FORM 10-Q

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

DUKE ENERGY FIELD SERVICES, LLC

370 17th Street, Suite 2500
Denver, Colorado 80202
(Address of principal executive offices)
(Zip Code)

303-595-3331
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yesx   Noo

Indicate by check mark whether the registrant is an accelerated filer as defined by Rule 12b-2 of the Act. NoYeso   YesNox

DUKE ENERGY FIELD SERVICES, LLC
FORM 10-Q FOR THE QUARTER ENDED MARCH 31,JUNE 30, 2004

INDEX

	x		the timing and extent of changes in commodity prices, interest rates, foreign currency exchange rates and demand for our services;
	x		weather and other natural phenomena;
	x		industry changes, including the impact of consolidations, and changes in competition;
	x		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;
	x		the extent of success in connecting natural gas supplies to gathering and processing systems;
	x		general economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities; and
	x		The effect of accounting pronouncements issued periodically by accounting standard-setting bodies.

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

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

DUKE ENERGY FIELD SERVICES, LLC

DUKE ENERGY FIELD SERVICES, LLC

DUKE ENERGY FIELD SERVICES, LLC

DUKE ENERGY FIELD SERVICES, LLC

DUKE ENERGY FIELD SERVICES, LLC

1. General

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

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

2. Summary of Significant Accounting Policies

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

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

     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.

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

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

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     For derivatives designated as a cash flow hedge or a fair value hedge, the Companywe formally assesses,assess, both at the inception of the hedge and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in fair values or cash flows of hedged items. The Company excludesWe exclude the time value of the options when assessing hedge effectiveness.

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

     Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating the open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

     Commodity Trading and Marketing — A favorable or unfavorable price movement of any derivative contract held for trading and marketing purposes is reported as Trading and marketing net margin in the Consolidated Statements of Operations. An offsetting amount is recorded in the Consolidated Balance Sheets as Unrealized gains or unrealizedUnrealized losses on mark-to-market and hedging transactions. When the contractual delivery period occurs, the realized gain or loss is reclassified to aan account receivable or payable account.payable.

     Commodity Cash Flow Hedges — The fair value of a derivative designated as a cash flow hedge is recorded in the Consolidated Balance Sheets as Unrealized gains or unrealizedUnrealized losses on mark-to-market and hedging transactions. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in the Consolidated Balance Sheets as Accumulated other comprehensive income (“AOCI”). and the ineffective portion is recorded in the Consolidated Statements of Operations. During the period in which the hedged transaction occurs, amounts in AOCI associated with the hedged transaction are reclassified to the Consolidated Statements of Operations in the same accounts as the item being hedged. The Company discontinuesWe discontinue hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative continues to be carried on the Consolidated Balance Sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction occurs, unless it is no longer probable that

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period earnings. At March 31,June 30, 2004 and December 31, 2003, $28$16 million and $29 million, respectively, of losses related to cash flow hedges were deferred in AOCI.

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

     Interest Rate Fair Value Hedges — The CompanyWe periodically entersenter into interest rate swaps to convert some of itsour 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’sour hedged fixed-rate debt is carried at fair value. The terms of the outstanding swaps match those of the associated debt which permits the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps, no ineffectiveness will be recognized.

     Distributions –Under the terms of the Company’sour Limited Liability Company Agreement (the “LLC Agreement”), the Company iswe are required to make quarterly distributions to Duke Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement, as amended, provides for taxable income to be allocated in accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 69.7% for Duke Energy and 30.3% for ConocoPhillips. As of March 31,During the six months ended June 30, 2004, we paid distributions payable of $11 million were included in Other current liabilities in the Consolidated Balance Sheets. This amount was based on estimated annual taxable income allocated to the members according to their respective ownership percentages and was paidpercentages. As of June 30, 2004, additional distributions payable of $5 million were included in April 2004.Other current liabilities in the Consolidated Balance Sheets.

     In 2003, the Company’sour board of directors approved a plan to consider the payment of a quarterly dividend to Duke Energy and ConocoPhillips. The board of directors may consider net income, cash flow or any other criteria deemed appropriate for determining the amount of the quarterly dividend to be paid. The LLC Agreement restricts making distributions, which would include these dividends, except with the approval of both members. During the quartersix months ended March 31,June 30, 2004, with the approval of both members, the Companywe paid a total dividend of $50$137 million to the members, allocated in accordance with their respective ownership percentages.

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

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

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Pro Forma Stock-Based Compensation

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

Accumulated Other Comprehensive Income

     In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities” which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest

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

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

5. Asset Retirement ObligationsObligation

     The following table summarizes changes in the asset retirement obligation for the quarterssix months ended March 31,June 30, 2004 and 2003, respectively.

     During each of the quarterssix months ended March 31,June 30, 2004 and 2003, the Companywe recorded amortization expense associated with commodity sales and purchases contracts of $3$5 million. The average remaining amortization period for these contracts is 6.8approximately 7 years. Estimated amortization for these contracts for the next five years is as follows:

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

     The CompanyWe also maintainsmaintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of the Company’s general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.

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

     Severance Program— On October 30, 2003, the Companywe communicated a company-wide voluntary and involuntary severance program to itsour employees to reduce approximately 6% of the Company’sour workforce. The plan was completed on December 8, 2003 and includesincluded the reduction of 160 employees over the period offrom December 2003 to Junethrough 2004. The severance liability that was recorded in the fourth quarter of 2003 was $6 million at December 31, 2003. Approximately $4 million of the accrued severance payouts were paid in the first quarter of 2004. Included in General and administrative expense in the Consolidated Statement of Operations during the first quarter of 2004, the Company expensed an additional $1 million related to this severance program, and any remaining expense, which is not considered significant, will be recognizedprogram. The following table summarizes changes in the second quarter of 2004,severance liability for the remaining future service period.six months ended June 30, 2004.

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9. Business Segments

     The Company operatesWe operate in two principal business segments:

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

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

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

     These segments are monitored separately by management for performance against itsour internal forecast and are consistent with the Company’sour internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Margin is a performance measure utilized by management to monitor the business of each segment. The accounting policies for the segments are the same as those described in Note 2. Foreign operations are not material and are therefore not separately identified.

     The following table setstables set forth the Company’sour segment information.

     Three months ended March 31,June 30, 2004 (millions):

     Six months ended June 30, 2004 (millions):

     Six months ended June 30, 2003 (millions):

(a)

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

(b)

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

(c)

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

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10. Guarantor’s Obligations Under Guarantees

     On January 1, 2004, the Company waswe were the guarantor of $3 million of debt.debt for an affiliate. The guaranteed debt was repaid in full in January of 2004. At March 31, 2004, the Company had no liability recorded for the guarantees of this debt.

     The CompanyWe periodically entersenter into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities related to the assets being acquired or divested. Typically, claimsClaims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The effective periods on these indemnification provisions generally have terms of one to five years, although some are longer. The Company’sOur maximum potential exposure under these indemnification agreements can vary depending on the nature of the claim and the particular transaction. The Company isWe are unable to estimate the total maximum potential amount of future payments under indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities. At March 31,June 30, 2004, the Companywe had a liability of approximately $1 million recorded for theseknown liabilities related to outstanding indemnification provisions.

11. Subsequent Events

     On March 10, 2004, the Company entered into an agreement to acquire gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips for approximately $74 million. The transaction closed during the second quarter of 2004.

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

     The following discussion details the material factors that affected our historical financial condition and results of operations during the three and six months ended March 31,June 30, 2004 and 2003. This discussion should be read in conjunction with the Consolidated Financial Statements and related notes included elsewhere in this report.

Overview

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

	•		Natural gas gathering, processing, transportation and storage, from which we generate revenues primarily by providing services such as compression, gathering, treating, processing, transportation of residue gas, storage and trading and marketing (the “Natural Gas Segment”). In the first three months of 2004, approximately 79% 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 three months of 2004, approximately 21% of our operating revenues prior to intersegment revenue elimination and approximately 5% of our gross margin were derived from this segment.
	•		Intersegment activity is primarily related to the sale of NGLs from the Natural Gas Segment to the NGLs Segment at market based transfer prices.

     Our limited liability company agreement limits the scope of our business to the midstream industry in the United States and Canada, the marketing of NGLsNGL 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 wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, based on the type of contractual agreement. Based on the Company’sour current contract mix, the Company haswe have a long NGL position and a short gas position, however, the short gas position is less significant than the long NGL position. Based upon our portfolio of supply contracts, without giving effect to hedging activities that would reduce the impact of commodity price decreases, a decrease of $0.01 per gallon in the price of NGLsNGL and $0.10 per million Btus in the average price of natural gas would result in changes in annual pre-tax net income of approximately $(18)$(19) million and $1 million, respectively. In addition, a decrease of $1 per barrel in the average price of crude oil would result in a change to annual pre-tax net income of approximately $(5) million.

     During the first threesix months of 2004, approximately 80% of our gross margin is generated by commodity sensitive arrangements and approximately 20% of our gross margin (excluding hedging and including earnings of unconsolidated affiliates) is generated by fee-based arrangements. We actively manage our commodity exposure as discussed below.

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

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be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. The 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. Drilling activity increased in 2003 due to higher commodity prices. The average number of active oil and gas rigs drilling in the United States increasedwere 170 and 1,005, respectively, as of June 30, 2004, compared to 1,157144 and 924, respectively, as of June 30, 2003. This increase is mainly attributable to recent significant increases in natural gas prices which could result in sustained increases in drilling activity during 2004. However, energy market uncertainty could negatively impact North American drilling activity in the first quarter of 2004 from 959 during the first quarter of 2003.short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

     To address the risks associated with volatile commodity prices, we employ a comprehensive commodity price risk management program. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGLsNGL contracts to hedge a portion of the value of our assets and operations from such price risks. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” We do not realize the full impact of commodity price changes because some of our sales volumes were previously hedged at prices different than actual market prices. The recognition in the Consolidated Statements of Operations of the cumulative changes in the fair value of these hedge instruments reduced the results of operations by $19$23 million and $40$24 million in the firstsecond quarter of 2004 and 2003, respectively. During the first six months of 2004 and 2003 the changes in fair value of our hedging contracts reduced results of operations by $41 million and $63 million, respectively. See “Item 3. Quantitative and Qualitative Disclosure About Market Risk”. The remaining term over which we are currently hedging our exposure to the variability of future cash flows is through the end of 2004.

     Effects of Our Raw Natural Gas Supply Arrangements

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

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

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

     In 2004 and 2003, we converted a portion of our keep-whole contracts to percentage-of-proceeds contracts and we amended a portion of our keep-whole contracts to add a minimum fee clause. This had the impact of reducing the Company’s exposure to natural gas prices and reducing the exposure to NGL prices.

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needed for debt service, capital expenditures and capital expenditures. The primary goals of our hedging program include maintaining minimumtax distributions. However, we do not currently anticipate using cash flow hedges in 2005 because management believes cash flows will be sufficient to fund debt service; production replacement and maintenance capital projects; and retaining a high percentage of potential upside relating to increases in prices of NGLs.the Company’s business.

Accounting Adjustments

     Certain prior period amounts have been reclassified in the Consolidated Financial Statements to conform to the current period presentation. Included in the reclassified amounts are increases in both Sales of natural gas and petroleum products and in Purchases of natural gas and petroleum products in the amountamounts of approximately $236$223 million and $459 million, respectively, for the quarterthree and six months ended March 31,June 30, 2003. This reclassification resulted from intersegment trading activities being eliminated twice from the Consolidated Statements of Operations induring the quarterthree and six months ended March 31,June 30, 2003. Management has concluded that these reclassifications are not material to the fair presentation of the Company’s financial statements.

Results of Operations

Three months ended March 31,June 30, 2004 compared with three months ended March 31,June 30, 2003

     Operating Revenues –Total operating revenues decreased $165increased $326 million, or 6%16%, to $2,402$2,382 million in the firstsecond quarter of 2004 from $2,567$2,056 million in the same period of 2003. This increase was primarily due to the following factors:

Purchases of Natural Gas and Petroleum Products– Purchases of natural gas and petroleum products increased $256 million, or 15%, to $2,002 million in the second quarter of 2004 from $1,746 million in the same period of 2003. The increase was primarily due to the following factors: