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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 900
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 [  ]

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

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DUKE ENERGY FIELD SERVICES, LLC
FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2003

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

     All of such statements other than statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

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

	•		our ability to access the debt and equity markets, which will depend on general market conditions and our credit ratings for our debt obligations;
	•		our use of derivative financial instruments to hedge commodity and interest rate risks;
	•		the level of creditworthiness of counterparties to transactions;
	•		the amount of collateral required to be posted from time to time in our transactions;

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

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

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

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

See Notes to Consolidated Financial Statements.

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

See Notes to Consolidated Financial Statements.

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

See Notes to Consolidated Financial Statements.

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

See Notes to Consolidated Financial Statements.

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

1. General

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

2. Accounting Policies

     Consolidation — The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, after eliminating significant intercompany transactions and balances. Investments in 20% to 50% owned affiliates are accounted for using the equity method. Investments greater than 50% are consolidated unless the Company does not operate these investments and as a result does not have the ability to exercise control.

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

     Inventories — Inventories consist primarily of materials and supplies and natural gas and NGLs held in storage for transmission, marketing and sales commitments. Inventories are recorded at the lower of cost or market value using the average cost method. Historically, since January 2001, natural gas storage arbitrage inventories were marked to market. However, effective January 1, 2003, in accordance with the Financial Accounting Standard Board’s (“FASB”) Emerging Issues Task Force’s (“EITF”) rescission of Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” all gas storage inventory is now recorded at the lower of cost or market, (see “New Accounting Standards” below).

     Accounting for Hedges and Commodity Trading Activities — All derivatives not qualifying for the normal purchases and sales exemption under Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” are recorded in the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Trading and Hedging Transactions. On the date that derivative contracts are entered into, the Company designates the derivative as either trading or non-trading; as a hedge of a recognized asset, liability or firm commitment (fair value hedges); as a hedge of a forecasted transaction or future cash flows (cash flow hedges); or as a normal purchase or sale contract.

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

     When available, quoted market prices or prices obtained through external sources are used to verify a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices.

     Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating the positions held in an orderly manner over a reasonable time period under current conditions. Changes in market price 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.

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     Commodity Trading — A favorable or unfavorable price movement of any derivative contract held for trading 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 Trading and Hedging Transactions. When a contract is settled, the realized gain or loss is reclassified to a receivable or payable account. Settlement has no revenue presentation effect on the Consolidated Statements of Operations.

     See the “New Accounting Standards” section below for a discussion of the implications of EITF Issue 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” on the accounting for trading activities subsequent to October 25, 2002.

     Commodity Cash Flow Hedges — The effective portion of the change in fair value of a derivative designated and qualified as a cash flow hedge is included in the Consolidated Balance Sheets as Accumulated Other Comprehensive Income (Loss) (“AOCI”) until earnings are affected by the hedged item. Settlement amounts of cash flow hedges are removed from AOCI and recorded in the Consolidated Statements of Operations in the same accounts as the item being hedged. The Company discontinues hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative continues to be carried on the Consolidated Balance Sheets at its fair value, with subsequent changes in its fair value recognized in current-period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until earnings are affected by the hedged item, unless it is no longer probable that the hedged transaction will occur, in which case, the gains and losses that were accumulated in AOCI will be immediately recognized in current-period earnings.

     Commodity Fair Value Hedges — Changes in the fair value of a derivative that is designated and qualifies as a fair value hedge are included in the Consolidated Statements of Operations as Sales of Natural Gas and Petroleum Products and Purchases of Natural Gas and Petroleum Products, as appropriate. Changes in the fair value of the physical portion of a fair value hedge (i.e., the hedged item) are recorded in the Consolidated Statements of Operations in the same accounts as the changes in the fair value of the derivative, with offsetting amounts in the Consolidated Balance Sheets as Other Current Assets, Other Noncurrent Assets, Other Current Liabilities, or Other Long Term Liabilities, as appropriate.

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

     Income Taxes — The Company is required to make quarterly distributions to Duke Energy and ConocoPhillips based on allocated taxable income. The distributions are based on the highest taxable income allocated to either member, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 69.7% for Duke Energy and 30.3% for ConocoPhillips.

     Stock-Based Compensation — Under Duke Energy’s 1998 Long Term Incentive Plan, stock options for Duke Energy’s common stock may be granted to the Company’s key employees. The Company accounts for stock-based compensation using the intrinsic value recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and FASB Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the date of grant, no compensation cost is recognized in the accompanying Consolidated Statements of Operations. Restricted stock grants, phantom stock awards and stock-based performance awards are recorded over the required vesting period as compensation cost, based on the market value on the date of grant. (See Note 7 for pro forma disclosures using the fair value accounting method.)

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

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

     New Accounting Standards — In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 improves the accounting for certain financial instruments that, under previous guidance, issuers could account for as equity. SFAS No. 150 requires that those instruments be classified as liabilities in statements of financial position. In addition to its requirements for the classification and measurement of financial instruments in its scope, SFAS No. 150 also requires disclosures about alternative ways of settling the instruments and the capital structure of entities, all of whose shares are mandatorily redeemable. The provisions of SFAS No. 150 are effective for all financial instruments entered into or modified after May 31, 2003, and are otherwise effective at the beginning of the first interim period beginning after June 15, 2003. The Company is currently assessing SFAS No. 150 but does not anticipate that it will have a material impact on its consolidated results of operations, cash flows or financial position.

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

     In January 2003, the FASB issued Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities.” FIN 46 requires an entity to consolidate a variable interest entity if it is the primary beneficiary of the variable interest entity’s activities. The primary beneficiary is the party that absorbs a majority of the expected losses, receives a majority of the expected residual returns, or both, from the variable interest entity’s activities. FIN 46 is applicable immediately to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003. For those variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 is required to be applied in the first fiscal year or interim period beginning after June 15, 2003. FIN 46 may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 also requires certain disclosures of an entity’s relationship with variable interest entities.

     The Company shares ownership interests with other industry partners in a variety of different partnership and joint venture entities in order to share the risks and rewards of ownership in certain gas and NGL plant and pipeline assets. The Company does not provide supplemental financial support to these entities, other than the debt guarantees discussed in Note 9. In general, these entities are structured such that the voting and equity interests in these entities are consistent with the allocation of the entities’ profits and losses. The Company is continuing the process of examining all of its ownership interests to determine the necessary disclosures and procedures for complying with FIN 46. At this point, the Company does not anticipate that these entities will qualify as variable interest entities under FIN 46. However, in the event that it is determined that any such entities are variable interest

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entities, the Company believes that it would not be the primary beneficiary of such entities and thus the consolidation provisions of FIN 46 would not apply. For all of these partnership and joint venture entities, the Company believes that its maximum exposure to loss would be equal to its investment in these entities plus its potential obligations under its guarantees of unconsolidated debt. At March 31, 2003, the Company’s total investment in, plus the value of any guaranteed debt for entities that may reasonably possibly be determined to be variable interest entities, was approximately $169 million.

     In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure – an amendment of FASB Statement No. 123.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company adopted the disclosure-only provisions of SFAS No. 148 as of December 31, 2002. Adoption of the new standard had no material effect on the Company’s consolidated results of operations or financial position.

     In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor about its obligations under certain guarantees issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The Company adopted the initial recognition and measurement provisions of Interpretation No. 45 effective January 1, 2003. Adoption of the new interpretation had no material effect on the Company’s consolidated results of operations or financial position.

     In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” The Company adopted the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of the Company’s commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized.

     In June 2002, the EITF reached a partial consensus on Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Operations. The Company had previously chosen to report certain of its energy trading contracts on a gross basis, as sales in operating revenues and the associated costs recorded as purchases in costs and expenses, in accordance with prevailing industry practice.

     In October 2002, the EITF, as part of their further deliberations on Issue No. 02-03, rescinded the consensus reached in Issue No. 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133, and trading inventories that previously had been recorded at fair values, must now be recorded at the lower of cost or market and are reported on an accrual basis resulting in the recognition of earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 should be accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair values have been adjusted to the lower of historical cost or market via a cumulative-effect adjustment of $5.4 million as a reduction to 2003 earnings. In connection with the consensus reached on Issue No. 02-03, the FASB staff observed that, effective July 1, 2002, an entity should not recognize unrealized gains or losses

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at the inception of a derivative instrument unless the fair value of that instrument is evidenced by quoted market prices or current market transactions.

     In October 2002, the EITF also reached a consensus on Issue No. 02-03 that, effective for periods beginning after December 15, 2002, all gains and losses on all derivative instruments held for trading purposes should be shown on a net basis in the income statement. Gains and losses on non-derivative energy trading contracts should similarly be presented on a gross or net basis in connection with the guidance in Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Upon application of this presentation, comparative financial statements for prior periods are required to be reclassified to conform to the consensus other than for energy trading contracts that were shown on a net basis under Issue No. 98-10. Accordingly, for the quarter ended March 31, 2003, only derivative instruments that are held for trading purposes and are accounted for under mark-to-market accounting are included in trading and marketing net margin on the Consolidated Statements of Operations. For the quarter ended March 31, 2002, trading and marketing net margin also includes the net margin on non-derivative energy trading contracts (primarily gas storage inventories and the related physical purchases and sales) that no longer qualify for net presentation after the rescission of Issue No. 98-10. The new gross versus net revenue presentation requirements had no impact on operating income or net income.

     In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. The Company adopted the provisions of SFAS No. 143 as of January 1, 2003. In accordance with the transition provisions of SFAS No. 143, the Company recorded a cumulative-effect adjustment of $17.4 million as a reduction in 2003 earnings.

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

     3.     Derivative Instruments, Hedging Activities, Credit and Risk

     Commodity price risk — The Company’s principal operations of gathering, processing, transportation, marketing and trading and storage of natural gas, and the accompanying operations of fractionation, transportation, trading and marketing of NGLs create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. As an owner and operator of natural gas processing and other midstream assets, the Company has an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts entered into to purchase and process raw gas. Risk is also dependent on the types and mechanisms for sales of natural gas and natural gas liquid products produced, processed, transported or stored.

     Energy trading (market) risk — Certain of the Company’s subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments.

     Corporate economic risks — The Company enters into debt arrangements that are exposed to market risks related to changes in interest rates. The Company periodically uses interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with new debt issuances. The Company’s primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for the Company’s debt rating; (2) reducing volatility

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of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates.

     Counterparty risks — The Company sells various commodities (i.e., natural gas, NGLs and crude oil) to a variety of customers. The natural gas customers include local utilities, industrial consumers, independent power producers and merchant energy trading organizations. The NGLs customers range from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of the Company’s NGLs sales are made at market-based prices, including approximately 40% of NGLs production that is committed to ConocoPhillips and Chevron Phillips Chemical LLC, under a contract with a primary term that expires on December 31, 2014. This concentration of credit risk may affect the Company’s overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. On transactions where the Company is exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. The corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure. The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreements also provide that the failure to post collateral is sufficient cause to terminate a contract and liquidate all positions.

     Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.

     Commodity cash flow hedges — The Company uses cash flow hedges, as specifically defined by SFAS No. 133, to reduce the potential negative impact that commodity price changes could have on the Company’s earnings, and its ability to adequately plan for cash needed for debt service, dividends, capital expenditures and tax distributions. The Company’s primary corporate hedging goals include maintaining minimum cash flows to fund debt service, dividends, production replacement, maintenance capital projects and tax distributions; and retaining a high percentage of potential upside relating to price increases of NGLs.

     The Company uses natural gas, crude oil and NGL swaps and options to hedge the impact of market fluctuations in the price of NGLs, natural gas and other energy-related products. For the three months ended March 31, 2003, the Company recognized a net loss of $39.5 million, of which a $2.2 million gain represented the total ineffectiveness of all cash flow hedges and a $41.7 million loss represented the total derivative settlements. No derivative gains or losses were reclassified from OCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

     Gains and losses on derivative contracts that are reclassified from accumulated OCI to current period earnings are included in the line item in which the hedged item is recorded. As of March 31, 2003, $51.5 million of the deferred net losses on derivative instruments accumulated in OCI are expected to be reclassified into earnings during the next 12 months as the hedge transactions occur; however, due to the volatility of the commodities markets, the corresponding value in OCI is subject to change prior to its reclassification into earnings. The maximum term over which the Company is hedging its exposure to the variability of future cash flows is three years.

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

     For the three months ended March 31, 2003, the gains or losses representing the ineffective portion of the Company’s fair value hedges were not significant. All components of each derivative’s gain or loss are included in

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the assessment of hedge effectiveness, unless otherwise noted. The Company did not have any firm commitments that no longer qualified as fair value hedge items and therefore, did not recognize an associated gain or loss.

     Interest rate fair value hedge — In October 2001, the Company entered into an interest rate swap to convert the fixed interest rate of $250.0 million of debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on a six-month London Interbank Offered Rate (“LIBOR”), which is re-priced semiannually through 2005. The swap meets conditions which permit the assumption of no ineffectiveness, as defined by SFAS No. 133. As such, for the life of the swap no ineffectiveness will be recognized. As of March 31, 2003, the fair value of the interest rate swap of $12.8 million was included in the Consolidated Balance Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions with an offset to the underlying debt included in Long Term Debt.

     Commodity Derivatives — Trading and Marketing — The trading of energy related products and services exposes the Company to the fluctuations in the market values of traded instruments. The Company manages its traded instrument 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 a daily earnings at risk measurement.

4. Asset Retirement Obligations

     SFAS No. 143,“Accounting for Asset Retirement Obligations.” In June 2001, the FASB issued SFAS No. 143 which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. The Company’s asset retirement obligations relate primarily to the retirement of certain gathering pipelines and processing facilities, obligations related to right-of-way agreements and contractual leases for land use.

     SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.

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

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

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

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     The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The reconciliation of the asset retirement obligation for the three months ended March 31, 2003 is shown in the following table.

5. Financing

     Credit Facility with Financial Institutions — On March 28, 2003, the Company entered into a new credit facility (the “New Facility”). The New Facility replaces the credit facility that matured on March 28, 2003. The New Facility is used to support the Company’s commercial paper program and for working capital and other general corporate purposes. The New Facility matures on March 26, 2004, however; any outstanding loans under the New Facility at maturity may, at the Company’s option, be converted to a one-year term loan. The New Facility is a $350.0 million revolving credit facility, of which $100.0 million can be used for letters of credit. The New Facility requires the Company to maintain at all times a debt to total capitalization ratio of less than or equal to 53%; and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of EBITDA for the four most recent quarters to interest expense for the same period) of at least 2.5 to 1 (see Note 8 for definition of EBITDA); and contains certain restrictions applicable to dividends and other payments to the Company’s members. The New Facility bears interest at a rate equal to, at the Company’s option and based on the Company’s current debt rating, either (1) LIBOR plus 1.25% per year or (2) the higher of (a) the JP Morgan Chase Bank prime rate and (b) the Federal Funds rate plus 0.50% per year. At March 31, 2003, there were no borrowings against the New Facility.

     On March 28, 2003, the Company also entered into a $100.0 million funded short-term loan with Bank One, NA (the “Short-Term Loan”). The Short-Term Loan is used for working capital and other general corporate purposes. The Short-Term Loan matures on September 30, 2003, and may be prepaid at any time. The Short-Term Loan has the same financial covenants as the New Facility. The Short-Term Loan bears interest at a rate equal to, at the Company’s option, either (1) LIBOR plus 1.35% per year or (2) the higher of (a) the Bank One, NA prime rate and (b) the Federal Funds rate plus 0.50% per year. The Company’s management believes our cash flows and the New Facility will be adequate to meet our liquidity needs subsequent to the maturity of the Short-Term Loan. As such, the Company does not plan to refinance the Short-Term Loan when it matures.

6. Commitments and Contingent Liabilities

     The midstream natural gas industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. A number of these cases are now being brought as class actions. The Company and its subsidiaries are currently named as defendants in some of these cases. Management believes the Company and its subsidiaries have meritorious defenses to these cases, and therefore will continue to defend them vigorously. However, these class actions can be costly and time consuming to defend. Management believes that the final disposition of these proceedings will not have a material adverse effect on the consolidated results of operations or financial position of the Company.

     On September 18, 2001, General Gas Company, LP (“GGC”) filed a lawsuit against the Company claiming damages for breach of contract under a Gas Purchase and Processing Agreement. The Company then filed counterclaims against GGC on related contract issues. On January 28, 2003, the Company entered into a Compromise and Settlement Agreement whereby the Company agreed to acquire GGC for $16.5 million, payable in equal installments over three years, beginning on the settlement date. The Compromise and Settlement Agreement

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settles all claims between the parties. As a result of the Compromise and Settlement Agreement, the Company capitalized $6.2 million associated with acquired gas supply contracts, recorded a charge to natural gas purchases of $8.1 million and a $0.9 million charge to other current liabilities in the first quarter of 2003.

7. Stock-Based Compensation

     The Company accounts for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” and the FASB Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” Since the exercise price for all stock options granted under those plans was equal to the market value of the underlying common stock on the date of grant, no compensation cost is recognized in the accompanying Consolidated Statements of Operations. Restricted stock grants, phantom stock awards and Company performance awards are recorded over the required vesting period as compensation cost, based on the market value on the date of the grant. The following disclosures reflect the provisions of SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of FASB Statement No. 123.”

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

8. Business Segments

     The Company operates in two principal business segments as follows: (1) natural gas gathering, compression, treatment, processing, transportation, marketing and trading and storage, and (2) NGL fractionation, transportation, marketing and trading. These segments are monitored separately by management for performance against its internal forecast and are consistent with the Company’s internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Margin, earnings before interest, taxes, depreciation and amortization (“EBITDA”) and earnings before interest and taxes (“EBIT”) are the performance measures used by management to monitor the business of each segment. The accounting policies for the segments are the same as those described in Note 2. Foreign operations are not material and are therefore not separately identified.

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

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9. Guarantor’s Obligations Under Guarantees

     At March 31, 2003, the Company was the guarantor of approximately $97.3 million of debt associated with non-consolidated entities, of which $84.6 million is related to our 33.33% ownership interest in Discovery Producer Services, LLC, (“Discovery”) and $12.7 million is related to our 50.0% ownership interest in GPM Gas Gathering, LLC (“GGG”). The guaranteed debt related to Discovery is due December 31, 2003, and is expected to be refinanced. The guaranteed debt related to GGG is scheduled to be repaid in full by January 31, 2004. In the event that the unconsolidated subsidiaries default on the debt payments, the Company would be required to pay the debt. Assets of the unconsolidated subsidiaries are pledged as collateral for the debt. At March 31, 2003, the Company had no liability recorded for the guarantees of the debt associated with the unconsolidated subsidiaries.

     The Company periodically enters into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation and other liabilities related to the assets being acquired or divested. The survival periods on these indemnification provisions generally have terms of one to five years, although some are longer. The Company cannot estimate the maximum potential amount of future payments under these indemnification provisions due to the contingent nature of these liabilities. In addition, many of these indemnification provisions do not contain any limits on potential liability. At March 31, 2003, we had no liability recorded for these outstanding indemnification provisions.

10. Accounting Adjustments

     During 2002, the Company completed a comprehensive account reconciliation project to review and analyze its balance sheet accounts. This account reconciliation project identified the following five categories where account adjustments were necessary: operating expense accruals; gas inventory adjustments; gas imbalances; joint venture and investment account reconciliation; and other balance sheet accounts. As a result of this account reconciliation project, the Company recorded numerous adjustments in 2002. For the quarter ended March 31, 2002, adjustments totaling approximately $11 million may be related to corrections of accounting errors in prior periods. However,

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management has determined that the charges related to error corrections are immaterial both individually and in the aggregate on both a quantitative and qualitative basis to the trends in the financial statements for the periods presented, the prior periods affected and to a fair presentation of the Company’s financial statements. In addition, numerous items identified in the account reconciliation project resulted from system conversions and otherwise unsupportable balance sheet amounts. Due to the nature of certain of these account reconciliation adjustments, it would be impractical to determine what periods such adjustments relate to. Accordingly, the corrections were made in the first quarter 2002 financial statements.

11. Subsequent Events

     In April and May 2003, the Company entered into purchase and sale agreements with two buyers to sell various gathering, transmission and processing assets, plus a minority interest in a partnership owning a gas processing plant, for a total sales price of $91 million, plus or minus various adjustments that will be made at closing. At March 31, 2003, the book value of these assets was approximately $66 million. Total sales and operating income associated with these assets for the three months ended March 31, 2003 were $93.5 million and $3.6 million, respectively; for the three months ended March 31, 2002, sales and operating income totaled $36.7 and $(0.1) million, respectively. The Company anticipates closing these transactions on June 30, 2003. One of these sales is subject to various regulatory approvals.

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

     The following discussion details the material factors that affected our historical financial condition and results of operations during the three months ended March 31, 2003 and 2002. This discussion should be read in conjunction with the Consolidated Financial Statements and related notes included elsewhere in this report.

Overview

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

	•		natural gas gathering, processing, transportation and storage, from which we generate revenues primarily by providing services such as compression, gathering, treating, processing, transportation of residue gas, storage, and trading and marketing (the “Natural Gas Segment”). In the first quarter of 2003, approximately 84% of our operating revenues prior to intersegment revenue elimination and approximately 95% of our gross margin were derived from this segment.
	•		NGLs fractionation, transportation, marketing and trading, from which we generate revenues from transportation fees, market center fractionation and the marketing and trading of NGLs (the “NGLs Segment”). In the first quarter of 2003, approximately 16% of our operating revenues prior to intersegment revenue elimination and approximately 5% of our gross margin were derived from this segment.

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

Effects of Commodity Prices

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

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     We are also exposed to changes in commodity prices as a result of our NGL and natural gas trading activities. NGL trading includes trading and storage at the Mont Belvieu, Texas and Conway, Kansas NGL market centers to manage our price risk and provide additional services to our customers. Natural gas trading activities are supported by our ownership of a natural gas storage facility and various intrastate pipelines. We undertake these activities through the use of fixed forward sales, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. We also execute natural gas and NGL proprietary trades based upon our knowledge and expertise obtained through the operation of our assets and our position as a leading NGL marketer.

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

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

     We generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, the relationship or correlation between crude oil value and NGL prices declined significantly during 2001 and 2002. In late 2002, this relationship strengthened and remained near historical trend levels during the first quarter of 2003.

     We believe that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. The price increases in crude oil, NGLs and natural gas experienced during 2000 and first half of 2001 spurred increased natural gas drilling activity. However, a decline in commodity prices in late 2001, continuing into 2002, negatively affected drilling activity. The average number of active rigs drilling in North America increased to 1,394 during the first quarter of 2003 from 1,201 during the first quarter of 2002. This increase is mainly attributable to recent significant increases in natural gas prices which could result in sustained increases in drilling activity during 2003. However, energy market uncertainty could negatively impact North American drilling activity in the short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

     To better address the risks associated with volatile commodity prices, we employ a comprehensive commodity price risk management program. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge the value of our assets and operations from such price risks. See “Item 3. Quantitative and Qualitative Disclosure About Market Risk.” Our first quarter 2003 and first quarter 2002 results of operations include a hedging loss of $39.5 million and a gain of $7.4 million, respectively.

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Results of Operations

Three months ended March 31, 2003 compared with three months ended March 31, 2002

     Gross Margin — Gross margin increased $62.4 million or 25% to $311.0 million in the first quarter of 2003 from $248.6 million in 2002. Of this increase, approximately $137 million (net of hedging) was the result of a $.27 per gallon increase in average NGL prices. These increases were partially offset by approximately $62 million due to a $4.27 per million British thermal units (“Btus”) increase in natural gas prices. These price changes yielded average NGL prices of $.58 per gallon and natural gas prices of $6.59 per million Btus as compared with $.31 per gallon and $2.32 per million Btus during the same period in 2002.

     Gross margin associated with the Natural Gas Segment increased $63.1 million, or 27%, to $295.6 million from $232.5 million, mainly as a result of higher commodity prices. Commodity sensitive processing arrangements accounted for approximately $75 million (net of hedging) of this increase due mainly to the $.27 per gallon increase in average NGL prices offset by the $4.27 per million Btu increase in natural gas prices. Offsetting this increase were decreases due to trading and marketing net margin of a negative $32.8 million associated with derivative settlements and marked to market value of unsettled contracts related to our gas trading and marketing activities. Natural gas trading and marketing net margin excludes approximately $20 million realized during the first quarter of 2003 on the Company’s natural gas asset based trading activity which, prior to January 1, 2003, was recorded in trading and marketing net margin. As a result of the rescission of EITF 98-10, this activity is now presented on a gross basis in gas sales and purchases (see Note 2 to Consolidated Financial Statements).

     During the first quarter of 2003, the Company elected to reduce levels of keep-whole processing activities from time to time due to less profitable processing margins. This resulted in lower NGL production and natural gas transported and/or processed. NGL production during the first quarter of 2003 decreased 13,400 barrels per day, or 3%, to 375,200 barrels per day from 388,600 barrels per day during the first quarter of 2002, and natural gas transported and/or processed decreased 0.4 trillion Btus per day, or 5%, to 8.0 trillion Btus per day from 8.4 trillion Btus per day.

     Gross margin associated with the NGLs Segment decreased $0.6 million, or 4% to $15.5 million in the first quarter of 2003 from $16.1 million in the same period of 2002. Decreases of $8.7 million resulting from trading and marketing net margin were offset by increases in northeast wholesale propane marketing and terminals of $3.6 million, sale of inventory resulting from renegotiation of certain pipeline operating agreements of $1.0 million and higher margins from other NGL assets.

     Costs and Expenses — Operating and maintenance expenses increased $13.2 million (excluding $11 million in first quarter 2002 accounting adjustments – see Note 10 to Consolidated Financial Statements), or 14%, to $110.2 million in the first quarter of 2003 from $97.0 million in the same period of 2002. Contributing to this increase were

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increased expenditures for facility maintenance and pipeline repair of $5 million, environmental compliance of $3 million, and accretion expense associated with SFAS No. 143 implementation (see Note 2 and Note 4 to Consolidated Financial Statements) of $1 million. General and administrative expenses increased $0.2 million, or 1%, to $39.4 million in the first quarter of 2003, from $39.2 million in the same period of 2002.

     Depreciation and amortization expense increased $3.8 million, or 5%, to $77.6 million in the first quarter of 2003 from $73.8 million in the same period of 2002. This increase was due primarily to ongoing capital expenditures for well connections, facility maintenance and enhancements, and the implementation of SFAS No. 143.

     Other costs and expenses decreased $5.3 million to a credit of $0.1 million in the first quarter of 2003 from expense of $5.2 million in the first quarter of 2002. This decrease is due primarily to the first quarter 2002 accounting adjustment for the recognition of a loss on the sale of assets associated with a partnership investment (see Note 10 to Consolidated Financial Statements).

     Equity in Earnings of Unconsolidated Affiliates — Equity in earnings of unconsolidated affiliates increased $6.0 million, or 98%, to $12.1 million in the first quarter of 2003 from $6.1 million in the first quarter of 2002. This increase is primarily the result of increased earnings from our general partnership interest in TEPPCO of $3.8 million and the 2002 acquisition of an interest in the Discovery Pipeline located in offshore Gulf of Mexico of $2.8 million.

     Interest Expense — Interest expense decreased $0.6 million, or 1%, to $42.7 million in the first quarter of 2003 from $43.3 million in the same period of 2002. This decrease was primarily the result of lower outstanding debt levels.

     Income Taxes — The Company is structured as a limited liability company, which is a pass-through entity for U.S income tax purposes. First quarter 2003 income tax expenses decreased $0.5 million to $1.8 million in the first quarter of 2003 from $2.3 million in the same period of 2002 due primarily to lower earnings associated with tax-paying subsidiaries.

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

     Net Income — Net income increased $45.7 million to $28.7 million in the first quarter of 2003 from a loss of $17.0 million in the first quarter of 2002. This increase was largely the result of higher NGL prices offset by higher natural gas prices, hedging activity, and the cumulative effects of changes in accounting principles.

Liquidity and Capital Resources

     As of March 31, 2003, we had $36.2 million in cash and cash equivalents compared to $24.8 million as of December 31, 2002. Our working capital was a $203.9 million deficit as of March 31, 2003, compared to a $306.2 million deficit as of December 31, 2002. We rely upon cash flows from operations and borrowings to fund our liquidity and capital requirements. A material adverse change in operations or available financing may impact our ability to fund our current liquidity and capital resource requirements.

Operating Cash Flows

     During the first quarter of 2003, funds of $61.0 million were provided by operating activities, a decrease of $38.2 from $99.2 million in the first quarter 2002. The decrease is primarily due to changes in working capital balances, unrealized mark-to-market and hedging activity offset by an increase in net income.

     Price volatility in crude oil, NGLs and natural gas prices has a direct impact on our use and generation of cash from operations.

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Investing Cash Flows

     During the first quarter of 2003, funds of $17.8 million were used in investing activities, a decrease of $80.0 million from $97.8 million in the first quarter of 2002. Our capital expenditures consist of expenditures for construction of additional gathering systems, processing plants, fractionators and other facilities and infrastructure in addition to well connections and upgrades to our existing facilities and acquisitions. For the first quarter of 2003, we spent approximately $37.1 million on capital expenditures compared to $106.8 million in the first quarter of 2002.

     Our level of capital expenditures for acquisitions and construction depends on many factors, including industry conditions, the availability of attractive acquisition opportunities and construction projects, the level of commodity prices and competition. We expect to finance our capital expenditures with our cash on hand, cash flow from operations and borrowings available under our commercial paper program, our credit facilities or other available sources of financing.

     Investments in unconsolidated affiliates provided $14.3 million in cash distributions to us during the first quarter of 2003.

Financing Cash Flows

     On March 28, 2003, we entered into a new credit facility (the “New Facility”). The New Facility replaces the credit facility that matured on March 28, 2003. The New Facility is used to support our commercial paper program and for working capital and other general corporate purposes. The New Facility matures on March 26, 2004, however; any outstanding loans under the New Facility at maturity may, at our option, be converted to a one-year term loan. The New Facility is a $350.0 million revolving credit facility, of which $100.0 million can be used for letters of credit. The New 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 EBITDA for the four most recent quarters to interest expense for the same period) of at least 2.5 to 1 (see Note 8 for definition of EBITDA); and contains certain restrictions applicable to dividends and other payments to our members. The New Facility bears interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 1.25% per year or (2) the higher of (a) the JP Morgan Chase Bank prime rate and (b) the Federal Funds rate plus 0.50% per year. At March 31, 2003, there were no borrowings against the New Facility.

     On March 28, 2003, we also entered into a $100.0 million funded short-term loan with Bank One, NA (the “Short-Term Loan”). The Short-Term Loan is used for working capital and other general corporate purposes. The Short-Term Loan matures on September 30, 2003, and may be prepaid at any time. The Short-Term Loan has the same financial covenants as the New Facility. The Short-Term Loan bears interest at a rate equal to, at our option, either (1) LIBOR plus 1.35% per year or (2) the higher of (a) the Bank One, NA prime rate and (b) the Federal Funds rate plus 0.50% per year. We believe that our cash flows and the existing New Facility will be adequate to meet our liquidity needs subsequent to the maturity of the Short-Term Loan. As such, we do not plan to refinance the Short-Term Loan when it matures.

     At March 31, 2003, we had $84.4 million in outstanding commercial paper, with maturities ranging from one day to 29 days and annual interest rates ranging from 1.53% to 1.55%. At no time did the amount of our outstanding commercial paper exceed the available amount under the New Facility. In the future, our debt levels will vary depending on our liquidity needs, capital expenditures and cash flow.

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

     Based on current and anticipated levels of operations, we believe that our cash on hand and cash flow from operations, combined with borrowings available under the commercial paper program and the New Facility, will be sufficient to enable us to meet our current and anticipated cash operating requirements and working capital needs for

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the next year. Actual capital requirements, however, may change, particularly as a result of any acquisitions that we may make. Our ability to meet current and anticipated operating requirements will depend on our future performance.

Contractual Obligations and Commercial Commitments

     As part of our normal business, we are a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of us having to honor our contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We would record a reserve if events occurred that required that one be established. See Note 9 to the Consolidated Financial Statements for more information on guarantee obligations.

     At March 31, 2003, we were the guarantor of approximately $97.3 million of debt associated with nonconsolidated entities, of which $84.6 million related to our 33.33% ownership interest in Discovery Producer Services, LLC, (“Discovery”) and $12.7 million is related to our 50.0% ownership interest in GPM Gas Gathering, LLC (“GGG”). The guaranteed debt related to Discovery is due December 31, 2003, and is expected to be refinanced. The guaranteed debt related to GGG is scheduled to be repaid in full by January 31, 2004. In the event that the unconsolidated subsidiaries default on the debt payments, we would be required to pay the debt. Assets of the unconsolidated subsidiaries are pledged as collateral for the debt. At March 31, 2003, we had no liability recorded for the guarantees of the debt associated with the unconsolidated subsidiaries.

     The Company periodically enters into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation and other liabilities related to the assets being acquired or divested. The survival periods on these indemnification provisions generally have terms of one to five years, although some are longer. The Company cannot estimate the maximum potential amount of future payments under these indemnification provisions due to the contingent nature of these liabilities. In addition, many of these indemnification provisions do not contain any limits on potential liability. At March 31, 2003, we had no liability recorded for these outstanding indemnification provisions.

New Accounting Standards

     In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 improves the accounting for certain financial instruments that, under previous guidance, issuers could account for as equity. SFAS No. 150 requires that those instruments be classified as liabilities in statements of financial position. In addition to its requirements for the classification and measurement of financial instruments in its scope, SFAS No. 150 also requires disclosures about alternative ways of settling the instruments and the capital structure of entities, all of whose shares are mandatorily redeemable. The provisions of SFAS No. 150 are effective for all financial instruments entered into or modified after May 31, 2003, and are otherwise effective at the beginning of the first interim period beginning after June 15, 2003. The Company is currently assessing SFAS No. 150 but does not anticipate that it will have a material impact on its consolidated results of operations, cash flows or financial position.

     In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 149 clarifies the discussion around initial net investment, clarifies when a derivative contains a financing component, and amends the definition of an underlying to conform it to language used in FIN 45. In addition, SFAS No. 149 also incorporates certain of the Derivative Implementation Group Implementation Issues. The provisions of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The guidance should be applied to hedging relationships on a prospective basis. We are currently assessing SFAS No. 149 but do not anticipate that it will have a material impact on our consolidated results of operations, cash flows or financial position.

     In January 2003, the FASB issued Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities.” FIN 46 requires an entity to consolidate a variable interest entity if it is the primary beneficiary of the variable interest entity’s activities. The primary beneficiary is the party that absorbs a majority of the expected losses, receives a majority of the expected residual returns, or both, from the variable interest entity’s activities. FIN 46 is applicable immediately to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003. For those variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 is required to be applied in the first fiscal year or interim period beginning after June 15, 2003. FIN 46 may be applied prospectively with a cumulative-effect adjustment as of the date it is first

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applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 also requires certain disclosures of an entity’s relationship with variable interest entities.

     We share ownership interests with other industry partners in a variety of different partnership and joint venture entities in order to share the risks and rewards of ownership in certain gas and NGL plant and pipeline assets. We do not provide supplemental financial support to these entities, other than the debt guarantees discussed in Note 9. In general, these entities are structured such that the voting and equity interests in these entities are consistent with the allocation of the entities’ profits and losses. We are continuing the process of examining all of our ownership interests to determine the necessary disclosures and procedures for complying with FIN 46. At this point, we do not anticipate that these entities will qualify as variable interest entities under FIN 46. However, in the event that it is determined that any such entities are variable interest entities, we believe that we would not be the primary beneficiary of such entities and thus the consolidation provisions of FIN 46 would not apply. For all of these partnership and joint venture entities, we believe that our maximum exposure to loss would be equal to our investment in these entities plus our potential obligations under our guarantees of unconsolidated debt. At March 31, 2003, our total investment in, plus the value of any guaranteed debt for entities that may reasonably possibly be determined to be variable interest entities, was approximately $169 million.

     In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure – an amendment of FASB Statement No. 123.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. We adopted the disclosure-only provisions of SFAS No. 148 as of December 31, 2002. Adoption of the new standard had no material effect on our consolidated results of operations or financial position.

     In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” which elaborates on the disclosures to be made by a guarantor about its obligations under certain guarantees issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. We adopted the initial recognition and measurement provisions of Interpretation No. 45 effective January 1, 2003. Adoption of the new interpretation had no material effect on our consolidated results of operations or financial position.

     In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” We adopted the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of our commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized.

     In June 2002, the EITF reached a partial consensus on Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Operations. We had previously chosen to report certain of its energy trading contracts on a gross basis, as sales in operating revenues and the associated costs recorded as purchases in costs and expenses, in accordance with prevailing industry practice. The amounts in the comparative Consolidated Statements of Operations have been reclassified to conform to the 2003 presentation of all amounts on a net basis.

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     In October 2002, the EITF, as part of their further deliberations on Issue No. 02-03, rescinded the consensus reached in Issue No. 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133, and trading inventories that previously had been recorded at fair values, must now be recorded at the lower of cost or market and are reported on an accrual basis resulting in the recognition of earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 should be accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair values have been adjusted to the lower of historical cost or market via a cumulative-effect adjustment of $5.4 million as a reduction to 2003 earnings. In connection with the consensus reached on Issue No. 02-03, the FASB staff observed that, effective July 1, 2002, an entity should not recognize unrealized gains or losses at the inception of a derivative instrument unless the fair value of that instrument is evidenced by quoted market prices or current market transactions.

     In October 2002, the EITF also reached a consensus on Issue No. 02-03 that, effective for periods beginning after December 15, 2002, all gains and losses on all derivative instruments held for trading purposes should be shown on a net basis in the income statement. Gains and losses on non-derivative energy trading contracts should similarly be presented on a gross or net basis in connection with the guidance in Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Upon application of this presentation, comparative financial statements for prior periods are required to be reclassified to conform to the consensus other than for energy trading contracts that were shown on a net basis under Issue No. 98-10. Accordingly, for the quarter ended March 31, 2003, only derivative instruments that are held for trading purposes and are accounted for under mark-to-market accounting are included in trading and marketing net margin on the Consolidated Statements of Operations. For the quarter ended March 31, 2002, trading and marketing net margin also includes the net margin on non-derivative energy trading contracts (primarily gas storage inventories and the related physical purchases and sales) that no longer qualify for net presentation after the rescission of Issue No. 98-10. The new gross versus net revenue presentation requirements had no impact on operating income or net income.

     In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. We adopted the provisions of SFAS No. 143 as of January 1, 2003. In accordance with the transition provisions of SFAS No. 143, we recorded a cumulative-effect adjustment of $17.4 million as a reduction in 2003 earnings.

Subsequent Events

     In April and May 2003, we entered into purchase and sale agreements with two buyers to sell various gathering, transmission and processing assets, plus a minority interest in a partnership owning a gas processing plant, for a total sales price of $91 million, plus or minus various adjustments that will be made at closing. At March 31, 2003, the book value of these assets was approximately $66 million. Total sales and operating income associated with these assets for the three months ended March 31, 2003 were $93.5 million and $3.6 million, respectively; for the three months ended March 31, 2002, sales and operating income totaled $36.7 and $(0.1) million, respectively. We anticipate closing these transactions on June 30, 2003. One of these sales is subject to various regulatory approvals.

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Item 3. Quantitative and Qualitative Disclosure about Market Risks

Risk Policies

     We are exposed to market risks associated with commodity prices, credit exposure, interest rates, and, to a limited extent, foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Duke Energy Field Services’ Risk Management Committee 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 commodity price risk and various other risks, including monitoring exposure limits.

Commodity Price Risk

     We are exposed to the impact of market fluctuations primarily in the price of NGLs that we own as a result of our processing activities. We employ established policies and procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including forward contracts, swaps and options for non-trading activity (primarily hedge strategies). (See Notes 2 and 3 to the Consolidated Financial Statements.)

     Commodity Derivatives — Trading — The risk in the commodity trading portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk (“DER”) as described below. DER is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor the risk in the commodity trading portfolio (which includes all trading 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.

     DER computations are based on a historical simulation, which uses price movements over an eleven 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, gas and other energy-related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. The Company’s DER amounts for commodity derivatives instruments held for trading purposes are shown in the following table.

Daily Earnings at Risk (in thousands)

     DER is an estimate based on historical price volatility. Actual volatility can exceed predicted results. DER also assumes a normal distribution of price changes, thus if the actual distribution is not normal, the DER may understate or overstate actual results. DER 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 DER to measure risk where market data information is limited. In the current DER methodology, options are modeled in a manner equivalent to forward contracts which may understate the risk.

     Our exposure to commodity price risk is influenced by a number of factors, including contract size, length of contract, market liquidity, location and unique or specific contract terms. The unrealized fair value of trading and marketing instruments outstanding at March 31, 2003 and December 31, 2002 was a gain of $7.7 million and a loss of $28.0 million respectively.

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     The fair value of these contracts is expected to be realized in future periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events that could impact the amount and/or realization of these values. At March 31, 2003 we held cash or letters of credit of $50.6 million to secure such future performance, and had $20.7 million deposited with counterparties.

     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 exceeds 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 and market risk and administration costs are used to adjust the fair value of the contract to the gain or loss ultimately recognized in the Consolidated Statements of Operations.

     The following table shows the fair value of our trading portfolio as of March 31, 2003.