UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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


For Quarter Ended June 30, 2004		Commission File Number 0-31095

DUKE ENERGY FIELD SERVICES, LLC

(Exact name of registrant as specified in its charter)


Delaware		76-0632293
(State or other jurisdiction of incorporation)		(IRS Employer Identification No.)

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

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

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

INDEX


Item		Page
	PART I. FINANCIAL INFORMATION (UNAUDITED)
1.	Financial Statements		1
	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2004 and 2003		1
	Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2004 and 2003		2
	Consolidated Balance Sheets as of June 30, 2004 and December 31, 2003		3
	Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2004 and 2003		4
	Condensed Notes to Consolidated Financial Statements		5
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
3.	Quantitative and Qualitative Disclosure about Market Risks		27
4.	Controls and Procedures		31
	PART II. OTHER INFORMATION
1.	Legal Proceedings		32
6.	Exhibits and Reports on Form 8-K		32
	Signatures		33
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 906
Certification of CEO Pursuant to Section 906

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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

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

•

our ability to access the capital and bank markets, which will depend on general market conditions and the credit ratings for our debt obligations;

•

our use of derivative financial instruments to hedge commodity and interest rate risks;

•

the level of creditworthiness of counterparties to transactions;

•

the amount of collateral required to be posted from time to time in our transactions;

•

changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment or the increased regulation of the gathering and processing industry;

•

the timing and extent of changes in commodity prices, interest rates, foreign currency exchange rates and demand for our services;

•

weather and other natural phenomena;

•

industry changes, including the impact of consolidations, and changes in competition;

•

our ability to obtain required approvals for construction or modernization of gathering and processing facilities, and the timing of production from such facilities, which are dependent on the issuance by federal, state and municipal governments, or agencies thereof, of building, environmental and other permits, the availability of specialized contractors and work force and prices of and demand for products;

•

the extent of success in connecting natural gas supplies to gathering and processing systems;

•

general economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities; and

•

The effect of accounting pronouncements issued periodically by accounting standard-setting bodies.

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(millions)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2004		2003		2004		2003
Operating Revenues:
Sales of natural gas and petroleum products	$	1,759	$	1,409	$	3,480	$	3,025
Sales of natural gas and petroleum products to affiliates		545		578		1,156		1,502
Transportation, storage and processing		76		68		144		129
Trading and marketing net margin		2		1		4		(33	)

Total operating revenues		2,382		2,056		4,784		4,623

Costs and Expenses:
Purchases of natural gas and petroleum products		1,863		1,555		3,752		3,624
Purchases of natural gas and petroleum products from affiliates		139		191		287		393
Operating and maintenance		107		113		201		218
Depreciation and amortization		75		75		150		150
General and administrative		41		41		82		79

Total costs and expenses		2,225		1,975		4,472		4,464

Operating Income		157		81		312		159
Equity in earnings of unconsolidated affiliates		14		12		31		24
Interest expense, net		39		42		79		84

Income from continuing operations before income taxes		132		51		264		99
Income tax expense		2		—		5		2

Income from continuing operations before cumulative effect of accounting change		130		51		259		97
Income from discontinued operations		—		31		5		37
Cumulative effect of change in accounting principles		—		—		—		(23	)

Net income		130		82		264		111
Dividends on preferred members’ interest		—		4		—		9

Earnings available for members’ interest	$	130	$	78	$	264	$	102

See Condensed Notes to Consolidated Financial Statements.

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(millions)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2003			2004			2003
Net income	$	130		$	82		$	264		$	111
Other comprehensive income:
Foreign currency translation adjustment		(9	)		25			(13	)		45
Net unrealized losses on cash flow hedges		(12	)		(24	)		(29	)		(61	)
Reclassification of previously deferred losses on cash flow hedges into earnings		24			24			42			66

Total other comprehensive income		3			25			—			50

Total comprehensive income	$	133		$	107		$	264		$	161

See Condensed Notes to Consolidated Financial Statements.

