs                           |         | $                        | 661,129   |      |         | $          | 502,168   |   |         | $          | 492,066   | 
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|Equity in earnings of unconsolidated affiliates: |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 | Natural gas                                             |                                                       | $       | 36,811                   |           |      | $       | 28,899     |           |   | $       | 25,554     |          
|                                                 | NGLs                                                    |                                                       |         | 1,385                    |           |      |         | 1,170      |           |   |         | 1,870      |          
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 |                                                         | Total equity in earnings of unconsolidated affiliates |         | $                        | 38,196    |      |         | $          | 30,069    |   |         | $          | 27,424    | 
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|EBITDA(b):                                       |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 | Natural gas                                             |                                                       | $       | 548,656                  |           |      | $       | 892,579    |           |   | $       | 865,786    |          
|                                                 | NGLs                                                    |                                                       |         | 46,711                   |           |      |         | 49,090     |           |   |         | 58,674     |          
|                                                 | Corporate                                               |                                                       |         | (167,115                 | )         |      |         | (129,968   | )         |   |         | (171,154   | )        
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 |                                                         | Total EBITDA                                          |         | $                        | 428,252   |      |         | $          | 811,701   |   |         | $          | 753,306   | 
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|Depreciation and amortization:                   |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 | Natural gas                                             |                                                       | $       | 283,898                  |           |      | $       | 264,445    |           |   | $       | 218,593    |          
|                                                 | NGLs                                                    |                                                       |         | 11,242                   |           |      |         | 10,077     |           |   |         | 12,636     |          
|                                                 | Corporate                                               |                                                       |         | 3,813                    |           |      |         | 4,408      |           |   |         | 3,633      |          
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 |                                                         | Total depreciation and amortization                   |         | $                        | 298,953   |      |         | $          | 278,930   |   |         | $          | 234,862   | 
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|EBIT(b):                                         |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 | Natural gas                                             |                                                       | $       | 264,758                  |           |      | $       | 628,134    |           |   | $       | 647,193    |          
|                                                 | NGLs                                                    |                                                       |         | 35,469                   |           |      |         | 39,013     |           |   |         | 46,038     |          
|                                                 | Corporate                                               |                                                       |         | (170,928                 | )         |      |         | (134,376   | )         |   |         | (174,787   | )        
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 |                                                         | Total EBIT                                            |         | $                        | 129,299   |      |         | $          | 532,771   |   |         | $          | 518,444   | 
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|Corporate interest expense                       |                                                         | $                                                     | 165,841 |                          |           | $    | 165,670 |            |           | $ | 149,220 |           
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|(Loss) income before income taxes:               |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 | Natural gas                                             |                                                       | $       | 264,758                  |           |      | $       | 628,134    |           |   | $       | 647,193    |          
|                                                 | NGLs                                                    |                                                       |         | 35,469                   |           |      |         | 39,013     |           |   |         | 46,038     |          
|                                                 | Corporate                                               |                                                       |         | (336,769                 | )         |      |         | (300,046   | )         |   |         | (324,007   | )        
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 |                                                         | Total (loss) income before income taxes               |         | $                        | (36,542   | )    |         | $          | 367,101   |   |         | $          | 369,224   | 
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|Capital Expenditures:                            |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 | Natural gas                                             |                                                       | $       | 279,105                  |           |      | $       | 565,515    |           |   | $       | 356,657    |          
|                                                 | NGLs                                                    |                                                       |         | 9,322                    |           |      |         | 10,911     |           |   |         | 1,284      |          
|                                                 | Corporate                                               |                                                       |         | 13,204                   |           |      |         | 20,944     |           |   |         | 13,122     |          
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           
|                                                 |                                                         | Total Capital Expenditures                            |         | $                        | 301,631   |      |         | $          | 597,370   |   |         | $          | 371,063   | 
|                                                 |                                                         |                                                       |         |                          |           |      |         |            |           |   |         |           

|              |              |              |   |                    |           |      |   |           |           | 
|------------- | ------------ | ------------ | - | ------------------ | --------- | ---- | - | --------- | --------- | 
|              |              |              |   | As of December 31,
|              |              |              |   |                   
|              |              |              |   | 2002               |           | 2001
|              |              |              |   |                    |           |     
|              |              |              |   | (In thousands)    
|Total assets: |              |              |   |                    |           |      |   |          
|              | Natural gas  |              | $ | 5,190,492          |           |      | $ | 5,326,889 |          
|              | NGLs         |              |   | 293,398            |           |      |   | 258,177   |          
|              | Corporate(d) |              |   | 1,096,545          |           |      |   | 1,045,143 |          
|              |              |              |   |                    |           |      |   |          
|              |              | Total assets |   | $                  | 6,580,435 |      |   | $         | 6,630,209 | 
|              |              |              |   |                    |           |      |   |          



---

|(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.
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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|(b) |  | EBITDA consists of income from continuing operations before interest expense, income tax expense, and
depreciation and amortization expense. EBIT is EBITDA less depreciation and amortization. These measures
are not a measurement presented in accordance with generally accepted accounting principles and should
not be considered in isolation from or as a substitute for net income or cash flow measures prepared in
accordance with generally accepted accounting principles or as a measure of the Companys profitability
or liquidity. The measures are included as a supplemental disclosure because it may provide useful
information regarding the Companys ability to service debt and to fund capital expenditures. However,
not all EBITDA or EBIT may be available to service debt. This measure may not be comparable to similarly
titled measures reported by other companies.
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(c) |  | Other operating cost for NGLs in 2000 include a gain on sale of NGL Pipeline Assets of $12 million.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|   
|(d) |  | Includes items such as unallocated working capital, intercompany accounts and intangible and other assets.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           

18. Guarantors Obligations Under Guarantees

At December 31, 2002, the Company was the guarantor of approximately
$100.5 million of debt associated with unconsolidated subsidiaries, of which
$84.5 million is related to our 33.3% ownership interest in Discovery Producer
Services, LLC. These guarantees expire December 31, 2003. The debt related to
Discovery Producer Services, LLC is due December 31, 2003, and is expected to
be refinanced. In the event that the unconsolidated subsidiaries default on the
debt payments, the Company would be required to pay the debt. Assets of the
unconsolidated subsidiaries are pledged as collateral for the debt. At
December 31, 2002, the Company had no liability recorded for the guarantees of
the debt associated with the unconsolidated subsidiaries.

At December 31, 2002, the Company has various indemnification agreements
outstanding contained in asset purchase and sale agreements. These
indemnification agreements generally relate to changes 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. The
Company cannot estimate the maximum potential amount of future payments under
these indemnification agreements due to the uncertainties related to changes in
laws and regulations with regard to taxes, safety and protection of the
environment or the settlement of outstanding litigation, which are outside the
Companys control. In addition, many of these indemnification agreements do not
contain any limits on potential liability.

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, 2002.

19. Accounting Adjustments

The Company has completed a comprehensive account reconciliation project
to review and analyze its balance sheet accounts. 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 in the current years financial statements.

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20. Quarterly Financial Data (Unaudited)

|     |                   |  |                |           |         |  |         |           |         |  |       |           |  |  |   |           |   |  |   |           |  
|---- | ----------------- |  | -------------- | --------- | ------- |  | ------- | --------- | ------- |  | ----- | --------- |  |  | - | --------- | - |  | - | --------- | -
|     |                   |  | First          |           | Second  |  | Third   |           | Fourth  |  |       |           | 
|     |                   |  | Quarter        |           | Quarter |  | Quarter |           | Quarter |  | Total
|     |                   |  |                |           |         |  |         |           |         |  |      
|     |                   |  | (In thousands)
|2002 |                   |  |                |           |         |  |         |           |         |  |       |           |  |  |   |           |   |  |   |          
|     | Operating revenue |  | $              | 1,132,274 |         |  | $       | 1,365,571 |         |  | $     | 1,307,623 |  |  | $ | 1,686,088 |   |  | $ | 5,491,556 |  
|     | Operating income  |  |                | 24,999    |         |  |         | 19,092    |         |  |       | 40,614    |  |  |   | 6,398     |   |  |   | 91,103    |  
|     | Net (loss) income |  |                | (17,000   | )       |  |         | (21,344   | )       |  |       | 12,040    |  |  |   | (20,247   | ) |  |   | (46,551   | )
|2001 |                   |  |                |           |         |  |         |           |         |  |       |           |  |  |   |           |   |  |   |          
|     | Operating revenue |  | $              | 2,957,530 |         |  | $       | 1,963,408 |         |  | $     | 1,423,138 |  |  | $ | 1,680,618 |   |  | $ | 8,024,694 |  
|     | Operating income  |  |                | 179,688   |         |  |         | 145,393   |         |  |       | 114,672   |  |  |   | 62,949    |   |  |   | 502,702   |  
|     | Net income        |  |                | 142,378   |         |  |         | 115,642   |         |  |       | 78,836    |  |  |   | 27,051    |   |  |   | 363,907   |  

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DUKE ENERGY FIELD SERVICES, LLC

Schedule II  Valuation and Qualifying Accounts and Reserves

|                   |                                 |   |            |      |            |   |             |      |                      |   |                |       |            |   |       |       |   |   |      |      | 
|------------------ | ------------------------------- | - | ---------- | ---- | ---------- | - | ----------- | ---- | -------------------- | - | -------------- | ----- | ---------- | - | ----- | ----- | - | - | ---- | ---- | 
|                   |                                 |   |            |      |            |   | Additions   |      |                      |   |                |       |            |   |      
|                   |                                 |   |            |      |            |   |             |      |                      |   |                |       |            |   |      
|                   |                                 |   | Balance at |      |            |   |             |      | Charged to           |   | Principal Cash |       | Balance at
|                   |                                 |   | Beginning  |      | Charged to |   | Other       |      | Payments and Reserve |   | End of        
|                   |                                 |   | of Period  |      | Expenses   |   | Accounts(b) |      | Reversals            |   | Period        
|                   |                                 |   |            |      |            |   |             |      |                      |   |               
|December 31, 2002: |                                 |   |            |      |            |   |             |      |                      |   |                |       |            |   |       |       |   |   |      |     
|                   | Allowance for doubtful accounts |   | $          | 5.9  |            |   | $           | .4   |                      |   | $              | 1.8   |            |   | $     |      |   |   | $    | 8.1  | 
|                   | Environmental                   |   |            | 40.0 |            |   |             |     |                      |   |                | 1.1   |            |   |       | (15.1 | ) |   |      | 26.0 | 
|                   | Litigation                      |   |            | 7.5  |            |   |             | 1.5  |                      |   |                |      |            |   |       | (5.0  | ) |   |      | 4.0  | 
|                   | Other(a)                        |   |            | 12.1 |            |   |             | 30.5 |                      |   |                | (10.9 | )          |   |       | (22.3 | ) |   |      | 9.4  | 
|                   |                                 |   |            |      |            |   |             |      |                      |   |                |       |            |   |       |       |   |   |      |     
|                   |                                 | $ | 65.5       |      |            | $ | 32.4        |      |                      | $ | (8.0           | )     |            | $ | (42.4 | )     |   | $ | 47.5 |     
|December 31, 2001: |                                 |   |            |      |            |   |             |      |                      |   |                |       |            |   |       |       |   |   |      |     
|                   | Allowance for doubtful accounts |   | $          | 3.6  |            |   | $           | 3.3  |                      |   | $              |      |            |   | $     | (1.0  | ) |   | $    | 5.9  | 
|                   | Environmental                   |   |            | 38.7 |            |   |             |     |                      |   |                | 8.9   |            |   |       | (7.6  | ) |   |      | 40.0 | 
|                   | Litigation                      |   |            | 28.7 |            |   |             |     |                      |   |                | 1.2   |            |   |       | (22.4 | ) |   |      | 7.5  | 
|                   | Other(a)                        |   |            | 18.6 |            |   |             |     |                      |   |                | 16.2  |            |   |       | (22.7 | ) |   |      | 12.1 | 
|                   |                                 |   |            |      |            |   |             |      |                      |   |                |       |            |   |       |       |   |   |      |     
|                   |                                 | $ | 89.6       |      |            | $ | 3.3         |      |                      | $ | 26.3           |       |            | $ | (53.7 | )     |   | $ | 65.5 |     
|December 31, 2000: |                                 |   |            |      |            |   |             |      |                      |   |                |       |            |   |       |       |   |   |      |     
|                   | Allowance for doubtful accounts |   | $          | 6.7  |            |   | $           | 1.2  |                      |   | $              |      |            |   | $     | (4.3  | ) |   | $    | 3.6  | 
|                   | Environmental                   |   |            | 15.7 |            |   |             | .7   |                      |   |                | 26.5  |            |   |       | (4.2  | ) |   |      | 38.7 | 
|                   | Litigation                      |   |            | 10.9 |            |   |             |     |                      |   |                | 20.0  |            |   |       | (2.2  | ) |   |      | 28.7 | 
|                   | Other(a)                        |   |            | 19.5 |            |   |             |     |                      |   |                | 2.6   |            |   |       | (3.5  | ) |   |      | 18.6 | 
|                   |                                 |   |            |      |            |   |             |      |                      |   |                |       |            |   |       |       |   |   |      |     
|                   |                                 | $ | 52.8       |      |            | $ | 1.9         |      |                      | $ | 49.1           |       |            | $ | (14.2 | )     |   | $ | 89.6 |     



---

|(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 assumed in business acquisitions and combinations.   

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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, 2002 and 2001,
and the related consolidated statements of operations, comprehensive (loss)
income, members equity, and cash flows for each of the three years in the
period ended December 31, 2002. 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 these 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, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such 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 2002
the Company changed its method of accounting for goodwill to conform to
Statement of Financial Accounting Standards No. 142, Goodwill and Other
Intangible Assetsand in 2001 the Company changed its method of accounting for
derivative instruments and hedging activities to conform to Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities.

DELOITTE & TOUCHE LLP

Denver, Colorado
March 12, 2003

65



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

None.




PART III.




ITEM 10. Directors and Executive Officers of the Registrant.

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

|                       |  |     |    |          |  |                                                                          
|---------------------- |  | --- | -- | -------- |  | -------------------------------------------------------------------------
|Name                   |  | Age |    | Position
|                       |  |     |    |         
|Jim W. Mogg            |  |     | 54 |          |  | Director and Chairman of the Board, President and Chief
Executive Officer
|Mark A. Borer          |  |     | 48 |          |  | Executive Vice President, Marketing and Corporate Development            
|Michael J. Bradley     |  |     | 48 |          |  | Executive Vice President, Gathering and Processing                       
|Robert F. Martinovich  |  |     | 45 |          |  | Senior Vice President, Northern Division                                 
|Rose M. Robeson        |  |     | 42 |          |  | Vice President and Chief Financial Officer                               
|Brent L. Backes        |  |     | 43 |          |  | Vice President, General Counsel and Secretary                            
|William W. Slaughter   |  |     | 55 |          |  | Executive Vice President                                                 
|Philip L. Frederickson |  |     | 46 |          |  | Director                                                                 
|Fred J. Fowler         |  |     | 57 |          |  | Director                                                                 
|John E. Lowe           |  |     | 44 |          |  | Director                                                                 
|Richard J. Osborne     |  |     | 52 |          |  | Director                                                                 

Jim W. Moggis Chairman of the Board, President and Chief Executive
Officer of our company. Mr. Mogg also serves as Senior Vice President  Field
Services for Duke Energy. Mr. Mogg was President and Chief Executive Officer of
the Predecessor Company from 1994 until the Combination. Mr. Mogg is also a
director, Chairman of the Board and Chairman of the Compensation Committee of
the general partner of TEPPCO. Mr. Mogg has been in the energy industry since
1973.

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 is a member of
our Audit Committee. Mr. Fowler has been in the energy industry since 1968.

Richard J. Osborne,a Director of our company, is the Executive Vice
President and Chief Risk Officer of Duke Energy. Mr. Osborne is also
responsible for the Duke Ventures Group of non-energy businesses. Mr. Osborne
served as the Executive Vice President and Chief Financial Officer of Duke
Energy from 1997 to 2000. From 1994 to 1997, Mr. Osborne served as Senior Vice
President and Chief Financial Officer of Duke Power. From 1991 to 1994, he
served as Vice President and Chief Financial Officer of Duke Power. 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.

John E. Lowe,a Director of our company, is the Executive Vice President,
Planning and Strategic Transactions 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.

66



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##### Table of Contents



William W. Slaughteris Executive Vice President of our company. Mr.
Slaughter held the position of Advisor to the Chief Executive Officer of the
Predecessor Company from 1998 until his appointment as Executive Vice President
in 2000. From 1997 until 1998, Mr. Slaughter was Vice President of Energy
Services for Duke Energy. From 1994 until 1997, Mr. Slaughter served as Vice
President of Corporate Strategic Planning for PanEnergy and President of
PanEnergy International Development Corporation. Mr. Slaughter is also a
director of the general partner of TEPPCO. Mr. Slaughter has been in the energy
industry since 1970.

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 Senior Associate Attorney at
LeBoeuf, Lamb, Greene & MacRae, LLP. 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.

67



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##### Table of Contents






ITEM 11. Executive Compensation.

The following table sets forth compensation information for the years
ended December 31, 2000, December 31, 2001 and December 31, 2002 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 Compensation |         |      |  |          
|                            |                           |      |      |      |  |     |         |         |       |        |                     |         |            |     |              |         |            |  |                        |         |      |  |          
|                            |                           |      |      |      |  |     |         |         |       |        | Annual Compensation |         |            |     |              |         | Securities |  |                        |         |      |  |           |         | 
|                            |                           |      |      |      |  |     |         |         |       |        |                     |         | Restricted |     | Underlying   |         |            |  |                        |         |      |  |          
|                            |                           |      |      |      |  |     |         |         |       |        |                     |         |            |     | Other Annual |         | Stock      |  | Stock                  |         | LTIP |  | All Other
|                            |                           |      |      |      |  |     | Salary  |         | Bonus |        | Compensation        |         | Awards     |     | Options      |         | Payouts    |  | Compensation          
|Name and Principal Position |                           | Year |      | ($)  |  | ($) |         | ($)(5)  |       | ($)(6) |                     | (#)(10) |            | ($) |              | ($)(11)
|                            |                           |      |      |      |  |     |         |         |       |        |                     |         |            |     |              |        
|Jim W. Mogg(1)              |                           |      | 2002 |      |  |     | 450,000 |         |       |        | 40,072              |         |            |     |              |         |            |  | (7                     | )       |      |  | 7,500     |         |  |  | 319,560 |        |  |  | 93,225 |       
|                            | Chairman of the Board,    |      |      | 2001 |  |     |         | 419,231 |       |        |                     | 201,482 |            |     |              |         |            |  |                        | 337,990 |      |  |           | 74,800  |  |  |         |        |  |  |        | 91,825 | 
|                            | President and Chief       |      |      | 2000 |  |     |         | 376,474 |       |        |                     | 475,219 |            |     |              |         |            |  |                        | 193,513 |      |  |           | 133,000 |  |  |         | 76,102 |  |  |        | 37,399 | 
|                            | Executive Officer         |      |      |      |  |     |         |         |       |        |                     |         |            |     |              |         |            |  |                        |         |      |  |           |         |  |  |         |        |  |  |        |        | 
|Mark A. Borer(1)            |                           |      | 2002 |      |  |     | 269,615 |         |       |        | 59,531              |         |            |     |              |         |            |  | (8                     | )       |      |  | 6,100     |         |  |  |         |        |  |  | 41,057 |       
|                            | Executive Vice President, |      |      | 2001 |  |     |         | 219,230 |       |        |                     | 65,500  |            |     |              |         |            |  |                        | 116,431 |      |  |           | 25,800  |  |  |         |        |  |  |        | 39,457 | 
|                            | Marketing and Corporate   |      |      | 2000 |  |     |         | 196,154 |       |        |                     | 166,300 |            |     |              |         |            |  |                        | 145,730 |      |  |           | 33,600  |  |  |         |        |  |  |        | 24,497 | 
|                            | Development               |      |      |      |  |     |         |         |       |        |                     |         |            |     |              |         |            |  |                        |         |      |  |           |         |  |  |         |        |  |  |        |        | 
|Michael J. Bradley(1)       |                           |      | 2002 |      |  |     | 269,615 |         |       |        | 59,501              |         |            |     |              |         |            |  | (9                     | )       |      |  | 2,300     |         |  |  |         |        |  |  | 41,367 |       
|                            | Executive Vice President, |      |      | 2001 |  |     |         | 219,230 |       |        |                     | 61,800  |            |     |              |         |            |  |                        | 116,431 |      |  |           | 25,800  |  |  |         |        |  |  |        | 27,587 | 
|                            | Gathering and Processing  |      |      | 2000 |  |     |         | 196,154 |       |        |                     | 169,400 |            |     |              |         |            |  |                        | 145,730 |      |  |           | 34,400  |  |  |         | 52,553 |  |  |        | 19,277 | 
|Robert F. Martinovich(2)    |                           |      | 2002 |      |  |     | 250,000 |         |       |        | 54,687              |         |            |     |              |         |            |  |                        |         |      |  |           |         |  |  |         |        |  |  | 87,246 |       
|                            | Senior Vice President,    |      |      | 2001 |  |     |         | 219,230 |       |        |                     | 55,800  |            |     |              |         |            |  |                        | 116,431 |      |  |           | 25,800  |  |  |         |        |  |  |        | 38,632 | 
|                            | Northern Division         |      |      | 2000 |  |     |         | 190,797 |       |        |                     | 160,400 |            |     |              |         |            |  |                        | 145,730 |      |  |           | 33,600  |  |  |         |        |  |  |        | 54,507 | 
|William W. Slaughter (1)(3) |                           |      | 2002 |      |  |     | 236,304 |         |       |        | 102,824             | (4)     |            |     |              |         |            |  |                        |         |      |  | 57,492    |         |  |  |         |        |  |  | 58,294 |       
|                            | Executive Vice President  |      |      | 2001 |  |     |         | 198,261 |       |        |                     | 89,217  |            |     |              |         |            |  |                        |         |      |  |           |         |  |  |         |        |  |  |        | 68,658 | 
|                            |                           |      | 2000 |      |  |     | 260,878 |         |       |        | 73,565              |         |            |     |              |         |            |  | 112,500                |         |      |  | 48,720    |         |  |  |         |        |  |  | 56,613 |       



---

|(1) |  | Prior to the Combination on March 31, 2000 all compensation paid to
Messrs. Mogg, Borer, Bradley and Slaughter was paid by Duke Energy and
was attributable to services provided to the Predecessor Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Prior to the Combination on March 31, 2000 all compensation paid to
Mr. Martinovich was paid by ConocoPhillips.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|   
|(3) |  | Mr. Slaughter provides services to our company pursuant to a
Consulting Agreement, which provides for the terms of his compensation
as Executive Vice President. For a description of his current
agreement, see the disclosure below under the heading Consulting
Agreement. For the years ended December 31, 2000 and 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 provides for allocations for base
salary, bonus, supplemental payments to offset his ineligibility for
company benefits and phantom stock options, but no other benefits.
|   
|(4) |  | The bonus paid to Mr. Slaughter for fiscal year 2000 and 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|   
|(5) |  | 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               

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|(6) |  | Messrs. Mogg, Borer, Bradley and Martinovich elected to receive a
portion of the value of their long term incentive component for their
2001 and 2002 compensation in the form of phantom stock. The awards were
granted under the Duke Energy 1998 Long Term Incentive Plan. 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, 2002 and their values on that date
are as follows:                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  

|               |  |               |       |              |  |   |         | 
|-------------- |  | ------------- | ----- | ------------ |  | - | ------- | 
|               |  | Number of     |       | Value At    
|               |  | Phantom Stock |       | December 31,
|               |  | Units         |       | 2002        
|               |  |               |       |             
|J. Mogg        |  |               | 8,988 |              |  | $ | 175,626 | 
|M. Borer       |  |               | 2,878 |              |  |   | 56,236  | 
|M. Bradley     |  |               | 2,878 |              |  |   | 56,236  | 
|R. Martinovich |  |               | 2,878 |              |  |   | 56,236  | 



|(7)  |  | In addition to the 8,988 phantom stock units in note 5, at December
31, 2002, Mr. Mogg held an aggregate of 24,000 restricted shares of Duke
Energy common stock having a value of $468,960. Dividends are paid on
such shares. The vesting of these shares is determined by, among other
things, the performance of Duke Energy.
|---- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    
|(8)  |  | In addition to the 2,878 phantom stock units in note 5, at December
31, 2002, Mr. Borer held an aggregate of 3,390 restricted shares of Duke
Energy common stock having a value of $66,241. Dividends are paid on
such shares. These restricted shares will vest on May 26, 2003.                                                
|    
|(9)  |  | In addition to the 2,878 phantom stock units in note 5, at December
31, 2002, Mr. Bradley held an aggregate of 3,390 restricted shares of
Duke Energy common stock having a value of $66,241. Dividends are paid
on such shares. These restricted shares will vest on May 26, 2003.                                              
|    
|(10) |  | 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.                                                                                                                   
|    
|(11) |  | Represents the following for 2002:                                                                                                                                                                                                                                                                                               



| |  |  | Matching contributions under the Companys 401(k) and Retirement
Plan as follows: J. Mogg, $20,000; M. Borer, $19,000; M. Bradley,
$19,000; R. Martinovich, $19,000.            
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | Make-whole contributions under the Companys Executive Deferred
Compensation Plan as follows: J. Mogg, $72,445; M. Borer, $21,553; M.
Bradley, $21,863; R. Martinovich, $20,963.

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| |  |  | Life Insurance premiums paid by the Company as follows: J. Mogg,
$810; M. Borer, $504; M. Bradley, $504; R. Martinovich, $450.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | Supplemental relocation payments made under the Companys relocation policy as follows: R. Martinovich, $46,833.              
|
| |  |  | Supplemental payment to offset ineligibility for Company benefit plan as follows: W. Slaughter, $58,297.                      

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 have entered into a contract for consulting services with Mr. Slaughter
that terminates in December 2003. The agreement was amended on June 28, 2002.
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, vests on
December 31, 2003 and is exercisable for three years following vesting. The
agreement also provides that Mr. Slaughter will be awarded a long term
incentive award for 2003, that tracks the performance of Duke Energy common
stock. This award will be valued at $406,875 at the time of grant, will vest
December 31, 2003 and is exercisable for three years following vesting. 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, 2002.

This table shows options granted of Duke Energy common stock to the Named
Executive Officers during 2002, along with the present value of the options on
the date they were granted, calculated as described in footnote 2 to the table.

Option/SAR Grants in Last Fiscal Year

|                   |  |                   |        |              |  |                  |   |                 |  |             |       |         |  |            |            |  |  |  |         | 
|------------------ |  | ----------------- | ------ | ------------ |  | ---------------- | - | --------------- |  | ----------- | ----- | ------- |  | ---------- | ---------- |  |  |  | ------- | 
|                   |  | Individual Grants |        |              |  |                 
|                   |  |                   |        |              |  |                 
|                   |  | Number of Shares  |        | % of Total   |  |                  |   |                 |  |             |       |         |  |            |            | 
|                   |  | Underlying        |        | Options/SARS |  |                  |   |                 |  |             |       |         |  | Grant Date
|                   |  | Options/SARS      |        | Granted to   |  | Exercise or Base |   |                 |  |             |       | Present
|Name               |  | Granted(1)(#)     |        | Employees(2) |  | Price ($/Sh)     |   | Expiration Date |  | Value(3)($)
|                   |  |                   |        |              |  |                  |   |                 |  |            
|J. W. Mogg         |  |                   | 7,500  |              |  |                  |  | (5)             |  |             | 38.33 |         |  |            | 1/17/2012  |  |  |  | 80,250  | 
|M. A. Borer        |  |                   | 6,100  |              |  |                  |  | (5)             |  |             | 38.33 |         |  |            | 1/17/2012  |  |  |  | 65,270  | 
|M. J. Bradley      |  |                   | 2,300  |              |  |                  |  | (5)             |  |             | 38.33 |         |  |            | 1/17/2012  |  |  |  | 24,610  | 
|R. F. Martinovich  |  |                   | 0      |              |  |                  |  | (5)             |  |             |      |         |  |            |           |  |  |  |        | 
|W. W. Slaughter(4) |  |                   | 57,492 |              |  |                  |  |                 |  |             | 31.10 |         |  |            | 12/31/2006 |  |  |  | 387,500 | 



---

|(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.
|--- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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|(2) |  | Reflects percentage that the grant represents of the total options
granted to employees of Duke Energy and its subsidiaries during 2002.
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------
|   
|(3) |  | Based on the Black-Scholes option valuation model. The following table
lists key input variables used in valuing the options:           

|                        |  |          |       |  
|----------------------- |  | -------- | ----- | -
|Input Variable:         |  |          |       |  
|Risk-free Interest Rate |  |          | 5.23  | %
|Dividend Yield          |  |          | 3.37  | %
|Stock Price Volatility  |  |          | 29.71 | %
|Option Term             |  | 10 years



|    |  | With respect to all option grants listed in the table, the volatility
variable reflected historical monthly stock price trading date from November
30, 1998 through November 30, 2001. An adjustment was made with respect to
each valuation for a risk of forfeiture during the vesting period. The actual
value, if any, that a grantee may realized 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 option valuation 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).                                                                                                                                                                                                                                                                                                                                                                                                                               
|   
|(5) |  | Less than one percent.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       

OPTION EXERCISES AND YEAR-END VALUES

This table shows aggregate exercises of options for Duke Energy common
stock during 2002 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, 2002, which was $19.5442. The fair market value is
the average of the high and low prices 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 of       |                 |                      |  | 
|                  |  |                 |       |                   |  |               |        |               |  | Securities      |                 |                      |  | 
|                  |  |                 |       |                   |  |               |        |               |  | Underlying      |                 | Value of Unexercised
|                  |  |                 |       |                   |  |               |        |               |  | Unexercised     |                 | In-the-Money        
|                  |  |                 |       |                   |  |               |        |               |  | Options/SARS at |                 | Options/SARS at     
|                  |  |                 |       |                   |  |               |        |               |  | FY-End*(#)      |                 | FY-End($)           
|                  |  |                 |       |                   |  |               |        |               |  |                 |                 |                     
|                  |  | Shares Acquired |       |                   |  |               |        | Exercisable/  |  | Exercisable/   
|Name              |  | on Exercise(#)  |       | Value Realized($) |  | Unexercisable |        | Unexercisable
|                  |  |                 |       |                   |  |               |        |              
|J. W. Mogg        |  |                 | 0     |                   |  |               | 0      |               |  |                 | 206,471/133,517 |                      |  |  | 0/0 | 
|M. A. Borer       |  |                 | 0     |                   |  |               | 0      |               |  |                 | 42,050/37,050   |                      |  |  | 0/0 | 
|M. J. Bradley     |  |                 | 1,899 |                   |  |               | 43,346 |               |  |                 | 35,100/37,250   |                      |  |  | 0/0 | 
|R. F. Martinovich |  |                 | 0     |                   |  |               | 0      |               |  |                 | 27,750/34,650   |                      |  |  | 0/0 | 
|W. W. Slaughter   |  |                 | 0     |                   |  |               | 0      |               |  |                 | 48,720/57,492   |                      |  |  | 0/0 | 



---

|* |  | Neither the Company nor Duke Energy has granted any SARs to the Named
Executive Officers or any other persons.
|- |  | --------------------------------------------------------------------------------------------------------------

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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 Ownership
|                                                             |                                                              |                     
|Duke Energy Corporation                                      |                                                              |                      | 69.7 | %
|                                                             | 526 South Church Street
Charlotte, North Carolina 28201-1006 |                      |      |   | 
|ConocoPhillips                                               |                                                              |                      | 30.3 |  
|                                                             | 600 N. Dairy Ashford
Houston, TX 77079                       |                      |      |  | 
|Jim W. Mogg                                                  |                                                              |                      |     |  
|Mark A. Borer                                                |                                                              |                      |     |  
|Michael J. Bradley                                           |                                                              |                      |     |  
|Robert F. Martinovich                                        |                                                              |                      |     |  
|Philip L. Frederickson                                       |                                                              |                      |     |  
|Fred J. Fowler                                               |                                                              |                      |     |  
|John E. Lowe                                                 |                                                              |                      |     |  
|Richard J. Osborne                                           |                                                              |                      |     |  
|All directors and executive officers as a group
(11 persons) |                                                              |                      |     |  

In August 2000, we issued $300.0 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, 2003,
we redeemed $100.0 million of our preferred members interest by paying cash to
each of our members (Duke Energy and ConocoPhillips) in proportion to their
ownership interests. Duke Energy may be deemed to have dispositive power over
the preferred member interest held by Duke Energy Field Services Investment
Corp., and ConocoPhillips may be deemed to have dispositive power over the
preferred member interest held by Phillips Gas Investment Company.

The Company does not have any equity compensation plans. However,
employees of the Company receive stock options 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 future transactions and
agreements between us and Duke Energy or ConocoPhillips will be at least as
favorable to us as could be

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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.
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.

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 2002,
2001 and 2000, our total revenues from such activities, including amounts
netted in trading and marketing net margin, with Duke Energy and its
subsidiaries, including TEPPCO, were approximately $1,167.1 million, $1,648.5
million, and $1,459.2 million.

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 December 31, 2014. 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, 2002 2001 and 2000, our total
revenues from such activities, including amounts netted in trading and
marketing net margin, with ConocoPhillips and its subsidiaries, and CP Chem
were approximately $1,022.6 million, $1,309.5 million and $942.3 million,
respectively.




ITEM 14. Controls and Procedures

Within the 90 days prior to the date of this report, we carried out an
evaluation, under the supervision and with the participation of the Companys
management, including the Companys Chief Financial Officer and Chief Executive
Officer, of the effectiveness of the design and operation of the Companys
disclosure controls and procedures pursuant to Rule 13a-14 of the Securities
Exchange Act of 1934. Based upon that evaluation, the Chief Financial Officer
and Chief Executive Officer concluded that the Companys

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disclosure controls and procedures are effective in timely alerting them
to material information relating to the Company required to be included in the
Companys periodic SEC reports.

As part of the audit for 2001, our external auditors identified certain
deficiencies in the design and operation of our internal control procedures
that were reportable conditions as defined by the American Institute of
Certified Public Accountants. These conditions were related to balance sheet
reconciliation, supervisory review of such reconciliation, analysis of balance
sheet accounts, imbalances, joint venture accounting, employee benefit accruals
and revenue related functions. Accordingly, the Company significantly improved
its controls related to account reconciliations, including supervisory review
of such account reconciliations. In addition, the Company developed and
implemented an accounting policy related to gas imbalances, and improved the
process for monthly review and tracking of gas imbalances. Many other control
enhancements were made in 2002 related to joint venture accounting, revenue
accounting, NGL accounting, middle office procedures and other areas.

We have also completed a comprehensive account reconciliation project to
review and analyze our balance sheet accounts. The 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 certain charges in the current year as discussed above under
Results of Operations. Management believes 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 resulting 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
recorded in the current years financial statements.

The Company believes it has strengthened its internal controls to ensure
the integrity of its financial statements. Internal control enhancements will
continue over the next several months, however, appropriate detective controls
are in place to prevent material misstatements of financial results and
financial position.

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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,
2002, 2001 and 2000                 
| |  |  | -----------------------------------------------------------------------------------------------------------
|
| |  |  | Consolidated Statements of Comprehensive (Loss) Income for the Years
Ended December 31, 2002, 2001 and 2000
|
| |  |  | Consolidated Statements of Cash Flows for the Years Ended December 31,
2002, 2001 and 2000                 
|
| |  |  | Consolidated Balance Sheets as of December 31, 2002 and 2001                                               
|
| |  |  | Consolidated Statements of Members Equity for the Years Ended December
31, 2002, 2001 and 2000            



| |  | Notes to Consolidated Financial Statements                                                                                                        
| |  | --------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  | Quarterly 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, 2002, 2001 and 2000

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.

Consolidated
Financial Statements of TEPPCO Partners, L.P. are contained in
Exhibit 99.3 to this annual report.

(b)  Reports on Form 8-K

None.

(c)  Exhibits  See Exhibit Index immediately following the signature page.

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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, LLC
| |  |                                 |  |                                                             
| |  | By:                             |  | /s/ JIM W. MOGG                                             
| |  |                                 |  |                                                             
| |  |                                 |  | Jim W. Mogg                                                 
| |  |                                 |  | Chairman of the Board, President and
Chief Executive Officer

March 21, 2003

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/ JIM W. MOGGJim W. Mogg                       |  | Chairman of the Board, President and Chief
Executive Officer (Principal Executive
Officer)
|                                                
|/s/ ROSE M ROBESONRose M. Robeson                |  | Chief Financial Officer (Principal Financial
and Accounting Officer)                      
|                                                
|/s/ PHILIP L. FREDERICKSONPhilip L. Frederickson |  | Director                                                                                  
|                                                
|/s/ FRED J. FOWLERFred J. Fowler                 |  | Director                                                                                  
|                                                
|/s/ JOHN E. LOWEJohn E. Lowe                     |  | Director                                                                                  
|                                                
|/s/ RICHARD J. OSBORNERichard J. Osborne         |  | Director                                                                                  

Date: March 21, 2003

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CERTIFICATIONS

I, Rose M. Robeson certify that:

1.     I have reviewed this annual report on Form 10-K of Duke Energy Field
Services, LLC;

2.     Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3.     Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4.     The registrants other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrants disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the Evaluation Date); and

c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5.     The registrants other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrants auditors and the audit
committee of registrants board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrants ability to record, process,
summarize and report financial data and have identified for the registrants
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrants internal controls;
and

6.     The registrants other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

| |                                                           
| | ----------------------------------------------------------
| | /s/ Rose M. Robeson                                       
| |                                                           
| | Rose M. Robeson
Vice President and Chief Financial Officer

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CERTIFICATIONS

I, Jim W. Mogg certify that:

1.     I have reviewed this annual report on Form 10-K of Duke Energy Field
Services, LLC;

2.     Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3.     Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4.     The registrants other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrants disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the Evaluation Date); and

c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5.     The registrants other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrants auditors and the audit
committee of registrants board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrants ability to record, process,
summarize and report financial data and have identified for the registrants
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrants internal controls;
and

6.     The registrants other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

| |                                                             
| | ------------------------------------------------------------
| | /s/ Jim W. Mogg                                             
| |                                                             
| | Jim W. Mogg                                                 
| | Chairman of the Board, President and
Chief Executive Officer

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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 |  | Description
|               |  |            
|3.1            |  |            |  | 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                                                                                                                                                                                                                                                                                                      

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|               |    |             |  |                                                                                                                                                                                                                                                                                                                                                                                                                 
|-------------- | -- | ----------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit Number |    | Description
|               |    |            
|               |    |             |  | Services, 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          |    |            |  | 364-Day Credit Facility among Duke Energy Field
Services, LLC, Duke Energy Field Services Corporation, Bank
of America, N.A., as Agent and the Lenders named therein,
Dated March 29, 2002 (incorporated by reference to Exhibit 10.1
to Quarterly Report on Form 10-Q of registrant filed on
May 15, 2002).                                                                                                    
|*12.1          |    |            |  | Calculation of Ratio of Earnings to Fixed Charges.                                                                                                                                                                                                                                                                                                                                                              
|*21.1          |    |            |  | Subsidiaries of the Company.                                                                                                                                                                                                                                                                                                                                                                                    
|*23.1          |    |            |  | Consent of Deloitte & Touche LLP.                                                                                                                                                                                                                                                                                                                                                                               
|*23.2          |    |            |  | Consent of KPMG LLP                                                                                                                                                                                                                                                                                                                                                                                             
|*99.1          |    |            |  | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2003.                                                                                                                                                                                                                                                                                         
|*99.2          |    |            |  | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2003.                                                                                                                                                                                                                                                                                         
|*99.3          |    |            |  | Consolidated Financial Statements of TEPPCO Partners, L.P.                                                                                                                                                                                                                                                                                                                                                      

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