UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

____________________

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)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]x No [   ]o

DUKE ENERGY FIELD SERVICES, LLC
FORM 10-Q FOR THE QUARTER ENDED MARCH 31,SEPTEMBER 30, 2002

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 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;

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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;

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	•		the timing and extent of changes in commodity prices, interest 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; and
	•		the effect of accounting policies 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.

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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 Condensed Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) INCOME
(Unaudited)
(In Thousands)

See Condensed Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In Thousands)

See Condensed Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In Thousands)

See Condensed 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 midstream natural gas gathering, processing, marketing and natural gas liquids industries. The Company operates in the two principal segments of the midstream natural gas industry of (1) natural gas gathering, processing, transportation, marketing 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 (“Conoco Phillips”) 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. 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 periods.

     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 Activities —— All derivatives 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 swaps or optionderivative contracts are entered into, the Company designates the derivative as either held for trading (trading instruments); 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 leaves the derivative undesignated and marks it to market.

     For hedge contracts, the Company formally assesses, both at the hedge contractscontract’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 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.

     Commodity Trading — A favorable or unfavorable price movement of any derivative contract held for trading purposes is reported as Purchases of Natural GasTrading and Petroleum ProductsMarketing 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 to sell is physically settled, the fair value entries are reversed and the gross amount invoiced to the customer is included as Sales of Natural Gas and Petroleum Products in the Consolidated Statements of Operations. Similarly, when a contract to purchase is physically settled, the purchase price is included as Purchases of Natural Gas and Petroleum Products in the Consolidated Statements of Operations. If a contract is not physically settled, the unrealizedrealized gain or unrealized loss in the Consolidated Balance

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Sheets is reclassified to a receivable or payable account. For income statement purposes, financial settlement has no net operating incomerevenue presentation effect on the Consolidated Statements of Operations.

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See the “New Accounting Standards” section below for a discussion of the implications of the Financial Accounting Standards Board’s (FASB) Emerging Issues Task Force (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 prospectively.

     Commodity Cash Flow Hedges — The effective portion of the change in fair value of a derivative designated and qualified as a cash flow hedge are included in the Consolidated Statements of Comprehensive Income (Loss) Income as Other Comprehensive Income (Loss) Income (“OCI”) until earnings are affected by the hedged item. Settlement amounts of cash flow hedges are removed from OCI 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 OCI will remain in OCI 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 OCI 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 Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” As such, for the life of the swap no ineffectiveness will be recognized.

     Income Taxes— The Company is required to make quarterly distributions to its members, Duke Energy Corporation (“Duke Energy”) and Phillips, Petroleum Company (“Phillips”) 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 Phillips.

     New Accounting Standards —— The Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” on January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts are subject to a fair-value-based annual impairment assessment. The Company did not recognize any impairments due to the implementation of SFAS No. 142. The standard also requires certain identifiable intangible assets to be recognized separately and amortized as appropriate. No suchadjustments to intangibles have beenwere identified by the Company at transition.

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     The following table shows what net income (loss) would have been if amortization related to goodwill that is no longer being amortized had been excluded from prior periods.

The changes in the carrying amount of goodwill for the threenine months ended March 31,September 30, 2002 and March 31,September 30, 2001 are as follows:

Goodwill (In Thousands)

     The Company adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002. The new rules supersede SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” The new rules retain many of the fundamental recognition and measurement provisions of SFAS No. 121, but significantly change the criteria for classifying an asset as held-for-sale. Adoption of the new standard had no material effect on the Company’s consolidated results of operations or financial position.

     In June 2002, the FASB’s 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 Income. 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 in operating expenses, in accordance with prevailing industry practice. The amounts in the comparative interim Consolidated Statements of Operations have been reclassified to conform to the 2002 presentation. For the nine months ended September 30, 2002 and 2001, application of the new consensus reclassified operating revenues and cost of sales by $1.778 million and $1.253 million, respectively, with no impact on net income.

     In October 2002, the EITF, as part of adoptingtheir 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. 144 was133 will be recorded at their historical cost and 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 will 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 will be removed with a cumulative effect adjustment.