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(millions)


	June 30,		December 31,
	2004		2003
ASSETS
Current assets:
Cash and cash equivalents	$	253	$	43
Accounts receivable:
Customers, net of allowance for doubtful accounts of $4 and $8, respectively		961		872
Affiliates		49		57
Other		27		29
Inventories		46		45
Unrealized gains on mark-to-market and hedging transactions.		125		135
Other current assets		12		20

Total current assets		1,473		1,201

Property, plant and equipment, net		4,457		4,462
Investment in unconsolidated affiliates		186		190
Intangible assets:
Commodity sales and purchases contracts, net		75		80
Goodwill, net		445		447

Total intangible assets		520		527

Unrealized gains on mark-to-market and hedging transactions		40		25
Other noncurrent assets		40		109

Total assets	$	6,716	$	6,514

LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	963	$	857
Affiliates		22		16
Other		36		33
Short term debt		6		6
Accrued interest payable		59		59
Unrealized losses on mark-to-market and hedging transactions		124		153
Other current liabilities		128		150

Total current liabilities		1,338		1,274

Deferred income taxes		18		17
Long term debt		2,248		2,262
Unrealized losses on mark-to-market and hedging transactions		43		24
Other long term liabilities		89		73
Minority interests		125		120
Commitments and contingent liabilities
Members’ equity:
Members’ interest		1,709		1,709
Retained earnings		1,122		1,011
Accumulated other comprehensive income		24		24

Total members’ equity		2,855		2,744

Total liabilities and members’ equity	$	6,716	$	6,514

See Condensed Notes to Consolidated Financial Statements.

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(millions)


	Six Months Ended
	June 30,
	2004			2003
Cash flows from operating activities:
Net income	$	264		$	111
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		(5	)		(37	)
Cumulative effect of change in accounting principles		—			23
Depreciation and amortization		150			150
Distributions received in excess of earnings from unconsolidated affiliates		7			7
Other, net		3			10
Change in operating assets and liabilities which provided (used) cash:
Accounts receivable		(89	)		(243	)
Accounts receivable from affiliates		16			128
Inventories		1			24
Net unrealized gains on mark-to-market and hedging transactions		(11	)		(32	)
Accounts payable		108			146
Accounts payable to affiliates		3			(59	)
Accrued interest payable		—			—
Other		(20	)		(7	)

Net cash provided by operating activities		427			221

Cash flows from investing activities:
Capital expenditures		(132	)		(66	)
Consolidation of previously unconsolidated investment		6			—
Contributions to minority interests, net		—			(1	)
Proceeds from sale of discontinued operations		62			90
Proceeds from sales of assets		2			5

Net cash (used in) provided by investing activities		(62	)		28

Cash flows from financing activities:
Payment of debt		(9	)		(115	)
Payment of dividends and distributions to members		(148	)		(10	)

Net cash used in financing activities		(157	)		(125	)

Effect of foreign exchange rate changes on cash		—			(1	)
Effect of discontinued operations on cash		2			10

Net increase in cash and cash equivalents		210			133
Cash and cash equivalents, beginning of period		43			35

Cash and cash equivalents, end of period	$	253		$	168

Supplementary cash flow information:
Cash paid for interest (net of amounts capitalized)	$	78		$	81

See Condensed Notes to Consolidated Financial Statements.

DUKE ENERGY FIELD SERVICES, LLC

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

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

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

2. Summary of Significant Accounting Policies

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

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

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

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


Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Trading Derivatives	Mark-to-market^a	Net basis in Trading and marketing net margin
Non-Trading Derivatives:
Cash Flow Hedge	Hedge method^b	Gross basis in the same income statement category as the related hedged item
Fair Value Hedge	Hedge method^b	Gross basis in the same income statement category as the related hedged item
Normal Purchase or Normal Sale	Accrual method^c	Gross basis upon settlement in the corresponding income statement category based on commodity type
Non-Trading Mark-to- Market	Mark-to-market^a	Net basis in Trading and marketing net margin

^a Mark-to-market- An accounting method whereby the change in the fair value of the asset or liability is recognized in the Consolidated Statements of Operations in Trading and marketing net margin during the current period.

^b Hedge method- An accounting method whereby the change in the fair value of the asset or liability is recorded in the Consolidated Balance Sheets and there is no recognition in the Consolidated Statements of Operations for the effective portion until the hedged transaction occurs.

^c Accrual method- An accounting method whereby there is no recognition in the Consolidated Statements of Operations for changes in fair value of a contract until the service is provided or the associated delivery of product occurs.

