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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549


_______________

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended September 30, 2003
    
    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)
    
    76-0632293
(IRS Employer Identification No.)


370 17th Street, Suite 2500
Denver, Colorado 80202
(Address of principal executive offices)
(Zip Code)

303-595-3331
(Registrants telephone number, including area code)

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 and (2) has been subject to such filing
requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant is an accelerated filer as
defined by Rule 12b-2 of the Act.
Yes o No x



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|                                              |                                                                                               |                                                        |  |  |  |  |  | 
|--------------------------------------------- | --------------------------------------------------------------------------------------------- | ------------------------------------------------------ |  |  |  |  |  | 
|PART I. FINANCIAL INFORMATION                
|                                              | Item 1. Financial Statements                                                                 
|                                              |                                                                                               | CONSOLIDATED STATEMENTS OF OPERATIONS                 
|                                              |                                                                                               | CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|                                              |                                                                                               | CONSOLIDATED STATEMENTS OF CASH FLOWS                 
|                                              |                                                                                               | CONSOLIDATED BALANCE SHEETS                           
|                                              |                                                                                               | CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  
|                                              | Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
|                                              | Item 3. Quantitative and Qualitative Disclosure about Market Risks                           
|                                              | Item 4. Controls and Procedures                                                              
|PART II. OTHER INFORMATION                   
|                                              | Item 1. Legal Proceedings                                                                    
|                                              | Item 6. Exhibits and Reports on Form 8-K                                                     
|                                              |                                                                                               | SIGNATURES                                            
|                                              | EXHIBIT INDEX                                                                                
|EX-10.1 IT Consolidation & Services Agreement
|EX-31.1 Certification of CFO to Section 302  
|EX-31.2 Certification of CEO to Section 302  
|EX-32.1 Certification of CFO to Section 906  
|EX-32.2 Certification of CEO to Section 906  



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DUKE ENERGY FIELD SERVICES, LLC
FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2003

INDEX

Item
    
    
    
    PagePART I. FINANCIAL INFORMATION (UNAUDITED)1

    Financial Statements
    
    
    1Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2003 and 2002
    
    
    1Consolidated Statements of Comprehensive Income  (Loss) for the Three and Nine Months Ended September 30, 2003 and 2002
    
    
    2Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2003 and 2002
    
    
    3Consolidated Balance Sheets as of September 30, 2003 and December 31, 2002
    
    
    4Condensed Notes to Consolidated Financial Statements
    
    
    52

    Management's Discussion and Analysis of Financial Condition and Results of Operations
    
    
    183
    Quantitative and Qualitative Disclosure about Market Risks
    
    
    284

    Controls and Procedures
    
    
    32PART II. OTHER INFORMATION1
    Legal Proceedings
    
    
    336
    Exhibits and Reports on Form 8-K
    
    
    33Signatures
    
    
    34


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, will, could, project, believe, anticipate, expect,
estimate, continue, potential, plan, forecast and other similar
words.

All of such statements other than 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 our 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;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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| |  |  | 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, including any potential effects
arising from terrorist attacks, the situation in Iraq and any
consequential hostilities or other hostilities.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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. FINANCIAL INFORMATION

Item 1. Financial Statements

DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(in thousands)

Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2003
    
    2002
    
    2003
    
    2002OPERATING REVENUES:Sales of natural gas and petroleum products
    
    $
    1,342,837
    
    
    $
    641,135
    
    
    $
    4,016,906
    
    
    $
    1,919,765Sales of natural gas and petroleum products-affiliates
    
    
    439,102
    
    
    
    537,776
    
    
    
    1,941,495
    
    
    
    1,511,745Transportation, storage and processing
    
    
    68,880
    
    
    
    62,958
    
    
    
    196,811
    
    
    
    183,232Trading and marketing net margin
    
    
    7,989
    
    
    
    7,643
    
    
    
    (24,802
    )
    
    
    18,471Total operating revenues
    
    
    1,858,808
    
    
    
    1,249,512
    
    
    
    6,130,410
    
    
    
    3,633,213COSTS AND EXPENSES:Purchases of natural gas and petroleum products
    
    
    1,334,511
    
    
    
    861,196
    
    
    
    4,596,428
    
    
    
    2,558,182Purchases of natural gas and petroleum products-affiliates
    
    
    205,208
    
    
    
    125,085
    
    
    
    597,953
    
    
    
    335,744Operating and maintenance
    
    
    112,050
    
    
    
    110,453
    
    
    
    333,009
    
    
    
    320,815Depreciation and amortization
    
    
    74,797
    
    
    
    71,104
    
    
    
    226,875
    
    
    
    211,691General and administrative
    
    
    36,006
    
    
    
    40,367
    
    
    
    102,715
    
    
    
    110,426General and administrative-affiliates
    
    
    6,189
    
    
    
    4,949
    
    
    
    19,238
    
    
    
    13,160Other
    
    
    (286
    )
    
    
    (1,500
    )
    
    
    (444
    )
    
    
    5,595Total costs and expenses
    
    
    1,768,475
    
    
    
    1,211,654
    
    
    
    5,875,774
    
    
    
    3,555,613OPERATING INCOME
    
    
    90,333
    
    
    
    37,858
    
    
    
    254,636
    
    
    
    77,600EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES
    
    
    12,381
    
    
    
    12,566
    
    
    
    36,251
    
    
    
    26,472INTEREST EXPENSE, NET
    
    
    44,803
    
    
    
    37,649
    
    
    
    129,300
    
    
    
    123,253INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
    
    
    57,911
    
    
    
    12,775
    
    
    
    161,587
    
    
    
    (19,181
    )INCOME TAX EXPENSE
    
    
    2,369
    
    
    
    1,061
    
    
    
    4,421
    
    
    
    6,675INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE CUMULATIVE
EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
    
    
    55,542
    
    
    
    11,714
    
    
    
    157,166
    
    
    
    (25,856
    )GAIN (LOSS) FROM DISCONTINUED OPERATIONS
    
    
    
    
    
    
    326
    
    
    
    32,357
    
    
    
    (448
    )CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
    
    
    
    
    
    
    
    
    
    
    (22,802
    )
    
    
    NET INCOME (LOSS)
    
    
    55,542
    
    
    
    12,040
    
    
    
    166,721
    
    
    
    (26,304
    )DIVIDENDS ON PREFERRED MEMBERS INTEREST
    
    
    
    
    
    
    6,703
    
    
    
    9,500
    
    
    
    20,953EARNINGS (DEFICIT) AVAILABLE FOR MEMBERS INTEREST
    
    $
    55,542
    
    
    $
    5,337
    
    
    $
    157,221
    
    
    $
    (47,257
    )


See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
(in thousands)

Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2003
    
    2002
    
    2003
    
    2002NET INCOME (LOSS)
    
    $
    55,542
    
    
    $
    12,040
    
    
    $
    166,721
    
    
    $
    (26,304
    )OTHER COMPREHENSIVE INCOME (LOSS):Foreign currency translation adjustment
    
    
    326
    
    
    
    (17,641
    )
    
    
    45,385
    
    
    
    (6,534
    )Net unrealized losses on cash flow hedges
    
    
    (4,775
    )
    
    
    (41,640
    )
    
    
    (66,016
    )
    
    
    (103,079
    )Reclassification of (gains) losses from
cash flow hedges into earnings
    
    
    25,058
    
    
    
    9,017
    
    
    
    91,284
    
    
    
    (6,975
    )Total other comprehensive income (loss)
    
    
    20,609
    
    
    
    (50,264
    )
    
    
    70,653
    
    
    
    (116,588
    )TOTAL COMPREHENSIVE INCOME (LOSS)
    
    $
    76,151
    
    
    $
    (38,224
    )
    
    $
    237,374
    
    
    $
    (142,892
    )


See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)

Nine Months EndedSeptember 30,2003
    
    2002CASH FLOWS FROM OPERATING ACTIVITIES:Net income (loss)
    
    $
    166,721
    
    
    $
    (26,304
    )Adjustments to reconcile net income (loss) to net cash provided by
operating activities:(Gain) loss on discontinued operations
    
    
    (32,357
    )
    
    
    448Cumulative effect of changes in accounting principles
    
    
    22,802
    
    
    
    Depreciation and amortization
    
    
    226,875
    
    
    
    211,691Deferred income taxes
    
    
    1,090
    
    
    
    1,968Equity in earnings of unconsolidated affiliates
    
    
    (36,251
    )
    
    
    (26,472
    )Other, net
    
    
    8,136
    
    
    
    (707
    )Change in operating assets and liabilities which provided (used) cash:Accounts receivable
    
    
    (78,383
    )
    
    
    (62,824
    )Accounts receivable-affiliates
    
    
    130,220
    
    
    
    145,375Inventories
    
    
    20,002
    
    
    
    (12,962
    )Net unrealized loss (gain) on mark-to-market and hedging transactions
    
    
    (35,027
    )
    
    
    59,479Other current assets
    
    
    (11,603
    )
    
    
    4,456Other noncurrent assets
    
    
    (3,574
    )
    
    
    (4,486
    )Accounts payable
    
    
    (2,838
    )
    
    
    (26,865
    )Accounts payable-affiliates
    
    
    (17,416
    )
    
    
    (10,992
    )Accrued interest payable
    
    
    (28,597
    )
    
    
    (32,984
    )Other current liabilities
    
    
    15,878
    
    
    
    31,055Other long term liabilities
    
    
    8,087
    
    
    
    11,264Net cash provided by continuing operations
    
    
    353,765
    
    
    
    261,140Net cash provided by discontinued operations
    
    
    8,619
    
    
    
    6,240Net cash provided by operating activities
    
    
    362,384
    
    
    
    267,380CASH FLOWS FROM INVESTING ACTIVITIES:Capital expenditures
    
    
    (98,038
    )
    
    
    (235,764
    )Investment expenditures, net of cash acquired
    
    
    (534
    )
    
    
    2,646Investment distributions
    
    
    46,727
    
    
    
    38,328Contributions to minority interests, net
    
    
    (956
    )
    
    
    Proceeds from sales of discontinued operations
    
    
    90,173
    
    
    
    Proceeds from sales of assets
    
    
    20,087
    
    
    
    12,420Net cash provided by (used in) continuing operations
    
    
    57,459
    
    
    
    (182,370
    )Net cash used in discontinued operations
    
    
    (2,946
    )
    
    
    (2,614
    )Net cash provided by (used in) investing activities
    
    
    54,513
    
    
    
    (184,984
    )CASH FLOWS FROM FINANCING ACTIVITIES:Distributions to members
    
    
    (34
    )
    
    
    (63,164
    )Redemption of preferred members interest (debt)
    
    
    (125,000
    )
    
    
    (100,000
    )Debt issue costs
    
    
    
    
    
    
    (1,209
    )Short term debt, net
    
    
    (215,094
    )
    
    
    103,023Payment of debt
    
    
    (550
    )
    
    
    (448
    )Payment of dividends
    
    
    (9,500
    )
    
    
    (14,250
    )Net cash used in continuing operations
    
    
    (350,178
    )
    
    
    (76,048
    )Net cash used in discontinued operations
    
    
    
    
    
    
    Net cash used in financing activities
    
    
    (350,178
    )
    
    
    (76,048
    )EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH
    
    
    (1,126
    )
    
    
    (6,534
    )NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    
    
    65,593
    
    
    
    (186
    )CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
    
    
    24,783
    
    
    
    4,906CASH AND CASH EQUIVALENTS, END OF PERIOD
    
    $
    90,376
    
    
    $
    4,720Cash paid for interest (net of amounts capitalized)
    
    $
    152,720
    
    
    $
    156,999


See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands)

September 30,
    
    December 31,2003
    
    2002ASSETSCURRENT ASSETS:Cash and cash equivalents
    
    $
    90,376
    
    
    $
    24,783Accounts receivable:Customers, net
    
    
    687,029
    
    
    
    595,445Affiliates
    
    
    29,027
    
    
    
    159,587Other
    
    
    38,643
    
    
    
    50,466Inventories
    
    
    43,357
    
    
    
    86,559Unrealized gains on mark-to-market and hedging transactions
    
    
    97,522
    
    
    
    158,891Other
    
    
    18,545
    
    
    
    6,713Total current assets
    
    
    1,004,499
    
    
    
    1,082,444PROPERTY, PLANT AND EQUIPMENT, NET
    
    
    4,493,395
    
    
    
    4,642,204INVESTMENT IN AFFILIATES
    
    
    112,798
    
    
    
    128,947INTANGIBLE ASSETS:Natural gas liquids sales and purchases contracts, net
    
    
    83,112
    
    
    
    84,304Goodwill, net
    
    
    444,270
    
    
    
    435,115Total intangible assets
    
    
    527,382
    
    
    
    519,419UNREALIZED GAINS ON MARK-TO-MARKET AND HEDGING TRANSACTIONS
    
    
    31,430
    
    
    
    21,685OTHER NONCURRENT ASSETS
    
    
    103,996
    
    
    
    89,504TOTAL ASSETS
    
    $
    6,273,500
    
    
    $
    6,484,203LIABILITIES AND MEMBERS EQUITYCURRENT LIABILITIES:Accounts payable:Trade
    
    $
    686,700
    
    
    $
    680,536Affiliates
    
    
    4,522
    
    
    
    21,938Other
    
    
    36,784
    
    
    
    45,786Short term debt
    
    
    5,360
    
    
    
    215,094Unrealized losses on mark-to-market and hedging transactions
    
    
    117,725
    
    
    
    245,469Accrued interest payable
    
    
    30,704
    
    
    
    59,294Accrued taxes
    
    
    31,239
    
    
    
    31,059Other
    
    
    96,736
    
    
    
    89,427Total current liabilities
    
    
    1,009,770
    
    
    
    1,388,603DEFERRED INCOME TAXES
    
    
    14,829
    
    
    
    11,740LONG TERM DEBT
    
    
    2,340,282
    
    
    
    2,255,508UNREALIZED LOSSES ON MARK-TO-MARKET AND HEDGING TRANSACTIONS
    
    
    27,643
    
    
    
    15,336OTHER LONG TERM LIABILITIES
    
    
    81,126
    
    
    
    37,633MINORITY INTERESTS
    
    
    121,447
    
    
    
    124,820PREFERRED MEMBERS INTEREST
    
    
    
    
    
    
    200,000COMMITMENTS AND CONTINGENT LIABILITIESMEMBERS EQUITY:Members interest
    
    
    1,709,290
    
    
    
    1,709,290Retained earnings
    
    
    963,306
    
    
    
    806,119Accumulated other comprehensive income (loss)
    
    
    5,807
    
    
    
    (64,846
    )Total members equity
    
    
    2,678,403
    
    
    
    2,450,563TOTAL LIABILITIES AND MEMBERS EQUITY
    
    $
    6,273,500
    
    
    $
    6,484,203


See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. General

Duke Energy Field Services, LLC (with its consolidated subsidiaries, the
Company or Field Services LLC) operates in the two principal segments of
the midstream natural gas industry of (1) natural gas gathering, compression,
treatment, processing, transportation, trading and marketing and storage; and
(2) natural gas liquids (NGLs), fractionation, transportation, and trading
and marketing. Duke Energy Corporation (Duke Energy) owns 69.7% of the
Companys outstanding member interests and ConocoPhillips owns the remaining
30.3%.

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 have the ability to
exercise control, in which case, they are accounted for using the equity
method.

These Consolidated Financial Statements reflect all normal recurring
adjustments that are, in the opinion of management, necessary to present fairly
the financial position and results of operations and cash flows for the
respective periods. Amounts reported in the interim Consolidated Statements of
Operations are not necessarily indicative of amounts expected for the
respective annual periods.

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, marketing and sales
commitments. Inventories are recorded at the lower of cost or market value
using the average cost method. Historically, since January 2001, natural gas
storage arbitrage inventories were marked-to-market. However, effective January
1, 2003, in accordance 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 is now recorded at the lower of cost or
market using the average cost method (see New Accounting Standards below).

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

Effective January 1, 2003, in connection with the implementation of the
remaining provisions of EITF Issue No. 02-03, the Company designates each
energy commodity derivative as either trading or non-trading. Certain
non-trading derivatives are further designated as either a hedge of a
forecasted transaction or future cash flow (cash flow hedge), a hedge of a
recognized asset, liability or firm commitment (fair value hedge), or a normal
purchase or sale contract, while certain non-trading derivatives remain
undesignated.

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

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

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

See the New Accounting Standards section below for a discussion of the
implications of EITF 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 fair value of a derivative designated and
qualified as a cash flow hedge is recorded in the Consolidated Balance Sheets
as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging
Transactions. The effective portion of the change in fair value of a
derivative designated and qualified as a cash flow hedge is included in the
Consolidated Balance Sheets as Accumulated Other Comprehensive Income (Loss)
(AOCI) until earnings are affected by the hedged item. Settlement amounts of
cash flow hedges are removed from AOCI and recorded in the Consolidated
Statements of Operations in the same accounts as the item being hedged. The
Company discontinues hedge accounting prospectively when it is determined that
the derivative no longer qualifies as an effective hedge, or when it is no
longer probable that the hedged transaction will occur. When hedge accounting
is discontinued because the derivative no longer qualifies as an effective
hedge, the derivative continues to be carried on the Consolidated Balance
Sheets at its fair value, with subsequent changes in its fair value recognized
in current period earnings. Gains and losses related to discontinued hedges
that were previously accumulated in AOCI will remain in AOCI until earnings are
affected by the hedged item, unless it is no longer probable that the hedged
transaction will occur, in which case, the gains and losses that were
accumulated in AOCI 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 periodically 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 swaps 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 swaps, no ineffectiveness will be recognized.

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Income Taxes- The Company follows the asset and liability method of
accounting for income taxes. The Company is a limited liability company, which
is a pass-through entity for United States income tax purposes. Income tax
expense represents federal, state and foreign taxes associated with tax-paying
subsidiaries.

The Company is required to make quarterly distributions to Duke
Energy and ConocoPhillips based on allocated taxable income. The distributions
are 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.

Stock-Based Compensation- Under Duke Energys 1998 Long Term Incentive
Plan, stock options for Duke Energys common stock may be granted to the
Companys key employees. The Company accounts for stock-based compensation
using the intrinsic value recognition and measurement principles of Accounting
Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to
Employees, and FASB Interpretation No. 44, Accounting for Certain
Transactions Involving Stock Compensation (an Interpretation of APB Opinion No.
25). Since the exercise price for all options granted under those plans was
equal to the market value of the underlying common stock on the date of grant,
no compensation cost is recognized in the accompanying Consolidated Statements
of Operations. Restricted stock grants, phantom stock awards and stock-based
performance awards are recorded over the required vesting period as
compensation cost, based on the market value on the date of grant. The
following disclosures reflect the provisions of SFAS No. 148, Accounting for
Stock-Based Compensation  Transition and Disclosure  an amendment of FASB
Statement No. 123.

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

Pro Forma Stock-Based Compensation
    
    Three months ended
    
    Nine month ended(in thousands)
    
    September 30,
    
    September 30,2003
    
    2002
    
    2003
    
    2002Earnings (Deficit) available for
members interest, as reported
    
    $
    55,542
    
    
    $
    5,337
    
    
    $
    157,221
    
    
    $
    (47,257
    )Add: stock-based compensation
expense included in reported net
income (loss)
    
    
    80
    
    
    
    277
    
    
    
    717
    
    
    
    892Deduct: total stock-based
compensation expense determined
under fair value-based method for
all awards
    
    
    (1,245
    )
    
    
    (1,784
    )
    
    
    (4,485
    )
    
    
    (5,541
    )Pro forma earnings (deficit)
available for members interest
    
    $
    54,377
    
    
    $
    3,830
    
    
    $
    153,453
    
    
    $
    (51,906
    )


Accumulated Other Comprehensive Income (Loss) The components of and
changes in accumulated other comprehensive income (loss) are as follows:

Net
    
    AccumulatedAccumulated Other Comprehensive
    
    Foreign
    
    Unrealized
    
    OtherIncome (Loss)
    
    Currency
    
    (Losses) Gains on
    
    Comprehensive(in thousands)
    
    Adjustments
    
    Cash Flow Hedges
    
    (Loss) IncomeBalance as of December 31, 2002
    
    $
    (6,728
    )
    
    $
    (58,118
    )
    
    $
    (64,846
    )Other comprehensive income
changes during the period
    
    
    45,385
    
    
    
    25,268
    
    
    
    70,653Balance as of September 30, 2003
    
    $
    38,657
    
    
    $
    (32,850
    )
    
    $
    5,807


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Cumulative Effect of Changes in Accounting Principles- The Company
adopted SFAS No. 143, Accounting for Asset Retirement Obligations, on January
1, 2003. In accordance with the transition provisions of SFAS No. 143, the
Company recorded asset retirement liabilities and a cumulative-effect
adjustment of $17.4 million as a reduction in earnings. In addition, in
accordance with the EITFs October 2002 consensus on Issue No. 02-03, on
January 1, 2003, the Company decreased its inventories from fair value to
historical cost and recorded a $5.4 million cumulative-effect adjustment as a
reduction in earnings.

New Accounting Standards- In May 2003, the FASB issued SFAS No. 150,
Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity. SFAS No. 150 requires that certain financial
instruments that could previously be accounted for as equity, be classified as
liabilities in the consolidated balance sheets and initially recorded at fair
value. In addition to its requirements for the classification and measurement
of financial instruments in its scope, SFAS No. 150 also requires disclosures
about the nature and terms of the financial instruments and about alternative
ways of settling the instruments. The provisions of SFAS No. 150 are effective
for all financial instruments entered into or modified after May 31, 2003, and
are otherwise effective at the beginning of the first interim period beginning
after June 15, 2003. Upon adoption on July 1, 2003, the Company reclassified
its preferred members interest, which are mandatorily redeemable, of $200.0
million from mezzanine equity to long term debt and prospectively classified
accrued or paid distributions on these securities, which had previously been
classified as dividends, as interest expense. Interest expense for the three
months ended September 30, 2003 on these securities was approximately $4.4
million. During the third quarter of 2003, the Company redeemed $125.0 million
of these securities in cash and the current outstanding balance at September
30, 2003 was $75.0 million.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133
on Derivative Instruments and Hedging Activities, which amends and clarifies
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities under SFAS No. 133.
SFAS No. 149 clarifies the discussion around initial net investment, clarifies
when a derivative contains a financing component, and amends the definition of
an underlying to conform it to language used in FIN 45, Guarantors Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others. In addition, SFAS No. 149 also incorporates certain of
the Derivative Implementation Group Implementation Issues. The provisions of
SFAS No. 149 are effective for contracts entered into or modified after June
30, 2003 and for hedging relationships designated after June 30, 2003. The
guidance is to be applied to hedging relationships on a prospective basis. The
Company does not anticipate SFAS No. 149 will have a material impact on its
consolidated results of operations, cash flows or financial position.

In January 2003, the FASB issued Interpretation No. 46 (FIN 46),
Consolidation of Variable Interest Entities. 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 and/or receives a majority of
the expected residual returns of the variable interest entitys activities. FIN
46 is immediately applicable 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 by the first fiscal year or interim period beginning after December 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 has not identified
any material variable interest entities created, or interests in variable
interest entities obtained, after January 31, 2003 and continues to assess the
existence of any interests in variable interest entities created on or prior to
January 31, 2003. The Company currently anticipates certain entities,
previously accounted for under the equity method of accounting, will be
consolidated under the provisions of FIN 46 as of December 31, 2003. These
entities, which are substantive operating entities, have total assets of
approximately $94.2 million at September 30, 2003 and total revenues of
approximately $32.2 million for the nine months ended September 30, 2003. The
Companys maximum exposure to loss as a result of its involvement with these
entities is approximately $84.2 million at September 30, 2003. The Company
continues to assess FIN 46 but does not anticipate that it will have a material
impact on its consolidated results of operations, cash flows or financial
position. The FASB continues to interpret the provisions of FIN 46 and has
issued an exposure draft to amend certain provisions of FIN 46 which is
expected to become effective in the fourth quarter of 2003. Until such

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interpretations and amendments are finalized, the Company is not able to
conclude as to whether such future changes would be likely to materially affect
its consolidated results of operations, cash flows or financial position.

In November 2002, the FASB issued Interpretation No. 45 (FIN 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 adopted the initial
recognition and measurement provisions of FIN 45 effective January 1, 2003.
Adoption of the new interpretation had no material effect on the Companys
consolidated results of operations, cash flows or financial position.

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 as purchases in costs and
expenses, in accordance with prevailing industry practice.

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, must now be recorded at the lower of cost or market and are reported on
an accrual basis resulting in the recognition of earnings or losses at the time
of contract settlement or termination. New non-derivative energy trading
contracts entered into after October 25, 2002 should be accounted for under the
accrual accounting basis. Non-derivative energy trading contracts on the
Consolidated Balance Sheet as of January 1, 2003 that existed at October 25,
2002 and inventories that were recorded at fair values have been adjusted to
the lower of historical cost or market 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 on 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 other than for energy trading
contracts that were shown on a net basis under Issue No. 98-10. Accordingly,
for the three and nine months ended September 30, 2003, derivative instruments
that are held for trading and marketing purposes and are accounted for under
mark-to-market accounting are included in Trading and Marketing Net Margin on
the Consolidated Statements of Operations. For the three and nine months ended
September 30, 2002, Trading and Marketing Net Margin also includes the net
margin on non-derivative energy trading contracts (primarily gas storage
inventories and the related physical purchases and sales) that no longer
qualify for net presentation after the rescission of Issue No. 98-10. The new
gross versus net revenue presentation requirements had no impact on operating
income or net income.

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

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On June 25, 2003, the FASB cleared the guidance contained in DIG Issue
C20, Scope Exceptions: Interpretation of the Meaning of Not Clearly and
Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment
Feature. DIG Issue C20, which applies only to the guidance in paragraph 10(b)
of FASB No. 133 and not in reference to embedded derivatives, describes three
circumstances in which the underlying in a price adjustment incorporated into
a contract that otherwise satisfies the requirements for the normal purchases
and normal sales exception would be considered to be not clearly and closely
related to the asset being sold or purchased. The guidance in DIG Issue C20 is
effective for the Company on October 1, 2003. The Company does not anticipate
that this Issue will have a material impact on its consolidated results of
operations, cash flows 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
increases due to the passage of time based on the time value of money until the
obligation is settled. The Company adopted the provisions of SFAS 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.

In May 2003, the EITF reached consensus in EITF Issue No. 01-08,
Determining Whether an Arrangement Contains a Lease, to clarify the
requirements of identifying whether an arrangement should be accounted for as a
lease at its inception. The guidance in the consensus is designed to mandate
reporting revenue as rental or leasing income that otherwise would be reported
as part of product sales or service revenue. EITF Issue No. 01-08 requires both
parties to an arrangement to determine whether a service contract or similar
arrangement is or includes a lease within the scope of SFAS No. 13, Accounting
for Leases. The consensus is to be applied prospectively to arrangements
agreed to, modified, or acquired in business combinations in fiscal periods
beginning on July 1, 2003. The Company does not anticipate that the adoption of
EITF Issue No. 01-08 will have a material effect on its consolidated results of
operations, cash flows or financial position.

Reclassifications- Certain prior period amounts have been reclassified in
the Consolidated Financial Statements and notes thereto to conform to the
current presentation.

3. Derivative Instruments, Hedging Activities, Credit and Risk

Commodity price risk- The Companys principal operations of gathering,
processing, transportation, trading and marketing, and storage of natural gas,
and the accompanying operations of fractionation, transportation, and 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 gas. Risk is also dependent on the types and mechanisms for sales
of natural gas and NGLs 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.

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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 debt. 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 transactions where the Company is exposed to credit risk, the
Company analyzes the counterparties financial condition prior to entering into
an agreement, establishes credit limits and monitors the appropriateness of
these limits on an ongoing basis. The corporate credit policy prescribes the
use of master collateral agreements to mitigate credit exposure. The collateral
agreements provide for a counterparty to post cash or letters of credit for
exposure in excess of the established threshold. The threshold amount
represents an open credit limit, determined in accordance with the corporate
credit policy. The collateral agreements also provide that the failure 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 capital, maintenance 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 prices of NGLs, natural gas and
other energy-related products. For the nine months ended September 30, 2003,
the Company recognized a net loss of $86.3 million, of which a $5.0 million
gain represented the total ineffectiveness of all cash flow hedges and a $91.3
million loss represented the total derivative settlements. No derivative gains
or losses were reclassified from AOCI to current period earnings as a result of
the discontinuance of cash flow hedges related to any forecasted transactions
that are not probable of occurring.

Gains and losses on derivative contracts that are reclassified from AOCI
to current period earnings are included in the line item in which the hedged
item is recorded. As of September 30, 2003, $31.7 million of the deferred net
losses on derivative instruments in AOCI are expected to be reclassified into
earnings during the next 12 months as the hedge transactions occur; however,
due to the volatility of the commodities markets, the corresponding value in
AOCI is subject to change prior to its reclassification into earnings. The
maximum term over which the Company is hedging its exposure to the variability
of future cash flows is 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
hedges 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).

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For the nine months ended September 30, 2003, the gains or losses
representing the ineffective portion of the Companys fair value hedges were
not significant. All components of each derivatives gain or loss are included
in the assessment of hedge effectiveness, unless otherwise noted. The Company
did not have any firm commitments that no longer qualified as fair value hedge
items and therefore, did not recognize an associated gain or loss.

Interest
rate fair value hedges In October 2001, the Company entered
into an interest rate swap to convert the fixed interest rate of $250.0 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
London Interbank Offered Rate (LIBOR), which is re-priced semiannually
through 2005. In August 2003, the Company entered into two additional interest
rate swaps to convert the fixed interest rate of $100.0 million of debt
securities issued on August 16, 2000 to floating rate debt. These interest
rate fair value hedges are also at a floating rate based on six-month LIBOR,
which is re-priced semiannually through 2030. The swaps meet conditions which
permit the assumption of no ineffectiveness, as defined by SFAS No. 133. As
such, for the life of the swaps no ineffectiveness will be recognized. As of
September 30, 2003, the fair value of the interest rate swaps of $17.8 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.

Commodity
Derivatives  Trading and Marketing The trading and marketing
of energy related products and services exposes the Company to the fluctuations
in the market values of traded and marketed instruments. The Company manages
its traded and marketed instrument portfolios 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 value at risk
measurement.

4. Asset Retirement Obligations

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.
The Companys asset retirement obligations relate primarily to the retirement
of various gathering pipelines and processing facilities, obligations related
to right-of-way easement agreements and contractual leases for land use.

SFAS 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
increases due to the passage of time based on the time value of money until the
obligation is settled.

The Company identified various assets as having an indeterminate life in
accordance with SFAS No. 143, which do not trigger a requirement to establish a
fair value for future retirement obligations associated with such assets. These
assets include certain pipelines, gathering systems and processing facilities.
A liability for these asset retirement obligations will be recorded if and when
a future retirement obligation is identified.

SFAS No. 143 was effective for fiscal years beginning after June 15, 2002,
and was adopted by the Company on January 1, 2003. At January 1, 2003, the
implementation of SFAS No. 143 resulted in a net increase in total assets of
$25.1 million, consisting of an increase in net property, plant and equipment.
Long term liabilities increased by $42.5 million, which represents the
establishment of an asset retirement obligation liability. A cumulative-effect
of a change in accounting principle adjustment of $17.4 million was recorded in
the first quarter of 2003, as a reduction in earnings.

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The following table shows the asset retirement obligation liability as
though SFAS No. 143 had been in effect for the prior three years.

Pro forma Asset Retirement Obligation (in thousands)January 1, 2000
    
    $
    13,493December 31, 2000
    
    
    31,561December 31, 2001
    
    
    38,879December 31, 2002
    
    
    42,549


The asset retirement obligation is adjusted each quarter for any
liabilities incurred or settled during the period, accretion expense and any
revisions made to the estimated cash flows. The following table rolls forward
the asset retirement obligation from the balance at December 31, 2002 to
September 30, 2003.

Reconciliation of Asset Retirement Obligation (in thousands)Balance as of January 1, 2003
    
    $
    42,549Accretion expense
    
    
    2,581Other
    
    
    (703
    )Balance as of September 30, 2003
    
    $
    44,427


5. Financing

Credit Facility with Financial Institutions On March 28, 2003, the
Company entered into a new credit facility (the Facility). The Facility
replaces the credit facility that matured on March 28, 2003. The Facility is
used to support the Companys commercial paper program and for working capital
and other general corporate purposes. The Facility matures on March 26, 2004;
however, any outstanding loans under the Facility at maturity may, at the
Companys option, be converted to a one-year term loan. The Facility is a
$350.0 million revolving credit facility, of which $100.0 million can be used
for letters of credit. The Facility requires the Company to maintain at all
times a debt to total capitalization ratio of less than or equal to 53%; and
maintain at the end of each fiscal quarter an interest coverage ratio (defined
to be the ratio of adjusted EBITDA, as defined by the Facility, for the four
most recent quarters to interest expense for the same period) of at least 2.5
to 1 (adjusted EBITDA, as defined by the Facility, is defined to be earnings
before interest, taxes and depreciation and amortization and other
adjustments); and contains various restrictions applicable to dividends and
other payments to the Companys members. The Facility bears interest at a rate
equal to, at the Companys option and based on the Companys current debt
rating, either (1) LIBOR plus 1.25% per year or (2) the higher of (a) the JP
Morgan Chase Bank prime rate plus 0.25% per year and (b) the Federal Funds rate
plus 0.75% per year. At September 30, 2003, there were no borrowings or letters
of credit drawn against the Facility.

On March 28, 2003, the Company also entered into a $100.0 million funded
short-term loan with a bank (the Short-Term Loan). The Short-Term Loan was
used for working capital and other general corporate purposes. The Short-Term
Loan matured on September 30, 2003, and was able to be repaid at any time prior
to that date. The Short-Term Loan had the same financial covenants as the
Facility and bore interest at a rate equal to, at the Companys option, either
(1) LIBOR plus 1.35% per year or (2) the higher of (a) the banks prime rate
and (b) the Federal Funds rate plus 0.50% per year. During the three months
ended September 30, 2003, the Company repaid the entire Short-Term Loan with
funds generated from asset sales and operations.

On November 3, 2003, subsequent to the end of the third quarter, the
Company executed a $32.0 million irrevocable standby letter of credit expiring
on May 15, 2004 to be used to secure transaction exposure with a counterparty.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity.
SFAS No. 150 requires that certain financial instruments that could previously
be accounted for as equity, be classified as liabilities in the balance sheets
and initially recorded at fair value. Upon adoption on July 1, 2003, the
Company reclassified its preferred members interest of $200.0 million from
mezzanine equity to long term debt. These mandatorily redeemable securities pay
a cumulative preferential distribution of 9.5% per annum which are mandatorily
payable semi-annually, unless deferred. These securities must be redeemed in
cash no later than August 2030 or upon the Companys consummation of an initial
public

13



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offering of equity securities. During the third quarter of 2003, the
Company redeemed $125.0 million of these securities and the outstanding balance
at September 30, 2003 is $75.0 million. Beginning on July 1, 2003, accrued or
paid distributions previously classified as dividends on these securities are
prospectively classified as interest expense. Interest expense for the three
months ended September 30, 2003 on these securities was approximately $4.4
million.

6. Commitments and Contingent Liabilities

The midstream industry has seen a number of class action lawsuits
involving royalty disputes, mismeasurement and mispayment allegations. Although
the industry has seen these types of cases before, they were typically brought
by a single plaintiff or small group of plaintiffs. A number of these cases are
now being brought as class actions. The Company and its subsidiaries are
currently named as defendants in some of these cases. Management believes the
Company and its subsidiaries have meritorious defenses to these cases, and
therefore will continue to defend them vigorously. However, these class actions
can be costly and time consuming to defend. Management believes that 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.

7. Business Segments

The Company operates in two principal business segments as follows: (1)
natural gas gathering, compression, treatment, processing, transportation,
trading and marketing, and storage (Natural Gas Segment), and (2) NGLs
fractionation, transportation, and trading and marketing (NGLs Segment).
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. The following table includes the components of the performance
measures used 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 not separately identified.

14



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

Three
    
    NineMonths Ended
    
    Months EndedSeptember 30,
    
    September 30,2003
    
    2002
    
    2003
    
    2002(in thousands)Operating revenues (a):Natural Gas, including trading and marketing net margin
    
    $
    1,971,018
    
    
    $
    1,252,882
    
    
    $
    6,324,923
    
    
    $
    3,614,074NGLs, including trading and marketing net margin
    
    
    440,462
    
    
    
    350,987
    
    
    
    1,392,567
    
    
    
    990,199Intersegment (b)
    
    
    (552,672
    )
    
    
    (354,357
    )
    
    
    (1,587,080
    )
    
    
    (971,060
    )Total operating revenues
    
    $
    1,858,808
    
    
    $
    1,249,512
    
    
    $
    6,130,410
    
    
    $
    3,633,213Margin:Natural Gas, including trading and marketing net margin
    
    $
    306,569
    
    
    $
    247,242
    
    
    $
    899,335
    
    
    $
    696,629NGLs, including trading and marketing net margin
    
    
    12,520
    
    
    
    15,989
    
    
    
    36,694
    
    
    
    42,658Total margin
    
    $
    319,089
    
    
    $
    263,231
    
    
    $
    936,029
    
    
    $
    739,287Other operating and administrative costs:Natural Gas
    
    $
    116,933
    
    
    $
    111,702
    
    
    $
    333,414
    
    
    $
    324,384NGLs
    
    
    2,043
    
    
    
    2,408
    
    
    
    6,363
    
    
    
    7,183Corporate
    
    
    34,983
    
    
    
    40,159
    
    
    
    114,741
    
    
    
    118,429Total other operating costs
    
    $
    153,959
    
    
    $
    154,269
    
    
    $
    454,518
    
    
    $
    449,996Depreciation and amortization:Natural Gas
    
    $
    62,984
    
    
    $
    63,845
    
    
    $
    199,722
    
    
    $
    194,860NGLs
    
    
    2,529
    
    
    
    1,923
    
    
    
    9,206
    
    
    
    7,546Corporate
    
    
    9,284
    
    
    
    5,336
    
    
    
    17,947
    
    
    
    9,285Total depreciation and amortization
    
    $
    74,797
    
    
    $
    71,104
    
    
    $
    226,875
    
    
    $
    211,691Equity in earnings of unconsolidated affiliates:Natural Gas
    
    $
    12,055
    
    
    $
    12,004
    
    
    $
    36,310
    
    
    $
    24,523NGLs
    
    
    326
    
    
    
    562
    
    
    
    (59
    )
    
    
    1,949Total equity in earnings of unconsolidated affiliates
    
    $
    12,381
    
    
    $
    12,566
    
    
    $
    36,251
    
    
    $
    26,472Total corporate interest expense
    
    $
    44,803
    
    
    $
    37,649
    
    
    $
    129,300
    
    
    $
    123,253Income (loss) from continuing operations before income taxes:Natural Gas
    
    $
    138,707
    
    
    $
    83,699
    
    
    $
    402,509
    
    
    $
    201,908NGLs
    
    
    8,274
    
    
    
    12,220
    
    
    
    21,066
    
    
    
    29,878Corporate
    
    
    (89,070
    )
    
    
    (83,144
    )
    
    
    (261,988
    )
    
    
    (250,967
    )Total income (loss) from continuing operations before
income taxes
    
    $
    57,911
    
    
    $
    12,775
    
    
    $
    161,587
    
    
    $
    (19,181
    )Capital expenditures:Natural Gas
    
    $
    27,794
    
    
    $
    66,574
    
    
    $
    93,215
    
    
    $
    216,000NGLs
    
    
    424
    
    
    
    1,270
    
    
    
    476
    
    
    
    8,166Corporate
    
    
    2,170
    
    
    
    2,717
    
    
    
    4,347
    
    
    
    11,598Total capital expenditures
    
    $
    30,388
    
    
    $
    70,561
    
    
    $
    98,038
    
    
    $
    235,764


As ofSeptember 30,
    
    December 31,2003
    
    2002(in thousands)Total assets:Natural Gas
    
    $
    5,049,540
    
    
    $
    5,136,967NGLs
    
    
    252,797
    
    
    
    293,398Corporate (c)
    
    
    971,163
    
    
    
    1,053,838Total assets
    
    $
    6,273,500
    
    
    $
    6,484,203




---

|(a) |  | As a result of the Companys review of its segment information, the
Company has reclassified certain operating revenues from the NGLs Segment
to the Natural Gas Segment and Intersegment for the three and nine months
ended September 30, 2002. These reclassifications had no effect on segment
margin. For the three months ended September 30, 2002, these
reclassifications resulted in an increase to the Natural Gas Segment
revenues of approximately $152.8 million, an increase to the NGLs Segment
revenues of approximately $24.5 million and a decrease to Intersegment
revenues of approximately $177.3 million. For the nine months ended
September 30, 2002, these reclassifications resulted in an increase to the
Natural Gas Segment revenues of approximately $489.7
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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|    |  | million, a decrease to the NGLs Segment revenues of approximately $362.4
million and a decrease to Intersegment revenues of approximately $127.3
million.                                                                                              
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | 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.
|   
|(c) |  | Includes items such as unallocated working capital, intercompany accounts
and intangible and other assets.                                                                                                                                             

8. Guarantors Obligations Under Guarantees

At September 30, 2003, the Company was the guarantor of approximately
$91.0 million of debt associated with non-consolidated entities, of which $84.6
million is related to our 33.33% ownership interest in Discovery Producer
Services, LLC (Discovery), and $6.4 million is related to our 50.0% ownership
interest in GPM Gas Gathering, LLC (GGG). The guaranteed debt related to
Discovery is due December 31, 2003, and is expected to be either refinanced or
repaid. The guaranteed debt related to GGG is scheduled to be repaid in full by
January 31, 2004. 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
September 30, 2003, the Company had no liability recorded for the guarantees of
the debt associated with the unconsolidated subsidiaries.

The Company periodically enters into agreements for the acquisition or
divestiture of assets. These agreements contain indemnification provisions that
may provide indemnity for environmental, tax, employment, outstanding
litigation, breaches of representations, warranties and covenants, or other
liabilities related to the assets being acquired or divested. Typically, claims
may be made by third parties under these indemnification agreements for various
periods of time depending on the nature of the claim. The effective periods on
these indemnification provisions generally have terms of one to five years,
although some are longer. The Companys maximum potential exposure under these
indemnification agreements can range depending on the nature of the claim and
the particular transaction. The Company is unable to estimate the total
maximum potential amount of future payments under indemnification agreements
due to several factors, including uncertainty as to whether claims will be made
under these indemnities. At September 30, 2003, the Company had a liability of
approximately $1.3 million recorded for these outstanding indemnification
provisions.

9. Accounting Adjustments

During 2002, the Company 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 accounting; and other
balance sheet accounts. As a result of this account reconciliation project, the
Company recorded numerous adjustments in 2002. For the three and nine months
ended September 30, 2002, adjustments totaling approximately $18 million and
$47 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 were made in the first nine months 2002 financial statements.

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10. Asset Sales

In the second quarter of 2003, the Company sold various gathering,
transmission and processing assets, plus a minority interest in a partnership
owning a gas processing plant, to two separate buyers for a combined sales
price of approximately $90.2 million. These assets were included in the
Companys Natural Gas Segment as disclosed in Note 7. These assets comprised a
component of the Company for purposes of reporting discontinued operations.
All prior period operations have been revised to reflect these assets as
discontinued operations.

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

Three
    
    NineMonths Ended
    
    Months EndedSeptember 30,
    
    September 30,2003
    
    2002
    
    2003
    
    2002(in thousands)Revenues
    
    $
    
    
    
    $
    49,286
    
    
    $
    160,096
    
    
    $
    134,731Operating income (loss)
    
    $
    
    
    
    $
    326
    
    
    $
    6,150
    
    
    $
    (448
    )Gain on sale
    
    
    
    
    
    
    
    
    
    
    26,207
    
    
    
    Gain (loss) from discontinued operations
    
    $
    
    
    
    $
    326
    
    
    $
    32,357
    
    
    $
    (448
    )


In July 2003, the Company entered into an agreement to sell approximately
900 vehicles for approximately $14 million. This is a sale-leaseback
transaction whereby the Company sold the vehicles but will lease them back over
a one-year lease term. The lease expires in July 2004, with subsequent annual
extensions exercisable at the Companys option. The future minimum lease
payments under the lease are approximately $15 million. The Company does not
have an option to purchase the leased vehicles at the end of the minimum lease
term. As the proceeds from the sale of the vehicles were equal to the net book
value of the vehicles, no gain or loss was recognized.

In August 2003, the Company entered into a purchase and sale agreement to
sell certain gas gathering and processing plant assets in West Texas to a third
party purchaser for a sales price of approximately $62 million. The
transaction was to be closed on September 30, 2003; however, the purchaser was
unable to meet the conditions of closing. In October 2003, subsequent to the
end of the third quarter, the Company entered into a new purchase and sale
agreement for the sale of these assets to a party related to the original third
party purchaser for a sales price of approximately $62 million. The
transaction is scheduled to close in December 2003 with no significant book
gain or loss.

11. Subsequent Events

On October 30, 2003, the Company communicated a voluntary and involuntary
severance program to its employees which is effective November 3, 2003 and will
be substantially completed by December 31, 2003. The Company anticipates a
reduction of approximately 6% of the Companys total workforce and will incur a
total charge of approximately $5 million to $10 million in the fourth quarter
of 2003 related to this program.

For information on subsequent events related to financing matters, see
Note 5, Financing, and related to asset sales, see Note 10, Asset Sales.

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##### Table of Contents






Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations

The following discussion details the material factors that affected our
historical financial condition and results of operations during the three and
nine months ended September 30, 2003 and 2002. This discussion should be read
in conjunction with the Consolidated Financial Statements and related notes
included elsewhere in this report.

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
the first nine months of 2003, approximately 82% of our operating
revenues prior to intersegment revenue elimination and approximately 96%
of our gross margin were derived from this segment.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | NGLs fractionation, transportation, and trading and marketing, from
which we generate revenues from transportation fees, market center
fractionation and the trading and marketing of NGLs (the NGLs
Segment). In the first nine months of 2003, approximately 18% of our
operating revenues prior to intersegment revenue elimination and
approximately 4% of our gross margin were derived from this segment.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Our limited liability company agreement limits the scope of our business
to the midstream industry in the United States and Canada, the marketing of
NGLs in Mexico and the transportation, marketing and storage of other petroleum
products, unless otherwise approved by our board of directors. This limitation
in scope is not currently expected to materially impact the results of our
operations.

Effects of Commodity Prices

We are exposed to commodity prices as a result of being paid for certain
services in the form of commodities rather than cash. For gathering services,
depending on the type of contractual agreement, we receive fees or commodities
from the producers to bring the raw natural gas from the well head to the
processing plant. For processing services, we either receive fees or
commodities as payment for these services, depending on the type of contractual
agreement. Based on our current contract mix, we have a long NGLs position and
are sensitive to changes in NGLs prices. We also have a short natural gas
position; however, the short natural gas position is less significant than the
long NGLs position.

We are also exposed to changes in commodity prices as a result of our NGLs
and natural gas trading activities. NGLs trading includes trading and storage
at the Mont Belvieu, Texas and Conway, Kansas NGLs market centers to manage our
price risk and provide additional services to our customers. Natural gas
trading activities are supported by our ownership of a natural gas storage
facility and various intrastate pipelines. 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
also execute NGLs proprietary trading, which includes commodities such as
natural gas, NGLs, crude oil and refined products, based upon our knowledge and
expertise obtained through the operation of our assets and our position as a
leading NGLs marketer.

During the first nine months of 2003, approximately 75% of our gross
margin was generated by commodity sensitive processing arrangements and
approximately 25% of our gross margin was generated by fee-based arrangements
and trading and marketing activities. We actively manage our commodity exposure
as discussed below.

The midstream industry is cyclical, with the operating results of
companies in the industry significantly affected by the prevailing price of
NGLs, which in turn has historically 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

18



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##### Table of Contents



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 NGLs 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 by the demand
generated by growth in the world economy. However, the relationship or
correlation between crude oil prices and NGLs prices declined significantly
during 2001 and 2002. In late 2002, this relationship strengthened and remained
near historical trend levels during the first nine months of 2003.

We believe that future natural gas prices will be influenced by supply
deliverability, the severity of weather and the level of economic growth in the
United States. 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 natural gas rigs drilling in the United States increased to 931
during the third quarter of 2003 from 724 during the third quarter of 2002.
This increase is mainly attributable to recent significant increases in natural
gas prices which could result in sustained increases in drilling activity
during 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 NGLs contracts to hedge the value of our assets and
operations from such price risks. See Item 3. Quantitative and Qualitative
Disclosure About Market Risk. Our third quarter 2003 and 2002 results of
operations include a hedging loss of $23.1 million and $5.0 million,
respectively. During the first nine months of 2003 and 2002 our hedging
activities resulted in a loss of $86.3 million and a loss of $5.9 million,
respectively. The hedging losses incurred relate to hedges placed during
periods of lower prices.

Results of Operations

Three Months Ended September 30,
    
    Nine Months Ended September 30,2003
    
    2002
    
    2003
    
    2002(in thousands)Operating revenues:Sales of natural gas and petroleum products
    
    $
    1,781,939
    
    
    $
    1,178,911
    
    
    $
    5,958,401
    
    
    $
    3,431,510Transportation, storage and processing
    
    
    68,880
    
    
    
    62,958
    
    
    
    196,811
    
    
    
    183,232Trading and marketing net margin
    
    
    7,989
    
    
    
    7,643
    
    
    
    (24,802
    )
    
    
    18,471Total operating revenues
    
    
    1,858,808
    
    
    
    1,249,512
    
    
    
    6,130,410
    
    
    
    3,633,213Purchases of natural gas and petroleum products
    
    
    1,539,719
    
    
    
    986,281
    
    
    
    5,194,381
    
    
    
    2,893,926Gross margin (a)
    
    
    319,089
    
    
    
    263,231
    
    
    
    936,029
    
    
    
    739,287Cost and expenses
    
    
    228,756
    
    
    
    225,373
    
    
    
    681,393
    
    
    
    661,687Equity in earnings of unconsolidated affiliates
    
    
    12,381
    
    
    
    12,566
    
    
    
    36,251
    
    
    
    26,472Gain (loss) from discontinued operations
    
    
    
    
    
    
    326
    
    
    
    32,357
    
    
    
    (448
    )Cumulative effect of changes in accounting
principles
    
    
    
    
    
    
    
    
    
    
    (22,802
    )
    
    
    EBIT (b)
    
    
    102,714
    
    
    
    50,750
    
    
    
    300,442
    
    
    
    103,624Interest expense, net
    
    
    44,803
    
    
    
    37,649
    
    
    
    129,300
    
    
    
    123,253Income tax expense
    
    
    2,369
    
    
    
    1,061
    
    
    
    4,421
    
    
    
    6,675Net income (loss)
    
    $
    55,542
    
    
    $
    12,040
    
    
    $
    166,721
    
    
    $
    (26,304
    )




---

|(a) |  | Gross margin consists of operating income before operating and
maintenance expense, depreciation and amortization expense, general and
administrative expense, and other expense. 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 our earnings.                                                                                                                                               
|--- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | EBIT consists of net income before net interest expense and income tax
expense. EBIT is viewed as a non-Generally Accepted Accounting Principles
(GAAP) measure under the rules of the Securities and Exchange
Commission, but is included as a supplemental disclosure because it is a
primary performance measure used by management as it represents the
results without regard to financing methods or capital structure. As an
indicator of our operating performance, EBIT should not be considered an
alternative to, or more

19



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| |  | meaningful than, net income or cash flow as determined in accordance with
GAAP. Our EBIT may not be comparable to a similarly titled measure of
another company because other entities may not calculate EBIT in the same
manner.
| |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Three months ended September 30, 2003 compared with three months ended September 30, 2002

Operating Revenues Total operating revenues increased $609.3 million, or
49%, to $1,858.8 million in the third quarter of 2003 from $1,249.5 million in
2002. Of this increase, approximately $603.0 million was the result of higher
sales of natural gas and petroleum products due mainly to higher commodity
prices. Other increases were attributable to transportation, storage and
processing fees of approximately $5.9 million which was primarily due to
increased fee revenue associated with our Canadian operations.

Purchases
of Natural Gas and Petroleum Products Purchases of natural gas
and petroleum products increased $553.4 million, or 56%, to $1,539.7 million in
the third quarter of 2003 from $986.3 million in 2002. Purchases increased by
approximately $569 million primarily due to higher commodity prices. This
increase was offset by approximately $16 million of non-recurring charges from
the third quarter of 2002 as discussed below.

Gross Margin Gross margin increased $55.9 million or 21%, to $319.1
million in the third quarter of 2003 from $263.2 million in 2002. Of this
increase, approximately $45 million (net of hedging) was the result of a $.10
per gallon increase in average NGLs prices. This increase was offset by an
approximate $24 million decrease in gross margin due to a $1.79 per million
British thermal units (Btus) increase in natural gas prices. During the third
quarter of 2003, we elected to reduce levels of keep-whole processing
activities from time to time through operational optionality and contract
renegotiation due to lower historical and forecasted processing profit margins.
These elections and contract restructuring efforts increased gross margin by
approximately $15 million and are not reflected in the above pricing impacts.
Average prices in the third quarter of 2003 were $.49 per gallon for NGLs and
$4.97 per million Btus for natural gas as compared with $.39 per gallon for
NGLs and $3.18 per million Btus for natural gas during the same period in 2002.
Other increases of approximately $3 million relate to our physical natural
gas asset based trading and marketing activity as discussed below.

Other increases in gross margin of approximately $16 million resulted from
non-recurring charges incurred during the third quarter of 2002 for reserves
for gas imbalances with suppliers and customers of approximately $13 million,
storage and miscellaneous other charges including items related to our account
reconciliation project and the resolution of disputed receivables and payables
of approximately $3 million. There were no similar charges during the third
quarter of 2003.

Gross margin associated with the Natural Gas Segment increased $59.4
million, or 24%, to $306.6 million in the third quarter of 2003 from $247.2
million in the same period of 2002, mainly as a result of higher commodity
prices. Commodity sensitive processing arrangements accounted for approximately
$36 million (net of hedging) of this increase due mainly to the increase in
average NGLs prices along with our election to reduce levels of keep-whole
processing activities and contract renegotiation efforts offset by the increase
in average natural gas prices. Also contributing to this increase was a $0.5
million increase in trading and marketing net margin associated with derivative
settlements and marked-to-market valuations of unsettled contracts related to
our gas trading and marketing activities. Natural gas trading and marketing
net margin excludes approximately $3 million of increases in gross margin
realized during the third quarter of 2003 on our physical natural gas asset
based trading and marketing activity. Gross margin associated with this
segment also increased by approximately $16 million resulting from
non-recurring charges incurred during the third quarter of 2002 related to
reserves for gas imbalances with suppliers and customers and charges related to
completion of our account reconciliation project as discussed above.

Costs and Expenses Operating and maintenance expenses increased $1.6
million, or 1%, to $112.1 million in the third quarter of 2003 from $110.5
million in the same period of 2002. This increase is mainly the result of
increased expenditures for environmental compliance of $1.0 million. General
and administrative expenses decreased $3.1 million, or 7%, to $42.2 million in
the third quarter of 2003, from $45.3 million in the same period of 2002. This
decrease is primarily the result of lower expenditures for core business
process improvement projects.

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Depreciation and amortization expenses increased $3.7 million, or 5%, to
$74.8 million in the third quarter of 2003 from $71.1 million in the same
period of 2002. This increase was due primarily to ongoing capital expenditures
for well connections, facility maintenance and enhancements, and the
implementation of SFAS No. 143.

Interest Expense, net Interest expense, net increased $7.2 million, or
19% to $44.8 million in the third quarter of 2003 from $37.6 million in the
same period of 2002. This increase was primarily the result of the
implementation of SFAS No. 150 requiring reclassification as interest expense
disbursements of approximately $4.4 million that were previously classified as
dividends on the Companys preferred members interest. Also contributing to
this increase were higher capitalized interest adjustments in the third quarter
of 2002 of approximately $4.2 million, partially offset by lower outstanding
debt levels and higher cash investments in the third quarter of 2003.

Income Taxes We are structured as a limited liability company, which is
a pass-through entity for United States income tax purposes. Income tax expense
increased $1.3 million to $2.4 million in the third quarter of 2003 from $1.1
million in the same period of 2002 due primarily to increased earnings
associated with tax-paying subsidiaries.

Nine months ended September 30, 2003 compared with nine months ended September 0, 2002

Operating Revenues Total operating revenues increased $2,497.2 million,
or 69%, to $6,130.4 million in the first nine months of 2003 from $3,633.2
million in the same period of 2002. Of this increase, approximately $2,526.9
million was the result of higher sales of natural gas and petroleum products
due mainly to higher commodity prices. Other increases were attributable to
transportation, storage and processing fees of approximately $13.6 million
which was primarily due to increased fee revenue associated with our Canadian
operations. These increases were partially offset by a decrease in trading and
marketing net margin of $43.3 million.

Purchases
of Natural Gas and Petroleum Products Purchases of natural gas
and petroleum products increased $2,300.5 million, or 79%, to $5,194.4 million
in the first nine months of 2003 from $2,893.9 million in the same period of
2002. Purchases increased by approximately $2,343 million primarily due to
higher commodity prices. This increase was offset by approximately $42 million
of non-recurring charges during 2002 as discussed below.

Gross Margin Gross margin increased $196.7 million or 27%, to $936.0
million in the first nine months of 2003 from $739.3 million in the same period
of 2002. Of this increase, approximately $241 million (net of hedging) was the
result of a $.16 per gallon increase in average NGLs prices. This increase was
offset by an approximate $113 million decrease in gross margin due to a $2.69
per million British thermal units (Btus) increase in natural gas prices.
During the first nine months of 2003, we elected to reduce levels of keep-whole
processing activities from time to time through operational optionality and
contract renegotiation due to lower historical and forecasted processing profit
margins. These elections and contract restructuring efforts increased gross
margin by approximately $41 million and are not reflected in the above pricing
impacts. Average prices in the first nine months of 2003 were $.52 per gallon
for NGLs and $5.66 per million Btus for natural gas as compared with $.36 per
gallon for NGLs and $2.97 per million Btus for natural gas during the same
period in 2002. Partially offsetting the increase in gross margin was a $43.3
million decrease in trading and marketing net margin. Other increases of
approximately $26 million relate to our physical natural gas asset based
trading and marketing activity as discussed below. Gross margin during the
first nine months of 2003 was negatively impacted by approximately $8 million
related to the January 2003 settlement of contract litigation with General Gas
Company, LP.

Other increases in gross margin of approximately $48 million resulted from
non-recurring charges incurred during the first nine months of 2002 for
reserves for gas imbalances with suppliers and customers of $25 million,
storage inventory writedown of $6 million and miscellaneous other charges
including items related to our account reconciliation project and the
resolution of disputed receivables and payables of $17 million. There were no
similar charges during the third quarter of 2003.

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Gross margin associated with the Natural Gas Segment increased $202.7
million, or 29%, to $899.3 million in the first nine months of 2003 from $696.6
million in the same period of 2002, mainly as a result of higher commodity
prices. Commodity sensitive processing arrangements accounted for approximately
$169 million (net of hedging) of this increase due mainly to the increase in
average NGLs prices along with our election to reduce levels of keep-whole
processing activities offset by the increase in average natural gas prices.
Offsetting this increase was a $31.9 million decrease in trading and marketing
net margin associated with derivative settlements and marked-to-market
valuations of unsettled contracts related to our gas trading and marketing
activities. Natural gas trading and marketing net margin excludes approximately
$26 million of increases in gross margin realized during the first nine months
of 2003 on our physical natural gas asset based trading and marketing activity.
Gross margin associated with this segment also increased approximately $48
million resulting from non-recurring charges incurred during the first nine
months of 2002 related to reserves for gas imbalances with suppliers and
customers, a writedown of storage inventory and charges related to completion
of our account reconciliation project as discussed above. Gross margin during
the first nine months of 2003 was negatively impacted by approximately $8
million related to the January 2003 settlement of contract litigation with
General Gas Company, LP.

Gross margin associated with the NGLs Segment decreased $6.0 million, or
14% to $36.7 million in the first nine months of 2003 from $42.7 million in the
same period of 2002. This decrease was comprised of an $11.4 million decrease
in trading and marketing net margin offset by increases in the northeast
wholesale propane marketing and terminals margin of $1 million and from the
operation of a newly constructed pipeline in south Texas of $2 million.

Costs and Expenses Operating and maintenance expenses increased $23.2
million, or 7%, (excluding $11 million in first nine months 2002 accounting
adjustments  see Note 9 to Consolidated Financial Statements) to $333.0
million in the first nine months of 2003 from $309.8 million in the same period
of 2002. Contributing to this increase were increased expenditures for facility
maintenance and pipeline repair of approximately $10 million, environmental
compliance of $6 million, accretion expense associated with SFAS No. 143
implementation (see Notes 2 and 4 to Consolidated Financial Statements) of $3
million, higher utilities of $1 million and increased costs associated with our
Canadian operations.

Depreciation and amortization expenses increased $15.2 million, or 7%, to
$226.9 million in the first nine months of 2003 from $211.7 million in the same
period of 2002. This increase was due primarily to ongoing capital expenditures
for well connections, facility maintenance and enhancements, and the
implementation of SFAS No. 143.

Other costs and expenses decreased $6.0 million to a gain of $0.4 million
in the first nine months of 2003 from a charge of $5.6 million in the first
nine months of 2002. This decrease is due primarily to the first nine months
2002 accounting adjustment of $6.8 million primarily for the recognition of a
loss on the sale of assets associated with a partnership investment (see Note 9
to Consolidated Financial Statements).

Equity in Earnings of Unconsolidated Affiliates Equity in earnings of
unconsolidated affiliates increased $9.8 million, or 37%, to $36.3 million in
the first nine months of 2003 from $26.5 million in the same period of 2002.
This increase is primarily the result of increased earnings from our general
partnership interest in TEPPCO Partners, L.P. (TEPPCO) of $7.7 million and
increased earnings from the 2002 acquisition of an interest in Discovery
Producer Services, LLC (Discovery) located in offshore Gulf of Mexico of $4.0
million, partially offset by other equity investments.

Interest Expense, net Interest expense, net increased $6.0 million, or
5%, to $129.3 million in the first nine months of 2003 from $123.3 million in
the same period of 2002. This increase was primarily the result of the third
quarter 2003 implementation of SFAS No. 150 requiring reclassification as
interest expense disbursements of approximately $4.4 million that were
previously classified as dividends on the Companys preferred members
interest. Also contributing to this increase were higher capitalized interest
adjustments in the third quarter of 2002 of approximately $3.7 million,
partially offset by lower outstanding debt levels and higher cash investments
in the first nine months of 2003.

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Income Taxes We are structured as a limited liability company, which is
a pass-through entity for United States income tax purposes. Income tax expense
decreased $2.3 million to $4.4 million in the first nine months of 2003 from
$6.7 million in the same period of 2002 due primarily to lower earnings
associated with tax-paying subsidiaries.

Gain
(Loss) From Discontinued Operations Gain (loss) from discontinued
operations increased $32.8 million, to a gain of $32.4 million in the first
nine months of 2003 from a $0.4 million loss in the same period of 2002. This
increase is primarily the result of the gain on the sale of various natural gas
gathering and processing assets (see Note 10 to the Consolidated Financial
Statements).

Cumulative Effect of Changes in Accounting Principles Cumulative effect
of changes in accounting principles was a loss of $22.8 million in the first
nine months of 2003 and no charge in the first nine months of 2002. Of this
amount, $17.4 million relates to the implementation of SFAS No. 143, and $5.4
million is due to the rescission of EITF 98-10 (see Note 2 to Consolidated
Financial Statements).

Liquidity and Capital Resources

As of September 30, 2003, we had $90.4 million in cash and cash
equivalents compared to $24.8 million as of December 31, 2002. Our working
capital was a $5.3 million deficit as of September 30, 2003, compared to a
$306.2 million deficit as of December 31, 2002. We rely upon cash flows from
operations and borrowings to fund our liquidity and capital requirements. A
material adverse change in operations or available financing may impact our
ability to fund our current liquidity and capital resource requirements.

Operating Cash Flows

During the first nine months of 2003, funds of $362.4 million were
provided by operating activities, an increase of $95.0 million from $267.4
million in the first nine months of 2002. The increase is primarily due to an
increase in net income, offset by the gain on discontinued operations, changes
in equity in earnings of unconsolidated affiliates and changes in unrealized
mark-to-market and hedging activity.

Volatility in crude oil, NGLs and natural gas prices has a direct impact
on our generation and use of cash from operations due to its impact on net
income as described in the Effects of Commodity Prices section above, along
with the resulting changes in working capital.

Investing Cash Flows

During the first nine months of 2003, funds of $54.5 million were provided
by investing activities, an increase of $239.5 million from $185.0 million of
funds used in investing activities during the first nine months of 2002. The
increase is partially related to proceeds of $90.2 million from sales of
discontinued operations. Our capital expenditures consist of expenditures for
construction of additional gathering systems, processing plants, fractionators
and other facilities and infrastructure in addition to well connections and
upgrades to our existing facilities and acquisitions. For the first nine months
of 2003, we spent approximately $98.0 million on capital expenditures of
continuing operations compared to $235.8 million in the first nine months of
2002. The decrease is due to reduced plant expansions, well connections and
plant upgrades in 2003, as compared to 2002.

Our level of capital expenditures for acquisitions and construction
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 $46.7 million in cash
distributions to us during the first nine months of 2003 compared with $38.3
million during the first nine months of 2002.

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Financing Cash Flows

On March 28, 2003, we entered into a new credit facility (the Facility).
The Facility replaces the credit facility that matured on March 28, 2003. The
Facility is used to support our commercial paper program and for working
capital and other general corporate purposes. The Facility matures on March 26,
2004; however; any outstanding loans under the Facility at maturity may, at our
option, be converted to a one-year term loan. The Facility is a $350.0 million
revolving credit facility, of which $100.0 million can be used for letters of
credit. The Facility requires us to maintain at all times a debt to total
capitalization ratio of less than or equal to 53%; and maintain at the end of
each fiscal quarter an interest coverage ratio (defined to be the ratio of
adjusted EBITDA, as defined by the Facility, for the four most recent quarters
to interest expense for the same period) of at least 2.5 to 1 (adjusted EBITDA
is defined by the Facility to be earnings before interest, taxes and
depreciation and amortization and other adjustments); and contains various
restrictions applicable to dividends and other payments to our members. The
Facility bears interest at a rate equal to, at our option and based on our
current debt rating, either (1) LIBOR plus 1.25% per year or (2) the higher of
(a) the JP Morgan Chase Bank prime rate plus 0.25% per year and (b) the Federal
Funds rate plus 0.75% per year. At September 30, 2003, there were no borrowings
or letters of credit drawn against the Facility.

On March 28, 2003, we also entered into a $100.0 million funded short-term
loan with a bank (the Short-Term Loan). The Short-Term Loan was used for
working capital and other general corporate purposes. The Short-Term Loan
matured on September 30, 2003, and was able to be repaid at any time prior to
that date. The Short-Term Loan had the same financial covenants as the Facility
and bore interest at a rate equal to, at our option, either (1) LIBOR plus
1.35% per year or (2) the higher of (a) the banks prime rate and (b) the
Federal Funds rate plus 0.50% per year. During the three months ended September
30, 2003, we repaid this entire loan with funds generated from asset sales and
operations.

On November 3, 2003, subsequent to the end of the third quarter, we
executed a $32.0 million irrevocable standby letter of credit expiring on May
15, 2004 to be used to secure transaction exposure with a counterparty.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity.
SFAS No. 150 requires that certain financial instruments that could previously
be accounted for as equity, be classified as liabilities in the balance sheets
and initially recorded at fair value. Upon adoption on July 1, 2003, we
reclassified our preferred members interest of $200.0 million from mezzanine
equity to long term debt. These mandatorily redeemable securities pay a
cumulative preferential distribution of 9.5% per annum which are mandatorily
payable semi-annually, unless deferred. The securities must be redeemed in cash
no later than August 2030 or upon our consummation of an initial public
offering of equity securities. During the third quarter of 2003, we redeemed
$125.0 million of the securities and the outstanding balance at September 30,
2003 is $75.0 million. Beginning on July 1, 2003, accrued or paid
distributions previously classified as dividends on the preferred members
interest are prospectively classified as interest expense. Interest expense
for the three months ended September 30, 2003 on the preferred members
interest was approximately $4.4 million.

At September 30, 2003, we had no outstanding commercial paper. In the
future, our debt levels will vary depending on our liquidity needs, capital
expenditures and cash flow.

In April 2002, we filed a shelf registration statement increasing our
ability to issue securities to $500.0 million. The shelf registration statement
provides for the issuance of senior notes, subordinated notes and trust
preferred securities.

Based on current and anticipated levels of operations, we believe that our
cash on hand and cash flow from operations, combined with borrowings available
under the commercial paper program and the 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 that we may make. Our
ability to meet current and anticipated operating requirements will depend on
our future performance.

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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 will record
a reserve if events occur requiring one to be established.

At September 30, 2003, we were the guarantor of approximately $91.0
million of debt associated with nonconsolidated entities, of which $84.6
million related to our 33.33% ownership interest in Discovery and $6.4 million
is related to our 50.0% ownership interest in GPM Gas Gathering, LLC (GGG).
The guaranteed debt related to Discovery is due December 31, 2003, and is
expected to be either refinanced or repaid. The guaranteed debt related to GGG
is scheduled to be repaid in full by January 31, 2004. 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 September 30, 2003, we had no liability recorded
for the guarantees of the debt associated with the unconsolidated subsidiaries.

We periodically enter into agreements for the acquisition or divestiture
of assets. These agreements contain indemnification provisions that may provide
indemnity for environmental, tax, employment, outstanding litigation, breaches
of representations, warranties and covenants, or other liabilities related to
the assets being acquired or divested. Typically, claims may be made by third
parties under these indemnification agreements for various periods of time
depending on the nature of the claim. The effective periods on these
indemnification provisions generally have terms of one to five years, although
some are longer. Our maximum potential exposure under these indemnification
agreements can range depending on the nature of the claim and the particular
transaction. We are unable to estimate the total maximum potential amount of
future payments under indemnification agreements due to several factors,
including uncertainty as to whether claims will be made under these
indemnities. At September 30, 2003, we had a liability of approximately $1.3
million recorded for these outstanding indemnification provisions.

New Accounting Standards

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity.
SFAS No. 150 requires that certain financial instruments that could previously
be accounted for as equity, be classified as liabilities in the consolidated
balance sheets and initially recorded at fair value. In addition to its
requirements for the classification and measurement of financial instruments in
its scope, SFAS No. 150 also requires disclosures about the nature and terms of
the financial instruments and about alternative ways of settling the
instruments. The provisions of SFAS No. 150 are effective for all financial
instruments entered into or modified after May 31, 2003, and are otherwise
effective at the beginning of the first interim period beginning after June 15,
2003. Upon adoption on July 1, 2003, we reclassified our preferred members
interest, which are mandatorily redeemable, of $200.0 million from mezzanine
equity to long term debt and prospectively classified accrued or paid
distributions on the preferred members interest, which had previously been
classified as dividends, as interest expense. Interest expense for the three
months ended September 30, 2003 on the preferred members interest was
approximately $4.4 million. During the third quarter of 2003, we redeemed
$125.0 million of the securities in cash and the current outstanding balance at
September 30, 2003 was $75.0 million.

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

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hedging relationships on a prospective basis. We do not anticipate SFAS
No. 149 will have a material impact on our consolidated results of operations,
cash flows or financial position.

In January 2003, the FASB issued Interpretation No. 46 (FIN 46),
Consolidation of Variable Interest Entities. 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 and/or receives a majority of
the expected residual returns of the variable interest entitys activities. FIN
46 is immediately applicable 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 by the first fiscal year or interim period beginning after December 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. We have not identified any
material variable interest entities created, or interests in variable interest
entities obtained, after January 31, 2003 and continue to assess the existence
of any interests in variable interest entities created on or prior to January
31, 2003. We currently anticipate certain entities, previously accounted for
under the equity method of accounting, will be consolidated under the
provisions of FIN 46 as of December 31, 2003. These entities, which are
substantive operating entities, have total assets of approximately $94.2
million at September 30, 2003 and total revenues of approximately $32.2 million
for the nine months ended September 30, 2003. Our maximum exposure to loss as
a result of its involvement with these entities is approximately $84.2 million
at September 30, 2003. We continue to assess FIN 46 but do not anticipate that
it will have a material impact on our consolidated results of operations, cash
flows or financial position. The FASB continues to interpret the provisions of
FIN 46 and has issued an exposure draft to amend certain provisions of FIN 46
which is expected to become effective in the fourth quarter of 2003. Until such
interpretations and amendments are finalized, we are not able to conclude as to
whether such future changes would be likely to materially affect our
consolidated results of operations, cash flows or financial position.

In November 2002, the FASB issued Interpretation No. 45 (FIN 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 adopted the initial
recognition and measurement provisions of FIN 45 effective January 1, 2003.
Adoption of the new interpretation had no material effect on our consolidated
results of operations, cash flows or financial position.

In June 2002, the EITF reached a partial consensus on 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. We had previously chosen to report
certain of our energy trading contracts on a gross basis, as sales in operating
revenues and the associated costs recorded as purchases in costs and expenses,
in accordance with prevailing industry practice.

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, must now be recorded at the lower of cost or market and are reported on
an accrual basis resulting in the recognition of earnings or losses at the time
of contract settlement or termination. New non-derivative energy trading
contracts entered into after October 25, 2002 should be accounted for under the
accrual accounting basis. Non-derivative energy trading contracts on the
Consolidated Balance Sheet as of January 1, 2003 that existed at October 25,
2002 and inventories that were recorded at fair values have been adjusted to
the lower of historical cost or market 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.

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In October 2002, the EITF also reached a consensus on 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 other than for energy trading
contracts that were shown on a net basis under Issue No. 98-10. Accordingly,
for the three and nine months ended September 30, 2003, derivative instruments
that are held for trading and marketing purposes and are accounted for under
mark-to-market accounting are included in Trading and Marketing Net Margin on
the Consolidated Statements of Operations. For the three and nine months ended
September 30, 2002, Trading and Marketing Net Margin also includes the net
margin on non-derivative energy trading contracts (primarily gas storage
inventories and the related physical purchases and sales) that no longer
qualify for net presentation after the rescission of Issue No. 98-10. The new
gross versus net revenue presentation requirements had no impact on operating
income or net income.

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

On June 25, 2003, the FASB cleared the guidance contained in DIG Issue
C20, Scope Exceptions: Interpretation of the Meaning of Not Clearly and
Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment
Feature. DIG Issue C20, which applies only to the guidance in paragraph 10(b)
of FASB No. 133 and not in reference to embedded derivatives, describes three
circumstances in which the underlying in a price adjustment incorporated into
a contract that otherwise satisfies the requirements for the normal purchases
and normal sales exception would be considered to be not clearly and closely
related to the asset being sold or purchased. The guidance in DIG Issue C20 is
effective for us on October 1, 2003. We do not anticipate that this Issue will
have a material impact on our consolidated results of operations, cash flows 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
increases due to the passage of time based on the time value of money until the
obligation is settled. We adopted the provisions of SFAS 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.

In May 2003, the EITF reached consensus in EITF Issue No. 01-08,
Determining Whether an Arrangement Contains a Lease, to clarify the
requirements of identifying whether an arrangement should be accounted for as a
lease at its inception. The guidance in the consensus is designed to mandate
reporting revenue as rental or leasing income that otherwise would be reported
as part of product sales or service revenue. EITF Issue No. 01-08 requires both
parties to an arrangement to determine whether a service contract or similar
arrangement is or includes a lease within the scope of SFAS No. 13, Accounting
for Leases. The consensus is to be applied prospectively to arrangements
agreed to, modified, or acquired in business combinations in fiscal periods
beginning on July 1, 2003. We do not anticipate that the adoption of EITF Issue
No. 01-08 will have a material effect on our consolidated results of
operations, cash flows or financial position.

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Subsequent Events

In August 2003, we entered into a purchase and sale agreement to sell
certain gas gathering and processing plant assets in West Texas to a third
party purchaser for a sales price of approximately $62 million. The
transaction was to be closed on September 30, 2003; however, the purchaser was
unable to meet the conditions of closing. In October 2003, subsequent to the
end of the third quarter, we entered into a new purchase and sale agreement
for the sale of these assets to a party related to the original third party
purchaser for a sales price of approximately $62 million. The transaction is
scheduled to close in December 2003 with no significant book gain or loss.

On October 30, 2003, we communicated a voluntary and involuntary severance
program to our employees which is effective November 3, 2003 and will be
substantially completed by December 31, 2003. We anticipate a reduction of
approximately 6 % of our total workforce and will incur a total charge of
approximately $5 million to $10 million in the fourth quarter of 2003 related
to this program.

For information on subsequent events related to financing matters, see the
Financing Cash Flows section above.




Item 3. Quantitative and Qualitative Disclosure about Market Risks

Risk Policies

We are exposed to market risks associated with commodity prices, credit
exposure, interest rates and foreign currency exchange rates. Management has
established comprehensive risk management policies to monitor and manage these
market risks. Our 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 our 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 commodity price risk and various other risks,
including monitoring exposure limits.

Commodity Price Risk

We are exposed to the impact of market fluctuations primarily in the price
of natural gas and 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 3 to the Consolidated Financial Statements.

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

DVaR computations are based on a historical simulation, which uses price
movements over an 11 day period to simulate forward price curves in the energy
markets to estimate the potential favorable or unfavorable impact of one days
price movement on the existing portfolio. The historical simulation emphasizes
the most recent market activity, which is considered the most relevant
predictor of immediate future market movements for crude oil, NGLs, natural gas
and other energy-related products. DVaR computations use several key
assumptions, including a 95% confidence level for the resultant price movement
and the holding period specified for the calculation. Our DVaR amounts for
commodity derivatives instruments held for trading and marketing purposes are
shown in the following table.

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Daily Value at Risk (in thousands)

Estimated Average
    
    Estimated Average
    
    High One-Day
    
    Low One-DayOne-Day Impact
    
    One-Day Impact
    
    Impact on EBIT
    
    Impact on EBITon EBIT for the
    
    on EBIT for the
    
    for the three
    
    for the threethree months ended
    
    three months ended
    
    months ended
    
    months endedSeptember 30, 2003
    
    September 30, 2002
    
    September 30, 2003
    
    September 30, 2003Calculated DVaR
    
    $
    567
    
    
    $
    2,062
    
    
    $
    1,046
    
    
    $
    199


Daily Value at Risk (in thousands)

Estimated Average
    
    Estimated Average
    
    High One-Day
    
    Low One-DayOne-Day Impact
    
    One-Day Impact
    
    Impact on EBIT
    
    Impact on EBITon EBIT for the
    
    on EBIT for the
    
    for the nine
    
    for the ninenine months ended
    
    nine months ended
    
    months ended
    
    months endedSeptember 30, 2003
    
    September 30, 2002
    
    September 30, 2003
    
    September 30, 2003Calculated DVaR
    
    
    $1,042
    
    
    $
    2,277
    
    
    $
    6,692
    
    
    $
    199


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

Our exposure to commodity price risk is influenced by a number of factors,
including contract size, length of contract, market liquidity, location and
unique or specific contract terms. The unrealized fair value of trading and
marketing instruments outstanding at September 30, 2003 and December 31, 2002
was a gain of $2.2 million and a loss of $28.0 million, respectively.

The fair value of these contracts is expected to be realized in future
periods, as detailed in the following table. The amount of cash ultimately
realized for these contracts will differ from the amounts shown in the
following table due to factors such as market volatility, counterparty default
and other unforeseen events that could impact the amount and/or realization of
these values.

When available, quoted market prices are used to record a contracts fair
value. However, market values for energy trading and marketing contracts may
not be readily determinable because the duration of the contracts exceeds the
liquid activity in a particular market. If no active 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 mark-to-market trading and
marketing portfolios as of September 30, 2003.

Fair Value of Contracts as of September 30, 2003 (in thousands)Maturity inMaturity in
    
    Maturity in
    
    Maturity in
    
    2006 and
    
    Total FairSources of Fair Value
    
    2003
    
    2004
    
    2005
    
    Thereafter
    
    ValuePrices supported by
quoted market prices
and other external
sources
    
    $
    (5,141
    )
    
    $
    6,178
    
    
    $
    1,171
    
    
    $
    (301
    )
    
    $
    1,907Prices based on
models and other
valuation methods
    
    
    531
    
    
    
    3,698
    
    
    
    (794
    )
    
    
    (3,099
    )
    
    
    336Total
    
    $
    (4,610
    )
    
    $
    9,876
    
    
    $
    377
    
    
    $
    (3,400
    )
    
    $
    2,243


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 has been included in this category due to the complex
nature of these transactions.

Hedging
Strategies We are exposed to market fluctuations in the prices
of energy commodities related to natural gas gathering, processing and
marketing activities. We closely monitor the risks associated with these
commodity price changes on our future operations and, where appropriate, use
various commodity instruments such as natural gas, crude oil and NGLs 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 Accumulated Other
Comprehensive Income (Loss) (AOCI) for cash flow hedges or included in Other
Current or Noncurrent Assets or Liabilities on the Consolidated Balance Sheets
for fair value hedges of firm commitments, in accordance with SFAS No. 133.
Amounts deferred in AOCI are realized in earnings concurrently with the
transaction being hedged. However, in instances where the hedging contract no
longer qualifies for hedge accounting, amounts included in AOCI through the
date of de-designation remain in AOCI until the underlying transaction actually
occurs. The derivative contract (if continued as an open position) will be
marked-to-market currently through earnings. Several factors influence the
effectiveness of a hedge contract, including counterparty credit risk and using
contracts with different commodities or unmatched terms. Hedge effectiveness is
monitored regularly and measured each month.

The following table shows when gains and losses deferred on the
Consolidated Balance Sheets for derivative instruments qualifying as effective
hedges of firm commitments or anticipated future transactions will be

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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
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 September 30, 2003 (in thousands)Maturity inMaturity in
    
    Maturity in
    
    Maturity in
    
    2006 and
    
    Total FairSources of Fair Value

    2003

    2004

    2005

    Thereafter
    
    ValuePrices supported by
quoted market prices
and other external
sources
    
    $
    (22,653
    )
    
    $
    (1,994
    )
    
    $
    7,762
    
    
    $
    (1,396
    )
    
    $
    (18,281
    )Prices based on
models and other
valuation methods
    
    
    (91
    )
    
    
    (287
    )
    
    
    
    
    
    
    
    
    
    
    (378
    )Total
    
    $
    (22,744
    )
    
    $
    (2,281
    )
    
    $
    7,762
    
    
    $
    (1,396
    )
    
    $
    (18,659
    )


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 principal customers in the Natural Gas Segment are large, natural gas
marketing services and industrial end-users. In the NGLs segment, our principal
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 a contract with a primary term that expires on January 1, 2015. This
concentration of credit risk may affect our overall credit risk in that these
customers may be similarly affected by changes in economic, regulatory or other
factors. Where exposed to credit risk, we analyze the counterparties financial
condition prior to entering into an agreement, establish credit limits and
monitor the appropriateness of these limits on an ongoing basis. The corporate
credit policy prescribes the use of master collateral agreements to mitigate
credit exposure. Collateral agreements provide for a counterparty to post cash
or letters of credit for exposure in excess of the established threshold. The
threshold amount represents an open credit limit, determined in accordance with
the corporate credit policy. The collateral agreements also provide that the
inability to post collateral is sufficient cause to terminate a contract and
liquidate all positions. Substantially all other agreements contain adequate
assurance provisions, which would allow us, at our discretion, to suspend
deliveries, cancel agreements or continue deliveries to the buyer after the
buyer provides security for payment satisfactory to us.

Despite the current credit environment in the energy sector, management
believes that the credit risk management process described above is operating
effectively. As of September 30, 2003, we had cash or letters of credit of
$15.2 million to secure future performance by counterparties, and had deposited
with counterparties $5.0 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
debt. Our primary goals include (1) maintaining an appropriate ratio of
fixed-rate debt to total debt for our debt rating; (2) reducing volatility of
earnings resulting from interest rate fluctuations; and (3) locking in
attractive interest rates based on historical averages. As of September 30,
2003, the fair value of our interest rate swaps was an asset of $17.8 million.
As of September 30, 2003, we had no outstanding commercial paper.

As a result of our debt and interest rate swaps, we are exposed to market
risks related to changes in interest rates. In the future, we intend to manage
our interest rate exposure using a mix of fixed and floating interest rate
debt. An increase of 0.5% in interest rates would result in an increase in
annual interest expense of approximately $1.8 million.

Foreign Currency Risk

Our primary foreign currency exchange rate exposure at September 30, 2003
was the Canadian dollar. Foreign currency risk associated with this exposure
was not significant.




Item 4.Controls and Procedures

Our management, including the Chief Financial Officer and the Chief
Executive Officer, have evaluated the effectiveness of our disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and
concluded that, as of the end of the period covered by this report, the
disclosure controls and procedures are effective in ensuring that all material
information required to be filed in this quarterly report has been made known
to them in a timely fashion. The required information was effectively recorded,
processed, summarized and reported within the time period necessary to prepare
this quarterly report. Our disclosure controls and procedures are effective in
ensuring that information required to be disclosed in our reports under the
Exchange Act are accumulated and communicated to management, including the
Chief Financial Officer and the Chief Executive Officer, as appropriate to
allow timely decisions regarding required disclosure. There have been no
significant changes in our internal controls over financial reporting that
occurred during the period covered by this report that have materially
affected, or are reasonably likely to materially affect, our internal controls
over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information concerning litigation and other contingencies, see Part I.
Item 1, Note 6 to the Consolidated Financial Statements, Commitments and
Contingent Liabilities, of this report and Item 3, Legal Proceedings,
included in our Form 10-K for December 31, 2002, which are incorporated herein
by reference.

Management believes that the resolution of the matters referred to above
will not have a material adverse effect on the consolidated results of
operations or financial position of the Company.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

|     |  |                                                                                                                                                             
|---- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.1 |  | IT Consolidation and Operations Services Agreement between Duke
Energy Business Services, LLC and Duke Energy Field Services, LP, dated
as of July 30, 2003.
|     |  |                                                                                                                                                             
|31.1 |  | Certification of Chief Financial Officer Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.                                                         
|     |  |                                                                                                                                                             
|31.2 |  | Certification of Chief Executive Officer Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.                                                         
|     |  |                                                                                                                                                             
|32.1 |  | Certification of Chief Financial Officer Pursuant to 18 U.S.C.
Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.          
|     |  |                                                                                                                                                             
|32.2 |  | Certification of Chief Executive Officer Pursuant to 18 U.S.C.
Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.          

(b) Reports on Form 8-K

None.

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SIGNATURES

Pursuant to the requirements of 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, LLCNovember 12, 2003/s/ Rose M. RobesonRose M. Robeson
Vice President and Chief Financial Officer
(On Behalf of the Registrant and as
Principal Financial and Accounting Officer)


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EXHIBIT INDEX

EXHIBITNUMBER
    
    DESCRIPTION10.1
    
    IT Consolidation and Operations Services Agreement between Duke
Energy Business Services, LLC and Duke Energy Field Services, LP, dated
as of July 30, 2003.31.1
    
    Certification of Chief Financial Officer Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.31.2
    
    Certification of Chief Executive Officer Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.32.1
    
    Certification of Chief Financial Officer Pursuant to 18 U.S.C.
Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.32.2
    
    Certification of Chief Executive Officer Pursuant to 18 U.S.C.
Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.