     In connection with the decision to rescind Issue No. 98-10, the EITF also reached a consensus that, effective for periods beginning after December 15, 2002, all gains and losses on all derivative instruments held for trading purposes should be shown net in the income statement as Trading and Marketing Net Margin (Loss). 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.”

     The Company is currently assessing the provisions of Issue No. 02-03 and the rescission of Issue No. 98-10 but has not materialyet determined the impact on the results of operations or financial position.

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     In June 2001, the Financial Accounting Standards Board (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 Company.carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is increased due to the passage of time based on the time value of money until the obligation is settled.

     We are required and plan to adopt the provisions of SFAS No. 143 as of January 1, 2003. To accomplish this, the Company must identify any legal obligations for asset retirement obligations, and determine the fair value of these obligations on the date of adoption. The determination of fair value is complex and requires gathering market information and developing cash flow models. Additionally, the Company will be required to develop processes to track and monitor these obligations. Because of the effort needed to comply with the adoption of SFAS No. 143, the Company is currently assessing the new standard but has not yet determined the impact on its consolidated results of operations, cash flows 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. The Company will adopt 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.

     Reclassifications— Certain prior period amounts have been reclassified in the Consolidated Financial Statements and Note 6 to conform to the current presentation.

3. Derivative Instruments, Hedging Activities and Credit Risk

     Commodity price risk— The Company’s principal operations of gathering, processing, transportation 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 and natural gas. 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 in tointo purchase and process natural gas feedstock. 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

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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

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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 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 ranginginclude local utilities, industrial consumers, independent power producers and merchant energy trading organizations. The NGL customers range from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of the Company’s NGL sales are made at market-based prices, including approximately 40% of NGL production that is committed to Phillips and Chevron Phillips Chemical LLC, under a contract with a primary term that expires on January 1, 2015 .2015. 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 all 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 inability 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. However, these transactionsfinancial derivatives are generally subject to margin agreements with the majority of our counterparties.

     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 (1) maintaining minimum cash flows to fund debt service, dividends, production replacement, maintenance capital projects and tax distributions; (2) avoiding disruption of the Company’s growth capital and value creation process; and (3) 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 liquids and other energy-related products. For the threenine months ended March 31,September 30, 2002, the Company recognized a net gainloss of $7.4$5.9 million, of which a $5.9$10.6 million loss represented the total ineffectiveness of all cash flow hedges and an $18.5$7.0 million gain represented the total derivative settlements. The time value of the options, a recognized $5.2$2.3 million loss for the threenine months ended March 31,September 30, 2002, was excluded in the assessment of hedge effectiveness. The time value of the options is included in Sales of Natural Gas and Petroleum Products in the Consolidated Statements of Operations. 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,September 30, 2002, $15.8$45.8 million of the deferred net losses on derivative instruments accumulated in OCI are expected to be reclassified asinto 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.

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     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 hedgesmay hedge producer price locks (fixed price gas purchases) and market locks (fixed price gas sales) to reduce the Company’s exposure to fixed price risk via swapping out the fixed price risk for a floating price position (New York Mercantile Exchange or index based).

     For the threenine months ended March 31,September 30, 2002, the gains or losses representing the ineffective portion of the Company’s fair value hedges were not material. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. The Company did not have any firm commitments that no longer qualified as fair value hedge items and therefore, did not recognize an associated gain or loss.

     Interest rate fair value 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 133. As such, for the life of the swap no ineffectiveness will be recognized. As of March 31,September 30, 2002, the fair value of the interest rate swap of ($7.4)$12.0 million gain 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— 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. Financing

     Credit Facility with Financial Institutions —On March 29, 2002, the Company entered into a new credit facility which was recently amended (the “New Facility”). The New Facility replaces the credit facility that matured on March 29, 2002. 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 28, 2003, 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 $650.0 million revolving credit facility, of which $150.0 million can be used for letters of credit. The New Facility, as amended, requires the Company to maintain at all times a debt to total capitalization ratio of less than or equal to 53%. The Company entered into an amendment to the New Facility on November 13, 2002. 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 0.75%1.25% per year (as recently increased) or (2) the higher of (a) the Bank of America prime rate and (b) the Federal Funds rate plus 0.50% per year. At March 31,September 30, 2002, there were no borrowings against the New Facility.

     On September 9, 2002 the Company redeemed $100.0 million of its preferred members’ interest by paying cash to each member (Duke Energy and Conoco Phillips) in proportion to their ownership interests.

At March 31,September 30, 2002 the Company had a $30.0 million outstanding Irrevocable Standby Letter of Credit expiring March 31, 2003.

     At March 31,September 30, 2002 the Company was the guarantor of approximately $25.6$103.8 million of debt associated with an unconsolidated subsidiary.subsidiaries. Assets of the unconsolidated subsidiarysubsidiaries are pledged as collateral for the debt.

5. Commitments and Contingent Liabilities

     Litigation— The midstream natural gas industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement, pricing 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 numberSome of these cases are now being

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brought as class actions. The Company and its subsidiaries are currently named as defendants in somea number of these

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cases. types of cases, including the referenced class actions and other similar types of cases impacting the midstream natural gas industry. 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.

Environmental— The Company received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (“LDEQ”) in the spring of 2001 enabling the Company to discharge certain wastewater streams from its Minden Gas Processing Plant until the LDEQ issued a new discharge permit. The Compliance Order authorized certain discharges, and otherwise addressed various historic and recent deviations from Clean Water Act regulatory requirements, including the lapse of the facility’s discharge permit. The LDEQ issued a new discharge permit in the spring of 2002 and the Company completed operational improvements in the fall of 2002 that resulted in the cessation of remaining point source discharges. In August 2002, a penalty assessment was issued by the LDEQ in the amount of $155,383. The Company paid the penalty and has notified the LDEQ that all items in the Compliance Order have been completed.

6. Business Segments

     The Company operates in two principal business segments as follows: (1) natural gas gathering, processing, transportation, marketing 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.

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

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(a)		Intersegment sales represent sales of NGLs from the natural gas segment to the NGLs segment at either index prices or weighted average prices of NGLs. Both measures of intersegment sales are effectively based on current economic market conditions.
(b)		EBITDA consists of income from continuing operations before interest expense, income tax expense, and depreciation and amortization expense. EBIT is equal to EBITDA less depreciation and amortization. These measures are not a measurement presented in accordance with generally accepted accounting principles and should not be considered in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as a measure of the Company’s profitability or liquidity. The measures are included as a supplemental disclosure because it may provide useful information regarding the Company’s ability to service debt and to fund capital expenditures. However, not all EBITDA or EBIT may be available to service debt.
(c)		Includes items such as unallocated working capital, intercompanyaffiliate related accounts and other assets.

7. Subsequent EventAcquisition

     In AprilOn May 31, 2002, the Company filedacquired 33.33% of the outstanding membership interests in Discovery Producer Services, LLC (“DPS”). The base purchase price of $71.0 million was adjusted for working capital and certain capital expenditures. This adjusted purchase price was then reduced by approximately $84.6 million of DPS debt guaranteed by the Company, resulting in the Company receiving cash of approximately $11.5 million on the closing date of the transaction. This acquisition is accounted for under the equity method of accounting. The pro forma impact of the acquisition on the Company’s results of operations was not material.

8. Accounting Adjustments

     We have substantially completed a shelf registration statement increasing its abilitycomprehensive account reconciliation project to issue securities to $500.0 million. The shelf registration statement providesreview and analyze our 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 has recorded numerous adjustments in the current year as discussed above under "Results of Operations". Total charges recorded were approximately $65 million for the issuancenine months ended September 30, 2002, of senior notes, subordinated noteswhich management believes $44 million may be related to corrections of accounting errors in prior periods. However, management has determined that the charges related to error corrections are immaterial both individually and trust preferred securities.in the aggregate on both a quantitative and qualitative basis and to the trends in the financial statements for the periods presented, the prior periods affected and are a fair presentation of the Company's financial statements. In addition, approximately $16 million of the $44 million relates to numerous items identified in the account reconciliation project resulting from system conversions and otherwise unsupportable balance sheet amounts. Due to the nature of these account reconciliation adjustments, it would be impractical to determine what periods these adjustments relate to. Accordingly, the corrections have been made in the current year's financial statements. Please also see Item 4. Controls and Procedures.

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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 months and nine months ended March 31,September 30, 2002 and 2001. 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, marketing and storage, from which we generate revenues primarily by providing services such as compression, treating and gathering, processing, local fractionation, transportation of residue gas, storagemarketing and marketing;storage;
	•		natural gas liquids (“NGLs”) fractionation, transportation, marketing and trading, from which we generate revenues from transportation fees, market center fractionation and the marketing and trading of NGLs.

     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

     The Company is exposed to commodity prices as a result of being paid for certain services in the form of commodities rather than cash. For gathering services, the Company receives fees from producers to bring natural gas from the well head to the processing plant. For processing services, the Company either receives fees or physical commodities as payment for these services, depending on the type of contract. Under a percentage-of-proceeds contract type, the Company is paid for its services by keepingretaining a percentage of both the NGLs produced and the residue gas resulting from processing the natural gas. Under a keep-whole contract, the Company keeps all or a portion of the NGLs produced, but returns the equivalent British thermal unit (“Btu”) content of the gas back to the producer. Based on the Company’s current contract mix, the Company has a net long NGL position and is sensitive to changes in NGL prices. The Company also has a net short residue gas position, however the short residue gas position is less significant than the long NGL position.

     During 2001 and the first quarterthree quarters of 2002, 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. The commodity exposure is actively managed by the Company as discussed below.

     The midstream natural gas industry has been 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.

     The depressed NGL and natural gas price environment experienced in 1998 prevailed during the first quarter of 1999. However, during the last three quarters of 1999, NGL prices increased sharply as major crude oil exporting countries agreed to maintain crude oil production at predetermined levels and world demand for crude oil and NGLs increased. The lower crude oil and natural gas prices in 1998 and early 1999 caused a significant

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reduction in the exploration activities of United States producers, which in turn had a significant negative effect on natural gas volumes gathered and processed in 1999. Due to reduced supply and strong demand, natural gas and NGL prices increased throughout 2000 along with renewed strength in drilling activity.

     The slowing economy combined with an increase in supply availability resulting from increased drilling levels drove declines in both crude oil and natural gas prices during the final two quarters of 2001. The dramatic decline in NGL prices is attributed to the drop in crude oil prices in addition to a decline in the correlation between NGL prices and crude oil.

     During the last two quarters of 2001 and first quarter of 2002, the relationship or correlation between crude oil value and NGL prices remained depressed. 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, during the last two quarters of 2001 and first three quarters of

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2002, the relationship or correlation between crude oil value and NGL prices declined significantly. During the second and third quarters of 2002, NGL prices strengthened while the relationship between NGL prices and crude remained weak.

     In contrast, weWe believe that future natural gas prices will be influenced by supply deliverability, the severity of winter weather and the level of United States economic growth. We believe that weather will be the strongest determinant of near term natural gas prices. The price increases in crude oil, NGLs and natural gas experienced during 2000 and the first two quarters of 2001 spurred increased natural gas drilling activity. For example, the average number of active drilling rigs in North America increased by approximately 19% from 1,263 in 2000 to 1,497 in 2001. The decline in commodity prices over the final two quarters of 2001 and first quarter of 2002 negatively effectedaffected drilling activity as the average number of active rigs in North America declined to 1,1361,048 during the firstsecond quarter of 2002. Active rigs increased to 1,110 as of September 30, 2002, as a result of higher pricing experienced in the third quarter. We expect that continued pressure from reducedlower commodity prices and market uncertainty on drilling willcould negatively impact North American drilling activity in the short term. We expect lower drilling levels over a sustained period will have a negative effect on natural gas volumes gathered and processed.

     To better address the risks associated with volatile commodity prices, the Company employs 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 Disclosures About Market Risk.” Our firstthird quarter 20012002 and 20022001 results of operations include a hedging losslosses of $14.6$5.0 million and gaingains of $7.4$14.1 million, respectively. During the first nine months of 2002 and 2001 our hedging activities resulted in losses of $5.9 million and $1.7 million, respectively. The hedging loss observedlosses incurred in the firstthird quarter of 2001 relates2002 relate to hedges placed during periods of increasinglower prices. The slight gain recognized in the first quarter of 2002 is the result of hedging gains achieved as a result of a sharp decline in commodity prices during the third and fourth quarters of 2001 continuing through the first quarter of 2002.

Results of Operations