##### Table of Contents



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 June 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 JUNE 30, 2004 INDEX Item
    
    
    
    PagePART I. FINANCIAL INFORMATION (UNAUDITED)1.
    
    Financial Statements
    
    
    1Consolidated Statements of Operations for the Three and Six Months Ended
June 30, 2004 and 2003
    
    
    1Consolidated Statements of Comprehensive Income for the Three and Six
Months Ended June 30, 2004 and 2003
    
    
    2Consolidated Balance Sheets as of June 30, 2004 and December 31, 2003
    
    
    3Consolidated Statements of Cash Flows for the Three and Six Months Ended
June 30, 2004 and 2003
    
    
    4Condensed Notes to Consolidated Financial Statements
    
    
    52.
    
    Managements Discussion and Analysis of Financial Condition and Results of
Operations
    
    
    173.
    
    Quantitative and Qualitative Disclosure about Market Risks
    
    
    274.
    
    Controls and Procedures
    
    
    31PART II. OTHER INFORMATION1.
    
    Legal Proceedings
    
    
    326.
    
    Exhibits and Reports on Form 8-K
    
    
    32Signatures
    
    
    33Certification 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 hedge commodity and interest rate risks;  
    
    the level of creditworthiness of counterparties to transactions;  
    
    the amount of collateral required to be posted from time to time in our transactions;  
    
    changes in laws and regulations, particularly with regard to taxes,
safety and protection of the environment or the increased regulation of
the gathering and processing industry; i




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##### Table of Contents




    
    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
    
    Six Months EndedJune 30,
    
    June 30,2004
    
    2003
    
    2004
    
    2003Operating Revenues:Sales of natural gas and petroleum products
    
    $
    1,759
    
    
    $
    1,409
    
    
    $
    3,480
    
    
    $
    3,025Sales of natural gas and petroleum products to
affiliates
    
    
    545
    
    
    
    578
    
    
    
    1,156
    
    
    
    1,502Transportation, storage and processing
    
    
    76
    
    
    
    68
    
    
    
    144
    
    
    
    129Trading and marketing net margin
    
    
    2
    
    
    
    1
    
    
    
    4
    
    
    
    (33
    )Total operating revenues
    
    
    2,382
    
    
    
    2,056
    
    
    
    4,784
    
    
    
    4,623Costs and Expenses:Purchases of natural gas and petroleum products
    
    
    1,863
    
    
    
    1,555
    
    
    
    3,752
    
    
    
    3,624Purchases of natural gas and petroleum products
from affiliates
    
    
    139
    
    
    
    191
    
    
    
    287
    
    
    
    393Operating and maintenance
    
    
    107
    
    
    
    113
    
    
    
    201
    
    
    
    218Depreciation and amortization
    
    
    75
    
    
    
    75
    
    
    
    150
    
    
    
    150General and administrative
    
    
    41
    
    
    
    41
    
    
    
    82
    
    
    
    79Total costs and expenses
    
    
    2,225
    
    
    
    1,975
    
    
    
    4,472
    
    
    
    4,464Operating Income
    
    
    157
    
    
    
    81
    
    
    
    312
    
    
    
    159Equity in earnings of unconsolidated affiliates
    
    
    14
    
    
    
    12
    
    
    
    31
    
    
    
    24Interest expense, net
    
    
    39
    
    
    
    42
    
    
    
    79
    
    
    
    84Income from continuing operations before income
taxes
    
    
    132
    
    
    
    51
    
    
    
    264
    
    
    
    99Income tax expense
    
    
    2
    
    
    
    
    
    
    
    5
    
    
    
    2Income from continuing operations before cumulative
effect of accounting change
    
    
    130
    
    
    
    51
    
    
    
    259
    
    
    
    97Income from discontinued operations
    
    
    
    
    
    
    31
    
    
    
    5
    
    
    
    37Cumulative effect of change in accounting
principles
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (23
    )Net income
    
    
    130
    
    
    
    82
    
    
    
    264
    
    
    
    111Dividends on preferred members interest
    
    
    
    
    
    
    4
    
    
    
    
    
    
    
    9Earnings available for members interest
    
    $
    130
    
    
    $
    78
    
    
    $
    264
    
    
    $
    102
 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
    
    Six Months EndedJune 30,
    
    June 30,2004
    
    2003
    
    2004
    
    2003Net income
    
    $
    130
    
    
    $
    82
    
    
    $
    264
    
    
    $
    111Other comprehensive income:Foreign currency translation adjustment
    
    
    (9
    )
    
    
    25
    
    
    
    (13
    )
    
    
    45Net unrealized losses on cash flow hedges
    
    
    (12
    )
    
    
    (24
    )
    
    
    (29
    )
    
    
    (61
    )Reclassification of previously deferred
losses on cash flow hedges into earnings
    
    
    24
    
    
    
    24
    
    
    
    42
    
    
    
    66Total other comprehensive income
    
    
    3
    
    
    
    25
    
    
    
    
    
    
    
    50Total comprehensive income
    
    $
    133
    
    
    $
    107
    
    
    $
    264
    
    
    $
    161
 See Condensed Notes to Consolidated Financial Statements. 2




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DUKE ENERGY FIELD SERVICES, LLC 
 CONSOLIDATED BALANCE SHEETS
 (Unaudited)
 (millions)
 June 30,
    
    December 31,2004
    
    2003ASSETSCurrent assets:Cash and cash equivalents
    
    $
    253
    
    
    $
    43Accounts receivable:Customers, net of allowance for doubtful accounts of $4
and $8, respectively
    
    
    961
    
    
    
    872Affiliates
    
    
    49
    
    
    
    57Other
    
    
    27
    
    
    
    29Inventories
    
    
    46
    
    
    
    45Unrealized gains on mark-to-market and hedging transactions.
    