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

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

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

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

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

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

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

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

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

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

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

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

Pro Forma Stock-Based Compensation


	Three months ended						Six months ended
	June 30,						June 30,
(millions)	2004			2003			2004			2003
Earnings available for members’ interest, as reported	$	130		$	78		$	264		$	102
Add: stock-based compensation expense included in reported net income		1			—			1			—
Deduct: total stock-based compensation expense determined under fair value-based method for all awards		(2	)		(2	)		(2	)		(3	)

Pro forma earnings available for members’ interest	$	129		$	76		$	263		$	99

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

Accumulated Other Comprehensive Income


				Net			Accumulated
	Foreign			Unrealized			Other
	Currency			(Losses) Gains on			Comprehensive
(millions)	Adjustments			Cash Flow Hedges			Income
Balance as of December 31, 2003	$	53		$	(29	)	$	24
Other comprehensive income changes during the period		(13	)		13			—

Balance as of June 30, 2004	$	40		$	(16	)	$	24

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

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

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

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

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

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

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

3. Acquisitions and Dispositions

On March 10, 2004, we entered into an agreement to acquire gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips, a related party, for a total purchase price of approximately $80 million, consisting of $74 million in cash and the assumption of approximately $6 million of liabilities. The transaction closed during the second quarter of 2004.

In February 2004, we sold gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million. These assets comprised a component of the Company for purposes of reporting discontinued operations. All prior period operations have been revised to reflect these assets as discontinued operations.

During the six months ended June 30, 2003, we sold gathering, transmission and processing assets to two separate buyers for a combined sales price of approximately $90 million. These assets comprised a component of the Company for purposes of reporting discontinued operations. All prior period operations have been revised to reflect these assets as discontinued operations.

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


	Three				Six
	Months Ended				Months Ended
	June 30,				June 30,
	2004		2003		2004		2003
	(millions)				(millions)
Revenues	$	—	$	98	$	14	$	237
Operating income		—		5		2		11
Gain on sale		—		26		3		26

Income from discontinued operations	$	—	$	31	$	5	$	37

4. Derivative Instruments, Hedging Activities and Credit Risk

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

We use natural gas, crude oil and NGL swaps to hedge the impact of market fluctuations in the prices of NGL, natural gas and other energy-related products. For the three and six months ended June 30, 2004, the recognition in the Consolidated Statements of Operations of the cumulative changes in the fair value of these hedge instruments reduced revenues by $23 million and $41 million, respectively, compared to $24 million and $63 million, respectively, in the same periods of 2003. The above changes in the fair value of these hedge instruments include the effects of any ineffectiveness, which for the six months ended June 30, 2004 and 2003, were a $1 million gain and a $3 million loss, respectively. No derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to any forecasted transactions that are not probable of occurring.

Gains and losses on derivative contracts that are reclassified from AOCI to current period earnings are included in the line item in which the hedged item is recorded. As of June 30, 2004, $16 million of the remaining deferred net losses on derivative instruments in AOCI are expected to be reclassified into earnings within the next 12 months as the hedged transactions occur; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings. The remaining term over which we are currently hedging our exposure to the variability of future cash flows is through the end of 2004.

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

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

Interest rate fair value hedges — In October 2001, we entered into an interest rate swap to convert $250 million of fixed-rate debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on a six-month London Interbank Offered Rate (“LIBOR”), which is re-priced semiannually through 2005. In August 2003, we entered into two additional interest rate swaps to convert $100 million of fixed-rate debt securities issued on August 16, 2000 to floating rate debt. These interest rate fair value hedges are also at a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet conditions which permit the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps no ineffectiveness will be recognized. As of June 30, 2004, the fair value of the interest rate swaps was a $6 million asset, which is included in the Consolidated Balance Sheets as Unrealized gains or losses on mark-to-market and hedging transactions with an offset to the underlying debt included in Long term debt.

