UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

_______________

FORM 10-Q

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

DUKE ENERGY FIELD SERVICES, LLC

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

DUKE ENERGY FIELD SERVICES, LLC
FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2004

INDEX

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

     Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

     All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

     These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks include, but are not limited to, the following:

•		our ability to access the capital and bank markets, which will depend on general market conditions and the credit ratings for our debt obligations;
•		our use of derivative financial instruments to manage commodity and interest rate risks;
•		the level of creditworthiness of counterparties to transactions;
•		the amount of collateral required to be posted from time to time in our transactions;
•		changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment or the increased regulation of the gathering and processing industry;

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•		the timing and extent of changes in commodity prices, interest rates, foreign currency exchange rates and demand for our services;
•		weather and other natural phenomena;
•		industry changes, including the impact of consolidations, and changes in competition;
•		our ability to obtain required approvals for construction or modernization of gathering and processing facilities, and the timing of production from such facilities, which are dependent on the issuance by federal, state and municipal governments, or agencies thereof, of building, environmental and other permits, the availability of specialized contractors and work force and prices of and demand for products;
•		the extent of success in connecting natural gas supplies to gathering and processing systems;
•		general economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities; and
•		The effect of accounting pronouncements issued periodically by accounting standard-setting bodies.

     In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

DUKE ENERGY FIELD SERVICES, LLC

See Condensed Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

See Condensed Notes to Consolidated Financial Statements.

2

DUKE ENERGY FIELD SERVICES, LLC

See Condensed Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

See Condensed Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

1. General and Summary of Significant Accounting Policies

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

     These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. These consolidated financial statements and other information included in this quarterly report on Form 10-Q should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the fiscal year ended December 31, 2003.

     Consolidation — The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, after eliminating intercompany transactions and balances, and variable interest entities where we are the primary beneficiary. Investments in 20% to 50% owned affiliates, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Investments greater than 50% are consolidated unless we do not have the ability to exercise control, in which case, they are accounted for using the equity method.

     Use of Estimates — Conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.

     Accounting for Hedges and Commodity Trading and Marketing Activities — Each derivative not qualifying for the normal purchases and sales exception under Statement of Financial Accounting Standards (“SFAS”) No. 133 (“SFAS 133”), “Accounting for Derivative Instruments and Hedging Activities,” as amended, is recorded on a gross basis in the Consolidated Balance Sheets at its fair value as Unrealized gains or Unrealized losses on mark-to-market and hedging transactions. Derivative assets and liabilities remain classified in the Consolidated Balance Sheets as Unrealized gains or Unrealized losses on mark-to-market or hedging transactions at fair value until the contractual delivery period occurs.

     Effective January 1, 2003, we designate each energy commodity derivative as either trading or non-trading. For each of our derivatives, the accounting method and presentation of gains and losses or revenue and expense in the Consolidated Statements of Operations are as follows:

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^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

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period earnings. At September 30, 2004 and December 31, 2003, $15 million and $29 million, respectively, of losses related to cash flow hedges were deferred in AOCI.

     Commodity Fair Value Hedges — Changes in the fair value of a derivative that is designated and qualifies as a fair value hedge are included in the Consolidated Statements of Operations as Sales of natural gas and petroleum products and Purchases of natural gas and petroleum products, as appropriate, and are included in the Consolidated Balance Sheets as Unrealized gains or Unrealized losses on mark-to-market and hedging transactions. Changes in the fair value of the physical portion of a fair value hedge (i.e., the hedged item) are recorded in the Consolidated Statements of Operations in the same accounts as the changes in the fair value of the derivative, with offsetting amounts in the Consolidated Balance Sheets as Other current assets, Other noncurrent assets, Other current liabilities or Other long term liabilities, as appropriate.

     Interest Rate Fair Value Hedges — We periodically enter into interest rate swaps to convert some of our fixed-rate long term debt to floating-rate long term debt. Hedged items in fair value hedges are marked-to-market with the respective derivative instruments. Accordingly, our hedged fixed-rate debt is carried at fair value. The terms of the outstanding swaps match those of the associated debt which permits the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps, no ineffectiveness will be recognized.

     Distributions — Under the terms of our Limited Liability Company Agreement (the “LLC Agreement”), we are required to make quarterly distributions to Duke Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement, as amended, provides for taxable income to be allocated in accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 69.7% for Duke Energy and 30.3% for ConocoPhillips. During the nine months ended September 30, 2004, we paid distributions of $16 million based on estimated annual taxable income allocated to the members according to their respective ownership percentages. As of September 30, 2004, distributions payable of $78 million were included in Other current liabilities in the Consolidated Balance Sheets.

     In 2003, our board of directors approved a plan to consider the payment of a quarterly dividend to Duke Energy and ConocoPhillips. The board of directors may consider net income, cash flow or any other criteria deemed appropriate for determining the amount of the quarterly dividend to be paid. The LLC Agreement restricts making distributions, which would include these dividends, except with the approval of both members. During the nine months ended September 30, 2004, with the approval of both members, we paid a total dividend of $277 million to the members, allocated in accordance with their respective ownership percentages.

     Stock-Based Compensation — Under Duke Energy’s 1998 Long Term Incentive Plan, stock options and other stock-based instruments for Duke Energy’s common stock and other stock-based awards may be granted to our key employees. We account for stock-based compensation arrangements using the intrinsic value recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and FASB Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” Under this method, any compensation cost is measured as the quoted market price of stock at the date of the grant less the amount an employee must pay to acquire the stock. Because the exercise price for all options granted under the plan was equal to the market value of the underlying common stock on the date of grant, no compensation cost is recognized in the accompanying Consolidated Statements of Operations. Restricted stock grants and phantom stock awards are recorded as compensation cost over the required vesting period, based on the fair value on the date of grant. Performance awards are recorded as compensation cost over the required vesting period, based on the fair value of the awards at the balance sheet date.

     The following table shows what earnings available for members’ interest would have been if we had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to stock options and reflects the provisions of SFAS No. 148 “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of FASB Statement No. 123.”

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     Accumulated Other Comprehensive Income — The components of and changes in accumulated other comprehensive income are as follows:

     Cumulative Effect of Change in Accounting Principles — We adopted the provisions of EITF Issue 02-03 (“EITF 02-03”), “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities,” that required new non-derivative energy trading contracts entered into after October 25, 2002 to be accounted for under the accrual basis of accounting. Non-derivative energy trading contracts recorded in the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair value were adjusted to historical cost via a cumulative effect adjustment of $5 million as a reduction to earnings in the first quarter of 2003.

     We adopted the provisions of SFAS No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations,” as of January 1, 2003 which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. In accordance with the transition provisions of SFAS 143, we recorded a cumulative effect adjustment of $18 million as a reduction to earnings in the first quarter of 2003.

     New Accounting Standards — In May 2003, the FASB issued SFAS No. 150 (“SFAS 150”), “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” including the deferral of certain effective dates as a result of the provisions of FASB Staff Position 150-3, “Effective Date, Disclosures, and Transition for Mandatorily Redeemable Noncontrolling Interests Under FASB Statement No. 150, ‘Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity’.” SFAS 150 requires that certain financial instruments that could previously be accounted for as equity, be classified as liabilities in the consolidated balance sheets and initially recorded at fair value. In addition to its requirements for the classification and measurement of financial instruments in its scope, SFAS 150 also requires disclosures about the nature and terms of the financial instruments and about alternative ways of settling the instruments. Upon adoption on July 1, 2003, we reclassified our preferred members’ interest, which were mandatorily redeemable, of $200 million from mezzanine equity to long term debt and prospectively classified accrued or paid distributions on these securities, which had previously been classified as dividends, as interest expense. During 2003, we redeemed the remaining $200 million of these securities in cash.

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     In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities” which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. We adopted the provisions of FIN 46 and its related interpretations (“FIN 46R”) in the first quarter of 2004. As a result, we consolidated one entity, previously accounted for under the equity method of accounting, on January 1, 2004. This entity, which is a substantive entity, had total assets of approximately $92 million as of January 1, 2004. Adoption of FIN 46R had no material effect on our consolidated results of operations, cash flows or financial position.

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

     In May 2003, the EITF reached consensus in EITF Issue No. 01-08 (“EITF 01-08”), “Determining Whether an Arrangement Contains a Lease,” to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to mandate reporting revenue as rental or leasing income that otherwise would be reported as part of product sales or service revenue. EITF 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, “Accounting for Leases.” The consensus is to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations in fiscal periods beginning on July 1, 2003. The adoption of EITF 01-08 had no material effect on our consolidated results of operations, cash flows or financial position.

     Reclassifications — Certain prior period amounts have been reclassified in the Consolidated Financial Statements to conform to the current period presentation. Included in the reclassified amounts are increases in both Sales of natural gas and petroleum products and in Purchases of natural gas and petroleum products in the amount of approximately $264 million and $723 million, for the three and nine months ended September 30, 2003, respectively. This reclassification resulted from intersegment trading activities being eliminated twice from the Consolidated Statements of Operations during the nine months ended September 30, 2003. Management has concluded that these reclassifications are not material to the fair presentation of our financial statements.

2. Impairments of Long-Lived Assets and Investments in Affiliates

     Impairments of Long-Lived Assets – We recorded impairments of $22 million as Asset impairments, included in the Consolidated Statements of Operations, with an offset to Property, plant and equipment, net, included in the Consolidated Balances Sheets, in the third quarter of 2004 as described below.

     Approximately $9 million of the asset impairments were related to our periodic review of the carrying value of our assets and a planned shut down of a specific plant. We determined that these assets, which are located in Onshore and Offshore Gulf of Mexico, were impaired, therefore they were written down to their fair value. Fair value was determined based on management’s best estimates of sales value and/or discounted future cash flow models. The charges associated with these impairments were recorded in the Natural Gas Segment.

     Approximately $13 million (offset by $7 million in minority interest income) of the asset impairments were related to assets that were distributed to a minority interest holder in exchange for their 42% minority interest (see discussion related to Mobile Bay Processing Partners in Note 3 below). We determined that these assets, which are located Onshore Gulf of Mexico, were impaired, therefore they were written down to fair value. Fair value was determined based on an independent third-party valuation. The charges associated with these impairments were recorded in the Natural Gas Segment.

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     Impairments of Investments in Affiliates — In the third quarter of 2004, we recorded an impairment totaling $23 million as Impairment of equity method investments, included in the Consolidated Statements of Operations, with an offset to Investment in unconsolidated affiliates included in the Consolidated Balance Sheets. Our investments in these assets, which are located Onshore Gulf of Mexico, were analyzed during the third quarter and determined to be impaired. As a result, these investments were written down to fair value which was determined based on management’s best estimates of sales value and/or discounted future cash flow models. The charges associated with these impairments were recorded in the NGL Segment.

3. Acquisitions and Dispositions

     Based upon management’s current assessment of the probable disposition of certain gathering, compression and transportation assets expected to occur by early 2005, we have classified these assets as held for sale and have reclassified the assets to Other current assets in the Consolidated Balance Sheet as of September 30, 2004. The book value of these assets has been written down by $23 million to $27 million, the estimated fair value less costs to sell. These assets comprise a component of the Company for purposes of reporting discontinued operations. The results of operations and cash flows related to these assets held for sale have been reclassified to discontinued operations for all periods presented. These assets were previously included in the Natural Gas Segment.

     On August 31, 2004, we acquired a 42% minority interest in Mobile Bay Processing Partners (“MBPP”) in exchange for certain assets of MBPP. MBPP is a consolidated entity, which, prior to this transaction, was owned 58% by us, and subsequent to the transaction is wholly-owned by us. As a result of the exchange, we recorded an impairment charge of $13 million (offset by $7 million in minority interest income) related to the assets that were distributed, which had a fair market value of less than book value. Minority interests in the Consolidated Balance Sheet decreased by $40 million related to this transaction. MBPP owns processing assets in the Onshore Gulf of Mexico.

     On August 31, 2004, we purchased a 42% minority interest in Gulf Coast NGL Pipeline, LLC (“GC”) for $2 million. GC is a consolidated entity, which, prior to this transaction, was owned 58% by us, and subsequent to the transaction is wholly-owned by us. Minority interests in the Consolidated Balance Sheet decreased by $7 million related to this transaction. GC owns a 16.67% interest in two investments in unconsolidated affiliates.

     On August 31, 2004, we purchased a 12% minority interest in Dauphin Island Gathering Partners (“DIGP”) for $2 million. DIGP is a consolidated entity, which, prior to this transaction, was owned 72% by us, and subsequent to the acquisition is owned 84% by us. Minority interests in the Consolidated Balance Sheet decreased by $29 million related to this transaction. DIGP owns gathering and transmission assets in the Offshore Gulf of Mexico.

     In April 2004, we acquired gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips, a related party, for a total purchase price of approximately $80 million, consisting of $74 million in cash and the assumption of approximately $6 million of liabilities.

     In February 2004, we sold gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million, with no significant book gain or loss. These assets comprised a component of the Company for purposes of reporting discontinued operations. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented. These assets were previously included in the Natural Gas Segment.

     In the second quarter of 2003, we sold gathering, transmission and processing assets to two separate buyers for a combined sales price of approximately $90 million. These assets comprised a component of the Company for purposes of reporting discontinued operations. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented. These assets were previously included in the Natural Gas Segment.

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     The following table sets forth selected financial information associated with the assets discussed above which are accounted for as discontinued operations:

4. Derivative Instruments, Hedging Activities and Credit Risk

     Commodity cash flow hedges — We may, from time to time, use cash flow hedges, as specifically defined by SFAS 133, to reduce the potential negative impact that commodity price changes could have on our earnings and ability to adequately plan for cash needed for debt service, capital expenditures and tax distributions.

     We use natural gas, crude oil and NGL swaps to hedge the impact of market fluctuations in the prices of NGLs, natural gas and other energy-related products. For the three and nine months ended September 30, 2004, the recognition in the Consolidated Statements of Operations of the cumulative changes in the fair value of these hedge instruments reduced revenues by $12 million and $54 million, respectively, compared to $23 million and $87 million, respectively, in the same periods of 2003. The above changes in the fair value of these hedge instruments include the effects of any ineffectiveness, which for the nine months ended September 30, 2004 and 2003, were a $1 million gain and a $5 million gain, respectively. No derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to any forecasted transactions that are not probable of occurring.

     Gains and losses on derivative contracts that are reclassified from AOCI to current period earnings are included in the line item in which the hedged item is recorded. As of September 30, 2004, $15 million of the remaining deferred net losses on derivative instruments in AOCI are expected to be reclassified into earnings within the next 12 months as the hedged transactions occur; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings. The remaining term over which we are currently hedging our exposure to the variability of future cash flows is through the end of 2004.

     Commodity fair value hedges — We use fair value hedges to hedge exposure to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to price risk. We may hedge producer price locks (fixed price gas purchases) and market locks (fixed price gas sales) to reduce our exposure to fixed price risk via swapping the fixed price risk for a floating price position (New York Mercantile Exchange or index based).

     For the nine months ended September 30, 2004, the gains or losses representing the ineffective portion of our fair value hedges were not material. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. We did not have any firm commitments that no longer qualified as fair value hedge items and therefore, did not recognize an associated gain or loss.

     Interest rate fair value hedges — In October 2001, we entered into an interest rate swap to convert $250 million of fixed-rate debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on a six-month London Interbank Offered Rate (“LIBOR”), which is re-priced semiannually through 2005. In August 2003, we entered into two additional interest rate swaps to convert $100 million of fixed-rate debt securities issued in August 2000 to floating rate debt. These interest rate fair value hedges are also at a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet conditions which permit the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps no ineffectiveness will be recognized. As of September 30, 2004, the fair value of the interest rate swaps was a $10 million asset, which is included in the Consolidated Balance Sheets as Unrealized gains or losses on mark-to-market and hedging transactions with offsets to the underlying debt included in Current maturities of long term debt and Long term debt.

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     Commodity Derivatives — Trading and Marketing — The trading and marketing of energy related products and services exposes us to fluctuations in the market values of traded instruments. We manage our trading and marketing portfolio with strict policies which limit exposure to market risk and require daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate daily earnings at risk measurement.

5. Asset Retirement Obligation

     The following table summarizes changes in the asset retirement obligation, included in Other long term liabilities in the Consolidated Balance Sheets, for the nine months ended September 30, 2004 and 2003, respectively.

6. Goodwill and Other Intangibles

     Goodwill — The changes in the carrying amount of goodwill for the nine months ended September 30, 2004 are as follows:

     During the quarter ended September 30, 2004, we changed the date of our annual goodwill impairment test to August 31st from September 30th. We selected August 31st to perform our annual goodwill impairment test because this earlier date allows us to complete our goodwill impairment test within the same quarter as the testing date. In addition, the change in date will be consistent with the annual goodwill impairment test date of our majority parent. The change in testing goodwill date is not intended to delay, accelerate or avoid an impairment charge. We believe that the accounting change described above is to an alternative accounting principle which is preferable under the circumstances.

     We completed our annual goodwill impairment test as of August 31, 2004 by comparing our reporting units’ fair values to their carrying or book values. This valuation indicated reporting units’ fair values in excess of our book values; therefore, we have determined that no impairment exists.

     Other intangibles — The gross carrying amount and accumulated amortization for commodity sales and purchases contracts are as follows:

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     We recorded amortization expense associated with commodity sales and purchases contracts of $7 million in each of the nine month periods ended September 30, 2004 and 2003. The remaining amortization periods for these contracts range from 1 to 12 years with a weighted average remaining period of approximately 6 years. Estimated amortization for these contracts for the next five years is as follows:

7. Financing

     Credit Facility with Financial Institutions — On March 26, 2004, we entered into a new credit facility (the “Facility”). The Facility replaces the credit facility that matured on March 26, 2004. The Facility is used to support our commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 25, 2005; however, any outstanding borrowings under the Facility at maturity may, at our option, be converted to a one-year term loan. The Facility is a $250 million revolving credit facility, all of which can be used for letters of credit. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 53%; and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the Facility, for the four most recent quarters to interest expense for the same period) of at least 2.5 to 1 (adjusted EBITDA, is defined by the Facility, to be earnings before interest, taxes and depreciation and amortization and other adjustments). The Facility bears interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 1.125% per year or (2) the higher of (a) the JP Morgan Chase Bank prime rate plus 0.125% per year and (b) the Federal Funds rate plus 0.625% per year. At September 30, 2004, there were no borrowings or letters of credit drawn against the Facility.

     In the third quarter of 2004, $600 million of debt securities due in 2005 were reclassified from long term to short term.

     On March 28, 2003, we also entered into a $100 million funded short-term loan with a bank (the “Short-Term Loan”). The Short-Term Loan was used for working capital and other general corporate purposes. The Short-Term Loan contained an original maturity of September 30, 2003, but was repaid by August 2003 with funds generated from asset sales and operations.

     On November 3, 2003, we executed a $32 million irrevocable standby letter of credit, to be used to secure transaction exposure with a counterparty, which expired on May 15, 2004.

     Preferred Financing — Upon adoption of SFAS 150 on July 1, 2003, we reclassified our preferred members’ interest, which were mandatorily redeemable securities, of $200 million from mezzanine equity to long term debt. During 2003, subsequent to the reclassification, we redeemed the remaining $200 million. Beginning on July 1, 2003, accrued or paid distributions previously classified as dividends on the preferred members’ interest were prospectively classified as interest expense in the Consolidated Statements of Operations.

8. Commitments and Contingent Liabilities

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

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information, these proceedings will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

     General Insurance — We carry insurance coverage, with an affiliate of Duke Energy, that management believes is consistent with companies engaged in similar commercial operations with similar type properties. Our insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

     We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size.

     In the third quarter 2004, certain assets, located Onshore and Offshore in the Gulf of Mexico, were damaged as a result of Hurricane Ivan. Management is in the process of assessing the impact of these damages, however, we believe that the resulting losses will be covered by insurance, subject to applicable deductibles for property and business interruption. We do not expect this event to have a material effect on our consolidated results of operations.

     Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States and Canadian laws and regulations at the federal, state, provincial and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

     Severance Program — On October 30, 2003, we communicated a company-wide voluntary and involuntary severance program to our employees to reduce approximately 6% of our workforce. The plan was completed on December 8, 2003 and included the reduction of 160 employees over the period from December 2003 through September 2004. The severance liability that was recorded in the fourth quarter of 2003 was $6 million at December 31, 2003. The Company expensed an additional $1 million, included in General and administrative expense in the Consolidated Statement of Operations, related to this severance program during first quarter of 2004. The following table summarizes changes in the severance liability for the nine months ended September 30, 2004.

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9. Business Segments

     We operate in two principal business segments:

     (1) natural gas gathering, processing, transportation and storage, from which we generate revenues primarily by providing services such as compression, gathering, treating, processing, transportation of residue gas, storage and trading and marketing (the “Natural Gas Segment”), and

     (2) NGL fractionation, transportation, marketing and trading, from which we generate revenues from transportation fees, market center fractionation and the marketing and trading of NGLs (the “NGL Segment”).

     Intersegment activity is primarily related to the sale of NGLs from the Natural Gas Segment to the NGL Segment at market based transfer prices.

     These segments are monitored separately by management for performance against our internal forecast and are consistent with our internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Margin is a performance measure utilized by management to monitor the business of each segment. The accounting policies for the segments are the same as those described in Note 1. Foreign operations are not material and are therefore not separately identified.

     The following tables set forth our segment information.

     Three months ended September 30, 2004 (millions):

     Three months ended September 30, 2003 (millions):

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     Nine months ended September 30, 2004 (millions):

     Nine months ended September 30, 2003 (millions):

(a)

Intersegment sales represent sales of NGLs from the Natural Gas Segment to the NGL Segment at either index prices or weighted average prices of NGLs. Both measures of intersegment sales are effectively based on market conditions.

(b)

Gross margin consists of total operating revenues less purchases of natural gas and petroleum products. Gross margin is viewed as a non-Generally Accepted Accounting Principles (“GAAP”) measure under the rules of the Securities and Exchange Commission (“SEC”), but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

(c)

Includes Corporate expense items such as unallocated working capital, intercompany accounts and intangible and other assets.

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

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

     The following discussion details the material factors that affected our historical financial condition and results of operations during the three and nine months ended September 30, 2004 and 2003. This discussion should be read in conjunction with the Consolidated Financial Statements and related notes included elsewhere in this report.

Overview

     We operate in the two principal business segments of the midstream natural gas industry:

•		Natural gas gathering, processing, transportation and storage, from which we generate revenues primarily by providing services such as compression, gathering, treating, processing, transportation of residue gas, storage and trading and marketing (the “Natural Gas Segment”). In the first nine months of 2004, approximately 80% of our operating revenues prior to intersegment revenue elimination and approximately 96% of our gross margin were derived from this segment.
•		NGL fractionation, transportation, marketing and trading, from which we generate revenues from transportation fees, market center fractionation and the marketing and trading of NGLs (the “NGL Segment”). In the first nine months of 2004, approximately 20% of our operating revenues prior to intersegment revenue elimination and approximately 4% of our gross margin were derived from this segment.
•		Intersegment activity is primarily related to the sale of NGLs from the Natural Gas Segment to the NGL Segment at market based transfer prices.

     Our limited liability company agreement limits the scope of our business to the midstream industry in the United States and Canada, the marketing of NGLs in Mexico and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our board of directors.

Effects of Commodity Prices

     We are exposed to commodity prices as a result of being paid for certain services in the form of commodities rather than cash. For gathering services, we receive fees or commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, based on the type of contractual agreement. Based on our current contract mix, we have a long NGL position and a short gas position, however, the short gas position is less significant than the long NGL position. Based upon our portfolio of supply contracts, without giving effect to hedging activities that would reduce the impact of commodity price decreases, a decrease of $0.01 per gallon in the price of NGLs and $0.10 per million Btus in the average price of natural gas would result in changes in annual pre-tax net income of approximately $(19) million and $1 million, respectively. In addition, a decrease of $1 per barrel in the average price of crude oil would result in a change to annual pre-tax net income of approximately $(5) million.

     During the first nine months of 2004, approximately 80% of our gross margin is generated by commodity sensitive arrangements and approximately 20% of our gross margin (excluding hedging and including earnings of unconsolidated affiliates) is generated by fee-based arrangements.

     The midstream industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which in turn has historically been generally correlated to the price of crude oil. Although the prevailing price of natural gas has less short term significance to our operating results than the price of NGLs, in the long term, the growth of our business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production. In the past, the prices of NGLs and natural gas have been extremely volatile.

     Based on historical trends, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. We believe that future natural gas prices will

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be influenced by supply deliverability, the severity of winter and summer weather and the level of worldwide economic growth. The number of active oil and gas rigs drilling in the United States were 161 and 1,081, respectively, as of September 30, 2004, compared to 155 and 932, respectively, as of September 30, 2003. This increase is mainly attributable to recent significant increases in natural gas prices which could result in sustained increases in drilling activity during 2004 and 2005. However, energy market uncertainty could negatively impact North American drilling activity in the future. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

     Raw Natural Gas Supply Arrangements

     Our results are affected by the types of arrangements we use to process raw natural gas. We obtain access to raw natural gas and provide our midstream natural gas services principally under three types of processing contracts:

•		Percentage-of-Proceeds Contracts — Under these contracts we receive as our fee a negotiated percentage of the residue natural gas and NGL value derived from our gathering and processing activities, with the producer retaining the remainder of the value or product. These types of contracts permit us and the producers to share proportionately in commodity price changes. Under these contracts, we share in both the increases and decreases in natural gas prices and NGL prices.
•		Fee-Based Contracts — Under these contracts we receive a set fee for gathering, processing and/or treating raw natural gas. Our revenue stream from these contracts is correlated with our level of gathering and processing activity and is not directly dependent on commodity prices.
•		Wellhead Purchase and Keep-Whole Contracts — Under the terms of a wellhead purchase contract, we purchase raw natural gas from the producer at the wellhead or defined receipt point for processing and then market the resulting NGL and residue gas at market prices. Under the terms of a keep-whole processing contract, we gather raw natural gas from the producer for processing and then we market the NGLs and return to the producer residue natural gas with a Btu content equivalent to the Btu content of the raw natural gas gathered. This arrangement keeps the producer whole to the thermal value of the raw natural gas we received. Under these types of contracts the Company is exposed to the “frac spread”. The frac spread is the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL prices are higher relative to natural gas prices.

     As defined in the terms of the above arrangements we sell condensate, which is generally similar to crude oil and is produced in association with natural gas gathering and processing.

     In 2004 and 2003, we converted a portion of our keep-whole contracts to percentage-of-proceeds contracts and we amended a portion of our keep-whole contracts to add a minimum fee clause. This had the impact of reducing our exposure to frac spread.

     Our current mix of percentage-of-proceeds contracts (where we are exposed to decreases in natural gas prices) and keep-whole and wellhead purchase contracts (where we are exposed to increases in natural gas prices) helps to mitigate our exposure to changes in natural gas prices. We may use hedging, if deemed necessary, to adequately plan for cash needed for debt service, capital expenditures and tax distributions. However, we do not currently anticipate using cash flow hedges to mitigate our overall commodity positions in 2005 because management believes cash flows will be sufficient to fund the Company’s business.

     Cash Flow Hedging

     We monitor the risks associated with commodity price changes on our future operations and, historically have used various commodity instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of our assets and operations from such price risks. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” The recognition in the Consolidated Statements of Operations of the cumulative changes in the fair value of these hedge instruments reduced the results of operations by $12 million and $23 million in the third quarter of 2004 and 2003, respectively. During the first nine months of 2004 and 2003 the changes in fair value of our hedging contracts reduced results of operations by $54 million and $87 million, respectively. See “Item 3.

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Quantitative and Qualitative Disclosure About Market Risk”. The remaining term over which we are currently hedging our exposure to the variability of future cash flows is through the end of 2004. We do not currently have plans to hedge our risk to commodity exposure in 2005.

     Natural Gas Asset Based Trading and Marketing

     We actively manage commodity risk related to owned natural gas storage and pipeline assets by engaging in natural gas asset based trading and marketing. The commercial activities related to our natural gas asset based trading and marketing primarily consists of time spreads and basis spreads. A time spread is executed when the difference between the current market price of natural gas and the current futures market for natural gas exceeds our cost of storing physical gas in our owned storage facility. When this market condition exists, we inject physical gas into our storage facility and execute derivative instruments for the forward price of the gas at the higher futures market price. This time spread allows us to lock in a future profit on our gas in storage. For financial reporting purposes, the gas in storage is recorded at the lower of average cost or market until sold. The derivative instruments are recorded at fair value with changes in fair value recorded in current earnings. The difference in accounting treatment for the physical inventory and the derivative instruments subject our earnings to market volatility during the period of the time spread even though the transaction represents an economic hedge in which we have locked in a future profit.

     A basis spread is executed when the market price differential between locations on a pipeline asset exceeds our cost of transporting physical gas through our owned pipeline asset. When this market condition exists, we physically transport gas through our pipeline asset and execute derivative instruments around this differential at the higher market price. This basis spread allows us to lock in a profit on our transported gas. For financial reporting purposes, the gas in the pipeline asset is recorded at the lower of average cost or market until sold. The derivative instruments are recorded at fair value with changes in fair value recorded in current earnings. The difference in accounting treatment for the physical inventory and the derivative instruments subject our earnings to market volatility even though the transaction represents an economic hedge in which we have locked in a future profit.

Accounting Adjustments

     Certain prior period amounts have been reclassified in the Consolidated Financial Statements to conform to the current period presentation. Included in the reclassified amounts are increases in both Sales of natural gas and petroleum products and in Purchases of natural gas and petroleum products in the amounts of approximately $264 million and $723 million, for the three and nine months ended September 30, 2003, respectively. This reclassification resulted from intersegment trading activities being eliminated twice from the Consolidated Statements of Operations during the three and nine months ended September 30, 2003. Management has concluded that these reclassifications are not material to the fair presentation of the Company’s financial statements.

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Results of Operations

(a)

Gross margin consists of total operating revenues less purchases of natural gas and petroleum products. Gross margin is a non-Generally Accepted Accounting Principles (“GAAP”) measure under the rules of the Securities and Exchange Commission (“SEC”), but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales and purchases, a key component of our operations. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

(b)

EBIT consists of income from continuing operations before cumulative effect of accounting change, net interest expense and income tax expense. EBIT is a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of operations without regard to financing methods or capital structure. As an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner.

Three months ended September 30, 2004 compared with three months ended September 30, 2003

     Operating Revenues — Total operating revenues increased $473 million, or 23%, to $2,561 million in the third quarter of 2004 from $2,088 million in the same period of 2003. This increase was primarily due to the following factors:

•		$316 million increase was attributable to a $0.23 per gallon increase in average NGL prices;
•		$154 million increase was attributable to a $0.79 per MMBtu increase in average natural gas prices;
•		$24 million decrease related to lower NGL and natural gas sales volumes, partially offset by an increase related to wholesale propane marketing activity and the acquisition of gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips;
•		$20 million increase was attributable to increased condensate sales due to a $13.69 per barrel increase in average crude oil prices;
•		$11 million increase related to cash flow hedging which reduced revenues by approximately $12 million during the quarter ended September 30, 2004 and by $23 million during the quarter ended September 30, 2003;
•		$8 million decrease from trading and marketing net margin primarily due to natural gas asset based trading and marketing; and
•		$4 million increase attributable to higher transportation, storage and processing fees which was primarily due to higher fees from processing contracts.

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     Purchases of Natural Gas and Petroleum Products - Purchases of natural gas and petroleum products increased $357 million, or 20%, to $2,132 million in the third quarter of 2004 from $1,775 million in the same period of 2003. The increase was primarily due to the following factors:

•		$373 million increase due to higher average costs of raw natural gas supply which is primarily due to an increase in average NGL and natural gas prices; and
•		$18 million decrease from lower purchased raw natural gas supply volume offset by an increase related the acquisition of gathering, processing and transmission assets in Southeast New Mexico from Conoco Phillips.

     Gross Margin — Total gross margin increased $116 million, or 37% to $429 million in the third quarter of 2004 from $313 million in the same period of 2003.

     Gross margin associated with the Natural Gas Segment increased $115 million, or 38%, to $416 million in the third quarter of 2004 from $301 million in the same period of 2003, primarily as a result of the following factors:

•		$128 million increase (net of hedging) was the result of commodity sensitive processing arrangements, mainly due to higher average NGL and crude oil prices; $7 million decrease relating to lower throughput volumes;
•		$6 million decrease from trading and marketing net margin due to natural gas asset based trading and marketing;
•		$6 million increase primarily related to the acquisition of gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips; and
•		$6 million decrease related to a variety of factors including operational and commercial performance.

     Gross margin associated with the NGL Segment increased $1 million, or 8% to $13 million in the third quarter 2004 from $12 million for the same period in 2003. This increase was comprised primarily of an increase in wholesale propane marketing and NGL pipelines, offset by a decrease in trading and marketing net margin.

     NGL production during the third quarter 2004 increased 17,000 barrels per day, or 5%, to 371,000 barrels per day from 354,000 barrels per day in the same period of 2003, and natural gas transported and/or processed during the third quarter of 2004 decreased 0.1 trillion Btus per day, or 1%, to 7.4 trillion Btus per day from 7.5 trillion Btus per day during the same period of 2003. The primary cause of the increase in NGL production was processing elections associated with poor processing economics on keep-whole volumes in 2003 and the acquisition of processing assets in Southeast New Mexico in the second quarter of 2004.

     Costs and Expenses — Total costs and expenses increased $26 million, or 12%, to $250 million in the third quarter of 2004 from $224 million in the same period of 2003. This increase was primarily due to the following factors:

•		Operating and maintenance expenses increased $2 million primarily related to the acquisition of gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips;
•		Depreciation and amortization expenses increased $2 million;
•		General and administrative expenses increased $1 million; and
•		Asset impairments were $22 million in the third quarter of 2004 related to the following:

•

$9 million of the impairments was related to our periodic review of the carrying value of our assets and a planned shut down of a specific plant. We determined that these assets, which are located in Onshore and Offshore Gulf of Mexico, were impaired, therefore they were written down to their fair value. Fair value was determined based on management’s best estimates of sales value and/or

22

discounted future cash flow models. The charges associated with these impairments were recorded in the Natural Gas Segment, and

•

$13 million (offset by $7 million in minority interest income discussed below) of the impairment was related to assets that were distributed to a minority interest holder in exchange for their 42% minority interest (see Note 3 to the Consolidated Financial Statements). We determined that these assets, which are located Onshore Gulf of Mexico, were impaired, therefore they were written down to fair value. Fair value was determined based on an independent third-party valuation. The charges associated with these impairments were recorded in the Natural Gas Segment.

     Equity in Earnings of Unconsolidated Affiliates — Equity in earnings of unconsolidated affiliates decreased $7 million, or 58%, to $5 million in the third quarter of 2004 from $12 million in the same period of 2003. This reduction is primarily the result of decreased earnings from our general partner interest in TEPPCO Partners, L.P. (“TEPPCO”). TEPPCO had decreased earnings due to an impairment and other charges recorded in the third quarter of 2004.

     Impairment of Equity Method Investments — In the third quarter of 2004, we recorded an impairment totaling $23 million as Impairment of equity method investments, included in the Consolidated Statements of Operations, with an offset to Investment in unconsolidated affiliates included in the Consolidated Balance Sheets. Our investments in these assets, which are located Onshore Gulf of Mexico, were analyzed during the third quarter and determined to be impaired. As a result, these investments were written down to fair value which was determined based on management’s best estimates of sales value and/or discounted future cash flow models. The charges associated with these impairments were recorded in the NGL Segment.

     Minority Interest Income-Minority interest income was $7 million in the third quarter of 2004 compared to $1 million in the same period of 2003. The increase to $7 million in 2004 is primarily related to a minority partner’s interest in an impairment recorded in the quarter (see Costs and Expenses above for a discussion of impairment charges).

     Interest Expense, net — Interest expense, net, decreased $6 million, or 13% to $39 million in the third quarter of 2004 from $45 million in the same period of 2003. This decrease was primarily due to lower outstanding debt levels in the third quarter of 2004 compared with the third quarter of 2003.

     Income Taxes — We are structured as a limited liability company, which is a pass-through entity for United States income tax purposes. Income tax expense of $2 million in the third quarter of 2004 and 2003 is attributable to earnings associated with tax-paying subsidiaries.

     (Loss) income from Discontinued Operations - (Loss) income from discontinued operations was a loss of $23 million in the third quarter of 2004 and income of $1 million in the third quarter of 2003. (Loss) income from discontinued operations includes the impairment of an asset held for sale, the sale of the assets associated with discontinued operations and the results of such operations (see Note 3 to the Consolidated Financial Statements).

Nine months ended September 30, 2004 compared with nine months ended September 30, 2003

     Operating Revenues — Total operating revenues increased $635 million, or 10%, to $7,314 million in the first nine months of 2004 from $6,679 million in the same period of 2003. This increase was primarily due to the following factors:

•		$506 million increase was attributable to a $0.12 per gallon increase in average NGL prices;
•		$94 million increase was attributable to a $0.15 per MMBtu increase in average natural gas prices;
•		$66 million decrease related to decreased natural gas and NGL sales volumes partially offset by an increase related to wholesale propane marketing activity and the acquisition of gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips;
•		$33 million increase related to cash flow hedging which reduced revenues by approximately $54 million for the nine months ended September 30, 2004 and by $87 million for the nine months ended September 30, 2003;
•		$29 million increase from trading and marketing net margin primarily due to natural gas asset based trading and marketing;

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•		$27 million increase was attributable to increased condensate sales due to a $8.13 per barrel increase in average crude oil prices; and
•		$19 million increase attributable to higher transportation, storage and processing fees which was primarily due to higher fees from processing contracts.

     Purchases of Natural Gas and Petroleum Products - Purchases of natural gas and petroleum products increased $380 million, or 7%, to $6,144 million in the first nine months of 2004 from $5,764 million in the same period of 2003. This increase was primarily due to the following factors:

•		$435 million increase due to higher average costs of raw natural gas supply which is primarily due to an increase in average NGL and natural gas prices;
•		$48 million decrease from lower purchased raw natural gas supply, offset by an increase related to the acquisition of gathering, processing and transmission assets in Southeast New Mexico from Conoco Phillips; and
•		$8 million decrease related to expenses incurred in the first quarter of 2003 related to a contract litigation settlement.

     Gross Margin — Total Gross margin increased $255 million, or 28% to $1,170 million in the first nine months of 2004 from $915 million in the same period of 2003.

     Gross margin associated with the Natural Gas Segment increased $246 million, or 28%, to $1,126 million in the first nine months of 2004 from $880 million in the same period of 2003, primarily as a result of the following factors:

•		$225 million increase (net of hedging) was the result of commodity sensitive processing arrangements, mainly due to higher average NGL and crude oil prices;
•		$16 million decrease related to lower throughput volumes;
•		$11 million increase related to the acquisition of gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips;
•		$8 million increase was the result of $23 million of improved trading and marketing net margin offset by approximately $15 million of lower results related to physical natural gas asset based trading activity;
•		$8 million increase related to expenses incurred in the first quarter of 2003 related to a contract litigation settlement; and
•		$10 million increase related to a variety of factors including operational and commercial performance.

     Gross margin associated with the NGL Segment increased $9 million, or 26% to $44 million in the first nine months of 2004 from $35 million for the same period in 2003. This increase was comprised primarily of an increase in trading and marketing net margin.

     NGL production during the first nine months of 2004 increased 8,000 barrels per day, or 2%, to 363,000 barrels per day from 355,000 barrels per day in the same period of 2003, and natural gas transported and/or processed during the first nine months of 2004 decreased 0.2 trillion Btus per day, or 3%, to 7.3 trillion Btus per day from 7.5 trillion Btus per day during the same period of 2003.

     Costs and Expenses — Total costs and expenses increased $13 million, or 2%, to $679 million in the first nine months of 2004 from $666 million in the same period of 2003. This increase was primarily due to the following factors:

•

Operating and maintenance expenses decreased $13 million primarily related to decreased expenses of approximately $10 million related to the consolidation of a previously unconsolidated affiliate as required

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		by FIN 46R (see Note 1 to the Consolidated Financial Statements). Certain operating costs paid by us to this affiliate are now eliminated in consolidation of this affiliate;
•		Depreciation and amortization expenses increased $2 million;
•		General and administrative expenses increased $3 million; and
•		Asset impairments were $22 million in the third quarter of 2004 related to the following:

•		$9 million of the impairments was related to our periodic review of the carrying value of our assets and a planned shut down of a specific plant. We determined that these assets, which are located in Onshore and Offshore Gulf of Mexico, were impaired, therefore they were written down to their fair value. Fair value was determined based on management’s best estimates of sales value and/or discounted future cash flow models. The charges associated with these impairments were recorded in the Natural Gas Segment, and
•		$13 million (offset by $7 million in minority interest income discussed below) of the impairment was related to assets that were distributed to a minority interest holder in exchange for their 42% minority interest (see Note 3 to the Consolidated Financial Statements). We determined that these assets, which are located Onshore Gulf of Mexico, were impaired, therefore they were written down to fair value. Fair value was determined based on an independent third-party valuation. The charges associated with these impairments were recorded in the Natural Gas Segment.

     Impairment of Equity Method Investments — In the third quarter of 2004, we recorded an impairment totaling $23 million as Impairment of equity method investments, included in the Consolidated Statements of Operations, with an offset to Investment in unconsolidated affiliates included in the Consolidated Balance Sheets. Our investments in these assets, which are located Onshore Gulf of Mexico, were analyzed during the third quarter and determined to be impaired. As a result, these investments were written down to fair value which was determined based on management’s best estimates of sales value and/or discounted future cash flow models. The charges associated with these impairments were recorded in the NGL Segment.

     Minority Interest Income — Minority interest income was $7 million in the first nine months of 2004 compared to $2 million in the same period of 2003. The increase to $7 million in 2004 is primarily related to the minority partner’s interest in an impairment recorded in the quarter (see costs and expenses above for a discussion of impairment charges).

     Interest Expense, net — Interest expense, net, decreased $11 million, or 9% to $118 million in the first nine months of 2004 from $129 million in the same period of 2003. This decrease was primarily due to lower outstanding debt levels in the first nine months of 2004 compared with first nine months of 2003.

     Income Taxes — We are structured as a limited liability company, which is a pass-through entity for United States income tax purposes. Income tax expense of $7 million in the first nine months of 2004 and $4 million in the first nine months of 2003 is attributable to earnings associated with tax-paying subsidiaries.

     (Loss) income from Discontinued Operations - (Loss) income from discontinued operations was a loss of $18 million in the first nine months of 2004 and income of $36 million in the first nine months of 2003. (Loss) income from discontinued operations includes the impairment of an asset held for sale, the sale of the assets associated with discontinued operations and the results of such operations in both periods presented (see Note 3 to the Consolidated Financial Statements).

     Cumulative Effect of Change in Accounting Principles — Cumulative effect of change in accounting principles was a loss of $23 million in the first nine months of 2003. Of this amount, $18 million relates to the implementation of SFAS 143, and $5 million is due to the rescission of EITF 98-10 (see Note 1 to Consolidated Financial Statements).

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Liquidity and Capital Resources

     Liquidity is a measure of a company’s ability to access cash. We have historically addressed our long-term liquidity and capital requirements through the use of bank credit facilities and cash provided by operating activities as well as through the issuance of debt securities, when market conditions permit. Volatility in crude oil, NGL and natural gas prices and the structure of our commodity supply contracts have a direct impact on our generation and use of cash from operations due to its impact on net income as described in the Effects of Commodity Prices section above, along with the resulting changes in working capital. A material adverse change in operations or available financing may impact our ability to fund our requirements for liquidity and capital resources.

     Working Capital — Working capital is the amount by which current assets exceed current liabilities. We had a working capital deficit of $420 million as of September 30, 2004, compared to a deficit of $73 million at December 31, 2003. The change was primarily due to the reclassification in the third quarter of 2004 of $600 million of debt securities due in 2005 from long term to short term, partially offset by an increase in cash and cash equivalents of $280 million. We may retire a portion of these debt securities and refinance a portion of these debt securities during 2005.

     As of September 30, 2004, we had $323 million in cash and cash equivalents compared to $43 million as of December 31, 2003. Included in cash and cash equivalents as of September 30, 2004 was approximately $35 million held by our Canadian subsidiaries for their operations. The remaining cash balance was primarily available for general corporate purposes.

     Cash flow — Historically, one of our primary sources of capital has been net cash provided by operating activities. Net cash provided by operating activities, net cash (used in) provided by investing activities and net cash used in financing activities for the nine months ended September 30, 2004 and 2003 were as follows:

Operating Cash Flows

     The increase in net cash provided by operating activities is attributable to our net income adjusted for non-cash charges and credits and changes in working capital. The increase in net income is due largely to the favorable effects of commodity prices, net of hedging and improved results from trading and marketing activities.

     We received cash distributions from unconsolidated affiliates of $36 million in the first nine months of 2004 and $47 million in the first nine months of 2003. These distributions were in excess of earnings from unconsolidated affiliates by $22 million in the first nine months of 2004 and $11 million in the same period of 2003.

Investing Cash Flows

     The increase in cash used in investing activities was due primarily to an increase in capital expenditures. Our capital expenditures generally consist of expenditures for construction and acquisition of additional gathering systems, processing plants, fractionators and other facilities and infrastructure in addition to well connections and upgrades to our existing facilities. For the first nine months of 2004, we spent approximately $157 million on capital expenditures compared to $93 million in the first nine months of 2003. The increase is due to the acquisition of gathering, processing and transmission assets in Southeast New Mexico, partially offset by reduced well connections and plant upgrades in the first nine months of 2004, as compared to the same period in 2003. The increase in cash used in investing activities is partially offset by proceeds from the sale of discontinued operations and sales of assets of $62 million and $10 million, respectively, in the first nine months of 2004 compared to $90 million and $20 million, respectively, in the first nine months of 2003.

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     Our level of capital expenditures for acquisitions and construction and other investments depends on many factors, including industry conditions, the availability of attractive acquisition opportunities and construction projects, the level of commodity prices and competition. We expect to finance our capital expenditures with our cash on hand, cash flow from operations, asset sales, or other available sources of financing. Our capital expenditures forecast for the year ending December 31, 2004 is approximately $200 million. Depending on cash flow results, redeployment of capital from divestitures and opportunities in the marketplace, 2004 acquisition and capital expenditures may vary from the forecast.

Financing Cash Flows

     The decrease in cash used in financing activities was primarily due to the redemption of outstanding preferred members’ interest and payment of debt of $125 million and $215 million, respectively, in the first nine months of 2003, compared to the payment of dividends and distributions to members of $293 million in the first nine months of 2004.

     Based on current and anticipated levels of operations, we believe that our cash on hand and cash flow from operations, combined with borrowings available under the commercial paper program as supported by the Facility, will be sufficient to enable us to meet our current and anticipated cash operating requirements and working capital needs for the next year. Actual capital requirements, however, may change, particularly as a result of any acquisitions or distributions that we may make. Our ability to meet current and anticipated operating requirements will depend on our future performance.

     In the third quarter of 2004, $600 million of debt securities due in 2005 were reclassified from long term to short term. We may retire a portion of these debt securities and refinance a portion of these debt securities during 2005.

     Bank Financing and Commercial Paper

     On March 26, 2004, we entered into a new credit facility (the “Facility”). The Facility replaces a credit facility that matured on March 26, 2004. The Facility is used to support our commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 25, 2005; however; any outstanding borrowings under the Facility at maturity may, at our option, be converted to a one-year term loan. The Facility is a $250 million revolving credit facility, all of which can be used for letters of credit. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 53%; and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the Facility, for the four most recent quarters to interest expense for the same period) of at least 2.5 to 1 (adjusted EBITDA is defined by the Facility to be earnings before interest, taxes and depreciation and amortization and other adjustments). The Facility bears interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 1.125% per year or (2) the higher of (a) the JP Morgan Chase Bank prime rate plus 0.125% per year and (b) the Federal Funds rate plus 0.625% per year. At September 30, 2004, there were no borrowings or letters of credit drawn against the Facility.

     At September 30, 2004, we had no outstanding commercial paper. In the future, our debt levels will vary depending on our liquidity needs, capital expenditures and cash flow.

     On November 3, 2003, we executed a $32 million irrevocable standby letter of credit, to be used to secure transaction exposure with a counterparty, which expired on May 15, 2004.

     In April 2002, we filed a shelf registration statement increasing our ability to issue securities to $500 million. The shelf registration statement provides for the issuance of senior notes, subordinated notes and trust preferred securities.

     Distributions

     We are required to make quarterly distributions to Duke Energy and ConocoPhillips based on allocated taxable income. Our Limited Liability Company Agreement provides for taxable income to be allocated in accordance with the Internal Revenue Code Section 704(c). This Code section takes into account the variation between the adjusted

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tax basis and the fair market value of assets contributed to the joint venture. The required distribution is based on the highest taxable income allocated to either member, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 69.7% for Duke Energy and 30.3% for ConocoPhillips. During the nine months ended September 30, 2004, we paid distributions of $16 million based on estimated annual taxable income allocated to the members according to their respective ownership percentages. As of September 30, 2004, distributions payable of $78 million were included in Other current liabilities in the Consolidated Balance Sheets.

     In 2003, our board of directors approved a plan to consider the payment of a quarterly dividend to our members. Our board of directors may consider net income, cash flow or any other criteria deemed appropriate for determining the amount of the quarterly dividend to be paid. Our LLC Agreement restricts making distributions, which would include these dividends, except with the approval of both members. During the nine months ended September 30, 2004, with the approval of both members, we paid total dividends of $277 million to the members, allocated in accordance with their respective ownership percentages.

Contractual Obligations, Commercial Commitments and Off-Balance Sheet Arrangements

     As part of our normal business, we are a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included in the Consolidated Balance Sheets. The possibility of us having to honor our contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We record reserves if events occur that require that one be established.

     At January 1, 2004, we were the guarantor of approximately $3 million of debt for an affiliate. Assets were pledged as collateral for the debt. This debt was repaid in January 2004.

     At September 30, 2004, we have various indemnification agreements outstanding contained in asset purchase and sale agreements. These indemnification agreements generally relate to the change in environmental and tax laws or settlement of outstanding litigation. These indemnification agreements generally have terms of one to five years, although some are longer. We cannot estimate the maximum potential amount of future payments under these indemnification agreements due to the uncertainties related to changes in laws and regulation with regard to taxes, safety and protection of the environment or the settlement of outstanding litigation, which are outside our control. At September 30, 2004, we had a liability of $1 million recorded for known liabilities related to outstanding indemnification provisions.

     For an in-depth discussion of our contractual obligations and commercial commitments, see “Management’s Discussion and Analysis of Quantitative and Qualitative Disclosures about Market Risk” in our Form 10-K for the year ended December 31, 2003.

New Accounting Standards

     In May 2003, the FASB issued SFAS No. 150 (“SFAS 150”), “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS 150 requires that certain financial instruments that could previously be accounted for as equity, be classified as liabilities in the consolidated balance sheets and initially recorded at fair value. In addition to its requirements for the classification and measurement of financial instruments in its scope, SFAS 150 also requires disclosures about the nature and terms of the financial instruments and about alternative ways of settling the instruments. The provisions of SFAS 150 are effective for all financial instruments entered into or modified after May 31, 2003, and are otherwise effective at the beginning of the first interim period beginning after June 15, 2003. Upon adoption on July 1, 2003, we reclassified preferred members’ interest, which are mandatorily redeemable, of $200 million from mezzanine equity to long term debt and prospectively classified accrued or paid distributions on these securities, which had previously been classified as dividends, as interest expense. During 2003, we redeemed the remaining $200 million of these securities in cash.

     In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities” which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. We adopted the provisions of FIN 46 and its related interpretations (“FIN 46R”) in the first quarter of 2004.

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As a result, we consolidated one entity, previously accounted for under the equity method of accounting, on January 1, 2004. This entity, which is a substantive entity, had total assets of approximately $92 million as of January 1, 2004. Adoption of FIN 46R had no material effect on our consolidated results of operations, cash flows or financial position.

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

     In May 2003, the EITF reached consensus in EITF Issue No. 01-08 (“EITF 01-08”), “Determining Whether an Arrangement Contains a Lease,” to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to mandate reporting revenue as rental or leasing income that otherwise would be reported as part of product sales or service revenue. EITF 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, “Accounting for Leases.” The consensus is to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations in fiscal periods beginning on July 1, 2003. The adoption of EITF 01-08 had no material effect on our consolidated results of operations, cash flows or financial position.

     Cumulative Effect of Accounting Change - We adopted the provisions of EITF 02-03 that required new non-derivative energy trading contracts entered into after October 25, 2002 to be accounted for under the accrual accounting basis. Non-derivative energy trading contracts recorded in the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair values were adjusted to historical cost via a cumulative effect adjustment of $5 million as a reduction to earnings in the first nine months of 2003.

     We adopted the provisions of SFAS No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations,” as of January 1, 2003 which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. In accordance with the transition provisions of SFAS 143, we recorded a cumulative effect adjustment of $18 million as a reduction to earnings in the first nine months of 2003.

Acquisitions and Dispositions

     Based upon management’s current assessment of the probable disposition of certain gathering, compression and transportation assets expected to occur in 2005, we have classified these assets as held for sale and have reclassified the assets to Other current assets in the Consolidated Balance Sheet as of September 30, 2004. The book value of these assets has been written down by $23 million to $27 million, the estimated fair value less costs to sell. These assets comprise a component of the Company for purposes of reporting discontinued operations. The results of operations and cash flows related to these assets held for sale have been reclassified to discontinued operations for all periods presented. These assets were previously included in the Natural Gas Segment.

     On August 31, 2004, we acquired a 42% minority interest in Mobile Bay Processing Partners (“MBPP”) in exchange for certain assets of MBPP. MBPP is a consolidated entity, which, prior to this transaction, was owned 58% by us, and subsequent to the transaction is wholly-owned by us. As a result of the exchange, we recorded an impairment charge of $13 million (offset by $7 million in minority interest income) related to the assets that were distributed, which had a fair market value of less than book value. Minority interests in the Consolidated Balance Sheet decreased by $40 million related to this transaction. MBPP owns processing assets in the Onshore Gulf of Mexico.

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     On August 31, 2004, we purchased a 42% minority interest in Gulf Coast NGL Pipeline, LLC (“GC”) for $2 million. GC is a consolidated entity, which, prior to this transaction, was owned 58% by us, and subsequent to the transaction is wholly-owned by us. Minority interests in the Consolidated Balance Sheet decreased by $7 million related to this transaction. GC owns a 16.67% interest in two investments in unconsolidated affiliates.

     On August 31, 2004, we purchased a 12% minority interest in Dauphin Island Gathering Partners (“DIGP”) for $2 million. DIGP is a consolidated entity, which, prior to this transaction, was owned 72% by us, and subsequent to the acquisition is owned 84% by us. Minority interests in the Consolidated Balance Sheet decreased by $29 million related to this transaction. DIGP owns gathering and transmission assets in the Offshore Gulf of Mexico.

     In April 2004, we acquired gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips, a related party, for a total purchase price of approximately $80 million, consisting of $74 million in cash and the assumption of approximately $6 million of liabilities.

     In February 2004, we sold gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million, with no significant book gain or loss. These assets comprised a component of the Company for purposes of reporting discontinued operations. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented. These assets were previously included in the Natural Gas Segment.

     In the second quarter of 2003, we sold gathering, transmission and processing assets to two separate buyers for a combined sales price of approximately $90 million. These assets comprised a component of the Company for purposes of reporting discontinued operations. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented. These assets were previously included in the Natural Gas Segment.

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Item 3. Quantitative and Qualitative Disclosure about Market Risks

Risk and Accounting Policies

     We are exposed to market risks associated with commodity prices, counterparty credit, interest rates, and, to a limited extent, foreign currency exchange rates. Management has established comprehensive risk management policies and procedures to monitor and manage these market risks. Duke Energy Field Services’ Risk Management Committee (“Risk Management Committee”) is responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. The Risk Management Committee is composed of senior executives who receive regular briefings on the Company’s positions and exposures as well as periodic updates from and consultations with the Duke Energy Chief Risk Officer (CRO) and other expert resources at Duke Energy regarding market risk positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.

Commodity Price Risk

     We are exposed to the impact of market fluctuations primarily in the price of NGLs that we own as a result of our processing activities. We employ established policies and procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including forward contracts, swaps, futures and options. (See Notes 1 and 4 to the Consolidated Financial Statements.)

     Commodity Derivatives — Trading and Marketing - The risk in the commodity trading and marketing portfolios is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Value at Risk (“DVaR”) as described below. DVaR is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor the risk in the commodity trading and marketing portfolios (which includes all trading and marketing contracts not designated as hedge positions) on a monthly and annual basis. These measures include limits on the nominal size of positions and periodic loss limits.

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

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     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:

^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.

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     The following table shows the fair value of our mark-to-market portfolio as of September 30, 2004:

     The “Prices supported by quoted market prices and other external sources” category includes our New York Mercantile Exchange (“NYMEX”) swap positions in natural gas, crude oil, propane, heating oil, and unleaded gasoline. The NYMEX has currently quoted monthly natural gas prices for the next 64 months and quoted monthly crude oil prices for the next 36 months. The NYMEX has quoted monthly prices for varying periods of 18 months or less for propane, heating oil, and unleaded gasoline. In addition, this category includes our forward positions and options in natural gas and natural gas basis swaps at points for which over-the-counter (“OTC”) broker quotes are available. On average, OTC quotes for natural gas swaps extend 48 months into the future. OTC quotes for natural gas options extend 12 months into the future, on average. We value these positions against internally developed forward market price curves that are validated and recalibrated against OTC broker quotes. This category also includes “strip” transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate.

     The “Prices based on models and other valuation methods” category includes (i) the value of options not quoted by an exchange or OTC broker and (ii) the value of transactions for which an internally developed price curve was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point. In certain instances structured transactions can be decomposed and modeled by us as simple forwards and options based on prices actively quoted. Although the valuation of the simple structures might not be different from the valuation of contracts in other categories, the effective model price for any given period is a combination of prices from two or more different instruments and therefore has been included in this category due to the complex nature of these transactions.

     Hedging Strategies - We are exposed to market fluctuations in the prices of energy commodities related to natural gas gathering, processing and marketing activities. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, may use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge the value of our assets and operations from such price

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risks. Our hedging program has historically reduced the potential negative impact that commodity price changes could have on our earnings and has improved our ability to adequately plan for cash needed for debt service and capital expenditures. However, we do not currently anticipate using cash flow hedges in 2005 because management believes cash flows will be sufficient to fund our business.

     Our primary use of hedging commodity derivatives has been to hedge the commodity exposure associated with the output and production of assets we physically own. Since these contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets, liabilities or firm commitments, to the extent that the hedge relationships are effective, their market value change impacts are not recognized in current earnings. The unrealized gains or losses on these contracts are deferred in Accumulated Other Comprehensive Income (“AOCI”) for cash flow hedges or included in Other Current or Noncurrent Assets or Liabilities on the Consolidated Balance Sheets for fair value hedges of firm commitments. Amounts in AOCI are realized in earnings concurrently with the transaction being hedged. However, in instances where the hedging contract no longer qualifies for hedge accounting, amounts included in AOCI through the date of de-designation remain in AOCI until the underlying transaction actually occurs. The derivative contract (if continued as an open position) will be marked to market currently through earnings. Several factors influence the effectiveness of a hedge contract, including counterparty credit risk and using contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured each month.

     We have utilized derivative instruments not only to hedge commodity exposures, but also to hedge interest rate exposures (as discussed in the Interest Rate Risk section on page 35). As mentioned previously, the effective portion of the gains and losses for any of our hedging contracts are not recognized in earnings until the contracts mature at their future market price. Therefore, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to contract maturity for the effective portion of these hedges.

     The fair value of our qualifying hedge positions at a point in time is not necessarily indicative of the results realized when such contracts mature. The following table contains the fair value of our hedging contracts, including both commodity hedges and interest rate hedges, as of September 30, 2004: