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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549
 _______________ FORM 10-Q QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934 For Quarter Ended September 30, 2004
    
    Commission File Number 0-31095
 DUKE ENERGY FIELD SERVICES, LLC  Delaware
    
    76-0632293(State or other jurisdiction of incorporation)
    
    (IRS Employer Identification No.)
 370 17th Street, Suite 2500
Denver, Colorado 80202
(Address of principal executive offices)
(Zip Code) 303-595-3331
(Registrants telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) has been subject to such filing
requirements for the past 90 days. Yes   x    No o Indicate by check mark whether the registrant is an accelerated filer as
defined by Rule 12b-2 of the Act.
Yes   o   No x




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DUKE ENERGY FIELD SERVICES, LLC
FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2004 INDEX Item
    
    PagePART I. FINANCIAL INFORMATION (UNAUDITED)1. Financial Statements
    
    
    1Consolidated Statements of Operations for the Three and Nine months Ended September 30,
2004 and 2003
    
    
    1Consolidated Statements of Comprehensive Income for the Three and Nine months Ended
September 30, 2004 and 2003
    
    
    2Consolidated Balance Sheets as of September 30, 2004 and December 31, 2003
    
    
    3Consolidated Statements of Cash Flows for the Nine months Ended September 30, 2004 and 2003
    
    
    4Condensed Notes to Consolidated Financial Statements
    
    
    52. Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    183. Quantitative and Qualitative Disclosure about Market Risks
    
    
    314. Controls and Procedures
    
    
    35PART II. OTHER INFORMATION1. Legal Proceedings
    
    
    366. Exhibits and Reports on Form 8-K
    
    
    36Signatures
    
    
    372nd Amendment to Amended/Restated Limited Liability Company Agreement3rd Amendment to Parent Company AgreementAmendment to Services AgreementChange in Control AgreementEmployee Severance AgreementLetter Re: Changes in Accounting PrinciplesCertification of CFO Pursuant to Section 302Certification of CEO Pursuant to Section 302Certification of CFO Pursuant to Section 906Certification of CEO Pursuant to Section 906
  CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS Our reports, filings and other public announcements may from time to time
contain statements that do not directly or exclusively relate to historical
facts. Such statements are forward-looking statements within the meaning of
the Private Securities Litigation Reform Act of 1995. You can typically
identify forward-looking statements by the use of forward-looking words, such
as may, could, project, believe, anticipate, expect, estimate,
potential, plan, forecast and other similar words. All statements that are not statements of historical facts, including
statements regarding our future financial position, business strategy, budgets,
projected costs and plans and objectives of management for future operations,
are forward-looking statements. These forward-looking statements reflect our intentions, plans,
expectations, assumptions and beliefs about future events and are subject to
risks, uncertainties and other factors, many of which are outside our control.
Important factors that could cause actual results to differ materially from the
expectations expressed or implied in the forward-looking statements include
known and unknown risks. Known risks include, but are not limited to, the
following:  
    
    our ability to access the capital and bank markets, which will depend
on general market conditions and the credit ratings for our debt
obligations;
    
    our use of derivative financial instruments to manage commodity and interest rate risks;
    
    the level of creditworthiness of counterparties to transactions;
    
    the amount of collateral required to be posted from time to time in our transactions;
    
    changes in laws and regulations, particularly with regard to taxes,
safety and protection of the environment or the increased regulation of
the gathering and processing industry; i




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
    
    the timing and extent of changes in commodity prices, interest rates,
foreign currency exchange rates and demand for our services;
    
    weather and other natural phenomena;
    
    industry changes, including the impact of consolidations, and changes in competition;
    
    our ability to obtain required approvals for construction or
modernization of gathering and processing facilities, and the timing of
production from such facilities, which are dependent on the issuance by
federal, state and municipal governments, or agencies thereof, of
building, environmental and other permits, the availability of
specialized contractors and work force and prices of and demand for
products;
    
    the extent of success in connecting natural gas supplies to gathering
and processing systems;
    
    general economic conditions, including any potential effects arising
from terrorist attacks and any consequential hostilities or other
hostilities; and
    
    The effect of accounting pronouncements issued periodically by
accounting standard-setting bodies. In light of these risks, uncertainties and assumptions, the events
described in the forward-looking statements might not occur or might occur to a
different extent or at a different time than we have described. We undertake no
obligation to publicly update or revise any forward-looking statements, whether
as a result of new information, future events or otherwise. 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 Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003Operating Revenues:Sales of natural gas and petroleum products
    
    $
    1,874
    
    
    $
    1,574
    
    
    $
    5,324
    
    
    $
    4,569Sales of natural gas and petroleum products to
affiliates
    
    
    616
    
    
    
    439
    
    
    
    1,772
    
    
    
    1,941Transportation, storage and processing
    
    
    71
    
    
    
    67
    
    
    
    214
    
    
    
    194Trading and marketing net margin
    
    
    
    
    
    
    8
    
    
    
    4
    
    
    
    (25
    )Total operating revenues
    
    
    2,561
    
    
    
    2,088
    
    
    
    7,314
    
    
    
    6,679Costs and Expenses:Purchases of natural gas and petroleum products
    
    
    1,962
    
    
    
    1,570
    
    
    
    5,687
    
    
    
    5,166Purchases of natural gas and petroleum products
from affiliates
    
    
    170
    
    
    
    205
    
    
    
    457
    
    
    
    598Operating and maintenance
    
    
    111
    
    
    
    109
    
    
    
    310
    
    
    
    323Depreciation and amortization
    


    
    75
    
    
    
    73
    
    
    
    223
    
    
    
    221General and administrative
    
    
    43
    
    
    
    42
    
    
    
    125
    
    
    
    122Asset impairments
    
    
    22
    
    
    
    
    
    
    
    22
    
    
    
    Net gain on sale of assets
    
    
    (1
    )
    
    
    
    
    
    
    (1
    )
    
    
    Total costs and expenses
    
    
    2,382
    
    
    
    1,999
    
    
    
    6,823
    
    
    
    6,430Operating income
    
    
    179
    
    
    
    89
    
    
    
    491
    
    
    
    249Equity in earnings of unconsolidated affiliates
    
    
    5
    
    
    
    12
    
    
    
    36
    
    
    
    36Impairment of equity method investments
    
    
    (23
    )
    
    
    
    
    
    
    (23
    )
    
    
    Minority interest income
    
    
    7
    
    
    
    1
    
    
    
    7
    
    
    
    2Interest expense, net
    
    
    (39
    )
    
    
    (45
    )
    
    
    (118
    )
    
    
    (129
    )Income from continuing operations before income
taxes
    
    
    129
    
    
    
    57
    
    
    
    393
    
    
    
    158Income tax expense
    
    
    (2
    )
    
    
    (2
    )
    
    
    (7
    )
    
    
    (4
    )Income from continuing operations before cumulative
effect of accounting change
    
    
    127
    
    
    
    55
    
    
    
    386
    
    
    
    154(Loss) income from discontinued operations
    
    
    (23
    )
    
    
    1
    
    
    
    (18
    )
    
    
    36Cumulative effect of change in accounting
principles
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (23
    )Net income
    
    
    104
    
    
    
    56
    
    
    
    368
    
    
    
    167Dividends on preferred members interest
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (9
    )Earnings available for members interest
    
    $
    104
    
    
    $
    56
    
    
    $
    368
    
    
    $
    158
 See Condensed Notes to Consolidated Financial Statements. 1




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DUKE ENERGY FIELD SERVICES, LLC 
 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(millions)
 Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003Net income
    
    $
    104
    
    
    $
    56
    
    
    $
    368
    
    
    $
    167Other comprehensive income:Foreign currency translation adjustment
    
    
    18
    
    
    
    
    
    
    
    5
    
    
    
    45Net unrealized losses on cash flow hedges
    
    
    (12
    )
    
    
    (5
    )
    
    
    (41
    )
    
    
    (66
    )Reclassification of previously deferred
losses on cash flow hedges into earnings.
    
    
    13
    
    
    
    25
    
    
    
    55
    
    
    
    91Total other comprehensive income
    
    
    19
    
    
    
    20
    
    
    
    19
    
    
    
    70Total comprehensive income
    
    $
    123
    
    
    $
    76
    
    
    $
    387
    
    
    $
    237
 See Condensed Notes to Consolidated Financial Statements. 2




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DUKE ENERGY FIELD SERVICES, LLC 
 CONSOLIDATED BALANCE SHEETS
(Unaudited)
(millions)
 September 30,
    
    December 31,2004
    
    2003ASSETSCurrent assets:Cash and cash equivalents
    
    $
    323
    
    
    $
    43Accounts receivable:Customers, net of allowance for doubtful accounts of $4
and $8, respectively
    
    
    908
    
    
    
    872Affiliates
    
    
    51
    
    
    
    57Other
    
    
    52
    
    
    
    29Inventories
    
    
    38
    
    
    
    45Unrealized gains on mark-to-market and hedging transactions.
    