    
    125
    
    
    
    135Other current assets
    
    
    12
    
    
    
    20Total current assets
    
    
    1,473
    
    
    
    1,201Property, plant and equipment, net
    
    
    4,457
    
    
    
    4,462Investment in unconsolidated affiliates
    
    
    186
    
    
    
    190Intangible assets:Commodity sales and purchases contracts, net
    
    
    75
    
    
    
    80Goodwill, net
    
    
    445
    
    
    
    447Total intangible assets
    
    
    520
    
    
    
    527Unrealized gains on mark-to-market and hedging transactions
    
    
    40
    
    
    
    25Other noncurrent assets
    
    
    40
    
    
    
    109Total assets
    
    $
    6,716
    
    
    $
    6,514LIABILITIES AND MEMBERS EQUITYCurrent liabilities:Accounts payable:Trade
    
    $
    963
    
    
    $
    857Affiliates
    
    
    22
    
    
    
    16Other
    
    
    36
    
    
    
    33Short term debt
    
    
    6
    
    
    
    6Accrued interest payable
    
    
    59
    
    
    
    59Unrealized losses on mark-to-market and hedging transactions
    
    
    124
    
    
    
    153Other current liabilities
    
    
    128
    
    
    
    150Total current liabilities
    
    
    1,338
    
    
    
    1,274Deferred income taxes
    
    
    18
    
    
    
    17Long term debt
    
    
    2,248
    
    
    
    2,262Unrealized losses on mark-to-market and hedging transactions
    
    
    43
    
    
    
    24Other long term liabilities
    
    
    89
    
    
    
    73Minority interests
    
    
    125
    
    
    
    120Commitments and contingent liabilitiesMembers equity:Members interest
    
    
    1,709
    
    
    
    1,709Retained earnings
    
    
    1,122
    
    
    
    1,011Accumulated other comprehensive income
    
    
    24
    
    
    
    24Total members equity
    
    
    2,855
    
    
    
    2,744Total liabilities and members equity
    
    $
    6,716
    
    
    $
    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)
 Six Months EndedJune 30,2004
    
    2003Cash flows from operating activities:Net income
    
    $
    264
    
    
    $
    111Adjustments to reconcile net income to net cash provided by operating
activities:Income from discontinued operations
    
    
    (5
    )
    
    
    (37
    )Cumulative effect of change in accounting principles
    
    
    
    
    
    
    23Depreciation and amortization
    
    
    150
    
    
    
    150Distributions received in excess of earnings from unconsolidated affiliates
    
    
    7
    
    
    
    7Other, net
    
    
    3
    
    
    
    10Change in operating assets and liabilities which provided (used) cash:Accounts receivable
    
    
    (89
    )
    
    
    (243
    )Accounts receivable from affiliates
    
    
    16
    
    
    
    128Inventories
    
    
    1
    
    
    
    24Net unrealized gains on mark-to-market and hedging transactions
    
    
    (11
    )
    
    
    (32
    )Accounts payable
    
    
    108
    
    
    
    146Accounts payable to affiliates
    
    
    3
    
    
    
    (59
    )Accrued interest payable
    
    
    
    
    
    
    Other
    
    
    (20
    )
    
    
    (7
    )Net cash provided by operating activities
    
    
    427
    
    
    
    221Cash flows from investing activities:Capital expenditures
    
    
    (132
    )
    
    
    (66
    )Consolidation of previously unconsolidated investment
    
    
    6
    
    
    
    Contributions to minority interests, net
    
    
    
    
    
    
    (1
    )Proceeds from sale of discontinued operations
    
    
    62
    
    
    
    90Proceeds from sales of assets
    
    
    2
    
    
    
    5Net cash (used in) provided by investing activities
    
    
    (62
    )
    
    
    28Cash flows from financing activities:Payment of debt
    
    
    (9
    )
    
    
    (115
    )Payment of dividends and distributions to members
    
    
    (148
    )
    
    
    (10
    )Net cash used in financing activities
    
    
    (157
    )
    
    
    (125
    )Effect of foreign exchange rate changes on cash
    
    
    
    
    
    
    (1
    )Effect of discontinued operations on cash
    
    
    2
    
    
    
    10Net increase in cash and cash equivalents
    
    
    210
    
    
    
    133Cash and cash equivalents, beginning of period
    
    
    43
    
    
    
    35Cash and cash equivalents, end of period
    
    $
    253
    
    
    $
    168Supplementary cash flow information:Cash paid for interest (net of amounts capitalized)
    
    $
    78
    
    
    $
    81
 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 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), fractionation, transportation, and trading and
marketing. Duke Energy Corporation (Duke Energy) owns 69.7% of the Companys
outstanding member interests and ConocoPhillips owns the remaining 30.3%. These Consolidated Financial Statements reflect all normal recurring
adjustments that are, in the opinion of management, necessary to present fairly
the financial position and results of operations for the respective interim
periods. These consolidated financial statements and other information included
in this quarterly report on Form 10-Q should be read in conjunction with
Managements Discussion and Analysis of Financial Condition and Results of
Operations and the consolidated financial statements and notes thereto
included in our annual report on Form 10-K for the fiscal year ended December
31, 2003. 2. Summary of Significant Accounting Policies Consolidation The Consolidated Financial Statements include the accounts
of the Company and all majority-owned subsidiaries, after eliminating
intercompany transactions and balances, and variable interest entities where 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 Contract
    
    Accounting Method
    
    Presentation of Gains & Losses or Revenue & ExpenseTrading Derivatives
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net marginNon-Trading Derivatives:Cash Flow Hedge
    
    Hedge methodb
    
    Gross basis in the same income
statement category as the related hedged itemFair Value Hedge
    
    Hedge methodb
    
    Gross basis in the same income
statement category as the related hedged itemNormal Purchase or Normal Sale
    
    Accrual methodc
    
    Gross basis upon settlement in the
corresponding income statement category based on commodity typeNon-Trading Mark-to- Market
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net margin
 a Mark-to-market- An accounting method whereby the change in the fair value of
the asset or liability is recognized in the Consolidated Statements of
Operations in Trading and marketing net margin during the current period. b Hedge method- An accounting method whereby the 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 June 30, 2004 and December 31, 2003, $16 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 six months ended June 30,
2004, we paid distributions of $11 million based on estimated annual taxable
income allocated to the members according to their respective ownership
percentages. As of June 30, 2004, additional distributions payable of $5
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 six months ended June 30, 2004,
with the approval of both members, we paid a total dividend of $137 million to
the members, allocated in accordance with their respective ownership
percentages. Stock-Based Compensation Under Duke Energys 1998 Long Term Incentive
Plan, stock options for Duke Energys common stock may be granted to our key
employees. We account for stock-based compensation using the intrinsic value
recognition and measurement principles of Accounting Principles Board (APB)
Opinion No. 25, Accounting for Stock Issued to Employees, and FASB
Interpretation No. 44, Accounting for Certain Transactions Involving Stock
Compensation (an Interpretation of APB Opinion No. 25). Under this method, any
compensation cost is measured as the quoted market price of stock at the date
of the grant less the amount an employee must pay to acquire the stock. Since
the exercise price for all options granted under the plan was equal to the
market value of the underlying common stock on the date of grant, no
compensation cost is recognized in the accompanying Consolidated Statements of
Operations. Restricted stock grants and phantom stock awards are recorded 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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Pro Forma Stock-Based Compensation Three months ended
    
    Six months endedJune 30,
    
    June 30,(millions)
    
    2004
    
    2003
    
    2004
    
    2003Earnings available
for members
interest, as
reported
    
    $
    130
    
    
    $
    78
    
    
    $
    264
    
    
    $
    102Add: stock-based
compensation
expense included in
reported net income
    
    
    1
    
    
    
    
    
    
    
