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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 March 31, 2004
    
    Commission File Number 0-31095
 DUKE ENERGY FIELD SERVICES, LLC  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.
No o Yes x




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DUKE ENERGY FIELD SERVICES, LLC
FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2004 INDEX Item
    
    
    
    
    
    PagePART I. FINANCIAL INFORMATION (UNAUDITED)1.
    
    Financial Statements
    
    
    1Consolidated Statements of Operations for the Three Months Ended March 31, 2004 and 2003
    
    
    1Consolidated Statements of Comprehensive Income for the Three Months Ended March 31,
2004 and 2003
    
    
    2Consolidated Balance Sheets as of March 31, 2004 and December 31, 2003
    
    
    3Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2004 and 2003
    
    
    4Condensed Notes to Consolidated Financial Statements
    
    
    52.
    
    Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    163.
    
    Quantitative and Qualitative Disclosure about Market Risks
    
    
    254.
    
    Controls and Procedures
    
    
    29PART II. OTHER INFORMATION1.
    
    Legal Proceedings
    
    
    306.
    
    Exhibits and Reports on Form 8-K
    
    
    30Signatures
    
    
    31
 CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS Our reports, filings and other public announcements may from time to time
contain statements that do not directly or exclusively relate to historical
facts. Such statements are forward-looking statements within the meaning of
the Private Securities Litigation Reform Act of 1995. You can typically
identify forward-looking statements by the use of forward-looking words, such
as may, could, project, believe, anticipate, expect, estimate,
potential, plan, forecast and other similar words. All statements that are not statements of historical facts, including
statements regarding our future financial position, business strategy, budgets,
projected costs and plans and objectives of management for future operations,
are forward-looking statements. These forward-looking statements reflect our intentions, plans,
expectations, assumptions and beliefs about future events and are subject to
risks, uncertainties and other factors, many of which are outside our control.
Important factors that could cause actual results to differ materially from the
expectations expressed or implied in the forward-looking statements include
known and unknown risks. Known risks include, but are not limited to, the
following:  x
    
    our ability to access the capital and bank markets, which will depend
on general market conditions and the credit ratings for our debt
obligations;x
    
    our use of derivative financial instruments to hedge commodity and interest rate risks;x
    
    the level of creditworthiness of counterparties to transactions;x
    
    the amount of collateral required to be posted from time to time in our transactions;x
    
    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;364-Day Credit FacilityAsset Purchase and Sale AgreementCertification of CFO Pursuant to Section 302Certification of CEO Pursuant to Section 302Certification of CFO Pursuant to Section 1350Certification of CEO Pursuant to Section 1350 i




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x
    
    the timing and extent of changes in commodity prices, interest rates,
foreign currency exchange rates and demand for our services;x
    
    weather and other natural phenomena;x
    
    industry changes, including the impact of consolidations, and changes in competition;x
    
    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;x
    
    the extent of success in connecting natural gas supplies to gathering
and processing systems;x
    
    general economic conditions, including any potential effects arising
from terrorist attacks and any consequential hostilities or other
hostilities; andx
    
    The effect of accounting pronouncements issued periodically by
accounting standard-setting bodies. In light of these risks, uncertainties and assumptions, the events
described in the forward-looking statements might not occur or might occur to a
different extent or at a different time than we have described. We undertake no
obligation to publicly update or revise any forward-looking statements, whether
as a result of new information, future events or otherwise. ii




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PART I. FINANCIAL INFORMATION 
 Item 1. Financial Statements DUKE ENERGY FIELD SERVICES, LLC 
 CONSOLIDATED STATEMENTS OF OPERATIONS
 (Unaudited)
 (millions)
 Three Months EndedMarch 31,2004
    
    2003Operating Revenues:Sales of natural gas and petroleum products
    
    $
    1,721
    
    
    $
    1,616Sales of natural gas and petroleum products to affiliates
    
    
    611
    
    
    
    924Transportation, storage and processing
    
    
    68
    
    
    
    61Trading and marketing net margin
    
    
    2
    
    
    
    (34
    )Total operating revenues
    
    
    2,402
    
    
    
    2,567Costs and Expenses:Purchases of natural gas and petroleum products
    
    
    1,889
    
    
    
    2,069Purchases of natural gas and petroleum products from affiliates
    
    
    148
    
    
    
    202Operating and maintenance
    
    
    94
    
    
    
    105Depreciation and amortization
    
    
    75
    
    
    
    75General and administrative
    
    
    41
    
    
    
    38Total costs and expenses
    
    
    2,247
    
    
    
    2,489Operating Income
    
    
    155
    
    
    
    78Equity in earnings of unconsolidated affiliates
    
    
    17
    
    
    
    12Interest expense, net
    
    
    40
    
    
    
    42Income from continuing operations before income taxes
    
    
    132
    
    
    
    48Income tax expense
    
    
    3
    
    
    
    2Income from continuing operations before cumulative effect
of accounting change
    
    
    129
    
    
    
    46Income from discontinued operations
    
    
    5
    
    
    
    6Cumulative effect of accounting change
    
    
    
    
    
    
    (23
    )Net income
    
    
    134
    
    
    
    29Dividends on preferred members interest
    
    
    
    
    
    
    5Earnings available for members interest
    
    $
    134
    
    
    $
    24
 See Notes to Consolidated Financial Statements. 1




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DUKE ENERGY FIELD SERVICES, LLC 
 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 (Unaudited)
 (millions)
 Three Months EndedMarch 31,2004
    
    2003Net income
    
    $
    134
    
    
    $
    29Other comprehensive income:Foreign currency translation adjustment
    
    
    (4
    )
    
    
    20Net unrealized losses on cash flow hedges
    
    
    (17
    )
    
    
    (37
    )Reclassification of previously deferred
losses on cash flow hedges into earnings
    
    
    18
    
    
    
    42Total other comprehensive income
    
    
    (3
    )
    
    
    25Total comprehensive income
    
    $
    131
    
    
    $
    54
 See Notes to Consolidated Financial Statements. 2




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DUKE ENERGY FIELD SERVICES, LLC 
 CONSOLIDATED BALANCE SHEETS
 (Unaudited)
 (millions)
 March 31,
    
    December 31,2004
    
    2003ASSETSCurrent assets:Cash and cash equivalents
    
    $
    248
    
    
    $
    43Accounts receivable:Customers, net of allowance for doubtful accounts of $6
and $8, respectively
    
    
    795
    
    
    
    872Affiliates
    
    
    52
    
    
    
    57Other
    
    
    30
    
    
    
    29Inventories
    
    
    26
    
    
    
    45Unrealized gains on mark-to-market and hedging transactions
    
    
    116
    
    
    
    135Other
    
    
    19
    
    
    
    20Total current assets
    
    
    1,286
    
    
    
    1,201Property, plant and equipment, net
    
    
    4,431
    
    
    
    4,462Investment in unconsolidated affiliates
    
    
    187
    
    
    
    190Intangible assets:Commodity sales and purchases contracts, net
    
    
    77
    
    
    
    80Goodwill, net
    
    
    447
    
    
    
    447Total intangible assets
    
    
    524
    
    
    
    527Unrealized gains on mark-to-market and hedging transactions
    
    
    33
    
    
    
    25Other noncurrent assets
    
    
    34
    
    
    
    109Total assets
    
    $
    6,495
    
    
    $
    6,514LIABILITIES AND MEMBERS EQUITYCurrent liabilities:Accounts payable:Trade
    
    $
    837
    
    
    $
    857Affiliates
    
    
    11
    
    
    
    16Other
    
    
    28
    
    
    
    33Short term debt
    
    
    6
    
    
    
    6Accrued interest payable
    
    
    26
    
    
    
    59Unrealized losses on mark-to-market and hedging transactions
    
    
    132
    
    
    
    153Other
    
    
    130
    
    
    
    150Total current liabilities
    
    
    1,170
    
    
    
    1,274Deferred income taxes
    
    
    17
    
    
    
    17Long term debt
    
    
    2,260
    
    
    
    2,262Unrealized losses on mark-to-market and hedging transactions
    
    
    29
    
    
    
    24Other long term liabilities
    
    
    80
    
    
    
    73Minority interests
    
    
    125
    
    
    
    120Commitments and contingent liabilitiesMembers equity:Members interest
    
    
    1,709
    
    
    
    1,709Retained earnings
    
    
    1,084
    
    
    
    1,011Accumulated other comprehensive income
    
    
    21
    
    
    
    24Total members equity
    
    
    2,814
    
    
    
    2,744Total liabilities and members equity
    
    $
    6,495
    
    
    $
    6,514
 See Notes to Consolidated Financial Statements. 3




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DUKE ENERGY FIELD SERVICES, LLC 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
 (Unaudited)
 (millions)
 Three Months EndedMarch 31,2004
    
    2003Cash flows from operating activities:Net income
    
    $
    134
    
    
    $
    29Adjustments to reconcile net income to net cash provided by operating
activities:Income from discontinued operations
    
    
    (5
    )
    
    
    (6
    )Cumulative effect of accounting change
    
    
    
    
    
    
    23Depreciation and amortization
    
    
    75
    
    
    
    75Distributions received in excess of earnings from unconsolidated affiliates
    
    
    2
    
    
    
    2Other, net
    
    
    3
    
    
    
    9Change in operating assets and liabilities which provided (used) cash:Accounts receivable
    
    
    79
    
    
    
    (612
    )Accounts receivable from affiliates
    
    
    8
    
    
    
    (122
    )Inventories
    
    
    20
    
    
    
    22Net unrealized gains on mark-to-market and hedging transactions
    
    
    (2
    )
    
    
    (37
    )Accounts payable
    
    
    (53
    )
    
    
    741Accounts payable to affiliates
    
    
    (7
    )
    
    
    (3
    )Accrued interest payable
    
    
    (33
    )
    
    
    (33
    )Other
    
    
    (3
    )
    
    
    (21
    )Net cash provided by continuing operations
    
    
    218
    
    
    
    67Net cash provided by discontinued operations
    
    
    2
    
    
    
    9Net cash provided by operating activities
    
    
    220
    
    
    
    76Cash flows from investing activities:Capital expenditures
    
    
    (25
    )
    
    
    (34
    )Consolidation of previously unconsolidated investment
    
    
    6
    
    
    
    Contributions from minority interests, net
    
    
    
    
    
    
    1Proceeds from sale of discontinued operations
    
    
    62
    
    
    
    Proceeds from sales of assets
    
    
    1
    
    
    
    4Net cash provided by (used in) continuing operations
    
    
    44
    
    
    
    (29
    )Net cash provided by (used in) discontinued operations
    
    
    
    
    
    
    (3
    )Net cash provided by (used in) investing activities
    
    
    44
    
    
    
    (32
    )Cash flows from financing activities:Payment of debt
    
    
    (9
    )
    
    
    (31
    )Payment of dividends
    
    
    (50
    )
    
    
    Costs of issuing debt, net
    
    
    
    
    
    
    (1
    )Net cash used in continuing operations
    
    
    (59
    )
    
    
    (32
    )Net cash used in discontinued operations
    
    
    
    
    
    
    Net cash used in financing activities
    
    
    (59
    )
    
    
    (32
    )Effect of foreign exchange rate changes on cash
    
    
    
    
    
    
    Net increase in cash and cash equivalents
    
    
    205
    
    
    
    12Cash and cash equivalents, beginning of period
    
    
    43
    
    
    
    35Cash and cash equivalents, end of period
    
    $
    248
    
    
    $
    47Supplementary cash flow information:Cash paid for interest (net of amounts capitalized)
    
    $
    69
    
    
    $
    73
 See Notes to Consolidated Financial Statements. 4




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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) 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%. 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 for the respective interim
periods. These consolidated financial statements and other information included
in this quarterly report on Form 10-Q should be read in conjunction with
Managements Discussion and Analysis of Financial Condition and Results of
Operations and the consolidated financial statements and notes thereto
included in our annual report on Form 10-K for the fiscal year ended December
31, 2003. 2. Summary of Significant Accounting Policies Consolidation The Consolidated Financial Statements include the accounts
of the Company and all majority-owned subsidiaries, after eliminating
intercompany transactions and balances, and variable interest entities where
the Company is the primary beneficiary. Investments in 20% to 50% owned
affiliates, and investments in less than 20% owned affiliates where the Company
had the ability to exercise significant influence, are accounted for using the
equity method. Investments greater than 50% are consolidated unless the Company
does not have the ability to exercise control, in which case, they are
accounted for using the equity method. 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. Accounting for Hedges and Commodity Trading and Marketing Activities
Each derivative not qualifying for the normal purchases and sales exception
under Statement of Financial Accounting Standards (SFAS) No. 133 (SFAS
133), Accounting for Derivative Instruments and Hedging Activities, as
amended, is recorded on a gross basis as assets and liabilities in the
Consolidated Balance Sheets at their fair value as Unrealized gains or
Unrealized losses on mark-to-market and hedging transactions. Derivative
assets and liabilities remain classified in the Consolidated Balance Sheets as
Unrealized gains or Unrealized losses on mark-to-market or hedging transactions
at fair value until the contractual delivery period occurs. Effective January 1, 2003, the Company designates each energy commodity
derivative as either trading or non-trading. For each of the Companys
derivatives, the accounting method and presentation of gains and losses or
revenue and expense in the Consolidated Statements of Operations are as
follows: 5




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Classification of Contract
    
    Accounting Method
    
    Presentation of Gains & Losses or Revenue & ExpenseTrading Derivatives
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net marginNon-Trading Derivatives:Cash Flow Hedge
    
    Hedge methodb
    
    Gross basis in the same income statement
category as the related hedged itemFair Value Hedge
    
    Hedge methodb
    
    Gross basis in the same income statement
category as the related hedged itemNormal Purchase or Normal Sale
    
    Accrual methodc
    
    Gross basis upon settlement in the
corresponding income statement category
based on commodity typeNon-Trading Mark-to-Market
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net margin
   a
    
    Mark-to-market- An accounting method whereby the change in the fair value of
the asset or liability is recognized in the Consolidated Statements of
Operations in Trading and marketing net margin during the current period.b
    
    Hedge method- An accounting method whereby the effective portion of the
change in the fair value of the asset or liability is recorded in Accumulated
other comprehensive income in the Consolidated Balance Sheets and there is no
recognition in the Consolidated Statements of Operations for the effective
portion until the hedged transaction occurs.c
    
    Accrual method- An accounting method whereby there is no recognition in the
Consolidated Statements of Operations for changes in fair value of a contract
until the service is provided or the associated delivery of product occurs. For derivatives designated as a cash flow hedge or a fair value hedge, the
Company formally assesses, both at the inception of the hedge 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 open positions in an orderly
manner over a reasonable time period under current conditions. Changes in
market prices and management estimates directly affect the estimated fair value
of these contracts. Accordingly, it is reasonably possible that such estimates
may change in the near term. Commodity Trading and Marketing  A favorable or unfavorable price
movement of any derivative contract held for trading and marketing purposes is
reported as Trading and marketing net margin in the Consolidated Statements of
Operations. An offsetting amount is recorded in the Consolidated Balance Sheets
as Unrealized gains or unrealized losses on mark-to-market and hedging
transactions. When the contractual delivery period occurs, the realized gain or
loss is reclassified to a receivable or payable account. Commodity Cash Flow Hedges  The fair value of a derivative designated 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 as a
cash flow hedge is recorded in the Consolidated Balance Sheets as Accumulated
other comprehensive income (AOCI). During the period in which the hedged
transaction occurs, amounts in AOCI associated with the hedged transaction are
reclassified to the Consolidated Statements of Operations in the same accounts
as the item being hedged. The Company discontinues hedge accounting
prospectively when it is determined that the derivative no longer qualifies as
an effective hedge, or when it is no longer probable that the hedged
transaction will occur. When hedge accounting is discontinued because the
derivative no longer qualifies as an effective hedge, the derivative continues
to be carried on the Consolidated Balance Sheets at its fair value; however,
subsequent changes in its fair value are recognized in current period earnings.
Gains and losses related to discontinued hedges that were previously
accumulated in AOCI will remain in AOCI until the hedged transaction occurs,
unless it is no longer probable that 6




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the hedged transaction will occur, in which case, the gains and losses
that were in AOCI will be immediately recognized in current period earnings. At
March 31, 2004 and December 31, 2003, $28 million and $29 million,
respectively, of losses related to cash flow hedges were deferred in AOCI. 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,
and are included in the Consolidated Balance Sheets as Unrealized gains or
losses on mark-to-market and hedging transactions. 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 133. As such, for the life
of the swaps, no ineffectiveness will be recognized. Distributions Under the terms of the Companys Limited Liability Company
Agreement (the LLC Agreement), the Company is required to make quarterly
distributions to Duke Energy and ConocoPhillips based on allocated taxable
income. The LLC Agreement, as amended, provides for taxable income to be
allocated in accordance with Internal Revenue Code Section 704(c). This Code
Section accounts for the variation between the adjusted tax basis and the fair
market value of assets contributed to the joint venture. The distribution is
based on the highest taxable income allocated to either member, with the other
member receiving a proportionate amount to maintain the ownership capital
accounts at 69.7% for Duke Energy and 30.3% for ConocoPhillips. As of March 31,
2004, distributions payable of $11 million were included in Other current
liabilities in the Consolidated Balance Sheets. This amount was based on
estimated annual taxable income allocated to the members according to their
respective ownership percentages and was paid in April 2004. In 2003, the Companys board of directors approved a plan to consider the
payment of a quarterly dividend to Duke Energy and ConocoPhillips. The board of
directors may consider net income, cash flow or any other criteria deemed
appropriate for determining the amount of the quarterly dividend to be paid.
The LLC Agreement restricts making distributions, which would include these
dividends, except with the approval of both members. During the quarter ended
March 31, 2004, with the approval of both members, the Company paid a dividend
of $50 million to the members allocated in accordance with their respective
ownership percentages. Stock-Based Compensation Under Duke Energys 1998 Long Term Incentive
Plan, stock options for Duke Energys common stock may be granted to the
Companys key employees. The Company accounts for stock-based compensation
using the intrinsic value recognition and measurement principles of Accounting
Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to
Employees, and FASB Interpretation No. 44, Accounting for Certain
Transactions Involving Stock Compensation (an Interpretation of APB Opinion No.
25). Under this method, any compensation cost is measured as the quoted market
price of stock at the date of the grant less the amount an employee must pay to
acquire the stock. Since the exercise price for all options granted under the
plan was equal to the market value of the underlying common stock on the date
of grant, no compensation cost is recognized in the accompanying Consolidated
Statements of Operations. Restricted stock grants and phantom stock awards are
recorded over the required vesting period as compensation cost, based on the
market value on the date of grant. Performance awards are recorded over the
required vesting period as compensation costs, based on the market value on the
date of the balance sheet. 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 and reflects the provisions of SFAS No. 148
Accounting for Stock-Based Compensation  Transition and Disclosure  an
amendment of FASB Statement No. 123. 7




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Pro Forma Stock-Based Compensation
    
    Three months ended(millions)
    
    March 31,2004
    
    2003Earnings available for members interest,as reported
    
    $
    134
    
    
    $
    24Add: stock-based compensation expenseincluded in reported net income
    
    
    
    
    
    
    Deduct: total stock-based compensationexpense determined under fair value-basedmethod for all awards
    
    
    (1
    )
    
    
    (1
    )Pro forma earnings available for membersinterest
    
    $
    133
    
    
    $
    23
 Accumulated Other Comprehensive Income The components of and changes in
accumulated other comprehensive income are as follows: Net
    
    AccumulatedAccumulated Other
    
    Foreign
    
    Unrealized
    
    OtherComprehensive Income
    
    Currency
    
    (Losses) Gains on
    
    Comprehensive(millions)
    
    Adjustments
    
    Cash Flow Hedges
    
    IncomeBalance as of December 31, 2003
    
    $
    53
    
    
    $
    (29
    )
    
    $
    24Other comprehensive income
changes during the period
    
    
    (4
    )
    
    
    1
    
    
    
    (3
    )Balance as of March 31, 2004
    
    $
    49
    
    
    $
    (28
    )
    
    $
    21
 Cumulative Effect of Accounting Change The Company adopted the
provisions of EITF Issue 02-03 (EITF 02-03), Issues Involved in Accounting
for Derivative Contracts Held for Trading Purposes and for Contracts Involved
in Energy Trading and Risk Management Activities, that required new
non-derivative energy trading contracts entered into after October 25, 2002 to
be accounted for under the accrual accounting basis. Non-derivative energy
trading contracts recorded in the Consolidated Balance Sheet as of January 1,
2003 that existed at October 25, 2002 and inventories that were recorded at
fair values were adjusted to historical cost via a cumulative effect adjustment
of $5 million as a reduction to earnings in the first quarter of 2003. The Company adopted the provisions of SFAS No. 143 (SFAS 143),
Accounting for Asset Retirement Obligations, as of January 1, 2003 which
addresses financial accounting and reporting for obligations associated with
the retirement of tangible long-lived assets and the associated asset
retirement costs. In accordance with the transition provisions of SFAS 143, the
Company recorded a cumulative effect adjustment of $18 million as a reduction
to earnings in the first quarter of 2003. New Accounting Standards In May 2003, the FASB issued SFAS No. 150
(SFAS 150), Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity. SFAS 150 requires that certain
financial instruments that could previously be accounted for as equity, be
classified as liabilities in the consolidated balance sheets and initially
recorded at fair value. In addition to its requirements for the classification
and measurement of financial instruments in its scope, SFAS 150 also requires
disclosures about the nature and terms of the financial instruments and about
alternative ways of settling the instruments. The provisions of SFAS 150 are
effective for all financial instruments entered into or modified after May 31,
2003, and are otherwise effective at the beginning of the first interim period
beginning after June 15, 2003. Upon adoption on July 1, 2003, the Company
reclassified its preferred members interest, which are mandatorily redeemable,
of $200 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. During 2003, the
Company redeemed the remaining $200 million of these securities in cash. In January 2003, the FASB issued Interpretation No. 46 (FIN 46),
Consolidation of Variable Interest Entities which requires the primary
beneficiary of a variable interest entitys activities to consolidate the
variable interest 8




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##### Table of Contents



entity. FIN 46 defines a variable interest entity as an entity in which
the equity investors do not have substantive voting rights and there is not
sufficient equity at risk for the entity to finance its activities without
additional subordinated financial support. The primary beneficiary is the party
that absorbs a majority of the expected losses and/or receives a majority of
the expected residual returns of the variable interest entitys activities. In
December 2003, the FASB issued FIN 46R, which supercedes and amends certain
provisions of FIN 46. While FIN 46R retains many of the concepts and provisions
of FIN 46, it also provides additional guidance related to the application of
FIN 46, provides for certain additional scope exceptions, and incorporates
several FASB Staff Positions issued related to the application of FIN 46. The provisions of FIN 46 are immediately applicable to variable interest
entities created, or interests in variable interest entities obtained, after
January 31, 2003 and the provisions of FIN 46R are required to be applied to
such entities by the end of the first reporting period ending after March 15,
2004 (March 31, 2004 for the Company). For variable interest entities created,
or interests in variable interest entities obtained, on or before January 31,
2003, FIN 46 or FIN 46R is required to be applied to special-purpose entities
by the end of the first reporting period ending after December 15, 2003
(December 31, 2003 for calendar-year entities) and is required to be applied to
all other non-special purpose entities by the end of the first reporting period
ending after March 15, 2004 (March 31, 2004 for calendar-year entities). FIN 46
and FIN 46R may be applied prospectively with a cumulative-effect adjustment as
of the date it is first applied, or by restating previously issued financial
statements with a cumulative-effect adjustment as of the beginning of the first
year restated. FIN 46 and FIN 46R also require certain disclosures of an
entitys relationship with variable interest entities. The Company has not identified any material variable interest entities
created, or interests in variable entities obtained, after January 31, 2003
which require consolidation or disclosure under FIN 46. The Company
consolidated one entity, previously accounted for under the equity method of
accounting, on January 1, 2004 under the provisions of FIN 46R. This entity,
which is a substantive entity, had total assets of approximately $92 million as
of January 1, 2004. Adoption of FIN 46R had no material effect on the Companys
consolidated results of operations, cash flows or financial position. In July 2003, the EITF reached consensus in EITF Issue No. 03-11 (EITF
03-11), Reporting Realized Gains and Losses on Derivative Instruments that
are Subject to FASB Statement No. 133, Accounting for Derivative Instruments
and Hedging Activities, and Not Held for Trading Purposes, that determining
whether realized gains and losses on derivative contracts not held for trading
purposes should be reported on a net or gross basis is a matter of judgment
that depends on the relevant facts and circumstances. In analyzing the facts
and circumstances, EITF 99-19, Reporting Revenue Gross as a Principal versus
Net as an Agent and Opinion No. 29, Accounting for Nonmonetary Transactions,
should be considered. EITF 03-11 is effective for transactions or arrangements
entered into after September 30, 2003. The adoption of EITF 03-11 had no
material effect on the Companys consolidated results of operations, cash flows
or financial position. In May 2003, the EITF reached consensus in EITF Issue No. 01-08 (EITF
01-08), Determining Whether an Arrangement Contains a Lease, to clarify the
requirements of identifying whether an arrangement should be accounted for as a
lease at its inception. The guidance in the consensus is designed to mandate
reporting revenue as rental or leasing income that otherwise would be reported
as part of product sales or service revenue. EITF 01-08 requires both parties
to an arrangement to determine whether a service contract or similar
arrangement is or includes a lease within the scope of SFAS No. 13, Accounting
for Leases. The consensus is to be applied prospectively to arrangements
agreed to, modified, or acquired in business combinations in fiscal periods
beginning on July 1, 2003. The adoption of EITF 01-08 had no material effect on
the Companys consolidated results of operations, cash flows or financial
position. Reclassifications Certain prior period amounts have been reclassified in
the Consolidated Financial Statements to conform to the current period
presentation. Included in the reclassified amounts are increases in both Sales
of natural gas and petroleum products and in Purchases of natural gas and
petroleum products in the amount of approximately $236 million for the quarter
ended March 31, 2003. This reclassification resulted from intersegment trading
activities being eliminated twice from the Consolidated Statements of
Operations in the quarter ended March 31, 2003. Management has concluded that
these reclassifications are not material to the fair presentation of the
Companys financial statements. 9




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3. Acquisitions and Dispositions In the first quarter of 2004, the Company sold gas gathering and
processing plant assets in West Texas to a third party purchaser for a sales
price of approximately $62 million. 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. In the second quarter of 2003, the Company sold gathering, transmission
and processing assets to two separate buyers for a combined sales price of
approximately $90 million. 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 the assets discussed above which are accounted for as discontinued
operations: ThreeMonths EndedMarch 31,2004
    
    2003(millions)Revenues
    
    $
    14
    
    
    $
    139Operating income
    
    
    2
    
    
    
    6Gain on sale
    
    
    3
    
    
    
    Income from discontinued operations
    
    $
    5
    
    
    $
    6
 4. Derivative Instruments, Hedging Activities and Credit Risk Commodity cash flow hedges The Company uses cash flow hedges, as
specifically defined by SFAS 133, to reduce the potential negative impact that
commodity price changes could have on the Companys earnings and its ability to
adequately plan for cash needed for debt service, capital expenditures and tax
distributions. The Companys primary corporate hedging goals include
maintaining minimum cash flows to fund debt service, 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 to hedge the impact
of market fluctuations in the prices of NGLs, natural gas and other
energy-related products. For the three months ended March 31, 2004 and 2003,
the recognition in the Consolidated Statements of Operations of the cumulative
changes in the fair value of these hedge instruments reduced revenues by $19
million and $40 million, respectively. For the three months ended March 31,
2004 and 2003, the gains or losses representing the ineffective portion of the
Companys cash flow hedges were not material. 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 March 31, 2004, $28 million of the deferred net losses
on derivative instruments in AOCI are expected to be reclassified into earnings
through the end of 2004 as the hedged 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 remaining
term over which the Company is currently hedging its exposure to the
variability of future cash flows is through the end of 2004. Commodity fair value hedges The Company uses fair value hedges to hedge
exposure to changes in the fair value of an asset or a liability (or an
identified portion thereof) that is attributable to price risk. The Company may
hedge producer price locks (fixed price gas purchases) and market locks (fixed
price gas sales) to reduce the Companys exposure to fixed price risk via
swapping out the fixed price risk for a floating price position (New York
Mercantile Exchange or index based). 10




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##### Table of Contents



For the three months ended March 31, 2004, the gains or losses
representing the ineffective portion of the Companys fair value hedges were
not material. All components of each derivatives gain or loss are included in
the assessment of hedge effectiveness, unless otherwise noted. The Company did
not have any firm commitments that no longer qualified as fair value hedge
items and therefore, did not recognize an associated gain or loss. Interest rate fair value hedges In October 2001, the Company entered
into an interest rate swap to convert $250 million of fixed-rate 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 $100 million of fixed-rate debt securities issued on August 16, 2000 to
floating rate debt. These interest rate fair value hedges are also at a
floating rate based on six-month LIBOR, which is re-priced semiannually through
2030. The swaps meet conditions which permit the assumption of no
ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps no
ineffectiveness will be recognized. As of March 31, 2004, the fair value of the
interest rate swaps was a $17 million asset, which is included in the
Consolidated Balance Sheets as Unrealized gains or losses on mark-to-market 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 instruments. The Company manages its trading and
marketing portfolio with strict policies which limit exposure to market risk
and require daily reporting to management of potential financial exposure.
These policies include statistical risk tolerance limits using historical price
movements to calculate daily earnings at risk measurement. 5. Asset Retirement Obligations The following table summarizes changes in the asset retirement obligation
for the quarters ended March 31, 2004 and 2003, respectively. ThreeMonths EndedMarch 31,Reconciliation of Asset Retirement Obligation (millions)
    
    2004
    
    2003Balance as of January 1
    
    $
    45
    
    
    $
    43Accretion expense
    
    
    1
    
    
    
    1Liabilities settled
    
    
    (1
    )
    
    
    Balance as of March 31
    
    $
    45
    
    
    $
    44
 6. Goodwill and Other Intangibles The changes in the carrying amount of goodwill for the three months ended
March 31, 2004 are as follows: ForeignPurchase
    
    CurrencyBalance
    
    Price
    
    Exchange
    
    BalanceDecember 31, 2003
    
    Adjustments
    
    Adjustments
    
    March 31, 2003(millions)Natural gas gathering, processing, transportation, marketing
and storage
    
    $
    407
    
    
    $
    
    
    
    $
    
    
    
    $
    407NGL fractionation, transportation, marketing and trading
    
    
    40
    
    
    
    
    
    
    
    
    
    
    
    40Total consolidated
    
    $
    447
    
    
    $
    
    
    
    $
    
    
    
    $
    447
 There were no impairments of goodwill for the quarter ended March 31,
2004. 11




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##### Table of Contents



The gross carrying amount and accumulated amortization for commodity sales
and purchases contracts are as follows: March 31,
    
    December 31,2004
    
    2003(millions)Commodity sales and purchases contracts
    
    $
    127
    
    
    $
    127Accumulated amortization
    
    
    (50
    )
    
    
    (47
    )Commodity sales and purchases contracts, net
    
    $
    77
    
    
    $
    80
 During each of the quarters ended March 31, 2004 and 2003, the Company
recorded amortization expense associated with commodity sales and purchases
contracts of $3 million. The average remaining amortization period for these
contracts is 6.8 years. Estimated amortization for these contracts for the next
five years is as follows: Estimated Amortization(millions)2004
    
    $
    62005
    
    
    82006
    
    
    82007
    
    
    82008
    
    
    8Thereafter
    
    
    39Total
    
    $
    77
 7. Financing Credit Facility with Financial Institutions On March 26, 2004, the
Company entered into a new credit facility (the Facility). The Facility
replaces the credit facility that matured on March 26, 2004. 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 25, 2005;
however, any outstanding borrowings under the Facility at maturity may, at the
Companys option, be converted to a one-year term loan. The Facility is a $250
million revolving credit facility, all of which can be used for letters of
credit. The Facility requires the Company to maintain at all times a debt to
total capitalization ratio of less than or equal to 53%; and maintain at the
end of each fiscal quarter an interest coverage ratio (defined to be the ratio
of adjusted EBITDA, as defined by the Facility, for the four most recent
quarters to interest expense for the same period) of at least 2.5 to 1
(adjusted EBITDA, is defined by the Facility, to be earnings before interest,
taxes and depreciation and amortization and other adjustments). 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 1.125% per year or (2) the
higher of (a) the JP Morgan Chase Bank prime rate plus 0.125% per year and (b)
the Federal Funds rate plus 0.625% per year. At March 31, 2004, there were no
borrowings or letters of credit drawn against the Facility. On March 28, 2003, the Company also entered into a $100 million funded
short-term loan with a bank (the Short-Term Loan). The Short-Term Loan was
used for working capital and other general corporate purposes. The Short-Term
Loan contained an original maturity of September 30, 2003, but was repaid by
August 2003 with funds generated from asset sales and operations. On November 3, 2003, the Company executed a $32 million irrevocable
standby letter of credit expiring on May 15, 2004 to be used to secure
transaction exposure with a counterparty. As of March 31, 2004, this letter of
credit was still in effect. Preferred Financing Upon adoption of SFAS 150 on July 1, 2003, the
Company reclassified its preferred members interest, which are mandatorily
redeemable securities, of $200 million from mezzanine equity to long term debt.
During 2003, subsequent to the reclassification, the Company redeemed the
remaining $200 million. Beginning on July 1, 2003, accrued or paid
distributions previously classified as dividends on the preferred members
interest are prospectively classified as interest expense in the Consolidated
Statements of Operations. 12




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##### Table of Contents



8. Commitments and Contingent Liabilities Litigation The midstream industry has seen a number of class action
lawsuits involving royalty disputes, mismeasurement and mispayment allegations.
Although the industry has seen these types of cases before, they were typically
brought by a single plaintiff or small group of plaintiffs. A number of these
cases are now being brought as class actions. The Company and its subsidiaries
are currently named as defendants in some of these cases. Management believes
the Company and its subsidiaries have meritorious defenses to these cases, and
therefore will continue to defend them vigorously. However, these class actions
can be costly and time consuming to defend. Management believes that, based on
currently known information, these proceedings will not have a material adverse
effect on the consolidated results of operations, financial position or cash
flows of the Company. General Insurance The Company carries insurance coverage, with an
affiliate of Duke Energy, that management believes is consistent with companies
engaged in similar commercial operations with similar type properties. The
Companys insurance coverage includes (1) commercial general public liability
insurance for liabilities arising to third parties for bodily injury and
property damage resulting from our operations; (2) workers compensation
liability coverage to required statutory limits; (3) automobile liability
insurance for all owned, non-owned and hired vehicles covering liabilities to
third parties for bodily injury and property damage, and (4) property insurance
covering the replacement value of all real and personal property damage,
excluding electric transmission and distribution lines, including damages
arising from boiler and machinery breakdowns, earthquake, flood damage and
business interruption/extra expense. All coverages are subject to certain
deductibles, terms and conditions common for companies with similar types of
operations. The Company also maintains excess liability insurance coverage above the
established primary limits for commercial general liability and automobile
liability insurance. Limits, terms, conditions and deductibles are comparable
to those carried by other energy companies of similar size. The cost of the
Companys general insurance coverages continued to fluctuate over the past year
reflecting the changing conditions of the insurance markets. Environmental- The operation of pipelines, plants and other facilities
for gathering, transporting, processing, treating, or storing natural gas, NGLs
and other products is subject to stringent and complex laws and regulations
pertaining to health, safety and the environment. As an owner or operator of
these facilities, we must comply with United States and Canadian laws and
regulations at the federal, state and local levels that relate to air and water
quality, hazardous and solid waste management and disposal, and other
environmental matters. The cost of planning, designing, constructing and
operating pipelines, plants, and other facilities must incorporate compliance
with environmental laws and regulations and safety standards. Failure to comply
with these laws and regulations may trigger a variety of administrative, civil
and potentially criminal enforcement measures, including citizen suits, which
can include the assessment of monetary penalties, the imposition of remedial
requirements, the issuance of injunctions or restrictions on operation.
Management believes that, based on currently known information, compliance with
these laws and regulations will not have a material adverse effect on the
consolidated results of operations, financial position or cash flows of the
Company. Severance Program On October 30, 2003, the Company communicated a
company-wide voluntary and involuntary severance program to its employees to
reduce approximately 6% of the Companys workforce. The plan was completed on
December 8, 2003 and includes the reduction of 160 employees over the period of
December 2003 to June 2004. The severance liability that was recorded in the
fourth quarter of 2003 was $6 million at December 31, 2003. Approximately $4
million of the accrued severance payouts were paid in the first quarter of
2004. Included in General and administrative expense in the Consolidated
Statement of Operations during the first quarter of 2004, the Company expensed
an additional $1 million related to this severance program, and any remaining
expense, which is not considered significant, will be recognized in the second
quarter of 2004, the remaining future service period. 13




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9. Business Segments The Company operates in two principal business segments: (1) natural gas gathering, processing, transportation and storage, from
which the Company generates revenues primarily by providing services such as
compression, gathering, treating, processing, transportation of residue gas,
storage and trading and marketing (the Natural Gas Segment), and (2) NGLs fractionation, transportation, marketing and trading, from which
the Company generates revenues from transportation fees, market center
fractionation and the marketing and trading of NGLs (the NGLs Segment). Intersegment activity is primarily related to the sale of NGLs from the
Natural Gas Segment to the NGLs Segment at market based transfer prices. These segments are monitored separately by management for performance
against its internal forecast and are consistent with the Companys internal
financial reporting. These segments have been identified based on the differing
products and services, regulatory environment and the expertise required for
these operations. Margin is a performance measure utilized by management to
monitor the business of each segment. The accounting policies for the segments
are the same as those described in Note 2. Foreign operations are not material
and are therefore not separately identified. The following table sets forth the Companys segment information. Three months ended March 31, 2004 (millions): Natural Gas
    
    NGLs (including(including trading
    
    trading and
    
    Intersegmentand marketing net
    
    marketing net
    
    Eliminations
    
    Othermargin)
    
    margin)
    
    (a)
    
    (c)
    
    Total CompanyOperating Revenues
    
    $
    2,204
    
    
    $
    578
    
    
    $
    (380
    )
    
    $
    
    
    
    $
    2,402Gross Margin(b)
    
    
    345
    
    
    
    20
    
    
    
    
    
    
    
    
    
    
    
    365Other operating and administrative costs
    
    
    92
    
    
    
    2
    
    
    
    
    
    
    
    41
    
    
    
    135Depreciation and amortization
    
    
    67
    
    
    
    4
    
    
    
    
    
    
    
    4
    
    
    
    75Earnings from unconsolidated affiliates
    
    
    17
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    17Interest expense
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    40
    
    
    
    40Income from continuing operations
before income taxes
    
    $
    203
    
    
    $
    14
    
    
    $
    
    
    
    $
    (85
    )
    
    $
    132Capital Expenditures
    
    $
    23
    
    
    $
    
    
    
    $
    
    
    
    $
    2
    
    
    $
    25
 Three months ended March 31, 2003 (millions): Natural Gas
    
    NGLs (including(including trading
    
    trading and
    
    Intersegmentand marketing net
    
    marketing net
    
    Eliminations
    
    Othermargin)
    
    margin)
    
    (a)
    
    (c)
    
    Total CompanyOperating Revenues
    
    $
    2,378
    
    
    $
    501
    
    
    $
    (312
    )
    
    $
    
    
    
    $
    2,567Gross Margin(b)
    
    
    279
    
    
    
    17
    
    
    
    
    
    
    
    
    
    
    
    296Other operating and administrative costs
    
    
    103
    
    
    
    2
    
    
    
    
    
    
    
    38
    
    
    
    143Depreciation and amortization
    
    
    68
    
    
    
    3
    
    
    
    
    
    
    
    4
    
    
    
    75Earnings from unconsolidated affiliates
    
    
    13
    
    
    
    (1
    )
    
    
    
    
    
    
    
    
    
    
    12Interest expense
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    42
    
    
    
    42Income from continuing operations
before income taxes
    
    $
    121
    
    
    $
    11
    
    
    $
    
    
    
    $
    (84
    )
    
    $
    48Capital Expenditures
    
    $
    33
    
    
    $
    
    
    
    $
    
    
    
    $
    1
    
    
    $
    34
 14




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##### Table of Contents



As ofMarch 31,
    
    December 31,2004
    
    2003(millions)Total assets:Natural Gas
    
    $
    4,952
    
    
    $
    5,074NGLs
    
    
    262
    
    
    
    271Corporate (c)
    
    
    1,281
    
    
    
    1,169Total assets
    
    $
    6,495
    
    
    $
    6,514
  (a)
    
    Intersegment sales represent sales of NGLs from the Natural Gas Segment
to the NGLs Segment at either index prices or weighted average prices of
NGLs. Both measures of intersegment sales are effectively based on current
economic market conditions.  (b)
    
    Gross margin consists of total operating revenues less purchases of
natural gas and petroleum products. Gross margin is viewed as a
non-Generally Accepted Accounting Principles (GAAP) measure under the
rules of the Securities and Exchange Commission (SEC), but is included
as a supplemental disclosure because it is a primary performance measure
used by management as it represents the results of product sales versus
product purchases. As an indicator of our operating performance, gross
margin should not be considered an alternative to, or more meaningful
than, net income or cash flow as determined in accordance with GAAP. Our
gross margin may not be comparable to a similarly titled measure of
another company because other entities may not calculate gross margin in
the same manner.  (c)
    
    Includes items such as unallocated working capital, intercompany accounts
and intangible and other assets. 10. Guarantors Obligations Under Guarantees On January 1, 2004, the Company was the guarantor of $3 million of debt.
The guaranteed debt was repaid in full in January of 2004. At March 31, 2004,
the Company had no liability recorded for the guarantees of this debt. 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 vary 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 March 31, 2004, the Company had a liability of
approximately $1 million recorded for these outstanding indemnification
provisions. 11. Subsequent Events On March 10, 2004, the Company entered into an agreement to acquire
gathering, processing and transmission assets in Southeast New Mexico from
ConocoPhillips for approximately $74 million. The transaction closed during the
second quarter of 2004. 15




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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
months ended March 31, 2004 and 2003. 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 three months of 2004, approximately 79% of our operating
revenues prior to intersegment revenue elimination and approximately 95%
of our gross margin were derived from this segment.
    
    NGLs fractionation, transportation, marketing and trading, from which
we generate revenues from transportation fees, market center
fractionation and the marketing and trading of NGLs (the NGLs
Segment). In the first three months of 2004, approximately 21% of our
operating revenues prior to intersegment revenue elimination and
approximately 5% of our gross margin were derived from this segment.
    
    Intersegment activity is primarily related to the sale of NGLs from
the Natural Gas Segment to the NGLs Segment at market based transfer
prices. Our limited liability company agreement limits the scope of our business
to the midstream 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,
we receive fees or commodities from the producers to bring the raw natural gas
from the wellhead to the processing plant. For processing services, we either
receive fees or commodities as payment for these services, based on the type of
contractual agreement. Based on the Companys current contract mix, the Company
has a long NGL position and a short gas position, however, the short gas
position is less significant than the long NGL position. Based upon our
portfolio of supply contracts, without giving effect to hedging activities that
would reduce the impact of commodity price decreases, a decrease of $0.01 per
gallon in the price of NGLs and $0.10 per million Btus in the average price of
natural gas would result in changes in annual pre-tax net income of
approximately $(18) million and $1 million, respectively. In addition, a
decrease of $1 per barrel in the average price of crude oil would result in a
change to annual pre-tax net income of approximately $(5) million. During the first three months of 2004, approximately 80% of our gross
margin is generated by commodity sensitive arrangements and approximately 20%
of our gross margin (excluding hedging and including earnings of unconsolidated
affiliates) is generated by fee-based arrangements. 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
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. 16




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We generally expect NGL prices to follow changes in crude oil prices over
the long term, which we believe will in large part be determined by the level
of production from major crude oil exporting countries and the demand generated
by growth in the world economy. However, the relationship or correlation
between crude oil value and NGL prices declined significantly during 2001 and
through the third quarter of 2002. Throughout the remainder of 2002, during
2003 and the first three months of 2004, this relationship reverted back toward
historical trends. We believe that future natural gas prices will be influenced by supply
deliverability, the severity of winter and summer weather and the level of
United States economic growth. The price increases in crude oil, NGLs and
natural gas experienced during 2000 and first half of 2001 spurred increased
natural gas drilling activity. However, a decline in commodity prices in late
2001, continuing into 2002, negatively affected drilling activity. Drilling
activity increased in 2003 due to higher commodity prices. The average number
of active oil and gas rigs drilling in the United States increased to 1,157
during the first quarter of 2004 from 959 during the first quarter of 2003. To 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 a portion of the value of our assets and
operations from such price risks. See Item 3. Quantitative and Qualitative
Disclosures About Market Risk. We do not realize the full impact of commodity
price changes because some of our sales volumes were previously hedged at
prices different than actual market prices. The recognition in the Consolidated
Statements of Operations of the cumulative changes in the fair value of these
hedge instruments reduced the results of operations by $19 million and $40
million in the first quarter of 2004 and 2003, respectively. See Item 3.
Quantitative and Qualitative Disclosure About Market Risk. Effects of Our Raw Natural Gas Supply Arrangements Our results are affected by the types of arrangements we use to process
raw natural gas. We obtain access to raw natural gas and provide our midstream
natural gas services principally under three types of processing contracts:  x
    
    Percentage-of-Proceeds Contracts  Under these contracts we receive
as our fee a negotiated percentage of the residue natural gas and NGLs
value derived from our gathering and processing activities, with the
producer retaining the remainder of the value or product. These types of
contracts permit us and the producers to share proportionately in
commodity price changes. Under these contracts, we share in both the
increases and decreases in natural gas prices and NGL prices.x
    
    Fee-Based Contracts  Under these contracts we receive a set fee for
gathering, processing and/or treating raw natural gas. Our revenue
stream from these contracts is correlated with our level of gathering
and processing activity and is not directly dependent on commodity
prices.x
    
    Keep-Whole and Wellhead Purchase Contracts  Under the terms of a
wellhead purchase contract, we purchase raw natural gas from the
producer at the wellhead or defined receipt point for processing and
then market the resulting NGLs and residue gas at market prices. Under
the terms of a keep-whole processing contract, we gather raw natural gas
from the producer for processing and then we market the NGLs and return
to the producer residue natural gas with a Btu content equivalent to the
Btu content of the raw natural gas gathered. This arrangement keeps the
producer whole to the thermal value of the raw natural gas we received.
Under these types of contracts the Company is exposed to the frac
spread. The frac spread is the difference between the value of the NGLs
extracted from processing and the value of the Btu equivalent of the
residue natural gas. We benefit in periods when NGL prices are higher
relative to natural gas prices.x
    
    In addition to the above arrangements, we sell condensate, which is
low grade crude oil that is produced in association with natural gas. In 2004 and 2003, we converted a portion of our keep-whole contracts to
percentage-of-proceeds contracts and we amended a portion of our keep-whole
contracts to add a minimum fee clause. This had the impact of reducing the
Companys exposure to natural gas prices and reducing the exposure to NGL
prices. 17




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Our current mix of percentage-of-proceeds contracts (where we are exposed
to decreases in natural gas prices) and keep-whole and wellhead purchase
contracts (where we are exposed to increases in natural gas prices) helps to
mitigate our exposure to changes in natural gas prices. Our exposure to
decreases in NGL prices is partially offset by our hedging program. Our hedging
program reduces the potential negative impact that commodity price changes
could have on our earnings and improves our ability to adequately plan for cash
needed for debt service and capital expenditures. The primary goals of our
hedging program include maintaining minimum cash flows to fund debt service;
production replacement and maintenance capital projects; and retaining a high
percentage of potential upside relating to increases in prices of NGLs. Accounting Adjustments Certain prior period amounts have been reclassified in the Consolidated
Financial Statements to conform to the current period presentation. Included in
the reclassified amounts are increases in both Sales of natural gas and
petroleum products and in Purchases of natural gas and petroleum products in
the amount of approximately $236 million for the quarter ended March 31, 2003.
This reclassification resulted from intersegment trading activities being
eliminated twice from the Consolidated Statements of Operations in the quarter
ended March 31, 2003. Management has concluded that these reclassifications are
not material to the fair presentation of the Companys financial statements. Results of Operations Three Months Ended March 31,2004
    
    2003(millions)Operating revenues:Sales of natural gas and petroleum products
    
    $
    2,332
    
    
    $
    2,540Transportation, storage and processing
    
    
    68
    
    
    
    61Trading and marketing net margin
    
    
    2
    
    
    
    (34
    )Total operating revenues
    
    
    2,402
    
    
    
    2,567Purchases of natural gas and petroleum products
    
    
    2,037
    
    
    
    2,271Gross margin (a)
    
    
    365
    
    
    
    296Cost and expenses
    
    
    210
    
    
    
    218Equity in earnings of unconsolidated affiliates
    
    
    17
    
    
    
    12EBIT from continuing operations before
Cumulative effect of accounting change (b)
    
    
    172
    
    
    
    90Interest expense, net
    
    
    40
    
    
    
    42Income tax expense
    
    
    3
    
    
    
    2Income from discontinued operations
    
    
    5
    
    
    
    6Cumulative effect of accounting change
    
    
    
    
    
    
    (23
    )Net income
    
    $
    134
    
    
    $
    29
  (a)
    
    Gross margin consists of total operating revenues less purchases of
natural gas and petroleum products. Gross margin is a non-Generally
Accepted Accounting Principles (GAAP) measure under the rules of the
Securities and Exchange Commission (SEC), but is included as a
supplemental disclosure because it is a primary performance measure used
by management as it represents the results of product sales and purchases,
a key component of our operations. As an indicator of our operating
performance, gross margin should not be considered an alternative to, or
more meaningful than, net income or cash flow as determined in accordance
with GAAP. Our gross margin may not be comparable to a similarly titled
measure of another company because other entities may not calculate gross
margin in the same manner.  (b)
    
    EBIT consists of net income from continuing operations before cumulative
effect of accounting change, net interest expense and income tax expense.
EBIT is a non-GAAP measure under the rules of the SEC, but is included as
a supplemental disclosure because it is a primary performance measure used
by management as it represents the results of operations without regard to
financing methods or capital structure. As an indicator of our operating
performance, EBIT should not be considered an alternative to, or more
meaningful than, net income or cash flow as determined in accordance with
GAAP. Our EBIT may not be comparable to a similarly titled measure of
another company because other entities may not calculate EBIT in the same
manner. 18




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Three months ended March 31, 2004 compared with three months ended March 31,
2003 Operating Revenues Total operating revenues decreased $165 million, or
6%, to $2,402 million in the first quarter of 2004 from $2,567 million in the
same period of 2003. This decrease was primarily due to the following factors:  x
    
    approximately $185 million was attributable to a $0.90 per
MMBtu decrease in average natural gas prices; andx
    
    approximately $110 million was attributable to lower throughput
related to reduced raw natural gas supply volume. Raw natural gas
supply volume has decreased due to reservoir decline exceeding new
supply from reduced drilling activity and increased plant downtime
due to maintenance. The decrease in revenues was partially offset by the following factors:  x
    
    approximately $50 million related to higher NGL sales volumes
which is primarily the result of wholesale marketing increases,
partially offset by lower NGL production due to throughput decline of
raw natural gas supply volume;x
    
    $21 million was related to the recognition of cash flow hedge
transactions which reduced revenues by $19 million in the first
quarter of 2004 compared to a revenue reduction of $40 million in the
first quarter of 2003;x
    
    approximately $15 million was attributable to a $0.01 per
gallon increase in average NGL prices;x
    
    $7 million was attributable to higher transportation, storage
and processing fees which was primarily due to increased fee revenue
associated with growth of our Canadian operations and higher fees
from other processing contracts; andx
    
    $36 million was attributable to higher trading and marketing
net margins, of which $29 million was related to the Natural Gas
Segment and $7 million was related to the NGLs Segment.The trading and marketing net margin gain of $2 million for the first
quarter of 2004 includes $5 million of income related to the NGLs
Segment offset by a $3 million loss related to the Natural Gas Segment.
The trading and marketing net margin loss of $34 million for the first
quarter of 2003 includes a $2 million loss related to the NGLs Segment
and a $32 million loss related to the Natural Gas Segment.Trading and marketing net margin in the Natural Gas Segment experienced
losses of approximately $10 million due to derivative trading
activities in the first quarter of 2003. The remaining losses included
in Trading and marketing net margin in the Natural Gas Segment are
primarily attributable to losses on mark-to-market derivatives for
which any related physical asset based gains are recognized on an
accrual basis and not included in trading and marketing net margin. Purchases of Natural Gas and Petroleum Products Purchases of natural gas
and petroleum products decreased $234 million, or 10%, to $2,037 million in the
first quarter of 2004 from $2,271 million in the same period of 2003. The
decrease was due primarily to lower costs of raw natural gas and natural gas
liquids supply of approximately $175 million, lower throughput of raw natural
gas supply volume of approximately $50 million and $8 million related to a
first quarter 2003 contract litigation settlement. Gross Margin Gross margin increased $69 million, or 23% to $365 million
in the first quarter of 2004 from $296 million in the same period of 2003. This
increase was primarily due to the following factors:  x
    
    approximately $35 million (net of hedging) was the result of
commodity sensitive processing; arrangements, mainly due to higher
average NGLs and crude oil prices and lower average natural gas
prices;x
    
    approximately $21 million was the result of $36 million of
improved net trading margin offset by approximately $15 million of
lower results related to physical natural gas asset based activity;x
    
    approximately $15 million due to higher margins resulting from
renegotiation of marginal supply contracts; andx
    
    $8 million related to expenses incurred in the first quarter of
2003 related to a contract litigation settlement. 19




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The increase in gross margin was partially offset by the following factors:  x
    
    approximately $5 million relating to decreased throughput volume; andx
    
    approximately $5 million primarily relating to lower margins on NGL inventory sales. Gross margin associated with the Natural Gas Segment increased $66
million, or 24%, to $345 million in the first quarter of 2004 from $279 million
in the same period of 2003, mainly as a result of the following factors:  x
    
    approximately $35 million (net of hedging) was the result of
commodity sensitive processing arrangements, mainly due to higher
average NGLs and crude oil prices and lower average natural gas
prices;x
    
    approximately $14 million was the result of $29 million of
improved net trading margin offset by approximately $15 million of
lower results related to physical natural gas asset based activity;x
    
    approximately $15 million due to higher margins resulting from
renegotiation of marginal supply contracts; andx
    
    $8 million related to expenses incurred in the first quarter
2003 related to a contract litigation settlement. The increase in gross margin associated with the Natural Gas Segment was
partially offset by approximately $5 million in decreased throughput volumes. Gross margin associated with the NGLs Segment increased $3 million, or 18%
to $20 million in the first quarter 2004 from $17 million for the same period
in 2003. This increase was comprised primarily of a $7 million increase in
trading and marketing net margin offset by approximately $5 million primarily
relating to lower margins on NGLinventory sales. NGL production during the first quarter 2004 decreased 11,000 barrels per
day, or 3%, to 357,000 barrels per day from 368,000 barrels per day in the same
period of 2003, and natural gas transported and/or processed during 2004
decreased 0.4 trillion Btus per day, or 5%, to 7.3 trillion Btus per day from
7.7 trillion Btus per day during the same period of 2003. The primary cause of
the decrease in NGL production was due to reservoir decline exceeding new
supply from drilling activity and increased plant downtime due to maintenance. Costs and Expenses Operating and maintenance expenses decreased $11
million, or 10%, to $94 million in the first quarter of 2004 from $105 million
in the same period of 2003. This decrease was primarily due to the following
factors:  x
    
    decreased facility maintenance and pipeline repair of approximately $5 million;x
    
    decreased labor and benefits of approximately $1 million; andx
    
    decreased expenses of approximately $5 million related to the
consolidation of a previously unconsolidated affiliate as required by
FASB Interpretation No. 46 (see Note 2 to the Consolidated Financial
Statements). Certain operating costs paid by us to this affiliate
are now eliminated through consolidation against the revenue of this
affiliate. General and administrative expenses increased $3 million, or 8%, to $41
million in the first quarter of 2004, from $38 million in the same period of
2003. This increase was primarily due to higher incentive compensation. Depreciation and amortization expenses were $75 million in both the first
quarter of 2004 and 2003. Interest Expense, net Interest expense, net, decreased $2 million, or 5%
to $40 million in the first quarter of 2004 from $42 million in the same period
of 2003. This decrease was primarily the result of lower outstanding debt
levels and higher cash investments in the first quarter of 2004 compared with
the first 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 million to $3 million in the first quarter of 2004 from $2 million
in the same period of 2003 due primarily to increased earnings associated with
state and foreign tax-paying subsidiaries. 20




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Income from Discontinued Operations Income from discontinued operations
was $5 million in the first quarter 2004 and $6 million in the first quarter
2003. Income from discontinued operations includes gains on the sale of
discontinued operations and the results of such operations in both periods
presented (see Note 3 to the Consolidated Financial Statements). Cumulative Effect of Accounting Change Cumulative effect of accounting
change was a loss of $23 million in the first quarter of 2003. Of this amount,
$18 million relates to the implementation of SFAS 143, and $5 million is due to
the rescission of EITF 98-10 (see Note 2 to Consolidated Financial Statements). Liquidity and Capital Resources As of March 31, 2004, we had $248 million in cash and cash equivalents
compared to $43 million as of December 31, 2003. Included in cash and cash
equivalents as of March 31, 2004 was approximately $74 million designated for
the anticipated acquisition of gathering, processing and transmission assets in
Southeast New Mexico; and approximately $25 million held by our Canadian
subsidiaries for their operations. The remaining cash balance was primarily
available for general corporate purposes. Current assets exceeded current
liabilities by $116 million at March 31, 2004 and current liabilities exceeded
current assets by $73 million at December 31, 2003. 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 three months of 2004, cash provided by operating
activities was $220 million, an increase of $144 million from $76 million in
the first three months of 2003. This increase was due primarily to a $105
million increase in net income. Additional increases were the result of
changes in working capital balances and unrealized mark-to-market and hedging
activity. The increase in net income is due largely to the favorable effects
of commodity prices, net of hedging, improved results from trading and
marketing activities, and decreased operating expenses, partially offset by
lower volumes. Cash distributions received from unconsolidated affiliates were $19
million in the first quarter of 2004 and $14 million in the first quarter of
2003. These distributions were in excess of earnings from unconsolidated
affiliates by $2 million in each period. Volatility in crude oil, NGLs and natural gas prices and the structure of
our commodity supply contracts have a direct impact on our generation and use
of cash from operations due to its impact on net income as described in the
Effects of Commodity Prices section above, along with the resulting changes in
working capital. Investing Cash Flows During the first three months of 2004, cash provided by investing
activities was $44 million, an increase of $76 million from cash used in
investing activities of $32 million in the first three months of 2003. The
increase is partially related to proceeds of $62 million from the sale 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. For the first three months of 2004, we
spent approximately $25 million on capital expenditures of continuing
operations compared to $34 million in the first three months of 2003. The
decrease is due to reduced well connections and plant upgrades in the first
quarter of 2004, as compared to the first quarter of 2003. Our level of capital expenditures for acquisitions and construction and
other investments depends on many factors, including industry conditions, the
availability of attractive acquisition opportunities and construction projects,
the level of commodity prices and competition. We expect to finance our capital
expenditures with our cash on hand, cash flow from operations, asset sales, our
credit facility or other available sources of financing. Our capital
expenditures forecast for the year ending December 31, 2004 is approximately
$220 million. Depending on cash flow results, redeployment of capital from
divestitures and opportunities in the marketplace, 2004 acquisition and capital
expenditures may vary from the forecast. 21




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Financing Cash Flows Bank Financing and Commercial Paper On March 26, 2004, we entered into a credit facility (the Facility). The
Facility replaces a credit facility that matured on March 26, 2004. The
Facility is used to support our commercial paper program and for working
capital and other general corporate purposes. The Facility matures on March 25,
2005; however; any outstanding borrowings under the Facility at maturity may,
at our option, be converted to a one-year term loan. The Facility is a $250
million revolving credit facility, all of which 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). The Facility bears
interest at a rate equal to, at our option and based on our current debt
rating, either (1) LIBOR plus 1.125% per year or (2) the higher of (a) the JP
Morgan Chase Bank prime rate plus 0.125% per year and (b) the Federal Funds
rate plus 0.625% per year. At March 31, 2004, there were no borrowings or
letters of credit drawn against the Facility. On November 3, 2003, we executed a $32 million irrevocable standby letter
of credit expiring on May 15, 2004 to be used to secure transaction exposure
with a counterparty. As of March 31, 2004, this letter of credit was still in
effect. At March 31, 2004, we had no outstanding commercial paper. In the future,
our debt levels will vary depending on our liquidity needs, capital
expenditures and cash flow. In April 2002, we filed a shelf registration statement increasing our
ability to issue securities to $500 million. The shelf registration statement
provides for the issuance of senior notes, subordinated notes and trust
preferred securities. Based on current and anticipated levels of operations, we believe that our
cash on hand and cash flow from operations, combined with borrowings available
under the commercial paper program as supported by the Facility, will be
sufficient to enable us to meet our current and anticipated cash operating
requirements and working capital needs for the next year. Actual capital
requirements, however, may change, particularly as a result of any acquisitions
or distributions that we may make. Our ability to meet current and anticipated
operating requirements will depend on our future performance. Distributions We are required to make quarterly distributions to Duke Energy and
ConocoPhillips based on allocated taxable income. Our Limited Liability Company
Agreement provides for taxable income to be allocated in accordance with the
Internal Revenue Code Section 704(c). This Code section takes into account the
variation between the adjusted tax basis and the fair market value of assets
contributed to the joint venture. The required distribution is based on the
highest taxable income allocated to either member, with the other member
receiving a proportionate amount to maintain the ownership capital accounts at
69.7% for Duke Energy and 30.3% for ConocoPhillips. As of March 31, 2004,
distributions payable of $11 million were included in Other current liabilities
in the Consolidated Balance Sheets. This amount was based on estimated annual
taxable income allocated to the members according to their respective ownership
percentages and was paid in April 2004. In 2003, our board of directors approved a plan to consider the payment of
a quarterly dividend to our members. Our board of directors may consider net
income, cash flow or any other criteria deemed appropriate for determining the
amount of the quarterly dividend to be paid. Our LLC Agreement restricts making
distributions, which would include these dividends, except with the approval of
both members. During the quarter ended March 31, 2004, with the approval of
both members, we paid a dividend of $50 million to the members allocated in
accordance with their respective ownership percentages. 22




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Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Arrangements As part of our normal business, we are a party to various financial
guarantees, performance guarantees and other contractual commitments to extend
guarantees of credit and other assistance to various subsidiaries, investees
and other third parties. To varying degrees, these guarantees involve elements
of performance and credit risk, which are not included in the Consolidated
Balance Sheets. The possibility of us having to honor our contingencies is
largely dependent upon future operations of various subsidiaries, investees and
other third parties, or the occurrence of certain future events. We record
reserves if events occur that require that one be established. At January 1, 2004, we were the guarantor of approximately $3 million of
debt. Assets were pledged as collateral for the debt. This debt was repaid in
January 2004. At March 31, 2004, we have various indemnification agreements outstanding
contained in asset purchase and sale agreements. These indemnification
agreements generally relate to the change in environmental and tax laws or
settlement of outstanding litigation. These indemnification agreements
generally have terms of one to five years, although some are longer. We cannot
estimate the maximum potential amount of future payments under these
indemnification agreements due to the uncertainties related to changes in laws
and regulation with regard to taxes, safety and protection of the environment
or the settlement of outstanding litigation, which are outside our control. At
March 31, 2004, we had a liability of $1 million recorded for these outstanding
indemnification provisions. For an in-depth discussion of our contractual obligations and commercial
commitments, see Managements Discussion and Analysis of Quantitative and
Qualitative Disclosures about Market Risk in our Form 10-K for December 31,
2003. New Accounting Standards In May 2003, the FASB issued SFAS No. 150 (SFAS 150), Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and
Equity. SFAS 150 requires that certain financial instruments that could
previously be accounted for as equity, be classified as liabilities in the
consolidated balance sheets and initially recorded at fair value. In addition
to its requirements for the classification and measurement of financial
instruments in its scope, SFAS 150 also requires disclosures about the nature
and terms of the financial instruments and about alternative ways of settling
the instruments. The provisions of SFAS 150 are effective for all financial
instruments entered into or modified after May 31, 2003, and are otherwise
effective at the beginning of the first interim period beginning after June 15,
2003. Upon adoption on July 1, 2003, we reclassified preferred members
interest, which are mandatorily redeemable, of $200 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. During 2003, we redeemed the remaining $200
million of these securities in cash. In January 2003, the FASB issued Interpretation No. 46 (FIN 46),
Consolidation of Variable Interest Entities which requires the primary
beneficiary of a variable interest entitys activities to consolidate the
variable interest entity. FIN 46 defines a variable interest entity as an
entity in which the equity investors do not have substantive voting rights and
there is not sufficient equity at risk for the entity to finance its activities
without additional subordinated financial support. The primary beneficiary is
the party that absorbs a majority of the expected losses and/or receives a
majority of the expected residual returns of the variable interest entitys
activities. In December 2003, the FASB issued FIN 46R, which supercedes and
amends certain provisions of FIN 46. While FIN 46R retains many of the concepts
and provisions of FIN 46, it also provides additional guidance related to the
application of FIN 46, provides for certain additional scope exceptions, and
incorporates several FASB Staff Positions issued related to the application of
FIN 46. The provisions of FIN 46 are immediately applicable to variable interest
entities created, or interests in variable interest entities obtained, after
January 31, 2003 and the provisions of FIN 46R are required to be applied to
such entities by the end of the first reporting period ending after March 15,
2004 (March 31, 2004 for us). For variable interest entities created, or
interests in variable interest entities obtained, on or before January 31,
2003, FIN 46 or FIN 46R is required to be applied to special-purpose entities
by the end of the first reporting period ending after December 15, 2003
(December 31, 2003 for calendar-year entities) and is required to be applied to
all other non- 23




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special purpose entities by the end of the first reporting period ending
after March 15, 2004 (March 31, 2004 for calendar-year entities). FIN 46 and
FIN 46R may be applied prospectively with a cumulative-effect adjustment as of
the date it is first applied, or by restating previously issued financial
statements with a cumulative-effect adjustment as of the beginning of the first
year restated. FIN 46 and FIN 46R also require certain disclosures of an
entitys relationship with variable interest entities. We did not identify any material variable interest entities created, or
interests in variable entities obtained, after January 31, 2003 which require
consolidation or disclosure under FIN 46. We consolidated one entity,
previously accounted for under the equity method of accounting, on January 1,
2004 under the provisions of FIN 46R. This entity, which is a substantive
entity, had total assets of approximately $92 million as of January 1, 2004.
Adoption of FIN 46R had no material effect on our consolidated results of
operations, cash flows or financial position. In July 2003, the EITF reached consensus in EITF Issue No. 03-11 (EITF
03-11), Reporting Realized Gains and Losses on Derivative Instruments that
are Subject to FASB Statement No. 133, Accounting for Derivative Instruments
and Hedging Activities, and Not Held for Trading Purposes, that determining
whether realized gains and losses on derivative contracts not held for trading
purposes should be reported on a net or gross basis is a matter of judgment
that depends on the relevant facts and circumstances. In analyzing the facts
and circumstances, EITF 99-19, Reporting Revenue Gross as a Principal versus
Net as an Agent and Opinion No. 29, Accounting for Nonmonetary Transactions,
should be considered. EITF 03-11 is effective for transactions or arrangements
entered into after September 30, 2003. The adoption of EITF 03-11 had no
material effect on the Companys consolidated results of operations, cash flows
or financial position. In May 2003, the EITF reached consensus in EITF Issue No. 01-08 (EITF
01-08), Determining Whether an Arrangement Contains a Lease, to clarify the
requirements of identifying whether an arrangement should be accounted for as a
lease at its inception. The guidance in the consensus is designed to mandate
reporting revenue as rental or leasing income that otherwise would be reported
as part of product sales or service revenue. EITF 01-08 requires both parties
to an arrangement to determine whether a service contract or similar
arrangement is or includes a lease within the scope of SFAS No. 13, Accounting
for Leases. The consensus is to be applied prospectively to arrangements
agreed to, modified, or acquired in business combinations in fiscal periods
beginning on July 1, 2003. The adoption of EITF 01-08 had no material effect on
the our consolidated results of operations, cash flows or financial position. Cumulative Effect of Accounting Change We adopted the provisions of EITF
02-03 that required new non-derivative energy trading contracts entered into
after October 25, 2002 to be accounted for under the accrual accounting basis.
Non-derivative energy trading contracts recorded in the Consolidated Balance
Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories
that were recorded at fair values were adjusted to historical cost via a
cumulative effect adjustment of $5 million as a reduction to earnings in the
first quarter of 2003. We adopted the provisions of SFAS No. 143 (SFAS 143), Accounting for
Asset Retirement Obligations, as of January 1, 2003 which addresses financial
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. In
accordance with the transition provisions of SFAS 143, we recorded a cumulative
effect adjustment of $18 million as a reduction to earnings in the first
quarter of 2003. Acquisitions and Dispositions In February 2004, we entered into a purchase and sale agreement to sell
gas gathering and processing plant assets in West Texas to a third party
purchaser for a sales price of approximately $62 million. The transaction
closed in the first quarter of 2004 with no significant book gain or loss. Subsequent Events On March 10, 2004, we entered into an agreement to acquire gathering,
processing and transmission assets in Southeast New Mexico from ConocoPhillips
for approximately $74 million. The transaction closed during the second quarter
of 2004. 24




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##### Table of Contents



Item 3. Quantitative and Qualitative Disclosure about Market Risks Risk and Accounting Policies We are exposed to market risks associated with commodity prices,
counterparty credit, interest rates, and, to a limited extent, foreign currency
exchange rates. Management has established comprehensive risk management
policies to monitor and manage these market risks. Duke Energy Field Services
Risk Management Committee (Risk Management Committee) is responsible for the
overall approval of market risk management policies and the delegation of
approval and authorization levels. The Risk Management Committee is composed of
senior executives who receive regular briefings on the Companys positions and
exposures as well as periodic updates from and consultations with the Duke
Energy Chief Risk Officer (CRO) and other expert resources at Duke Energy
regarding market risk positions and exposures, credit exposures and overall
risk management in the context of market activities. The Risk Management
Committee is responsible for the overall management of credit risk and
commodity price risk, including monitoring exposure limits. Commodity Price Risk We are exposed to the impact of market fluctuations primarily in the price
of NGLs that we own as a result of our processing activities. We employ
established policies and procedures to manage our risks associated with these
market fluctuations using various commodity derivatives, including forward
contracts, swaps, futures and options. (See Notes 2 and 4 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 derivative instruments held for trading and marketing purposes are
shown in the following table: Daily Value at Risk (millions) 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 endedMarch 31, 2004
    
    March 31, 2003
    
    March 31, 2004
    
    March 31, 2004Calculated DVaR
    
    $
    1
    
    
    $
    2
    
    
    $
    3
    
    
    
    
 DVaR is an estimate based on historical price volatility. Actual
volatility can exceed predicted results. DVaR also assumes a normal
distribution of price changes, thus if the actual distribution is not normal,
the DVaR may understate or overstate actual results. DVaR is used to estimate
the risk of the entire portfolio, and for locations that do not have daily
trading activity, it may not accurately estimate risk due to limited price
information. Stress tests may be employed in addition to DVaR to measure risk
where market data information is limited. In the current DVaR methodology,
options are modeled in a manner equivalent to forward contracts which may
understate the risk. 25




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##### Table of Contents



Our exposure to commodity price risk is influenced by a number of factors,
including contract size, length of contract, market liquidity, location and
unique or specific contract terms. Effective January 1, 2003, in connection
with the implementation of EITF 02-03, the Company designates each commodity
derivative as either trading or non-trading. Certain non-trading derivatives
are further designated as either a hedge of a forecasted transaction or future
cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm
commitment (fair value hedge), or a normal purchase or sale contract, while
certain non-trading derivatives, which are related to our asset based
marketing, are non-trading mark-to-market derivatives. For each of the
Companys derivatives, the accounting method and presentation of gains and
losses or revenue and expense in the Consolidated Statements of Operations are
as follows: Classification of Contract
    
    Accounting Method
    
    Presentation of Gains & Losses or Revenue & ExpenseTrading Derivatives
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net marginNon-Trading Derivatives:Cash Flow Hedge
    
    Hedge methodb
    
    Gross basis in the same income statement
category as the related hedged itemFair Value Hedge
    
    Hedge methodb
    
    Gross basis in the same income statement
category as the related hedged itemNormal Purchase or Normal Sale
    
    Accrual methodc
    
    Gross basis upon settlement in the
corresponding income statement category
based on commodity typeNon-Trading Mark-to-Market
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net margin
   a
    
    Mark-to-market- An accounting method whereby the change in the fair value of
the asset or liability is recognized in the Consolidated Statements of
Operations in Trading and marketing net margin during the current period.b
    
    Hedge method- An accounting method whereby the effective portion of the
change in the fair value of the asset or liability is recorded in Accumulated
Other Comprehensive Income in the Consolidated Balance Sheets and there is no
recognition in the Consolidated Statements of Operations for the effective
portion until the hedged transaction occurs.c
    
    Accrual method- An accounting method whereby there is no recognition in the
Consolidated Statements of Operations for changes in fair value of a contract
until the service is provided or the associated delivery of product occurs. The fair value of our mark-to-market contracts is expected to be realized
in future periods, as detailed in the following table. The amount of cash
ultimately realized for these contracts will differ from the amounts shown in
the following table due to factors such as market volatility, counterparty
default and other unforeseen events that could impact the amount and/or
realization of these values. When available, quoted market prices are used to record a contracts fair
value. However, market values for energy trading contracts may not be readily
determinable because the duration of the contracts could exceed the liquid
activity in a particular market. If no active trading market exists for a
commodity or for a contracts duration, holders of these contracts must
calculate fair value using internally developed valuation techniques or models.
Key components used in these valuation techniques include price curves,
volatility, correlation, interest rates, and tenor. Of these components,
volatility and correlation are the most subjective. Internally developed
valuation techniques include the use of interpolation, extrapolation, and
fundamental analysis in the calculation of a contracts fair value. All risk
components for new and existing transactions are valued using the same
valuation technique and market data and discounted using a LIBOR based interest
rate. Valuation adjustments for performance, market risk and administration
costs are used to adjust the fair value of the contract to the gain or loss
ultimately recognized in the Consolidated Statements of Operations. 26




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##### Table of Contents



The following table shows the fair value of our mark-to-market portfolio
as of March 31, 2004: Fair Value of Mark-to-Market Contracts as of March 31, 2004 (millions)Maturity in
    
    Maturity in
    
    Maturity in
    
    Maturity in 2007
    
    Total FairSources of Fair Value
    
    2004
    
    2005
    
    2006
    
    and Thereafter
    
    ValueTrading:Prices supported by
quoted market prices
and other external
sources
    
    $
    5
    
    
    $
    3
    
    
    $
    (1
    )
    
    $
    
    
    
    $
    7Prices based on models
and other valuation
methods
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    (2
    )
    
    
    Total
Trading
    
    
    7
    
    
    
    3
    
    
    
    (1
    )
    
    
    (2
    )
    
    
    7Non-Trading:Prices supported by
quoted market prices
and other external
sources
    
    
    (6
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (6
    )Prices based on models
and other valuation
methods
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
Non-Trading
    
    
    (6
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (6
    )Total
Mark-to-Market
    
    $
    1
    
    
    $
    3
    
    
    $
    (1
    )
    
    $
    (2
    )
    
    $
    1
 The Prices supported by quoted market prices and other external sources
category includes our New York Mercantile Exchange (NYMEX) swap positions in
natural gas and crude oil. The NYMEX has currently quoted prices for the next
32 months. In addition, this category includes our forward positions and
options in natural gas and natural gas basis swaps at points for which
over-the-counter (OTC) broker quotes are available. On average, OTC quotes
for natural gas forwards and swaps extend 22 and 32 months into the future,
respectively. OTC quotes for natural gas options extend 12 months into the
future, on average. We value these positions against internally developed
forward market price curves that are validated and recalibrated against OTC
broker quotes. This category also includes strip transactions whose prices
are obtained from external sources and then modeled to daily or monthly prices
as appropriate. The Prices based on models and other valuation methods category includes
(i) the value of options not quoted by an exchange or OTC broker and (ii) the
value of transactions for which an internally developed price curve was
constructed as a result of the long dated nature of the transaction or the
illiquidity of the market point. In certain instances structured transactions
can be decomposed and modeled by us as simple forwards and options based on
prices actively quoted. Although the valuation of the simple structures might
not be different from the valuation of contracts in other categories, the
effective model price for any given period is a combination of prices from two
or more different instruments and therefore has been included in this category
due to the complex nature of these transactions. Hedging Strategies We are exposed to market fluctuations in the prices
of energy commodities related to natural gas gathering, processing and
marketing activities. We closely monitor the risks associated with these
commodity price changes on our future operations and, where appropriate, may
use various commodity instruments such as natural gas, crude oil and NGL
contracts to hedge the value of our assets and operations from such price
risks. Our hedging program reduces the potential negative impact that
commodity price changes could have on our earnings and improves our ability to
adequately plan for cash needed for debt service and capital expenditures. The
primary goals of the hedging program include maintaining minimum cash flows to
fund debt service, production 27




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replacement and maintenance capital projects, and retaining a high
percentage of potential upside relating to price increases of NGLs. Our primary use of commodity derivatives is to hedge the output and
production of assets we physically own. Current remaining contract terms are
through the end of 2004; however, our risk management guidelines allow for
contract terms up to three years. Since these contracts are designated and
qualify as effective hedge positions of future cash flows, or fair values of
assets, liabilities or firm commitments, to the extent that the hedge
relationships are effective, their market value change impacts are not
recognized in current earnings. The unrealized gains or losses on these
contracts are deferred in Accumulated Other Comprehensive Income (AOCI) for
cash flow hedges or included in Other Current or Noncurrent Assets or
Liabilities on the Consolidated Balance Sheets for fair value hedges of firm
commitments. Amounts in AOCI are realized in earnings concurrently with the
transaction being hedged. However, in instances where the hedging contract no
longer qualifies for hedge accounting, amounts included in AOCI through the
date of de-designation remain in AOCI until the underlying transaction actually
occurs. The derivative contract (if continued as an open position) will be
marked to market currently through earnings. Several factors influence the
effectiveness of a hedge contract, including counterparty credit risk and using
contracts with different commodities or unmatched terms. Hedge effectiveness is
monitored regularly and measured each month. We utilize derivative instruments not only to hedge commodity exposures,
but also to hedge interest rate exposures (as discussed in the Interest Rate
Risk section on page 29). As mentioned previously, the effective portion of the
gains and losses for any of our hedging contracts are not recognized in
earnings until the contracts mature at their future market price. Therefore,
assumptions and valuation techniques for these contracts have no impact on
reported earnings prior to contract maturity 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 mature. The
following table contains the fair value of our hedging contracts, including
both commodity hedges and interest rate hedges, as of March 31, 2004: Fair Value of Hedging Contracts as of March 31, 2004 (millions)Maturity inMaturity in
    
    Maturity in
    
    Maturity in
    
    2007 andSources of Fair Value
    
    2004
    
    2005
    
    2006
    
    Thereafter
    
    Total Fair ValuePrices supported by
quoted market prices
and other external
sources
    
    $
    (24
    )
    
    $
    9
    
    
    $
    3
    
    
    $
    (1
    )
    
    $
    (13
    )Prices based on models
or other valuation
techniques
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    $
    (24
    )
    
    $
    9
    
    
    $
    3
    
    
    $
    (1
    )
    
    $
    (13
    )
 Based upon our portfolio of supply contracts, without giving effect to
hedging activities that would reduce the impact of commodity price decreases, a
decrease of $0.01 per gallon in the price of NGLs and $0.10 per million Btus in
the average price of natural gas would result in changes in annual pre-tax net
income of approximately $(18) million and $1 million, respectively. In
addition, a decrease of $1 per barrel in the average price of crude oil would
result in a change to annual pre-tax net income of approximately $(5) million. Credit Risk Our principle customers in the Natural Gas Segment are large, natural gas
marketing services and industrial end-users. In the NGLs segment, our
principle customers range from large multi-national petrochemical and refining
companies to small regional propane distributors. Substantially all of our
natural gas and NGLs sales are made at index, market-based prices.
Approximately 40% of our NGLs production is committed to ConocoPhillips and
ChevronPhillips, under an existing 15-year contract which expires in 2015. This
concentration of credit risk may affect our overall credit risk in that these
customers may be similarly affected by changes in economic, regulatory or 28




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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. As of March 31, 2004, we held cash or letters of credit of $45 million to
secure future performance by counterparties, and had deposited with
counterparties $40 million of such collateral to secure our obligations to
provide future services or to perform under financial contracts. Collateral
amounts held or posted may be fixed or may vary depending on the value of the
underlying contracts and could cover normal purchases and sales, trading and
hedging contracts. In many cases, we and our counterparties publicly
disclosed credit ratings impact the amounts of collateral requirements. Interest Rate Risk We enter into debt arrangements that are exposed to market risks related
to changes in interest rates. We periodically utilize interest rate lock
agreements and interest rate swaps to hedge interest rate risk associated with
debt. Our primary goals include (1) maintaining an appropriate ratio of
fixed-rate debt to total debt for our debt rating; (2) reducing volatility of
earnings resulting from interest rate fluctuations; and (3) locking in
attractive interest rates based on historical averages. As of March 31, 2004,
the fair value of our interest rate swaps was an asset of $17 million. As of March 31, 2004, we had no outstanding commercial paper. As a result
of our debt and interest rate swaps, we are exposed to market risks related to
changes in interest rates. In the future, we intend to manage our interest rate
exposure using a mix of fixed and floating interest rate debt. An increase of
0.5% in interest rates would result in an increase in annual interest expense
of approximately $2 million. Foreign Currency Risk Our primary foreign currency exchange rate exposure at March 31, 2004 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. As disclosed in our 2003 Annual Report on Form 10-K, our independent
auditor, Deloitte & Touche LLP (Deloitte), noted certain matters involving our
internal controls that it considered to be a reportable condition under the
standards established by the American Institute of Certified Public
Accountants. The reportable condition was not considered by Deloitte to be a
material weakness under the applicable auditing standards and had no material
affect on our financial statements. During the first quarter of 2004,
management established additional preventative and detective controls,
conducted company-wide training to our employees and implemented procedures and
controls to address the identified deficiencies. 29




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##### Table of Contents



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, 2003, 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)
    
    Exhibits10.1
    
    
    364-Day Credit Facility among Duke Energy Field Services, LLC, Duke
Energy Field Services Corporation, JP Morgan Chase Bank, as Agent and
the Lenders named therein, dated March 26, 2004.10.2
    
    
    Asset Purchase and Sale Agreement dated as of March 10, 2004, between
ConocoPhillips Company and Duke Energy Field Services, LP.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-KNone.
 30




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##### Table of Contents



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. May 14, 2004
    DUKE ENERGY FIELD SERVICES, LLC/s/ Rose M. RobesonRose M. RobesonVice President and Chief Financial Officer
(On Behalf of the Registrant and as
Principal Financial and Accounting Officer) 31




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##### Table of Contents



Index to Exhibits (a)
    
    Exhibits10.1
    
    
    364-Day Credit Facility among Duke Energy Field Services, LLC, Duke
Energy Field Services Corporation, JP Morgan Chase Bank, as Agent and
the Lenders named therein, dated March 26, 2004.10.2
    
    
    Asset Purchase and Sale Agreement dated as of March 10, 2004, between ConocoPhillips
Company and Duke Energy Field Services, LP.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.