    
    211
    
    
    
    135Other current assets
    
    
    70
    
    
    
    20Total current assets
    
    
    1,653
    
    
    
    1,201Property, plant and equipment, net
    
    
    4,289
    
    
    
    4,462Investment in unconsolidated affiliates
    
    
    156
    
    
    
    190Intangible assets:Commodity sales and purchases contracts, net
    
    
    74
    
    
    
    80Goodwill, net
    
    
    448
    
    
    
    447Total intangible assets
    
    
    522
    
    
    
    527Unrealized gains on mark-to-market and hedging transactions
    
    
    40
    
    
    
    25Other noncurrent assets
    
    
    31
    
    
    
    109Total assets
    
    $
    6,691
    
    
    $
    6,514LIABILITIES AND MEMBERS EQUITYCurrent liabilities:Accounts payable:Trade
    
    $
    911
    
    
    $
    857Affiliates
    
    
    19
    
    
    
    16Other
    
    
    67
    
    
    
    33Current debt, including current maturities of long-term debt
    
    
    609
    
    
    
    6Accrued interest payable
    
    
    26
    
    
    
    59Unrealized losses on mark-to-market and hedging transactions
    
    
    221
    
    
    
    153Other current liabilities
    
    
    220
    
    
    
    150Total current liabilities
    
    
    2,073
    
    
    
    1,274Deferred income taxes
    
    
    20
    
    
    
    17Long-term debt
    
    
    1,649
    
    
    
    2,262Unrealized losses on mark-to-market and hedging transactions
    
    
    40
    
    
    
    24Other long-term liabilities
    
    
    107
    
    
    
    73Minority interests
    
    
    42
    
    
    
    120Commitments and contingent liabilitiesMembers equity:Members interest
    
    
    1,709
    
    
    
    1,709Retained earnings
    
    
    1,008
    
    
    
    1,011Accumulated other comprehensive income
    
    
    43
    
    
    
    24Total members equity
    
    
    2,760
    
    
    
    2,744Total liabilities and members equity
    
    $
    6,691
    
    
    $
    6,514
 See Condensed Notes to Consolidated Financial Statements. 3




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DUKE ENERGY FIELD SERVICES, LLC 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(millions)
 Nine Months EndedSeptember 30,2004
    
    2003Cash flows from operating activities:Net income
    
    $
    368
    
    
    $
    167Adjustments to reconcile net income to net cash provided by operating
activities:Loss (income) from discontinued operations
    
    
    18
    
    
    
    (36
    )Cumulative effect of change in accounting principles
    
    
    
    
    
    
    23Depreciation, amortization and impairment charges
    
    
    268
    
    
    
    221Distributions received in excess of earnings of unconsolidated affiliates
    
    
    22
    
    
    
    11Other, net
    
    
    21
    
    
    
    8Change in operating assets and liabilities which provided (used) cash:Accounts receivable
    
    
    (60
    )
    
    
    (54
    )Accounts receivable from affiliates
    
    
    9
    
    
    
    136Inventories
    
    
    10
    
    
    
    20Net unrealized gains on mark-to-market and hedging transactions
    
    
    
    
    
    
    (35
    )Accounts payable
    
    
    89
    
    
    
    (35
    )Accounts payable to affiliates
    
    
    
    
    
    
    (15
    )Accrued interest payable
    
    
    (33
    )
    
    
    (29
    )Other
    
    
    (26
    )
    
    
    8Net cash provided by operating activities
    
    
    686
    
    
    
    390Cash flows from investing activities:Capital expenditures
    
    
    (157
    )
    
    
    (93
    )Consolidation of previously unconsolidated investment
    
    
    6
    
    
    
    Investment expenditures, net of cash acquired
    
    
    (4
    )
    
    
    (1
    )Contributions to minority interests, net of distributions
    
    
    (2
    )
    
    
    (1
    )Proceeds from sale of discontinued operations
    
    
    62
    
    
    
    90Proceeds from sales of assets
    
    
    10
    
    
    
    20Net cash (used in) provided by investing activities
    
    
    (85
    )
    
    
    15Cash flows from financing activities:Redemption of preferred members interest
    
    
    
    
    
    
    (125
    )Payment of debt
    
    
    (9
    )
    
    
    (215
    )Payment of dividends and distributions to members
    
    
    (293
    )
    
    
    (9
    )Net cash used in financing activities
    
    
    (302
    )
    
    
    (349
    )Effect of foreign exchange rate changes on cash
    
    
    1
    
    
    
    (1
    )Cash flows from discontinued operations
    
    
    (20
    )
    
    
    11Net increase in cash and cash equivalents
    
    
    280
    
    
    
    66Cash and cash equivalents, beginning of period
    
    
    43
    
    
    
    35Cash and cash equivalents, end of period
    
    $
    323
    
    
    $
    101Supplementary cash flow information:Cash paid for interest (net of amounts capitalized)
    
    $
    147
    
    
    $
    153
 See Condensed Notes to Consolidated Financial Statements. 4




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DUKE ENERGY FIELD SERVICES, LLC 
 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 1. General and Summary of Significant Accounting Policies Duke Energy Field Services, LLC (with its consolidated subsidiaries, us,
we, our or 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 (NGL or 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. 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 we
are the primary beneficiary. Investments in 20% to 50% owned affiliates, and
investments in less than 20% owned affiliates where we have the ability to
exercise significant influence, are accounted for using the equity method.
Investments greater than 50% are consolidated unless we do 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. 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 in the Consolidated Balance Sheets at its
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, we designate each energy commodity derivative
as either trading or non-trading. For each of our 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
    
    
    
    Presentation of Gains & Losses or Revenue &Contract
    
    Accounting Method
    
    ExpenseTrading Derivatives
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net marginNon-Trading Derivatives:Cash Flow Hedge
    
    Hedge methodb
    
    Gross basis in the same income statementcategory as the related hedged itemFair Value Hedge
    
    Hedge methodb
    
    Gross basis in the same income statementcategory as the related hedged itemNormal Purchase or
    
    Accrual methodc
    
    Gross basis upon settlement in theNormal Sale
    
    
    
    corresponding income statement categorybased on commodity typeNon-Trading Mark-to-
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net marginMarket
 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 change in the fair value of
the asset or liability is recorded in the Consolidated Balance Sheets and there
is no recognition in the Consolidated Statements of 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, we
formally assess, 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. We exclude 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 an account receivable or payable. 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) and the ineffective portion is recorded in
the Consolidated Statements of Operations. 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. We discontinue 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 the hedged transaction will occur, in
which case, the gains and losses that were previously deferred in AOCI will be
immediately recognized in current 6




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period earnings. At September 30, 2004 and December 31, 2003, $15 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
Unrealized 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  We periodically enter into interest rate
swaps to convert some of our 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, our 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 our Limited Liability Company Agreement
(the LLC Agreement), we are 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. During the nine months ended
September 30, 2004, we paid distributions of $16 million based on estimated
annual taxable income allocated to the members according to their respective
ownership percentages. As of September 30, 2004, distributions payable of $78
million were included in Other current liabilities in the Consolidated Balance
Sheets. In 2003, our 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 nine months ended September 30,
2004, with the approval of both members, we paid a total dividend of $277
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 and other stock-based instruments for Duke Energys common
stock and other stock-based awards may be granted to our key employees. We
account for stock-based compensation arrangements 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.
Because 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 as
compensation cost over the required vesting period, based on the fair value on
the date of grant. Performance awards are recorded as compensation cost over
the required vesting period, based on the fair value of the awards at the
balance sheet date. The following table shows what earnings available for members interest
would have been if we had applied the fair value recognition provisions of SFAS
No. 123, Accounting for Stock-Based Compensation, to stock options 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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##### Table of Contents



Three Months ended
    
    Nine Months endedSeptember 30,
    
    September 30,Pro Forma Stock-Based Compensation (millions)
    
    2004
    
    2003
    
    2004
    

    2003Earnings available
for members
interest, as
reported
    
    $
    104
    
    
    $
    56
    
    
    $
    368
    
    
    $
    158Add: stock-based
compensation
expense included in
reported net income
    
    
    1
    
    
    
    
    
    
    
    2
    
    
    
    1Deduct: total
stock-based
compensation
expense determined
under fair
value-based method
for all awards
    
    
    (2
    )
    
    
    (1
    )
    
    
    (4
    )
    
    
    (5
    )Pro forma earnings
available for
members interest
    
    $
    103
    
    
    $
    55
    
    
    $
    366
    
    
    $
    154
 Accumulated Other Comprehensive Income The components of and changes in
accumulated other comprehensive income are as follows: Net
    
    AccumulatedAccumulated Other Comprehensive
    
    Foreign
    
    Unrealized
    
    OtherIncome
    
    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
    
    
    5
    
    
    
    14
    
    
    
    19Balance as of September 30, 2004
    
    $
    58
    
    
    $
    (15
    )
    
    $
    43
 Cumulative
Effect of Change in Accounting Principles We 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 basis of accounting. 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 value 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. 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 including the deferral of
certain effective dates as a result of the provisions of FASB Staff Position
150-3, Effective Date, Disclosures, and Transition for Mandatorily Redeemable
Noncontrolling Interests Under FASB Statement No. 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.
Upon adoption on July 1, 2003, we reclassified our preferred members interest,
which were 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. 8




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##### Table of Contents



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. We adopted the provisions of FIN 46 and its related
interpretations (FIN 46R) in the first quarter of 2004. As a result, we
consolidated one entity, previously accounted for under the equity method of
accounting, on January 1, 2004. 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 our 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
our 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 $264 million and $723
million, for the three and nine months ended September 30, 2003, respectively.
This reclassification resulted from intersegment trading activities being
eliminated twice from the Consolidated Statements of Operations during the nine
months ended September 30, 2003. Management has concluded that these
reclassifications are not material to the fair presentation of our financial
statements. 2. Impairments of Long-Lived Assets and Investments in Affiliates Impairments
of Long-Lived Assets We recorded impairments of $22 million
as Asset impairments, included in the Consolidated Statements of Operations,
with an offset to Property, plant and equipment, net, included in the
Consolidated Balances Sheets, in the third quarter of 2004 as described below. Approximately $9 million of the asset impairments were related to our
periodic review of the carrying value of our assets and a planned shut down of
a specific plant. We determined that these assets, which are located in
Onshore and Offshore Gulf of Mexico, were impaired, therefore they were written
down to their fair value. Fair value was determined based on managements best
estimates of sales value and/or discounted future cash flow models. The charges
associated with these impairments were recorded in the Natural Gas Segment. Approximately $13 million (offset by $7 million in minority interest
income) of the asset impairments were related to assets that were distributed
to a minority interest holder in exchange for their 42% minority interest (see
discussion related to Mobile Bay Processing Partners in Note 3 below). We
determined that these assets, which are located Onshore Gulf of Mexico, were
impaired, therefore they were written down to fair value. Fair value was
determined based on an independent third-party valuation. The charges
associated with these impairments were recorded in the Natural Gas Segment. 9




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##### Table of Contents



Impairments of Investments in Affiliates In the third quarter of 2004,
we recorded an impairment totaling $23 million as Impairment of equity method
investments, included in the Consolidated Statements of Operations, with an
offset to Investment in unconsolidated affiliates included in the Consolidated
Balance Sheets. Our investments in these assets, which are located Onshore
Gulf of Mexico, were analyzed during the third quarter and determined to be
impaired. As a result, these investments were written down to fair value which
was determined based on managements best estimates of sales value and/or
discounted future cash flow models. The charges associated with these
impairments were recorded in the NGL Segment. 3. Acquisitions and Dispositions Based upon managements current assessment of the probable disposition of
certain gathering, compression and transportation assets expected to occur by
early 2005, we have classified these assets as held for sale and have
reclassified the assets to Other current assets in the Consolidated Balance
Sheet as of September 30, 2004. The book value of these assets has been
written down by $23 million to $27 million, the estimated fair value less costs
to sell. These assets comprise a component of the Company for purposes of
reporting discontinued operations. The results of operations and cash flows
related to these assets held for sale have been reclassified to discontinued
operations for all periods presented. These assets were previously included in
the Natural Gas Segment. On August 31, 2004, we acquired a 42% minority interest in Mobile Bay
Processing Partners (MBPP) in exchange for certain assets of MBPP. MBPP is a
consolidated entity, which, prior to this transaction, was owned 58% by us, and
subsequent to the transaction is wholly-owned by us. As a result of the
exchange, we recorded an impairment charge of $13 million (offset by $7 million
in minority interest income) related to the assets that were distributed, which
had a fair market value of less than book value. Minority interests in the
Consolidated Balance Sheet decreased by $40 million related to this
transaction. MBPP owns processing assets in the Onshore Gulf of Mexico. On August 31, 2004, we purchased a 42% minority interest in Gulf Coast NGL
Pipeline, LLC (GC) for $2 million. GC is a consolidated entity, which, prior
to this transaction, was owned 58% by us, and subsequent to the transaction is
wholly-owned by us. Minority interests in the Consolidated Balance Sheet
decreased by $7 million related to this transaction. GC owns a 16.67% interest
in two investments in unconsolidated affiliates. On August 31, 2004, we purchased a 12% minority interest in Dauphin Island
Gathering Partners (DIGP) for $2 million. DIGP is a consolidated entity,
which, prior to this transaction, was owned 72% by us, and subsequent to the
acquisition is owned 84% by us. Minority interests in the Consolidated Balance
Sheet decreased by $29 million related to this transaction. DIGP owns gathering
and transmission assets in the Offshore Gulf of Mexico. In April 2004, we acquired gathering, processing and transmission assets
in Southeast New Mexico from ConocoPhillips, a related party, for a total
purchase price of approximately $80 million, consisting of $74 million in cash
and the assumption of approximately $6 million of liabilities. In February 2004, we sold gas gathering and processing plant assets in
West Texas to a third party purchaser for a sales price of approximately $62
million, with no significant book gain or loss. These assets comprised a
component of the Company for purposes of reporting discontinued operations.
The results of operations and cash flows related to these assets have been
reclassified to discontinued operations for all periods presented. These assets
were previously included in the Natural Gas Segment. In the second quarter of 2003, we 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. The results of operations
and cash flows related to these assets have been reclassified to discontinued
operations for all periods presented. These assets were previously included in
the Natural Gas Segment. 10




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##### Table of Contents



The following table sets forth selected financial information associated
with the assets discussed above which are accounted for as discontinued
operations: Three
    
    NineMonths Ended
    
    Months EndedSeptember 30,

    
    September 30,2004
    
    2003
    
    2004
    
    2003(millions)
    
    (millions)Operating Revenues
    
    $
    10
    
    
    $
    29
    
    
    $
    54
    
    
    $
    296Operating income
    
    
    
    
    
    
    1
    
    
    
    2
    
    
    
    10(Loss) gain on sale, including assets held for sale
    
    
    (23
    )
    
    
    
    
    
    
    (20
    )
    
    
    26(Loss) income from discontinued operations
    
    $
    (23
    )
    
    $
    1
    
    
    $
    (18
    )
    
    $
    36
 4. Derivative Instruments, Hedging Activities and Credit Risk Commodity cash flow hedges We may, from time to time, use cash flow
hedges, as specifically defined by SFAS 133, to reduce the potential negative
impact that commodity price changes could have on our earnings and ability to
adequately plan for cash needed for debt service, capital expenditures and tax
distributions. We use natural gas, crude oil and NGL swaps to hedge the impact of market
fluctuations in the prices of NGLs, natural gas and other energy-related
products. For the three and nine months ended September 30, 2004, the
recognition in the Consolidated Statements of Operations of the cumulative
changes in the fair value of these hedge instruments reduced revenues by $12
million and $54 million, respectively, compared to $23 million and $87 million,
respectively, in the same periods of 2003. The above changes in the fair value
of these hedge instruments include the effects of any ineffectiveness, which
for the nine months ended September 30, 2004 and 2003, were a $1 million gain
and a $5 million gain, respectively. No derivative gains or losses were
reclassified from AOCI to current period earnings as a result of the
discontinuance of cash flow hedges related to any forecasted transactions that
are not probable of occurring. Gains and losses on derivative contracts that are reclassified from AOCI
to current period earnings are included in the line item in which the hedged
item is recorded. As of September 30, 2004, $15 million of the remaining
deferred net losses on derivative instruments in AOCI are expected to be
reclassified into earnings within the next 12 months 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 we are currently hedging our
exposure to the variability of future cash flows is through the end of 2004. Commodity
fair value hedges We use 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. We may hedge producer
price locks (fixed price gas purchases) and market locks (fixed price gas
sales) to reduce our exposure to fixed price risk via swapping the fixed price
risk for a floating price position (New York Mercantile Exchange or index
based). For the nine months ended September 30, 2004, the gains or losses
representing the ineffective portion of our 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. We 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, we 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, we
entered into two additional interest rate swaps to convert $100 million of
fixed-rate debt securities issued in August 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
September 30, 2004, the fair value of the interest rate swaps was a $10 million
asset, which is included in the Consolidated Balance Sheets as Unrealized gains
or losses on mark-to-market and hedging transactions with offsets to the
underlying debt included in Current maturities of long term debt and Long term
debt. 11




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##### Table of Contents



Commodity
Derivatives  Trading and Marketing The trading and marketing
of energy related products and services exposes us to fluctuations in the
market values of traded instruments. We manage our 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 Obligation The following table summarizes changes in the asset retirement obligation,
included in Other long term liabilities in the Consolidated Balance Sheets, for
the nine months ended September 30, 2004 and 2003, respectively. 2004
    
    2003Reconciliation of Asset Retirement Obligation
    
    (millions)Balance as of January 1
    
    $
    45
    
    
    $
    43Accretion expense
    
    
    8
    
    
    
    3Liabilities incurred
    
    
    3
    
    
    
    Liabilities settled
    
    
    (2
    )
    
    
    (2
    )Balance as of September 30
    
    $
    54
    
    
    $
    44
 6. Goodwill and Other Intangibles Goodwill The changes in the carrying amount of goodwill for the nine
months ended September 30, 2004 are as follows: Purchase
    
    ForeignBalance
    
    Price
    
    Currency
    
    BalanceDecember 31, 2003
    
    Adjustments
    
    Exchange Adjustments
    
    September 30, 2004(millions)Natural gas gathering, processing, transportation,
marketing
and storage
    
    $
    407
    
    
    $
    
    
    
    $
    1
    
    
    $
    408NGL fractionation, transportation, marketing and trading
    
    
    40
    
    
    
    
    
    
    
    
    
    
    
    40Total consolidated
    
    $
    447
    
    
    $
    
    
    
    $
    1
    
    
    $
    448
 During the quarter ended September 30, 2004, we changed the date of our
annual goodwill impairment test to August 31st from September 30th. We
selected August 31st to perform our annual goodwill impairment test because
this earlier date allows us to complete our goodwill impairment test within the
same quarter as the testing date. In addition, the change in date will be
consistent with the annual goodwill impairment test date of our majority
parent. The change in testing goodwill date is not intended to delay,
accelerate or avoid an impairment charge. We believe that the accounting
change described above is to an alternative accounting principle which is
preferable under the circumstances. We completed our annual goodwill impairment test as of August 31, 2004 by
comparing our reporting units fair values to their carrying or book values.
This valuation indicated reporting units fair values in excess of our book
values; therefore, we have determined that no impairment exists. Other intangibles The gross carrying amount and accumulated amortization
for commodity sales and purchases contracts are as follows: September 30,
    
    December 31,2004
    
    2003(millions)Commodity sales and purchases contracts
    
    $
    127
    
    
    $
    127Accumulated amortization
    
    
    (53
    )
    
    
    (47
    )Commodity sales and purchases contracts, net
    
    $
    74
    
    
    $
    80
 12




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##### Table of Contents



We recorded amortization expense associated with commodity sales and
purchases contracts of $7 million in each of the nine month periods ended
September 30, 2004 and 2003. The remaining amortization periods for these
contracts range from 1 to 12 years with a weighted average remaining period of
approximately 6 years. Estimated amortization for these contracts for the next
five years is as follows: Estimated Amortization(millions)2004
    
    $
    22005
    
    
    82006
    
    
    82007
    
    
    82008
    
    
    8Thereafter.
    
    
    40Total
    
    $
    74
 7. Financing Credit Facility with Financial Institutions On March 26, 2004, we
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
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 September 30,
2004, there were no borrowings or letters of credit drawn against the Facility. In the third quarter of 2004, $600 million of debt securities due in 2005
were reclassified from long term to short term. On March 28, 2003, we also entered into a $100 million funded short-term
loan with a bank (the Short-Term Loan). The Short-Term Loan was used for
working capital and other general corporate purposes. The Short-Term Loan
contained an original maturity of September 30, 2003, but was repaid by August
2003 with funds generated from asset sales and operations. On November 3, 2003, we executed a $32 million irrevocable standby letter
of credit, to be used to secure transaction exposure with a counterparty, which
expired on May 15, 2004. Preferred Financing Upon adoption of SFAS 150 on July 1, 2003, we
reclassified our preferred members interest, which were mandatorily redeemable
securities, of $200 million from mezzanine equity to long term debt. During
2003, subsequent to the reclassification, we redeemed the remaining $200
million. Beginning on July 1, 2003, accrued or paid distributions previously
classified as dividends on the preferred members interest were prospectively
classified as interest expense in the Consolidated Statements of Operations. 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. We are currently named as
defendants in some of these cases. Management believes we 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 13




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##### Table of Contents



information, these proceedings will not have a material adverse effect on
our consolidated results of operations, financial position or cash flows. General
Insurance We carry insurance coverage, with an affiliate of Duke
Energy, that management believes is consistent with companies engaged in
similar commercial operations with similar type properties. Our 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, 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. We also maintain 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. In the third quarter 2004, certain assets, located Onshore and Offshore in
the Gulf of Mexico, were damaged as a result of Hurricane Ivan. Management is
in the process of assessing the impact of these damages, however, we believe
that the resulting losses will be covered by insurance, subject to applicable
deductibles for property and business interruption. We do not expect this event
to have a material effect on our consolidated results of operations. 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, provincial 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 our
consolidated results of operations, financial position or cash flows. Severance
Program On October 30, 2003, we communicated a company-wide
voluntary and involuntary severance program to our employees to reduce
approximately 6% of our workforce. The plan was completed on December 8, 2003
and included the reduction of 160 employees over the period from December 2003
through September 2004. The severance liability that was recorded in the fourth
quarter of 2003 was $6 million at December 31, 2003. The Company expensed an
additional $1 million, included in General and administrative expense in the
Consolidated Statement of Operations, related to this severance program during
first quarter of 2004. The following table summarizes changes in the severance
liability for the nine months ended September 30, 2004. Reconciliation of Severance liability (millions)Balance as of December 31, 2003
    
    $
    6Additional severance expense
    
    
    1Severance paid
    
    
    (7
    )Balance as of September 30, 2004
    
    $
    
 14




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##### Table of Contents



9. Business Segments We operate in two principal business segments: (1) 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), and (2) NGL fractionation, transportation, marketing and trading, from which
we generate revenues from transportation fees, market center fractionation and
the marketing and trading of NGLs (the NGL Segment). Intersegment activity is primarily related to the sale of NGLs from the
Natural Gas Segment to the NGL Segment at market based transfer prices. These segments are monitored separately by management for performance
against our internal forecast and are consistent with our 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 1. Foreign operations are not material and are
therefore not separately identified. The following tables set forth our segment information. Three months ended September 30, 2004 (millions): Natural Gas
    
    NGL
    
    Intersegment
    
    
    
    
    
    TotalSegment
    
    Segment
    
    Eliminations (a)
    
    Other (c)
    
    CompanyOperating Revenues
    
    $
    2,302
    
    
    $
    585
    
    
    $
    (326
    )
    
    $
    
    
    
    $
    2,561Gross Margin (b)
    
    
    416
    
    
    
    13
    
    
    
    
    
    
    
    
    
    
    
    429Other operating and administrative costs
    
    
    142
    
    
    
    2
    
    
    
    
    
    
    
    31
    
    
    
    175Depreciation and amortization
    
    
    68
    
    
    
    3
    
    
    
    
    
    
    
    4
    
    
    
    75Earnings (loss) from unconsolidated
affiliates, net of impairments
    
    
    5
    
    
    
    (23
    )
    
    
    
    
    
    
    
    
    
    
    (18
    )Minority interest income
    
    
    7
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    7Interest expense, net
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    39
    
    
    
    39Income from continuing operations
before income taxes
    
    $
    218
    
    
    $
    (15
    )
    
    $
    
    
    
    $
    (74
    )
    
    $
    129Capital Expenditures
    
    $
    27
    
    
    $
    1
    
    
    $
    
    
    
    $
    (1
    )
    
    $
    27
 Three months ended September 30, 2003 (millions): Natural Gas
    
    NGL
    
    Intersegment
    
    
    
    
    
    TotalSegment
    
    Segment
    
    Eliminations (a)
    
    Other (c)
    
    CompanyOperating Revenues
    
    $
    1,943
    
    
    $
    434
    
    
    $
    (289
    )
    
    $
    
    
    
    $
    2,088Gross Margin (b)
    
    
    301
    
    
    
    12
    
    
    
    
    
    
    
    
    
    
    
    313Other operating and administrative costs
    
    
    114
    
    
    
    2
    
    
    
    
    
    
    
    35
    
    
    
    151Depreciation and amortization
    
    
    61
    
    
    
    3
    
    
    
    
    
    
    
    9
    
    
    
    73Earnings from unconsolidated affiliates
    
    
    12
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    12Minority interest income
    
    
    1
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1Interest expense, net
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    45
    
    
    
    45Income from continuing operations
before income taxes
    
    $
    139
    
    
    $
    7
    
    
    $
    
    
    
    $
    (89
    )
    
    $
    57Capital Expenditures
    
    $
    27
    
    
    $
    
    
    
    $
    
    
    
    $
    2
    
    
    $
    29
 15




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##### Table of Contents



Nine months ended September 30, 2004 (millions): Natural Gas
    
    NGL
    
    Intersegment
    
    
    
    
    
    TotalSegment
    
    Segment
    
    Eliminations (a)
    
    Other (c)
    
    CompanyOperating Revenues
    
    $
    6,644
    
    
    $
    1,633
    
    
    $
    (963
    )
    
    $
    
    
    
    $
    7,314Gross Margin (b)
    
    
    1,126
    
    
    
    44
    
    
    
    
    
    
    
    
    
    
    
    1,170Other operating and administrative costs
    
    
    337
    
    
    
    6
    
    
    
    
    
    
    
    113
    
    
    
    456Depreciation and amortization
    
    
    202
    
    
    
    9
    
    
    
    
    
    
    
    12
    
    
    
    223Earnings (loss) from unconsolidated
affiliates, net of impairments
    
    
    36
    
    
    
    (23
    )
    
    
    
    
    
    
    
    
    
    
    13Minority interest income
    
    
    7
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    7Interest expense, net
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    118
    
    
    
    118Income from continuing operations
before income taxes
    
    $
    630
    
    
    $
    6
    
    
    $
    
    
    
    $
    (243
    )
    
    $
    393Capital Expenditures
    
    $
    155
    
    
    $
    1
    
    
    $
    
    
    
    $
    1
    
    
    $
    157
 Nine months ended September 30, 2003 (millions): Natural Gas
    
    NGL
    
    Intersegment
    
    
    
    
    
    TotalSegment
    
    Segment
    
    Eliminations (a)
    
    Other (c)
    
    CompanyOperating Revenues
    
    $
    6,152
    
    
    $
    1,391
    
    
    $
    (864
    )
    
    $
    
    
    
    $
    6,679Gross Margin (b)
    
    
    880
    
    
    
    35
    
    
    
    
    
    
    
    
    
    
    
    915Other operating and administrative costs
    
    
    324
    
    
    
    6
    
    
    
    
    
    
    
    115
    
    
    
    445Depreciation and amortization
    
    
    194
    
    
    
    9
    
    
    
    
    
    
    
    18
    
    
    
    221Earnings from unconsolidated affiliates
    
    
    36
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    36Minority interest income
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2Interest expense, net
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    129
    
    
    
    129Income from continuing operations before income taxes
    
    $
    400
    
    
    $
    20
    
    
    $
    
    
    
    $
    (262
    )
    
    $
    158Capital Expenditures
    
    $
    89
    
    
    $
    
    
    
    $
    
    
    
    $
    4
    
    
    $
    93
 September 30,
    
    December 31,2004
    
    2003(millions)Total assets:Natural Gas
    
    $
    4,822
    
    
    $
    5,074NGL
    
    
    227
    
    
    
    271Corporate (c)
    
    
    1,642
    
    
    
    1,169Total assets
    
    $
    6,691
    
    
    $
    6,514
  (a)
    
    Intersegment sales represent sales of NGLs from the Natural Gas Segment
to the NGL Segment at either index prices or weighted average prices of
NGLs. Both measures of intersegment sales are effectively based on 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 Corporate expense items such as unallocated working capital,
intercompany accounts and intangible and other assets. 16




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##### Table of Contents



10. Guarantors Obligations Under Guarantees On January 1, 2004, we were the guarantor of $3 million of debt for an
affiliate. The guaranteed debt was repaid in full in January of 2004. We periodically enter into agreements for the acquisition or divestiture
of assets. These agreements contain indemnification provisions that may provide
indemnity for environmental, tax, employment, outstanding litigation, breaches
of representations, warranties and covenants, or other liabilities related to
the assets being acquired or divested. Claims may be made by third parties
under these indemnification agreements for various periods of time depending on
the nature of the claim. The effective periods on these indemnification
provisions generally have terms of one to five years, although some are longer.
Our maximum potential exposure under these indemnification agreements can vary
depending on the nature of the claim and the particular transaction. We are
unable to estimate the total maximum potential amount of future payments under
indemnification agreements due to several factors, including uncertainty as to
whether claims will be made under these indemnities. At September 30, 2004, we
had a liability of approximately $1 million recorded for known liabilities
related to outstanding indemnification provisions. 17




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##### Table of Contents



Item 2. Managements Discussion and Analysis of Financial Condition and Results
of Operations The following discussion details the material factors that affected our
historical financial condition and results of operations during the three and
nine months ended September 30, 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 nine months of 2004, approximately 80% of our operating
revenues prior to intersegment revenue elimination and approximately 96%
of our gross margin were derived from this segment.
    
    NGL fractionation, transportation, marketing and trading, from which
we generate revenues from transportation fees, market center
fractionation and the marketing and trading of NGLs (the NGL Segment).
In the first nine months of 2004, approximately 20% of our operating
revenues prior to intersegment revenue elimination and approximately 4%
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 NGL 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. 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 our current contract mix, we have 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 $(19)
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 nine 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. 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. Based on historical trends, 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. We believe
that future natural gas prices will 18




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##### Table of Contents



be influenced by supply deliverability, the severity of winter and summer
weather and the level of worldwide economic growth. The number of active oil
and gas rigs drilling in the United States were 161 and 1,081, respectively, as
of September 30, 2004, compared to 155 and 932, respectively, as of September
30, 2003. This increase is mainly attributable to recent significant increases
in natural gas prices which could result in sustained increases in drilling
activity during 2004 and 2005. However, energy market uncertainty could
negatively impact North American drilling activity in the future. Lower
drilling levels over a sustained period would have a negative effect on natural
gas volumes gathered and processed. Raw Natural Gas Supply Arrangements Our results are affected by the types of arrangements we use to process
raw natural gas. We obtain access to raw natural gas and provide our midstream
natural gas services principally under three types of processing contracts:  
    
    Percentage-of-Proceeds Contracts  Under these contracts we receive
as our fee a negotiated percentage of the residue natural gas and NGL
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.
    
    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.
    
    Wellhead Purchase and Keep-Whole 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 NGL 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. As defined in the terms of the above arrangements we sell condensate,

which is generally similar to crude oil and is produced in association with
natural gas gathering and processing. 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 our
exposure to frac spread. 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. We may use hedging, if
deemed necessary, to adequately plan for cash needed for debt service, capital
expenditures and tax distributions. However, we do not currently anticipate
using cash flow hedges to mitigate our overall commodity positions in 2005
because management believes cash flows will be sufficient to fund the Companys
business. Cash Flow Hedging We monitor the risks associated with commodity price changes on our future
operations and, historically have used various commodity instruments such as
natural gas, crude oil and NGL contracts to hedge a portion of the value of our
assets and operations from such price risks. See Item 3. Quantitative and
Qualitative Disclosures About Market Risk. 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 $12 million and $23
million in the third quarter of 2004 and 2003, respectively. During the first
nine months of 2004 and 2003 the changes in fair value of our hedging contracts
reduced results of operations by $54 million and $87 million, respectively. See
Item 3. 19




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##### Table of Contents



Quantitative and Qualitative Disclosure About Market Risk. The remaining
term over which we are currently hedging our exposure to the variability of
future cash flows is through the end of 2004. We do not currently have plans
to hedge our risk to commodity exposure in 2005. Natural Gas Asset Based Trading and Marketing We actively manage commodity risk related to owned natural gas storage and
pipeline assets by engaging in natural gas asset based trading and marketing.
The commercial activities related to our natural gas asset based trading and
marketing primarily consists of time spreads and basis spreads. A time spread
is executed when the difference between the current market price of natural gas
and the current futures market for natural gas exceeds our cost of storing
physical gas in our owned storage facility. When this market condition exists,
we inject physical gas into our storage facility and execute derivative
instruments for the forward price of the gas at the higher futures market
price. This time spread allows us to lock in a future profit on our gas in
storage. For financial reporting purposes, the gas in storage is recorded at
the lower of average cost or market until sold. The derivative instruments are
recorded at fair value with changes in fair value recorded in current earnings.
The difference in accounting treatment for the physical inventory and the
derivative instruments subject our earnings to market volatility during the
period of the time spread even though the transaction represents an economic
hedge in which we have locked in a future profit. A basis spread is executed when the market price differential between
locations on a pipeline asset exceeds our cost of transporting physical gas
through our owned pipeline asset. When this market condition exists, we
physically transport gas through our pipeline asset and execute derivative
instruments around this differential at the higher market price. This basis
spread allows us to lock in a profit on our transported gas. For financial
reporting purposes, the gas in the pipeline asset is recorded at the lower of
average cost or market until sold. The derivative instruments are recorded at
fair value with changes in fair value recorded in current earnings. The
difference in accounting treatment for the physical inventory and the
derivative instruments subject our earnings to market volatility even though
the transaction represents an economic hedge in which we have locked in a
future profit. 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 amounts of approximately $264 million and $723 million, for
the three and nine months ended September 30, 2003, respectively. This reclassification
resulted from intersegment trading activities being eliminated twice from the
Consolidated Statements of Operations during the three and nine months ended
September 30, 2003. Management has concluded that these reclassifications are
not material to the fair presentation of the Companys financial statements. 20




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##### Table of Contents



Results of Operations Three Months Ended September 30,
    
    Nine Months Ended September 30,2004
    
    2003
    
    2004
    
    2003(millions)
    
    (millions)Operating revenues:Natural gas segment
    
    $
    2,302
    
    
    $
    1,943
    
    
    $
    6,644
    
    
    $
    6,152NGL segment
    
    
    585
    
    
    
    434
    
    
    
    1,633
    
    
    
    1,391Intersegment eliminations
    
    
    (326
    )
    
    
    (289
    )
    
    
    (963
    )
    
    
    (864
    )Total operating revenues
    
    
    2,561
    
    
    
    2,088
    
    
    
    7,314
    
    
    
    6,679Purchases of natural gas and petroleum products
    
    
    (2,132
    )
    
    
    (1,775
    )
    
    
    (6,144
    )
    
    
    (5,764
    )Gross margin (a)
    
    
    429
    
    
    
    313
    
    
    
    1,170
    
    
    
    915Costs and expenses
    
    
    (250
    )
    
    
    (224
    )
    
    
    (679
    )
    
    
    (666
    )Equity in earnings of unconsolidated affiliates
    
    
    5
    
    
    
    12
    
    
    
    36
    
    
    
    36Impairment of equity method investments
    
    
    (23
    )
    
    
    
    
    
    
    (23
    )
    
    
    Minority interest income
    
    
    7
    
    
    
    1
    
    
    
    7
    
    
    
    2EBIT from continuing operations before Cumulative
effect of accounting change (b)
    
    
    168
    
    
    
    102
    
    
    
    511
    
    
    
    287Interest expense, net
    
    
    (39
    )
    
    
    (45
    )
    
    
    (118
    )
    
    
    (129
    )Income tax expense
    
    
    (2
    )
    
    
    (2
    )
    
    
    (7
    )
    
    
    (4
    )(Loss) income from discontinued operations
    
    
    (23
    )
    
    
    1
    
    
    
    (18
    )
    
    
    36Cumulative effect of change in accounting principles
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (23
    )Net income
    
    $
    104
    
    
    $
    56
    
    
    $
    368
    
    
    $
    167
  (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 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. Three months ended September 30, 2004 compared with three months ended
September 30, 2003 Operating Revenues Total operating revenues increased $473 million, or
23%, to $2,561 million in the third quarter of 2004 from $2,088 million in the
same period of 2003. This increase was primarily due to the following factors:  
    
    $316 million increase was attributable to a $0.23 per gallon increase in average NGL prices;
    
    $154 million increase was attributable to a $0.79 per MMBtu increase in average natural gas prices;
    
    $24 million decrease related to lower NGL and natural gas sales
volumes, partially offset by an increase related to wholesale propane
marketing activity and the acquisition of gathering, processing and
transmission assets in Southeast New Mexico from ConocoPhillips;
    
    $20 million increase was attributable to increased condensate
sales due to a $13.69 per barrel increase in average crude oil
prices;
    
    $11 million increase related to cash flow hedging which reduced
revenues by approximately $12 million during the quarter ended
September 30, 2004 and by $23 million during the quarter ended
September 30, 2003;
    
    $8 million decrease from trading and marketing net margin
primarily due to natural gas asset based trading and marketing; and
    
    $4 million increase attributable to higher transportation,
storage and processing fees which was primarily due to higher fees
from processing contracts. 21




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##### Table of Contents



Purchases of Natural Gas and Petroleum Products- Purchases of natural gas
and petroleum products increased $357 million, or 20%, to $2,132 million in the
third quarter of 2004 from $1,775 million in the same period of 2003. The
increase was primarily due to the following factors:  
    
    $373 million increase due to higher average costs of raw
natural gas supply which is primarily due to an increase in average
NGL and natural gas prices; and
    
    $18 million decrease from lower purchased raw natural gas
supply volume offset by an increase related the acquisition of
gathering, processing and transmission assets in Southeast New Mexico
from Conoco Phillips. Three Months Ended September 30,2004
    
    2003(millions)Gross Margin:Natural gas segment
    
    $
    416
    
    
    $
    301NGL segment
    
    
    13
    
    
    
    12Total gross margin
    
    $
    429
    
    
    $
    313
 Gross Margin Total gross margin increased $116 million, or 37% to $429
million in the third quarter of 2004 from $313 million in the same period of
2003. Gross margin associated with the Natural Gas Segment increased $115
million, or 38%, to $416 million in the third quarter of 2004 from $301 million
in the same period of 2003, primarily as a result of the following factors:  
    
    $128 million increase (net of hedging) was the result of
commodity sensitive processing arrangements, mainly due to higher
average NGL and crude oil prices; $7 million decrease relating to
lower throughput volumes;
    
    $6 million decrease from trading and marketing net margin due
to natural gas asset based trading and marketing;
    
    $6 million increase primarily related to the acquisition of
gathering, processing and transmission assets in Southeast New Mexico
from ConocoPhillips; and
    
    $6 million decrease related to a variety of factors including
operational and commercial performance. Gross margin associated with the NGL Segment increased $1 million, or 8%
to $13 million in the third quarter 2004 from $12 million for the same period
in 2003. This increase was comprised primarily of an increase in wholesale
propane marketing and NGL pipelines, offset by a decrease in trading and
marketing net margin. NGL production during the third quarter 2004 increased 17,000 barrels per
day, or 5%, to 371,000 barrels per day from 354,000 barrels per day in the same
period of 2003, and natural gas transported and/or processed during the third
quarter of 2004 decreased 0.1 trillion Btus per day, or 1%, to 7.4 trillion
Btus per day from 7.5 trillion Btus per day during the same period of 2003. The
primary cause of the increase in NGL production was processing elections
associated with poor processing economics on keep-whole volumes in 2003 and the
acquisition of processing assets in Southeast New Mexico in the second quarter
of 2004. Costs and Expenses Total costs and expenses increased $26 million, or
12%, to $250 million in the third quarter of 2004 from $224 million in the same
period of 2003. This increase was primarily due to the following factors:  
    
    Operating and maintenance expenses increased $2 million primarily
related to the acquisition of gathering, processing and transmission
assets in Southeast New Mexico from ConocoPhillips;
    
    Depreciation and amortization expenses increased $2 million;
    
    General and administrative expenses increased $1 million; and
    
    Asset impairments were $22 million in the third quarter of 2004 related to the following:  
    
    $9 million of the impairments was related to our periodic
review of the carrying value of our assets and a planned shut down
of a specific plant. We determined that these assets, which are
located in Onshore and Offshore Gulf of Mexico, were impaired,
therefore they were written down to their fair value. Fair value
was determined based on managements best estimates of sales value
and/or 22




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##### Table of Contents



discounted future cash flow models. The charges associated with
these impairments were recorded in the Natural Gas Segment, and  
    
    $13 million (offset by $7 million in minority interest
income discussed below) of the impairment was related to assets
that were distributed to a minority interest holder in exchange
for their 42% minority interest (see Note 3 to the Consolidated
Financial Statements). We determined that these assets, which are
located Onshore Gulf of Mexico, were impaired, therefore they were
written down to fair value. Fair value was determined based on an
independent third-party valuation. The charges associated with
these impairments were recorded in the Natural Gas Segment. Equity in Earnings of Unconsolidated Affiliates Equity in earnings of
unconsolidated affiliates decreased $7 million, or 58%, to $5 million in the
third quarter of 2004 from $12 million in the same period of 2003. This
reduction is primarily the result of decreased earnings from our general
partner interest in TEPPCO Partners, L.P. (TEPPCO). TEPPCO had decreased
earnings due to an impairment and other charges recorded in the third quarter
of 2004. Impairment of Equity Method Investments In the third quarter of 2004, we
recorded an impairment totaling $23 million as Impairment of equity method
investments, included in the Consolidated Statements of Operations, with an
offset to Investment in unconsolidated affiliates included in the Consolidated
Balance Sheets. Our investments in these assets, which are located Onshore
Gulf of Mexico, were analyzed during the third quarter and determined to be
impaired. As a result, these investments were written down to fair value which
was determined based on managements best estimates of sales value and/or
discounted future cash flow models. The charges associated with these
impairments were recorded in the NGL Segment. Minority Interest Income-Minority interest income was $7 million in the
third quarter of 2004 compared to $1 million in the same period of 2003. The
increase to $7 million in 2004 is primarily related to a minority partners
interest in an impairment recorded in the quarter (see Costs and Expenses above
for a discussion of impairment charges). Interest Expense, net Interest expense, net, decreased $6 million, or
13% to $39 million in the third quarter of 2004 from $45 million in the same
period of 2003. This decrease was primarily due to lower outstanding debt
levels in the third quarter of 2004 compared with the third quarter of 2003. Income Taxes We are structured as a limited liability company, which is
a pass-through entity for United States income tax purposes. Income tax expense
of $2 million in the third quarter of 2004 and 2003 is attributable to earnings
associated with tax-paying subsidiaries. (Loss) income from Discontinued Operations- (Loss) income from
discontinued operations was a loss of $23 million in the third quarter of 2004
and income of $1 million in the third quarter of 2003. (Loss) income from
discontinued operations includes the impairment of an asset held for sale, the
sale of the assets associated with discontinued operations and the results of
such operations (see Note 3 to the Consolidated Financial Statements). Nine months ended September 30, 2004 compared with nine months ended September
30, 2003 Operating Revenues Total operating revenues increased $635 million, or
10%, to $7,314 million in the first nine months of 2004 from $6,679 million in
the same period of 2003. This increase was primarily due to the following
factors:  
    
    $506 million increase was attributable to a $0.12 per gallon increase in average NGL prices;
    
    $94 million increase was attributable to a $0.15 per MMBtu increase in average natural gas prices;
    
    $66 million decrease related to decreased natural gas and NGL
sales volumes partially offset by an increase related to wholesale
propane marketing activity and the acquisition of gathering,
processing and transmission assets in southeast New Mexico from
ConocoPhillips;
    
    $33 million increase related to cash flow hedging which reduced
revenues by approximately $54 million for the nine months ended
September 30, 2004 and by $87 million for the nine months ended
September 30, 2003;
    
    $29 million increase from trading and marketing net margin
primarily due to natural gas asset based trading and marketing; 23




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
    
    $27 million increase was attributable to increased condensate
sales due to a $8.13 per barrel increase in average crude oil prices;
and
    
    $19 million increase attributable to higher transportation,
storage and processing fees which was primarily due to higher fees
from processing contracts. Purchases of Natural Gas and Petroleum Products- Purchases of natural gas
and petroleum products increased $380 million, or 7%, to $6,144 million in the
first nine months of 2004 from $5,764 million in the same period of 2003. This
increase was primarily due to the following factors:  
    
    $435 million increase due to higher average costs of raw
natural gas supply which is primarily due to an increase in average
NGL and natural gas prices;
    
    $48 million decrease from lower purchased raw natural gas
supply, offset by an increase related to the acquisition of
gathering, processing and transmission assets in Southeast New Mexico
from Conoco Phillips; and
    
    $8 million decrease related to expenses incurred in the first
quarter of 2003 related to a contract litigation settlement. Nine Months Ended September 30,2004
    
    2003(millions)Gross Margin:Natural gas segment
    
    $
    1,126
    
    
    $
    880NGL segment
    
    
    44
    
    
    
    35Total gross margin
    
    $
    1,170
    
    
    $
    915
 Gross Margin Total Gross margin increased $255 million, or 28% to $1,170
million in the first nine months of 2004 from $915 million in the same period
of 2003. Gross margin associated with the Natural Gas Segment increased $246
million, or 28%, to $1,126 million in the first nine months of 2004 from $880
million in the same period of 2003, primarily as a result of the following
factors:  
    
    $225 million increase (net of hedging) was the result of
commodity sensitive processing arrangements, mainly due to higher
average NGL and crude oil prices;
    
    $16 million decrease related to lower throughput volumes;
    
    $11 million increase related to the acquisition of gathering,
processing and transmission assets in Southeast New Mexico from
ConocoPhillips;
    
    $8 million increase was the result of $23 million of improved
trading and marketing net margin offset by approximately $15 million
of lower results related to physical natural gas asset based trading
activity;
    
    $8 million increase related to expenses incurred in the first
quarter of 2003 related to a contract litigation settlement; and
    
    $10 million increase related to a variety of factors including
operational and commercial performance. Gross margin associated with the NGL Segment increased $9 million, or 26%
to $44 million in the first nine months of 2004 from $35 million for the same
period in 2003. This increase was comprised primarily of an increase in trading
and marketing net margin. NGL production during the first nine months of 2004 increased 8,000
barrels per day, or 2%, to 363,000 barrels per day from 355,000 barrels per day
in the same period of 2003, and natural gas transported and/or processed during
the first nine months of 2004 decreased 0.2 trillion Btus per day, or 3%, to
7.3 trillion Btus per day from 7.5 trillion Btus per day during the same period
of 2003. Costs and Expenses Total costs and expenses increased $13 million, or
2%, to $679 million in the first nine months of 2004 from $666 million in the
same period of 2003. This increase was primarily due to the following factors:  
    
    Operating and maintenance expenses decreased $13 million primarily
related to decreased expenses of approximately $10 million related to
the consolidation of a previously unconsolidated affiliate as required 24




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by FIN 46R (see Note 1 to the Consolidated Financial Statements). Certain
operating costs paid by us to this affiliate are now eliminated in
consolidation of this affiliate;
    
    Depreciation and amortization expenses increased $2 million;
    
    General and administrative expenses increased $3 million; and
    
    Asset impairments were $22 million in the third quarter of 2004 related to the following:  
    
    $9 million of the impairments was related to our periodic
review of the carrying value of our assets and a planned shut down
of a specific plant. We determined that these assets, which are
located in Onshore and Offshore Gulf of Mexico, were impaired,
therefore they were written down to their fair value. Fair value
was determined based on managements best estimates of sales value
and/or discounted future cash flow models. The charges associated
with these impairments were recorded in the Natural Gas Segment,
and
    
    $13 million (offset by $7 million in minority interest
income discussed below) of the impairment was related to assets
that were distributed to a minority interest holder in exchange
for their 42% minority interest (see Note 3 to the Consolidated
Financial Statements). We determined that these assets, which are
located Onshore Gulf of Mexico, were impaired, therefore they were
written down to fair value. Fair value was determined based on an
independent third-party valuation. The charges associated with
these impairments were recorded in the Natural Gas Segment. Impairment of Equity Method Investments In the third quarter of 2004, we
recorded an impairment totaling $23 million as Impairment of equity method
investments, included in the Consolidated Statements of Operations, with an
offset to Investment in unconsolidated affiliates included in the Consolidated
Balance Sheets. Our investments in these assets, which are located Onshore
Gulf of Mexico, were analyzed during the third quarter and determined to be
impaired. As a result, these investments were written down to fair value which
was determined based on managements best estimates of sales value and/or
discounted future cash flow models. The charges associated with these
impairments were recorded in the NGL Segment. Minority Interest Income Minority interest income was $7 million in the
first nine months of 2004 compared to $2 million in the same period of 2003.
The increase to $7 million in 2004 is primarily related to the minority
partners interest in an impairment recorded in the quarter (see costs and
expenses above for a discussion of impairment charges). Interest Expense, net Interest expense, net, decreased $11 million, or
9% to $118 million in the first nine months of 2004 from $129 million in the
same period of 2003. This decrease was primarily due to lower outstanding debt
levels in the first nine months of 2004 compared with first nine months 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
of $7 million in the first nine months of 2004 and $4 million in the first nine
months of 2003 is attributable to earnings associated with tax-paying
subsidiaries. (Loss) income from Discontinued Operations- (Loss) income from
discontinued operations was a loss of $18 million in the first nine months of
2004 and income of $36 million in the first nine months of 2003. (Loss) income
from discontinued operations includes the impairment of an asset held for sale,
the sale of the assets associated with discontinued operations and the results
of such operations in both periods presented (see Note 3 to the Consolidated
Financial Statements). Cumulative Effect of Change in Accounting Principles Cumulative effect
of change in accounting principles was a loss of $23 million in the first nine
months 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 1 to
Consolidated Financial Statements). 25




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Liquidity and Capital Resources Liquidity is a measure of a companys ability to access cash. We have
historically addressed our long-term liquidity and capital requirements through
the use of bank credit facilities and cash provided by operating activities as
well as through the issuance of debt securities, when market conditions permit.
Volatility in crude oil, NGL 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. A material adverse change in operations or available
financing may impact our ability to fund our requirements for liquidity and
capital resources. Working Capital Working capital is the amount by which current assets
exceed current liabilities. We had a working capital deficit of $420 million
as of September 30, 2004, compared to a deficit of $73 million at December 31,
2003. The change was primarily due to the reclassification in the third
quarter of 2004 of $600 million of debt securities due in 2005 from long term
to short term, partially offset by an increase in cash and cash equivalents of
$280 million. We may retire a portion of these debt securities and refinance a
portion of these debt securities during 2005. As of September 30, 2004, we had $323 million in cash and cash equivalents
compared to $43 million as of December 31, 2003. Included in cash and cash
equivalents as of September 30, 2004 was approximately $35 million held by our
Canadian subsidiaries for their operations. The remaining cash balance was
primarily available for general corporate purposes. Cash flow Historically, one of our primary sources of capital has been
net cash provided by operating activities. Net cash provided by operating
activities, net cash (used in) provided by investing activities and net cash
used in financing activities for the nine months ended September 30, 2004 and
2003 were as follows: Nine Months Ended September 30,2004
    
    2003
    
    Change(millions)Net cash provided by operating activities
    
    $
    686
    
    
    
    390
    
    
    
    296Net cash (used in) provided by investing
activities
    
    $
    (85
    )
    
    
    15
    
    
    
    (100
    )Net cash used in financing activities
    
    $
    (302
    )
    
    
    (349
    )
    
    
    47
 Operating Cash Flows The increase in net cash provided by operating activities is attributable
to our net income adjusted for non-cash charges and credits and changes in
working capital. The increase in net income is due largely to the favorable
effects of commodity prices, net of hedging and improved results from trading
and marketing activities. We received cash distributions from unconsolidated affiliates of $36
million in the first nine months of 2004 and $47 million in the first nine
months of 2003. These distributions were in excess of earnings from
unconsolidated affiliates by $22 million in the first nine months of 2004 and
$11 million in the same period of 2003. Investing Cash Flows The increase in cash used in investing activities was due primarily to an
increase in capital expenditures. Our capital expenditures generally consist of
expenditures for construction and acquisition 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 nine months of 2004, we spent approximately $157 million on capital
expenditures compared to $93 million in the first nine months of 2003. The
increase is due to the acquisition of gathering, processing and transmission
assets in Southeast New Mexico, partially offset by reduced well connections
and plant upgrades in the first nine months of 2004, as compared to the same
period in 2003. The increase in cash used in investing activities is partially
offset by proceeds from the sale of discontinued operations and sales of assets
of $62 million and $10 million, respectively, in the first nine months of 2004
compared to $90 million and $20 million, respectively, in the first nine months
of 2003. 26




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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, or
other available sources of financing. Our capital expenditures forecast for the
year ending December 31, 2004 is approximately $200 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. Financing Cash Flows The decrease in cash used in financing activities was primarily due to the
redemption of outstanding preferred members interest and payment of debt of
$125 million and $215 million, respectively, in the first nine months of 2003,
compared to the payment of dividends and distributions to members of $293
million in the first nine months of 2004. 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. In the third quarter of 2004, $600 million of debt securities due in 2005
were reclassified from long term to short term. We may retire a portion of
these debt securities and refinance a portion of these debt securities during
2005. Bank Financing and Commercial Paper On March 26, 2004, we entered into a new 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 September 30, 2004, there were no borrowings or
letters of credit drawn against the Facility. At September 30, 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. On November 3, 2003, we executed a $32 million irrevocable standby letter
of credit, to be used to secure transaction exposure with a counterparty, which
expired on May 15, 2004. 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. 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 27




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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. During the nine months ended September 30, 2004, we
paid distributions of $16 million based on estimated annual taxable income
allocated to the members according to their respective ownership percentages.
As of September 30, 2004, distributions payable of $78 million were included in
Other current liabilities in the Consolidated Balance Sheets. 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 nine months ended September 30, 2004, with the
approval of both members, we paid total dividends of $277 million to the
members, allocated in accordance with their respective ownership percentages. 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 for an affiliate. Assets were pledged as collateral for the debt. This
debt was repaid in January 2004. At September 30, 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
September 30, 2004, we had a liability of $1 million recorded for known
liabilities related to 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 the year ended
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. We adopted the provisions of FIN 46 and its related
interpretations (FIN 46R) in the first quarter of 2004. 28




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As a result, we consolidated one entity, previously accounted for under
the equity method of accounting, on January 1, 2004. 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
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 nine months 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 nine
months of 2003. Acquisitions and Dispositions Based upon managements current assessment of the probable disposition of
certain gathering, compression and transportation assets expected to occur in
2005, we have classified these assets as held for sale and have reclassified
the assets to Other current assets in the Consolidated Balance Sheet as of
September 30, 2004. The book value of these assets has been written down by
$23 million to $27 million, the estimated fair value less costs to sell. These
assets comprise a component of the Company for purposes of reporting
discontinued operations. The results of operations and cash flows related to
these assets held for sale have been reclassified to discontinued operations
for all periods presented. These assets were previously included in the Natural
Gas Segment. On August 31, 2004, we acquired a 42% minority interest in Mobile Bay
Processing Partners (MBPP) in exchange for certain assets of MBPP. MBPP is a
consolidated entity, which, prior to this transaction, was owned 58% by us, and
subsequent to the transaction is wholly-owned by us. As a result of the
exchange, we recorded an impairment charge of $13 million (offset by $7 million
in minority interest income) related to the assets that were distributed, which
had a fair market value of less than book value. Minority interests in the
Consolidated Balance Sheet decreased by $40 million related to this
transaction. MBPP owns processing assets in the Onshore Gulf of Mexico. 29




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On August 31, 2004, we purchased a 42% minority interest in Gulf Coast NGL
Pipeline, LLC (GC) for $2 million. GC is a consolidated entity, which, prior
to this transaction, was owned 58% by us, and subsequent to the transaction is
wholly-owned by us. Minority interests in the Consolidated Balance Sheet
decreased by $7 million related to this transaction. GC owns a 16.67% interest
in two investments in unconsolidated affiliates. On August 31, 2004, we purchased a 12% minority interest in Dauphin Island
Gathering Partners (DIGP) for $2 million. DIGP is a consolidated entity,
which, prior to this transaction, was owned 72% by us, and subsequent to the
acquisition is owned 84% by us. Minority interests in the Consolidated Balance
Sheet decreased by $29 million related to this transaction. DIGP owns gathering
and transmission assets in the Offshore Gulf of Mexico. In April 2004, we acquired gathering, processing and transmission assets
in Southeast New Mexico from ConocoPhillips, a related party, for a total
purchase price of approximately $80 million, consisting of $74 million in cash
and the assumption of approximately $6 million of liabilities. In February 2004, we sold gas gathering and processing plant assets in
West Texas to a third party purchaser for a sales price of approximately $62
million, with no significant book gain or loss. These assets comprised a
component of the Company for purposes of reporting discontinued operations.
The results of operations and cash flows related to these assets have been
reclassified to discontinued operations for all periods presented. These assets
were previously included in the Natural Gas Segment. In the second quarter of 2003, we 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. The results of operations
and cash flows related to these assets have been reclassified to discontinued
operations for all periods presented. These assets were previously included in
the Natural Gas Segment. 30




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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 and procedures 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 1 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 endedSeptember 30, 2004
    
    September 30, 2003
    
    September 30, 2004
    
    September 30, 2004Calculated DVaR
    
    $
    1
    
    
    $
    2
    
    
    $
    2
    
    
    
    
 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 nine
    
    for the ninenine months ended
    
    nine months ended
    
    months ended
    
    months endedSeptember 30, 2004
    
    September 30, 2003
    
    September 30, 2004
    
    September 30, 2004Calculated DVaR
    
    $
    1
    
    
    $
    1
    
    
    $
    3
    
    
    
    
 31




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##### Table of Contents



DVaR is an estimate based on historical price volatility. Actual
volatility can exceed predicted results. DVaR also assumes a normal
distribution of price changes, thus if the actual distribution is not normal,
the DVaR may understate or overstate actual results. DVaR is used to estimate
the risk of the entire portfolio, and for locations that do not have daily
trading activity, it may not accurately estimate risk due to limited price
information. Stress tests may be employed in addition to DVaR to measure risk
where market data information is limited. In the current DVaR methodology,
options are modeled in a manner equivalent to forward contracts which may
understate the risk. Our exposure to commodity price risk is influenced by a number of factors,
including contract size, length of contract, market liquidity, location and
unique or specific contract terms. Effective January 1, 2003, in connection
with the implementation of EITF 02-03, the Company designates each commodity
derivative as either trading or non-trading. Certain non-trading derivatives
are further designated as either a hedge of a forecasted transaction or future
cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm
commitment (fair value hedge), or a normal purchase or sale contract, while
certain non-trading derivatives, which are related to our asset based
marketing, are non-trading mark-to-market derivatives. For each of the
Companys derivatives, the accounting method and presentation of gains and
losses or revenue and expense in the Consolidated Statements of Operations are
as follows: Presentation of Gains & Losses or Revenue &Classification of Contract
    
    Accounting Method
    
    ExpenseTrading Derivatives
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net marginNon-Trading Derivatives:Cash Flow Hedge
    
    Hedge methodb
    
    Gross basis in the same income statementcategory as the related hedged itemFair Value Hedge
    
    Hedge methodb
    
    Gross basis in the same income statementcategory as the related hedged itemNormal Purchase or Normal Sale
    
    Accrual methodc
    
    Gross basis upon settlement in thecorresponding income statement categorybased on commodity typeNon-Trading Mark-to-
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net marginMarket
 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 change in the fair value of
the asset or liability is recorded in the Consolidated Balance Sheets and there
is no recognition in the Consolidated Statements of 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. 32




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##### Table of Contents



The following table shows the fair value of our mark-to-market portfolio
as of September 30, 2004: Fair Value of Mark-to-Market Contracts as of September 30, 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
    
    $
    (1
    )
    
    $
    13
    
    
    $
    (2
    )
    
    $
    (2
    )
    
    $
    8Prices based on models
and other valuation
methods
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
Trading
    
    
    (1
    )
    
    
    13
    
    
    
    (2
    )
    
    
    (2
    )
    
    
    8Non-Trading:Prices supported by
quoted market prices
and other external
sources
    
    
    (3
    )
    
    
    (6
    )
    
    
    
    
    
    
    
    
    
    
    (9
    )Prices based on models
and other valuation
methods
    
    
    (1
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1
    )Total
Non-Trading
    
    
    (4
    )
    
    
    (6
    )
    
    
    
    
    
    
    
    
    
    
    (10
    )Total
Mark-to-Market
    
    $
    (5
    )
    
    $
    7
    
    
    $
    (2
    )
    
    $
    (2
    )
    
    $
    (2
    )
 The Prices supported by quoted market prices and other external sources
category includes our New York Mercantile Exchange (NYMEX) swap positions in
natural gas, crude oil, propane, heating oil, and unleaded gasoline. The NYMEX
has currently quoted monthly natural gas prices for the next 64 months and
quoted monthly crude oil prices for the next 36 months. The NYMEX has quoted
monthly prices for varying periods of 18 months or less for propane, heating
oil, and unleaded gasoline. 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 swaps extend 48 months into the future. 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 33




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##### Table of Contents



risks. Our hedging program has historically reduced the potential
negative impact that commodity price changes could have on our earnings and has
improved our ability to adequately plan for cash needed for debt service and
capital expenditures. However, we do not currently anticipate using cash flow
hedges in 2005 because management believes cash flows will be sufficient to
fund our business. Our primary use of hedging commodity derivatives has been to hedge the
commodity exposure associated with the output and production of assets we
physically own. 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 have utilized 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 35). 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 September 30, 2004: Fair Value of Hedging Contracts as of September 30, 2004 (millions)Maturity in
    
    Maturity in
    
    Maturity in
    
    Maturity in 2007
    
    Total FairSources of Fair Value
    
    2004
    
    2005
    
    2006
    
    and Thereafter
    
    ValuePrices supported by
quoted market prices
and other external
sources
    
    $
    (16
    )
    
    $
    6
    
    
    $
    2
    
    
    $
    
    
    
    $
    (8
    )Prices based on
models
or other valuation
techniques
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    $
    (16
    )
    
    $
    6
    
    
    $
    2
    
    
    $
    
    
    
    $
    (8
    )
 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 $(19) 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. 34




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##### Table of Contents



Credit Risk Our principal customers in the Natural Gas Segment are large, natural gas
marketing services and industrial end-users. In the NGL segment, our principal
customers range from large multi-national petrochemical and refining companies
to small regional propane distributors. Substantially all of our natural gas
and NGL sales are made at market-based prices. Approximately 40% of our NGL
production is committed to ConocoPhillips and ChevronPhillips; under an
existing 15-year contract which expires in 2015. This concentration of credit
risk may affect our overall credit risk in that these customers may be
similarly affected by changes in economic, regulatory or other factors. Where
exposed to credit risk, we analyze the counterparties financial condition
prior to entering into an agreement, establish credit limits and monitor the
appropriateness of these limits on an ongoing basis. The corporate credit
policy prescribes the use of master collateral agreements to mitigate credit
exposure. Collateral agreements provide for a counterparty to post cash or
letters of credit for exposure in excess of the established threshold. The
threshold amount represents an open credit limit, determined in accordance with
our credit policy. The collateral agreements also provide that the inability
to post collateral is sufficient cause to terminate a contract and liquidate
all positions. In addition, the Companys standard gas and NGL sales contracts
contain adequate assurance provisions which allow the Company to suspend
deliveries, cancel agreements or continue deliveries to the buyer after the
buyer provides security for payment in a form satisfactory to the Company. As of September 30, 2004, we held cash or letters of credit of $66 million
to secure future performance by counterparties, and had deposited with
counterparties $28 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 September 30,
2004, the fair value of our interest rate swaps was an asset of $10 million. As of September 30, 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 September 30, 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. 35




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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 8 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  3.1
    
    Second Amendment to Amended and Restated Limited Liability Company
Agreement of Duke Energy Field Services, LLC dated as of July 29, 2004.10.1
    
    Third Amendment to Parent Company Agreement among Duke Energy Field
Services Corporation, Duke Energy Field Services, LLC, ConocoPhillips
Company and Duke Energy Corporation dated as of July 29, 2004.10.2
    
    Amendment to Services Agreement effective January 1, 2004 between
Duke Energy Corporation, Duke Energy Business Services, LLC, Duke
Energy Americas, LLC, Duke Energy Gas Transmission Corporation and Duke
Energy Field Services, LLC.10.3
    
    Change in Control Agreement between Duke Energy Field Services, LP
and W. H. Easter III dated July 19, 2004.10.4
    
    Employee Severance Agreement and Release between Duke Energy Field
Services, LP and W. H. Easter III dated July 19, 2004.18.1
    
    Letter dated November 10, 2004 from Deloitte & Touche, LLP
regarding changes in accounting principles.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. 36




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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.  DUKE ENERGY FIELD SERVICES, LLC November 10, 2004 /s/ Rose M. RobesonRose M. RobesonVice President and Chief Financial
Officer
(On Behalf of the Registrant and as
Principal Financial and Accounting
Officer) 37




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##### Table of Contents



EXHIBIT INDEX  Exhibits3.1
    
    Second Amendment to Amended and Restated Limited Liability Company
Agreement of Duke Energy Field Services, LLC dated as of July 29, 2004.10.1
    
    Third Amendment to Parent Company Agreement among Duke Energy Field
Services Corporation, Duke Energy Field Services, LLC, ConocoPhillips
Company and Duke Energy Corporation dated as of July 29, 2004.10.2
    
    Amendment to Services Agreement effective January 1, 2004 between
Duke Energy Corporation, Duke Energy Business Services, LLC, Duke
Energy Americas, LLC, Duke Energy Gas Transmission Corporation and Duke
Energy Field Services, LLC.10.3
    
    Change in Control Agreement between Duke Energy Field Services, LP
and W. H. Easter III dated July 19, 2004.10.4
    
    Employee Severance Agreement and Release between Duke Energy Field
Services, LP and W. H. Easter III dated July 19, 2004.18.1
    
    Letter dated November 10, 2004 from Deloitte & Touche, LLP
regarding changes in accounting principles.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.