    1
    
    
    
    Deduct: total
stock-based
compensation
expense determined
under fair
value-based method
for all awards
    
    
    (2
    )
    
    
    (2
    )
    
    
    (2
    )
    
    
    (3
    )Pro forma earnings
available for
members interest
    
    $
    129
    
    
    $
    76
    
    
    $
    263
    
    
    $
    99
 Accumulated Other Comprehensive Income The components of and changes in
accumulated other comprehensive income are as follows: Accumulated Other Comprehensive Income Net
    
    AccumulatedForeign
    
    Unrealized
    
    OtherCurrency
    
    (Losses) Gains on
    
    Comprehensive(millions)
    
    Adjustments
    
    Cash Flow Hedges
    
    IncomeBalance as of December 31, 2003
    
    $
    53
    
    
    $
    (29
    )
    
    $
    24Other comprehensive income
changes during the period
    
    
    (13
    )
    
    
    13
    
    
    
    Balance as of June 30, 2004
    
    $
    40
    
    
    $
    (16
    )
    
    $
    24
 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 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 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 $223 million and $459
million, respectively, for the three and six months ended June 30, 2003. This
reclassification resulted from intersegment trading activities being eliminated
twice from the Consolidated Statements of Operations during the six months
ended June 30, 2003. Management has concluded that these reclassifications are
not material to the fair presentation of our financial statements. 3. Acquisitions and Dispositions On March 10, 2004, we entered into an agreement to acquire 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. The transaction closed during the second quarter of
2004. 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. These assets comprised a component of the Company for purposes of
reporting discontinued operations. All prior period operations have been
revised to reflect these assets as discontinued operations. During the six months ended June 30, 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. All prior period operations
have been revised to reflect these assets as discontinued operations. 9




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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
    
    SixMonths Ended
    
    Months EndedJune 30,
    
    June 30,2004
    
    2003
    
    2004
    
    2003(millions)
    
    (millions)Revenues
    
    $
    
    
    
    $
    98
    
    
    $
    14
    
    
    $
    237Operating income
    
    
    
    
    
    
    5
    
    
    
    2
    
    
    
    11Gain on sale
    
    
    
    
    
    
    26
    
    
    
    3
    
    
    
    26Income from discontinued operations
    
    $
    
    
    
    $
    31
    
    
    $
    5
    
    
    $
    37
 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 NGL, natural gas and other energy-related
products. For the three and six months ended June 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 $23 million and $41
million, respectively, compared to $24 million and $63 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 six
months ended June 30, 2004 and 2003, were a $1 million gain and a $3 million
loss, 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 June 30, 2004, $16 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 six months ended June 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 on August 16, 2000 to floating rate debt.
These interest rate fair value hedges are also at a floating rate based on
six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet
conditions which permit the assumption of no ineffectiveness, as defined by
SFAS 133. As such, for the life of the swaps no ineffectiveness will be
recognized. As of June 30, 2004, the fair value of the interest rate swaps was
a $6 million asset, which is included in the Consolidated Balance Sheets as
Unrealized gains or losses on mark-to-market and hedging transactions with an
offset to the underlying debt included in Long term debt. 10




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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 the 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
for the six months ended June 30, 2004 and 2003, respectively. SixMonths EndedJune 30,Reconciliation of Asset Retirement Obligation (millions)
    
    2004
    
    2003Balance as of January 1
    
    $
    45
    
    
    $
    43Accretion expense
    
    
    2
    
    
    
    3Liabilities incurred
    
    
    2
    
    
    
    Liabilities settled
    
    
    (1
    )
    
    
    (3
    )Balance as of June 30
    
    $
    48
    
    
    $
    43
 6. Goodwill and Other Intangibles The changes in the carrying amount of goodwill for the six months ended
June 30, 2004 are as follows: ForeignPurchase
    
    CurrencyBalance
    
    Price
    
    Exchange
    
    BalanceDecember 31, 2003
    
    Adjustments
    
    Adjustments
    
    June 30, 2004(millions)Natural gas gathering, processing, transportation,
marketing
and storage
    
    $
    407
    
    
    $
    
    
    
    $
    (2
    )
    
    $
    405NGL fractionation, transportation, marketing and trading
    
    
    40
    
    
    
    
    
    
    
    
    
    
    
    40Total consolidated
    
    $
    447
    
    
    $
    
    
    
    $
    (2
    )
    
    $
    445
 There were no impairments of goodwill during the six months ended June 30,
2004. The gross carrying amount and accumulated amortization for commodity sales
and purchases contracts are as follows: June 30,
    
    December 31,2004
    
    2003(millions)Commodity sales and purchases contracts
    
    $
    127
    
    
    $
    127Accumulated amortization
    
    
    (52
    )
    
    
    (47
    )Commodity sales and purchases contracts, net
    
    $
    75
    
    
    $
    80
 11




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##### Table of Contents



During the six months ended June 30, 2004 and 2003, we recorded
amortization expense associated with commodity sales and purchases contracts of
$5 million. The average remaining amortization period for these contracts is
approximately 7 years. Estimated amortization for these contracts for the next
five years is as follows: Estimated Amortization(millions)2004
    
    $
    42005
    
    
    82006
    
    
    82007
    
    
    82008
    
    
    8Thereafter
    
    
    39Total
    
    $
    75
 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 June 30, 2004,
there were no borrowings or letters of credit drawn against the Facility. 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 are 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 are 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 information, these
proceedings will not have a material adverse effect on our consolidated results
of operations, financial position or cash flows. 12




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##### Table of Contents



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. Environmental- The operation of pipelines, plants and other facilities
for gathering, transporting, processing, treating, or storing natural gas, NGL
and other products is subject to stringent and complex laws and regulations
pertaining to health, safety and the environment. As an owner or operator of
these facilities, we must comply with United States and Canadian laws and
regulations at the federal, state and local levels that relate to air and water
quality, hazardous and solid waste management and disposal, and other
environmental matters. The cost of planning, designing, constructing and
operating pipelines, plants, and other facilities must incorporate compliance
with environmental laws and regulations and safety standards. Failure to comply
with these laws and regulations may trigger a variety of administrative, civil
and potentially criminal enforcement measures, including citizen suits, which
can include the assessment of monetary penalties, the imposition of remedial
requirements, the issuance of injunctions or restrictions on operation.
Management believes that, based on currently known information, compliance with
these laws and regulations will not have a material adverse effect on 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 2004. The severance liability that was recorded in the fourth quarter
of 2003 was $6 million at December 31, 2003. Included in General and
administrative expense in the Consolidated Statement of Operations during first
quarter of 2004, the Company expensed an additional $1 million related to this
severance program. The following table summarizes changes in the severance
liability for the six months ended June 30, 2004. Reconciliation of Severance liability (millions)Balance as of December 31, 2003
    
    $
    6Additional severance expense
    
    
    1Severance paid
    
    
    (6
    )Balance as of June 30, 2004
    
    $
    1
 13




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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 NGL (the NGL Segment). Intersegment activity is primarily related to the sale of NGL 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 2. Foreign operations are not material and are
therefore not separately identified. The following tables set forth our segment information. Three months ended June 30, 2004 (millions): IntersegmentNatural Gas
    
    NGL
    
    Eliminations
    
    Other
    
    TotalSegment
    
    Segment
    
    (a)
    
    (c)
    
    CompanyOperating Revenues
    
    $
    2,177
    
    
    $
    482
    
    
    $
    (277
    )
    
    $
    
    
    
    $
    2,382Gross Margin(b)
    
    
    368
    
    
    
    12
    
    
    
    
    
    
    
    
    
    
    
    380Other operating and administrative costs
    
    
    104
    
    
    
    3
    
    
    
    
    
    
    
    41
    
    
    
    148Depreciation and amortization
    
    
    68
    
    
    
    3
    
    
    
    
    
    
    
    4
    
    
    
    75Earnings from unconsolidated affiliates
    
    
    14
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    14Interest expense
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    39
    
    
    
    39Income from continuing operations
before income taxes
    
    $
    210
    
    
    $
    6
    
    
    $
    
    
    
    $
    (84
    )
    
    $
    132Capital Expenditures
    
    $
    107
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    107
 Three months ended June 30, 2003 (millions): IntersegmentNatural Gas
    
    NGL
    
    Eliminations
    
    Other
    
    TotalSegment
    
    Segment
    
    (a)
    
    (c)
    
    CompanyOperating Revenues
    
    $
    1,872
    
    
    $
    450
    
    
    $
    (266
    )
    
    $
    
    
    
    $
    2,056Gross Margin(b)
    
    
    302
    
    
    
    8
    
    
    
    
    
    
    
    
    
    
    
    310Other operating and administrative costs
    
    
    111
    
    
    
    2
    
    
    
    
    
    
    
    41
    
    
    
    154Depreciation and amortization
    
    
    66
    
    
    
    4
    
    
    
    
    
    
    
    5
    
    
    
    75Earnings from unconsolidated affiliates
    
    
    11
    
    
    
    1
    
    
    
    
    
    
    
    
    
    
    
    12Interest expense
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    42
    
    
    
    42Income from continuing operations
before income taxes
    
    $
    136
    
    
    $
    3
    
    
    $
    
    
    
    $
    (88
    )
    
    $
    51Capital Expenditures
    
    $
    31
    
    
    $
    
    
    
    $
    
    
    
    $
    1
    
    
    $
    32
 14




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##### Table of Contents



Six months ended June 30, 2004 (millions): IntersegmentNatural Gas
    
    NGL
    
    Eliminations
    
    Other
    
    TotalSegment
    
    Segment
    
    (a)
    
    (c)
    
    CompanyOperating Revenues
    
    $
    4,381
    
    
    $
    1,060
    
    
    $
    (657
    )
    
    $
    
    
    
    $
    4,784Gross Margin(b)
    
    
    713
    
    
    
    32
    
    
    
    
    
    
    
    
    
    
    
    745Other operating and administrative costs
    
    
    196
    
    
    
    5
    
    
    
    
    
    
    
    82
    
    
    
    283Depreciation and amortization
    
    
    135
    
    
    
    7
    
    
    
    
    
    
    
    8
    
    
    
    150Earnings from unconsolidated affiliates
    
    
    31
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    31Interest expense
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    79
    
    
    
    79Income from continuing operations
before income taxes
    
    $
    413
    
    
    $
    20
    
    
    $
    
    
    
    $
    (169
    )
    
    $
    264Capital Expenditures
    
    $
    130
    
    
    $
    
    
    
    $
    
    
    
    $
    2
    
    
    $
    132
 Six months ended June 30, 2003 (millions): IntersegmentNatural Gas
    
    NGL
    
    Eliminations
    
    Other
    
    TotalSegment
    
    Segment
    
    (a)
    
    (c)
    
    CompanyOperating Revenues
    
    $
    4,250
    
    
    $
    951
    
    
    $
    (578
    )
    
    $
    
    
    
    $
    4,623Gross Margin(b)
    
    
    581
    
    
    
    25
    
    
    
    
    
    
    
    
    
    
    
    606Other operating and administrative costs
    
    
    214
    
    
    
    4
    
    
    
    
    
    
    
    79
    
    
    
    297Depreciation and amortization
    
    
    134
    
    
    
    7
    
    
    
    
    
    
    
    9
    
    
    
    150Earnings from unconsolidated affiliates
    
    
    24
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    24Interest expense
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    84
    
    
    
    84Income from continuing operations before income taxes
    
    $
    257
    
    
    $
    14
    
    
    $
    
    
    
    $
    (172
    )
    
    $
    99Capital Expenditures
    
    $
    64
    
    
    $
    
    
    
    $
    
    
    
    $
    2
    
    
    $
    66
 As ofJune 30,
    
    December 31,2004
    
    2003(millions)Total assets:Natural Gas
    
    $
    4,957
    
    
    $
    5,074NGL
    
    
    271
    
    
    
    271Corporate (c)
    
    
    1,488
    
    
    
    1,169Total assets
    
    $
    6,716
    
    
    $
    6,514
  (a)
    
    Intersegment sales represent sales of NGL from the Natural Gas Segment to
the NGL Segment at either index prices or weighted average prices of NGL.
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. 15




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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 June 30, 2004, we had a
liability of approximately $1 million recorded for known liabilities related to
outstanding indemnification provisions. 16




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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
six months ended June 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 six months of 2004, approximately 81% 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 NGL (the NGL Segment).
In the first six months of 2004, approximately 19% 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 NGL 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 NGL
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 NGL 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 six months of 2004, approximately 80% of our gross margin
is generated by commodity sensitive arrangements and approximately 20% of our
gross margin (excluding hedging and including earnings of unconsolidated
affiliates) is generated by fee-based arrangements. We actively manage our
commodity exposure as discussed below. The midstream industry is cyclical, with the operating results of
companies in the industry significantly affected by the prevailing price of
NGL, 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 NGL, 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 NGL 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 17




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be influenced by supply deliverability, the severity of winter and summer
weather and the level of United States economic growth. The number of active
oil and gas rigs drilling in the United States were 170 and 1,005,
respectively, as of June 30, 2004, compared to 144 and 924, respectively, as of
June 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. However, energy market uncertainty could
negatively impact North American drilling activity in the short term. Lower
drilling levels over a sustained period would have a negative effect on natural
gas volumes gathered and processed. To address the risks associated with volatile commodity prices, we employ
a comprehensive commodity price risk management program. We closely monitor the
risks associated with these commodity price changes on our future operations
and, where appropriate, use various commodity instruments such as natural gas,
crude oil and NGL contracts to hedge a portion of the value of our assets and
operations from such price risks. See Item 3. Quantitative and Qualitative
Disclosures About Market Risk. We do not realize the full impact of commodity
price changes because some of our sales volumes were previously hedged at
prices different than actual market prices. The recognition in the Consolidated
Statements of Operations of the cumulative changes in the fair value of these
hedge instruments reduced the results of operations by $23 million and $24
million in the second quarter of 2004 and 2003, respectively. During the first
six months of 2004 and 2003 the changes in fair value of our hedging contracts
reduced results of operations by $41 million and $63 million, respectively. See
Item 3. 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. Effects of Our Raw Natural Gas Supply Arrangements Our results are affected by the types of arrangements we use to process
raw natural gas. We obtain access to raw natural gas and provide our midstream
natural gas services principally under three types of processing contracts:  
    
    Percentage-of-Proceeds Contracts  Under these contracts we receive
as our fee a negotiated percentage of the residue natural gas and 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.  
    
    Keep-Whole and Wellhead Purchase Contracts  Under the terms of a
wellhead purchase contract, we purchase raw natural gas from the
producer at the wellhead or defined receipt point for processing and
then market the resulting 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 NGL 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 NGL
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, which 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 the
Companys exposure to natural gas and NGL prices. Our current mix of percentage-of-proceeds contracts (where we are exposed
to decreases in natural gas prices) and keep-whole and wellhead purchase
contracts (where we are exposed to increases in natural gas prices) helps to
mitigate our exposure to changes in natural gas prices. Our hedging program is
designed to adequately plan for cash 18




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needed for debt service, capital expenditures and tax distributions.
However, we do not currently anticipate using cash flow hedges in 2005 because
management believes cash flows will be sufficient to fund the Companys
business. 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 $223 million and $459 million, respectively, for
the three and six months ended June 30, 2003. This reclassification resulted
from intersegment trading activities being eliminated twice from the
Consolidated Statements of Operations during the three and six months ended
June 30, 2003. Management has concluded that these reclassifications are not
material to the fair presentation of the Companys financial statements. Results of Operations Three Months Ended June 30,
    
    Six Months Ended June 30,2004
    
    2003
    
    2004
    
    2003(millions)
    
    (millions)Operating revenues:Natural gas segment
    
    $
    2,177
    
    
    $
    1,872
    
    
    $
    4,381
    
    
    $
    4,250NGL segment
    
    
    482
    
    
    
    450
    
    
    
    1,060
    
    
    
    951Intersegment eliminations
    
    
    (277
    )
    
    
    (266
    )
    
    
    (657
    )
    
    
    (578
    )Total operating revenues
    
    
    2,382
    
    
    
    2,056
    
    
    
    4,784
    
    
    
    4,623Purchases of natural gas and petroleum products
    
    
    2,002
    
    
    
    1,746
    
    
    
    4,039
    
    
    
    4,017Gross margin (a)
    
    
    380
    
    
    
    310
    
    
    
    745
    
    
    
    606Costs and expenses
    
    
    223
    
    
    
    229
    
    
    
    433
    
    
    
    447Equity in earnings of unconsolidated affiliates
    
    
    14
    
    
    
    12
    
    
    
    31
    
    
    
    24EBIT from continuing operations before Cumulative
effect of accounting change (b)
    
    
    171
    
    
    
    93
    
    
    
    343
    
    
    
    183Interest expense, net
    
    
    39
    
    
    
    42
    
    
    
    79
    
    
    
    84Income tax expense
    
    
    2
    
    
    
    
    
    
    
    5
    
    
    
    2Income from discontinued operations
    
    
    
    
    
    
    31
    
    
    
    5
    
    
    
    37Cumulative effect of change in accounting principles
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (23
    )Net income
    
    $
    130
    
    
    $
    82
    
    
    $
    264
    
    
    $
    111
  (a)
    
    Gross margin consists of total operating revenues less purchases of
natural gas and petroleum products. Gross margin is a non-Generally
Accepted Accounting Principles (GAAP) measure under the rules of the
Securities and Exchange Commission (SEC), but is included as a
supplemental disclosure because it is a primary performance measure used
by management as it represents the results of product sales and purchases,
a key component of our operations. As an indicator of our operating
performance, gross margin should not be considered an alternative to, or
more meaningful than, net income or cash flow as determined in accordance
with GAAP. Our gross margin may not be comparable to a similarly titled
measure of another company because other entities may not calculate gross
margin in the same manner.  (b)
    
    EBIT consists of net income from continuing operations before cumulative
effect of accounting change, net interest expense and income tax expense.
EBIT is a non-GAAP measure under the rules of the SEC, but is included as
a supplemental disclosure because it is a primary performance measure used
by management as it represents the results of operations without regard to
financing methods or capital structure. As an indicator of our operating
performance, EBIT should not be considered an alternative to, or more
meaningful than, net income or cash flow as determined in accordance with
GAAP. Our EBIT may not be comparable to a similarly titled measure of
another company because other entities may not calculate EBIT in the same
manner. 19




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Three months ended June 30, 2004 compared with three months ended June 30, 2003 Operating Revenues Total operating revenues increased $326 million, or
16%, to $2,382 million in the second quarter of 2004 from $2,056 million in the
same period of 2003. This increase was primarily due to the following factors:  
    
    $175 million increase was attributable to a $0.12 per gallon increase in average NGL prices;  
    
    $125 million increase was attributable to a $0.58 per MMBtu increase in average natural gas prices;  
    
    $35 million increase related to the acquisition of gathering,
processing and transmission assets in Southeast New Mexico from
ConocoPhillips;  
    
    $30 million decrease primarily related to wholesale propane
marketing activity partially offset by higher NGL sales volumes; and  
    
    $20 million increase from higher processed volumes resulting
from favorable processing economics. Purchases of Natural Gas and Petroleum Products Purchases of natural gas
and petroleum products increased $256 million, or 15%, to $2,002 million in the
second quarter of 2004 from $1,746 million in the same period of 2003. The
increase was primarily due to the following factors:  
    
    $240 million increase due to higher average costs of raw
natural gas supply;  
    
    $30 million increase related to the acquisition of gathering,
processing and transmission assets in Southeast New Mexico from
ConocoPhillips; and  
    
    $10 million decrease from lower wholesale propane marketing
activity. Three Months Ended June 30,2004
    
    2003(millions)Gross Margin:Natural gas segment
    
    $
    368
    
    
    $
    302NGL segment
    
    
    12
    
    
    
    8Total gross margin
    
    $
    380
    
    
    $
    310
 Gross Margin Total gross margin increased $70 million, or 23% to $380
million in the second quarter of 2004 from $310 million in the same period of
2003. Gross margin associated with the Natural Gas Segment increased $66
million, or 22%, to $368 million in the second quarter of 2004 from $302
million in the same period of 2003, mainly as a result of the following
factors:  
    
    $60 million increase (net of hedging) was the result of
commodity sensitive processing arrangements, mainly due to higher
average NGL and crude oil prices; and  
    
    $10 million decrease relating to lower throughput volumes;  
    
    $8 million increase related to improved operational and commercial performance; and  
    
    $5 million increase primarily related to the acquisition of
gathering, processing and transmission assets in Southeast New Mexico
from ConocoPhillips. Gross margin associated with the NGL Segment increased $4 million, or 50%
to $12 million in the second quarter 2004 from $8 million for the same period
in 2003. This increase was comprised primarily of an increase in trading and
marketing net margin, wholesale propane marketing and NGL pipelines. NGL production during the second quarter 2004 increased 19,000 barrels per
day, or 5%, to 371,000 barrels per day from 352,000 barrels per day in the same
period of 2003, and natural gas transported and/or processed during the second
quarter of 2004 decreased 0.1 trillion Btus per day, or 1%, to 7.5 trillion
Btus per day from 7.6 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 Operating and maintenance expenses decreased $6
million, or 5%, to $107 million in the second quarter of 2004 from $113 million
in the same period of 2003. This decrease was primarily due to the following
factors:  
    
    decreased expenses of approximately $3 million related to the
consolidation of a previously 20




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unconsolidated affiliate as required by FIN 46R (see Note 2 to the
Consolidated Financial Statements). Certain operating costs paid by us
to this affiliate are now eliminated in consolidation of this
affiliate; and  
    
    decreased environmental remediation expense of approximately $4
million. Interest Expense, net Interest expense, net, decreased $3 million, or 7%
to $39 million in the second quarter of 2004 from $42 million in the same
period of 2003. This decrease was primarily the result of lower interest
expense due to lower outstanding debt and an increase in interest income from
higher cash investments which reduced interest expense in the second quarter of
2004 compared with the second 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 second quarter of 2004 is attributable to earnings
associated with tax-paying subsidiaries. Income from Discontinued Operations Income from discontinued operations
was $31 million in the second quarter of 2003. Income from discontinued
operations includes gains on the sale of discontinued operations and the
results of such operations (see Note 3 to the Consolidated Financial
Statements). Six months ended June 30, 2004 compared with six months ended June 30, 2003 Operating Revenues Total operating revenues increased $161 million, or
3%, to $4,784 million in the first six months of 2004 from $4,623 million in
the same period of 2003. This increase was primarily due to the following
factors:  
    
    $190 million increase was attributable to a $0.06 per gallon
increase in average NGL prices;  
    
    $90 million decrease from lower throughput related to reduced
raw natural gas supply volume, due to reservoir decline exceeding
supply from new drilling activity and increased plant downtime due to
maintenance;  
    
    $60 million decrease was attributable to a $0.16 per MMBtu
decrease in average natural gas prices;  
    
    $37 million increase from trading and marketing net margin
primarily due to natural gas asset based trading and marketing;  
    
    $35 million increase related to the acquisition of gathering,
processing and transmission assets in Southeast New Mexico from
ConocoPhillips;  
    
    $22 million increase related to cash flow hedging which reduced
revenues by approximately $41 million for the six months ended June
30, 2004 and by $63 million for the six months ended June 30, 2003;  
    
    $20 million increase related to higher NGL sales volumes; and  
    
    $15 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 $22 million, or 1%, to $4,039 million in the
first six months of 2004 from $4,017 million in the same period of 2003. This
increase was primarily due to the following factors:  
    
    $30 million increase related to the acquisition of gathering,
processing and transmission assets in Southeast New Mexico from
ConocoPhillips;  
    
    $60 million increase due to higher average costs of raw natural
gas supply which is primarily due to an increase in average NGL
prices partially offset by a decrease in natural gas prices;  
    
    $60 million decrease from lower processed raw natural gas
supply volume; and  
    
    $8 million decrease related to expenses incurred in the first
quarter of 2003 related to a contract litigation settlement. 21




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##### Table of Contents



Six Months Ended June 30,2004
    
    2003(millions)Gross Margin:Natural gas segment
    
    $
    713
    
    
    $
    581NGL segment
    
    
    32
    
    
    
    25Total gross margin
    
    $
    745
    
    
    $
    606
 Gross Margin Total Gross margin increased $139 million, or 23% to $745
million in the first six months of 2004 from $606 million in the same period of
2003. Gross margin associated with the Natural Gas Segment increased $132
million, or 23%, to $713 million in the first six months of 2004 from $581
million in the same period of 2003, mainly as a result of the following
factors:  
    
    $95 million increase (net of hedging) was the result of
commodity sensitive processing arrangements, mainly due to higher
average NGL and crude oil prices;  
    
    $23 million increase related to improved operational and commercial performance;  
    
    $15 million decrease related to lower throughput volumes;  
    
    $14 million increase was the result of $29 million of improved
net trading margin offset by approximately $15 million of lower
results related to physical natural gas asset based activity;  
    
    $8 million increase related to expenses incurred in the first
quarter of 2003 related to a contract litigation settlement; and  
    
    $5 million increase related to the acquisition of gathering,
processing and transmission assets in Southeast New Mexico from
ConocoPhillips. Gross margin associated with the NGL Segment increased $7 million, or 28%
to $32 million in the first six months of 2004 from $25 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 six months of 2004 increased 4,000 barrels
per day, or 1%, to 364,000 barrels per day from 360,000 barrels per day in the
same period of 2003, and natural gas transported and/or processed during the
first six months of 2004 decreased 0.2 trillion Btus per day, or 3%, to 7.4
trillion Btus per day from 7.6 trillion Btus per day during the same period of
2003. Costs and Expenses Operating and maintenance expenses decreased $17
million, or 8%, to $201 million in the first six months of 2004 from $218
million in the same period of 2003. This decrease was primarily due to the
following factors:  
    
    decreased expenses of approximately $8 million related to the
consolidation of a previously unconsolidated affiliate as required by
FIN 46R (see Note 2 to the Consolidated Financial Statements).
Certain operating costs paid by us to this affiliate are now
eliminated in consolidation of this affiliate; and  
    
    decreased environmental remediation expense of approximately $6
million. Interest Expense, net Interest expense, net, decreased $5 million, or 6%
to $79 million in the first six months of 2004 from $84 million in the same
period of 2003. This decrease was primarily the result of lower interest
expense due to lower outstanding debt and an increase in interest income from
higher cash investments which reduced interest expense in the first six months
of 2004 compared with first six 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 $5 million in the first six months of 2004 is attributable to earnings
associated with tax-paying subsidiaries. Income from Discontinued Operations Income from discontinued operations
was $5 million in the first six months of 2004 and $37 million in the first six
months of 2003. Income from discontinued operations includes gains on the sale
of discontinued operations and the results of such operations in both periods
presented (see Note 3 to the Consolidated Financial Statements). 22




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Cumulative Effect of Change in Accounting Principles Cumulative effect
of change in accounting principles was a loss of $23 million in the first six
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 2 to
Consolidated Financial Statements). Liquidity and Capital Resources As of June 30, 2004, we had $253 million in cash and cash equivalents
compared to $43 million as of December 31, 2003. Included in cash and cash
equivalents as of June 30, 2004 was approximately $28 million held by our
Canadian subsidiaries for their operations. The remaining cash balance was
primarily available for general corporate purposes. Current assets exceeded
current liabilities by $135 million at June 30, 2004 and current liabilities
exceeded current assets by $73 million at December 31, 2003. We rely upon cash
flows from operations and borrowings to fund our liquidity and capital
requirements. A material adverse change in operations or available financing
may impact our ability to fund our requirements for liquidity and capital
resources. Operating Cash Flows During the first six months of 2004, cash provided by operating activities
was $427 million, an increase of $206 million from $221 million in the first
six months of 2003. This increase was due primarily to a $153 million increase
in net income. The increase in net income is due largely to the favorable
effects of commodity prices, net of hedging, improved results from trading and
marketing activities, and decreased operating expenses, partially offset by
lower volumes. Additional increases were the result of changes in working
capital balances and unrealized mark-to-market and hedging activity. Cash distributions received from unconsolidated affiliates were $38
million in the first six months of 2004 and $31 million in the first six months
of 2003. These distributions were in excess of earnings from unconsolidated
affiliates by $7 million in each period. 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. Investing Cash Flows During the first six months of 2004, cash used in investing activities was
$62 million, a decrease of $90 million from cash provided by investing
activities of $28 million in the first six months of 2003. Our capital
expenditures 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 six months of 2004, we spent
approximately $132 million on capital expenditures for continuing operations
compared to $66 million in the first six 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 six months of 2004, as compared to the same period in 2003. The cash
used for capital expenditures is partially offset by proceeds of $62 million
from the sale of discontinued operations. Our level of capital expenditures for acquisitions and construction and
other investments depends on many factors, including industry conditions, the
availability of attractive acquisition opportunities and construction projects,
the level of commodity prices and competition. We expect to finance our capital
expenditures with our cash on hand, cash flow from operations, asset sales, our
credit facility or other available sources of financing. Our capital
expenditures forecast for the year ending December 31, 2004 is approximately
$220 million. Depending on cash flow results, redeployment of capital from
divestitures and opportunities in the marketplace, 2004 acquisition and capital
expenditures may vary from the forecast. 23




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##### Table of Contents



Financing Cash Flows 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 June 30, 2004, there were no borrowings or
letters of credit drawn against the Facility. On November 3, 2003, we executed a $32 million irrevocable standby letter
of credit, to be used to secure transaction exposure with a counterparty, which
expired on May 15, 2004. At June 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. In April 2002, we filed a shelf registration statement increasing our
ability to issue securities to $500 million. The shelf registration statement
provides for the issuance of senior notes, subordinated notes and trust
preferred securities. Based on current and anticipated levels of operations, we believe that our
cash on hand and cash flow from operations, combined with borrowings available
under the commercial paper program as supported by the Facility, will be
sufficient to enable us to meet our current and anticipated cash operating
requirements and working capital needs for the next year. Actual capital
requirements, however, may change, particularly as a result of any acquisitions
or distributions that we may make. Our ability to meet current and anticipated
operating requirements will depend on our future performance. Distributions We are required to make quarterly distributions to Duke Energy and
ConocoPhillips based on allocated taxable income. Our Limited Liability Company
Agreement provides for taxable income to be allocated in accordance with the
Internal Revenue Code Section 704(c). This Code section takes into account the
variation between the adjusted tax basis and the fair market value of assets
contributed to the joint venture. The required distribution is based on the
highest taxable income allocated to either member, with the other member
receiving a proportionate amount to maintain the ownership capital accounts at
69.7% for Duke Energy and 30.3% for ConocoPhillips. During the six months ended
June 30, 2004, we paid distributions of $11 million based on estimated annual
taxable income allocated to the members according to their respective ownership
percentages. As of June 30, 2004, additional distributions payable of $5
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 six months ended June 30, 2004, with the approval of
both members, we paid total dividends of $137 million to the members, allocated
in accordance with their respective ownership percentages. 24




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##### Table of Contents



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 June 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
June 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 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. 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. 25




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##### Table of Contents



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 six 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 six
months of 2003. Acquisitions and Dispositions In February 2004, we entered into a purchase and sale agreement to sell
gas gathering and processing plant assets in West Texas to a third party
purchaser for a sales price of approximately $62 million. The transaction
closed in the first quarter of 2004 with no significant book gain or loss. On March 10, 2004, we entered into an agreement to acquire 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. The transaction closed during the second quarter of
2004. 26




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##### Table of Contents



Item 3. Quantitative and Qualitative Disclosure about Market Risks Risk and Accounting Policies We are exposed to market risks associated with commodity prices,
counterparty credit, interest rates, and, to a limited extent, foreign currency
exchange rates. Management has established comprehensive risk management
policies to monitor and manage these market risks. Duke Energy Field Services
Risk Management Committee (Risk Management Committee) is responsible for the
overall approval of market risk management policies and the delegation of
approval and authorization levels. The Risk Management Committee is composed of
senior executives who receive regular briefings on the Companys positions and
exposures as well as periodic updates from and consultations with the Duke
Energy Chief Risk Officer (CRO) and other expert resources at Duke Energy
regarding market risk positions and exposures, credit exposures and overall
risk management in the context of market activities. The Risk Management
Committee is responsible for the overall management of credit risk and
commodity price risk, including monitoring exposure limits. Commodity Price Risk We are exposed to the impact of market fluctuations primarily in the price
of NGL that we own as a result of our processing activities. We employ
established policies and procedures to manage our risks associated with these
market fluctuations using various commodity derivatives, including forward
contracts, swaps, futures and options. (See Notes 2 and 4 to the Consolidated
Financial Statements.) Commodity Derivatives  Trading and Marketing The risk in the commodity
trading and marketing portfolios is measured and monitored on a daily basis
utilizing a Value-at-Risk model to determine the potential one-day favorable or
unfavorable Daily Value at Risk (DVaR) as described below. DVaR is monitored
daily in comparison to established thresholds. Other measures are also used to
limit and monitor the risk in the commodity trading and marketing portfolios
(which includes all trading and marketing contracts not designated as hedge
positions) on a monthly and annual basis. These measures include limits on the
nominal size of positions and periodic loss limits. DVaR computations are based on a historical simulation, which uses price
movements over an 11 day period to simulate forward price curves in the energy
markets to estimate the potential favorable or unfavorable impact of one days
price movement on the existing portfolio. The historical simulation emphasizes
the most recent market activity, which is considered the most relevant
predictor of immediate future market movements for crude oil, NGL, 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 endedJune 30, 2004
    
    June 30, 2003
    
    June 30, 2004
    
    June 30, 2004Calculated DVaR
    
    $
    1
    
    
    $
    2
    
    
    $
    1
    
    
    
    
 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 six
    
    for the sixsix months ended
    
    six months ended
    
    months ended
    
    months endedJune 30, 2004
    
    June 30, 2003
    
    June 30, 2004
    
    June 30, 2004Calculated DVaR
    
    $
    1
    
    
    $
    2
    
    
    $
    3
    
    
    
    
 27




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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: Classification of Contract
    
    Accounting Method
    
    Presentation of Gains & Losses or Revenue & ExpenseTrading Derivatives
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net marginNon-Trading Derivatives:Cash Flow Hedge
    
    Hedge methodb
    
    Gross basis in the same income
statement category as the related hedged itemFair Value Hedge
    
    Hedge methodb
    
    Gross basis in the same income
statement category as the related hedged itemNormal Purchase or Normal Sale
    
    Accrual methodc
    
    Gross basis upon settlement in the
corresponding income statement category based on commodity typeNon-Trading Mark-to- Market
    
    Mark-to-marketa
    
    Net basis in Trading and marketing net margin
 a Mark-to-market- An accounting method whereby the change in the fair value of
the asset or liability is recognized in the Consolidated Statements of
Operations in Trading and marketing net margin during the current period. b Hedge method- An accounting method whereby the 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. 28




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##### Table of Contents



The following table shows the fair value of our mark-to-market portfolio
as of June 30, 2004: Fair Value of Mark-to-Market Contracts as of June 30, 2004 (millions)Maturity in
    
    Maturity in
    
    Maturity in
    
    Maturity in 2007
    
    TotalSources of Fair Value
    
    2004
    
    2005
    
    2006
    
    and Thereafter
    
    Fair ValueTrading:Prices supported by
quoted market prices
and other external
sources
    
    $
    11
    
    
    $
    6
    
    
    $
    (2
    )
    
    $
    
    
    
    $
    15Prices based on models
and other valuation
methods
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2
    )
    
    
    (2
    )Total
Trading
    
    
    11
    
    
    
    6
    
    
    
    (2
    )
    
    
    (2
    )
    
    
    13Non-Trading:Prices supported by
quoted market prices
and other external
sources
    
    
    (1
    )
    
    
    (3
    )
    
    
    
    
    
    
    
    
    
    
    (4
    )Prices based on models
and other valuation
methods
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
Non-Trading
    
    
    (1
    )
    
    
    (3
    )
    
    
    
    
    
    
    
    
    
    
    (4
    )Total
Mark-to-Market
    
    $
    10
    
    
    $
    3
    
    
    $
    (2
    )
    
    $
    (2
    )
    
    $
    9
 The Prices supported by quoted market prices and other external sources
category includes our New York Mercantile Exchange (NYMEX) swap positions in
natural gas and crude oil. The NYMEX has currently quoted prices for the next
32 months. In addition, this category includes our forward positions and
options in natural gas and natural gas basis swaps at points for which
over-the-counter (OTC) broker quotes are available. On average, OTC quotes
for natural gas forwards and swaps extend 22 and 32 months into the future,
respectively. OTC quotes for natural gas options extend 12 months into the
future, on average. We value these positions against internally developed
forward market price curves that are validated and recalibrated against OTC
broker quotes. This category also includes strip transactions whose prices
are obtained from external sources and then modeled to daily or monthly prices
as appropriate. The Prices based on models and other valuation methods category includes
(i) the value of options not quoted by an exchange or OTC broker and (ii) the
value of transactions for which an internally developed price curve was
constructed as a result of the long dated nature of the transaction or the
illiquidity of the market point. In certain instances structured transactions
can be decomposed and modeled by us as simple forwards and options based on
prices actively quoted. Although the valuation of the simple structures might
not be different from the valuation of contracts in other categories, the
effective model price for any given period is a combination of prices from two
or more different instruments and therefore has been included in this category
due to the complex nature of these transactions. Hedging Strategies We are exposed to market fluctuations in the prices
of energy commodities related to natural gas gathering, processing and
marketing activities. We closely monitor the risks associated with these
commodity price changes on our future operations and, where appropriate, may
use various commodity instruments such as natural gas, crude oil and NGL
contracts to hedge the value of our assets and operations from such price
risks. Our hedging program 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 29




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##### Table of Contents



capital expenditures. However, we do not currently anticipate using cash
flow hedges in 2005 because management believes cash flows will be sufficient
to fund the Companys business. Our primary use of hedging commodity derivatives has been to hedge 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 31). 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 June 30, 2004: Fair Value of Hedging Contracts as of June 30, 2004 (millions)Maturity inMaturity in
    
    Maturity in
    
    Maturity in
    
    2007 and
    
    Total FairSources of Fair Value
    
    2004
    
    2005
    
    2006
    
    Thereafter
    
    ValuePrices supported by
quoted market prices
and other external
sources
    
    $
    (12
    )
    
    $
    5
    
    
    $
    2
    
    
    $
    (6
    )
    
    $
    (11
    )Prices based on
models
or other valuation
techniques
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    $
    (12
    )
    
    $
    5
    
    
    $
    2
    
    
    $
    (6
    )
    
    $
    (11
    )
 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 NGL 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. 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 30




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##### Table of Contents



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 June 30, 2004, we held cash or letters of credit of $74 million to
secure future performance by counterparties, and had deposited with
counterparties $3 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 June 30, 2004,
the fair value of our interest rate swaps was an asset of $6 million. As of June 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 June 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. 31




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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 and Reports on Form 8-K  (a)
    
    Exhibits 31.1
    
    
    Certification of Chief Financial Officer Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.31.2
    
    
    Certification of Chief Executive Officer Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.32.1
    
    
    Certification of Chief Financial Officer Pursuant to 18 U.S.C.
Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.32.2
    
    
    Certification of Chief Executive Officer Pursuant to 18 U.S.C.
Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
  (b)
    
    Reports on Form 8-KNone. 32




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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, LLCAugust 10, 2004/s/ Rose M. RobesonRose M. RobesonVice President and Chief Financial Officer(On Behalf of the Registrant and asPrincipal Financial and Accounting
Officer)
 33




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##### Table of Contents



EXHIBIT INDEX ExhibitNo.
    
    Description31.1
    
    
    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.