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

5. Asset Retirement Obligation

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


	Six
	Months Ended
	June 30,
Reconciliation of Asset Retirement Obligation (millions)	2004			2003
Balance as of January 1	$	45		$	43
Accretion expense		2			3
Liabilities incurred		2			—
Liabilities settled		(1	)		(3	)

Balance as of June 30	$	48		$	43

6. Goodwill and Other Intangibles

The changes in the carrying amount of goodwill for the six months ended June 30, 2004 are as follows:


					Foreign
			Purchase		Currency
	Balance		Price		Exchange			Balance
	December 31, 2003		Adjustments		Adjustments			June 30, 2004
			(millions)
Natural gas gathering, processing, transportation, marketing and storage	$	407	$	—	$	(2	)	$	405
NGL fractionation, transportation, marketing and trading		40		—		—			40

Total consolidated	$	447	$	—	$	(2	)	$	445

There were no impairments of goodwill during the six months ended June 30, 2004.

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


	June 30,			December 31,
	2004			2003
	(millions)
Commodity sales and purchases contracts	$	127		$	127
Accumulated amortization		(52	)		(47	)

Commodity sales and purchases contracts, net	$	75		$	80

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


Estimated Amortization
	(millions)
2004	$	4
2005		8
2006		8
2007		8
2008		8
Thereafter		39

Total	$	75

7. Financing

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

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

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

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

8. Commitments and Contingent Liabilities

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

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

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

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

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


Reconciliation of Severance liability (millions)
Balance as of December 31, 2003	$	6
Additional severance expense		1
Severance paid		(6	)

Balance as of June 30, 2004	$	1

9. Business Segments

We operate in two principal business segments:

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

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

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

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

The following tables set forth our segment information.

Three months ended June 30, 2004 (millions):


					Intersegment
	Natural Gas		NGL		Eliminations			Other			Total
	Segment		Segment		(a)			(c)			Company
Operating Revenues	$	2,177	$	482	$	(277	)	$	—		$	2,382
Gross Margin(b)		368		12		—			—			380
Other operating and administrative costs		104		3		—			41			148
Depreciation and amortization		68		3		—			4			75
Earnings from unconsolidated affiliates		14		—		—			—			14
Interest expense		—		—		—			39			39

Income from continuing operations before income taxes	$	210	$	6	$	—		$	(84	)	$	132

Capital Expenditures	$	107	$	—	$	—		$	—		$	107

Three months ended June 30, 2003 (millions):


					Intersegment
	Natural Gas		NGL		Eliminations			Other			Total
	Segment		Segment		(a)			(c)			Company
Operating Revenues	$	1,872	$	450	$	(266	)	$	—		$	2,056
Gross Margin(b)		302		8		—			—			310
Other operating and administrative costs		111		2		—			41			154
Depreciation and amortization		66		4		—			5			75
Earnings from unconsolidated affiliates		11		1		—			—			12
Interest expense		—		—		—			42			42

Income from continuing operations before income taxes	$	136	$	3	$	—		$	(88	)	$	51

Capital Expenditures	$	31	$	—	$	—		$	1		$	32

Six months ended June 30, 2004 (millions):


					Intersegment
	Natural Gas		NGL		Eliminations			Other			Total
	Segment		Segment		(a)			(c)			Company
Operating Revenues	$	4,381	$	1,060	$	(657	)	$	—		$	4,784
Gross Margin(b)		713		32		—			—			745
Other operating and administrative costs		196		5		—			82			283
Depreciation and amortization		135		7		—			8			150
Earnings from unconsolidated affiliates		31		—		—			—			31
Interest expense		—		—		—			79			79

Income from continuing operations before income taxes	$	413	$	20	$	—		$	(169	)	$	264

Capital Expenditures	$	130	$	—	$	—		$	2		$	132

Six months ended June 30, 2003 (millions):


					Intersegment
	Natural Gas		NGL		Eliminations			Other			Total
	Segment		Segment		(a)			(c)			Company
Operating Revenues	$	4,250	$	951	$	(578	)	$	—		$	4,623
Gross Margin(b)		581		25		—			—			606
Other operating and administrative costs		214		4		—			79			297
Depreciation and amortization		134		7		—			9			150
Earnings from unconsolidated affiliates		24		—		—			—			24
Interest expense		—		—		—			84			84

Income from continuing operations before income taxes	$	257	$	14	$	—		$	(172	)	$	99

Capital Expenditures	$	64	$	—	$	—		$	2		$	66


	As of
	June 30,		December 31,
	2004		2003
	(millions)
Total assets:
Natural Gas	$	4,957	$	5,074
NGL		271		271
Corporate (c)		1,488		1,169

Total assets	$	6,716	$	6,514

(a)

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

(b)

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

(c)

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

10. Guarantor’s Obligations Under Guarantees

On January 1, 2004, we were the guarantor of $3 million of debt for an affiliate. The guaranteed debt was repaid in full in January of 2004.

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

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

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

Overview

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

•

Natural gas gathering, processing, transportation and storage, from which we generate revenues primarily by providing services such as compression, gathering, treating, processing, transportation of residue gas, storage and trading and marketing (the “Natural Gas Segment”). In the first six months of 2004, approximately 81% of our operating revenues prior to intersegment revenue elimination and approximately 96% of our gross margin were derived from this segment.

•

NGL fractionation, transportation, marketing and trading, from which we generate revenues from transportation fees, market center fractionation and the marketing and trading of NGL (the “NGL Segment”). In the first six months of 2004, approximately 19% of our operating revenues prior to intersegment revenue elimination and approximately 4% of our gross margin were derived from this segment.

•

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

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

Effects of Commodity Prices

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

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

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

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

be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. The number of active oil and gas rigs drilling in the United States were 170 and 1,005, respectively, as of June 30, 2004, compared to 144 and 924, respectively, as of June 30, 2003. This increase is mainly attributable to recent significant increases in natural gas prices which could result in sustained increases in drilling activity during 2004. However, energy market uncertainty could negatively impact North American drilling activity in the short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

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

Effects of Our Raw Natural Gas Supply Arrangements

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

•

Percentage-of-Proceeds Contracts — Under these contracts we receive as our fee a negotiated percentage of the residue natural gas and NGL value derived from our gathering and processing activities, with the producer retaining the remainder of the value or product. These types of contracts permit us and the producers to share proportionately in commodity price changes. Under these contracts, we share in both the increases and decreases in natural gas prices and NGL prices.

•

Fee-Based Contracts — Under these contracts we receive a set fee for gathering, processing and/or treating raw natural gas. Our revenue stream from these contracts is correlated with our level of gathering and processing activity and is not directly dependent on commodity prices.

•

Keep-Whole and Wellhead Purchase Contracts – Under the terms of a wellhead purchase contract, we purchase raw natural gas from the producer at the wellhead or defined receipt point for processing and then market the resulting NGL and residue gas at market prices. Under the terms of a keep-whole processing contract, we gather raw natural gas from the producer for processing and then we market the NGL and return to the producer residue natural gas with a Btu content equivalent to the Btu content of the raw natural gas gathered. This arrangement keeps the producer whole to the thermal value of the raw natural gas we received. Under these types of contracts the Company is exposed to the “frac spread”. The frac spread is the difference between the value of the NGL extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL prices are higher relative to natural gas prices.

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

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

Our current mix of percentage-of-proceeds contracts (where we are exposed to decreases in natural gas prices) and keep-whole and wellhead purchase contracts (where we are exposed to increases in natural gas prices) helps to mitigate our exposure to changes in natural gas prices. Our hedging program is designed to adequately plan for cash

needed for debt service, capital expenditures and tax distributions. However, we do not currently anticipate using cash flow hedges in 2005 because management believes cash flows will be sufficient to fund the Company’s business.

Accounting Adjustments

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

Results of Operations


	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	(millions)						(millions)
Operating revenues:
Natural gas segment	$	2,177		$	1,872		$	4,381		$	4,250
NGL segment		482			450			1,060			951
Intersegment eliminations		(277	)		(266	)		(657	)		(578	)

Total operating revenues		2,382			2,056			4,784			4,623
Purchases of natural gas and petroleum products		2,002			1,746			4,039			4,017

Gross margin (a)		380			310			745			606
Costs and expenses		223			229			433			447
Equity in earnings of unconsolidated affiliates		14			12			31			24

EBIT from continuing operations before Cumulative effect of accounting change (b)		171			93			343			183
Interest expense, net		39			42			79			84
Income tax expense		2			—			5			2
Income from discontinued operations		—			31			5			37
Cumulative effect of change in accounting principles		—			—			—			(23	)

Net income	$	130		$	82		$	264		$	111

(a)

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

(b)

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

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

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

•

$175 million increase was attributable to a $0.12 per gallon increase in average NGL prices;

•

$125 million increase was attributable to a $0.58 per MMBtu increase in average natural gas prices;

•

$35 million increase related to the acquisition of gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips;

•

$30 million decrease primarily related to wholesale propane marketing activity partially offset by higher NGL sales volumes; and

•

$20 million increase from higher processed volumes resulting from favorable processing economics.

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

•

$240 million increase due to higher average costs of raw natural gas supply;

•

$30 million increase related to the acquisition of gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips; and

•

$10 million decrease from lower wholesale propane marketing activity.


	Three Months Ended June 30,
	2004		2003
	(millions)
Gross Margin:
Natural gas segment	$	368	$	302
NGL segment		12		8

Total gross margin	$	380	$	310

Gross Margin — Total gross margin increased $70 million, or 23% to $380 million in the second quarter of 2004 from $310 million in the same period of 2003.

Gross margin associated with the Natural Gas Segment increased $66 million, or 22%, to $368 million in the second quarter of 2004 from $302 million in the same period of 2003, mainly as a result of the following factors:

•

$60 million increase (net of hedging) was the result of commodity sensitive processing arrangements, mainly due to higher average NGL and crude oil prices; and

•

$10 million decrease relating to lower throughput volumes;

•

$8 million increase related to improved operational and commercial performance; and

•

$5 million increase primarily related to the acquisition of gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips.

Gross margin associated with the NGL Segment increased $4 million, or 50% to $12 million in the second quarter 2004 from $8 million for the same period in 2003. This increase was comprised primarily of an increase in trading and marketing net margin, wholesale propane marketing and NGL pipelines.

NGL production during the second quarter 2004 increased 19,000 barrels per day, or 5%, to 371,000 barrels per day from 352,000 barrels per day in the same period of 2003, and natural gas transported and/or processed during the second quarter of 2004 decreased 0.1 trillion Btus per day, or 1%, to 7.5 trillion Btus per day from 7.6 trillion Btus per day during the same period of 2003. The primary cause of the increase in NGL production was processing elections associated with poor processing economics on keep-whole volumes in 2003 and the acquisition of processing assets in Southeast New Mexico in the second quarter of 2004.

Costs and Expenses — Operating and maintenance expenses decreased $6 million, or 5%, to $107 million in the second quarter of 2004 from $113 million in the same period of 2003. This decrease was primarily due to the following factors:

•

decreased expenses of approximately $3 million related to the consolidation of a previously

unconsolidated affiliate as required by FIN 46R (see Note 2 to the Consolidated Financial Statements). Certain operating costs paid by us to this affiliate are now eliminated in consolidation of this affiliate; and

•

decreased environmental remediation expense of approximately $4 million.

Interest Expense, net — Interest expense, net, decreased $3 million, or 7% to $39 million in the second quarter of 2004 from $42 million in the same period of 2003. This decrease was primarily the result of lower interest expense due to lower outstanding debt and an increase in interest income from higher cash investments which reduced interest expense in the second quarter of 2004 compared with the second quarter of 2003.

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

Income from Discontinued Operations – Income from discontinued operations was $31 million in the second quarter of 2003. Income from discontinued operations includes gains on the sale of discontinued operations and the results of such operations (see Note 3 to the Consolidated Financial Statements).

Six months ended June 30, 2004 compared with six months ended June 30, 2003

Operating Revenues – Total operating revenues increased $161 million, or 3%, to $4,784 million in the first six months of 2004 from $4,623 million in the same period of 2003. This increase was primarily due to the following factors:

•

$190 million increase was attributable to a $0.06 per gallon increase in average NGL prices;

•

$90 million decrease from lower throughput related to reduced raw natural gas supply volume, due to reservoir decline exceeding supply from new drilling activity and increased plant downtime due to maintenance;

•

$60 million decrease was attributable to a $0.16 per MMBtu decrease in average natural gas prices;

•

$37 million increase from trading and marketing net margin primarily due to natural gas asset based trading and marketing;

•

$35 million increase related to the acquisition of gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips;

•

$22 million increase related to cash flow hedging which reduced revenues by approximately $41 million for the six months ended June 30, 2004 and by $63 million for the six months ended June 30, 2003;

•

$20 million increase related to higher NGL sales volumes; and

•

$15 million increase attributable to higher transportation, storage and processing fees which was primarily due to higher fees from processing contracts.

Purchases of Natural Gas and Petroleum Products – Purchases of natural gas and petroleum products increased $22 million, or 1%, to $4,039 million in the first six months of 2004 from $4,017 million in the same period of 2003. This increase was primarily due to the following factors:

•

$30 million increase related to the acquisition of gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips;

•

$60 million increase due to higher average costs of raw natural gas supply which is primarily due to an increase in average NGL prices partially offset by a decrease in natural gas prices;

•

$60 million decrease from lower processed raw natural gas supply volume; and

•

$8 million decrease related to expenses incurred in the first quarter of 2003 related to a contract litigation settlement.


	Six Months Ended June 30,
	2004		2003
	(millions)
Gross Margin:
Natural gas segment	$	713	$	581
NGL segment		32		25

Total gross margin	$	745	$	606

Gross Margin — Total Gross margin increased $139 million, or 23% to $745 million in the first six months of 2004 from $606 million in the same period of 2003.

Gross margin associated with the Natural Gas Segment increased $132 million, or 23%, to $713 million in the first six months of 2004 from $581 million in the same period of 2003, mainly as a result of the following factors:

•

$95 million increase (net of hedging) was the result of commodity sensitive processing arrangements, mainly due to higher average NGL and crude oil prices;

•

$23 million increase related to improved operational and commercial performance;

•

$15 million decrease related to lower throughput volumes;

•

$14 million increase was the result of $29 million of improved net trading margin offset by approximately $15 million of lower results related to physical natural gas asset based activity;

•

$8 million increase related to expenses incurred in the first quarter of 2003 related to a contract litigation settlement; and

•

$5 million increase related to the acquisition of gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips.

Gross margin associated with the NGL Segment increased $7 million, or 28% to $32 million in the first six months of 2004 from $25 million for the same period in 2003. This increase was comprised primarily of an increase in trading and marketing net margin.

NGL production during the first six months of 2004 increased 4,000 barrels per day, or 1%, to 364,000 barrels per day from 360,000 barrels per day in the same period of 2003, and natural gas transported and/or processed during the first six months of 2004 decreased 0.2 trillion Btus per day, or 3%, to 7.4 trillion Btus per day from 7.6 trillion Btus per day during the same period of 2003.

Costs and Expenses — Operating and maintenance expenses decreased $17 million, or 8%, to $201 million in the first six months of 2004 from $218 million in the same period of 2003. This decrease was primarily due to the following factors:

•

decreased expenses of approximately $8 million related to the consolidation of a previously unconsolidated affiliate as required by FIN 46R (see Note 2 to the Consolidated Financial Statements). Certain operating costs paid by us to this affiliate are now eliminated in consolidation of this affiliate; and

•

decreased environmental remediation expense of approximately $6 million.

Interest Expense, net — Interest expense, net, decreased $5 million, or 6% to $79 million in the first six months of 2004 from $84 million in the same period of 2003. This decrease was primarily the result of lower interest expense due to lower outstanding debt and an increase in interest income from higher cash investments which reduced interest expense in the first six months of 2004 compared with first six months of 2003.

Income Taxes — We are structured as a limited liability company, which is a pass-through entity for United States income tax purposes. Income tax expense of $5 million in the first six months of 2004 is attributable to earnings associated with tax-paying subsidiaries.

Income from Discontinued Operations – Income from discontinued operations was $5 million in the first six months of 2004 and $37 million in the first six months of 2003. Income from discontinued operations includes gains on the sale of discontinued operations and the results of such operations in both periods presented (see Note 3 to the Consolidated Financial Statements).

Cumulative Effect of Change in Accounting Principles — Cumulative effect of change in accounting principles was a loss of $23 million in the first six months of 2003. Of this amount, $18 million relates to the implementation of SFAS 143, and $5 million is due to the rescission of EITF 98-10 (see Note 2 to Consolidated Financial Statements).

Liquidity and Capital Resources

As of June 30, 2004, we had $253 million in cash and cash equivalents compared to $43 million as of December 31, 2003. Included in cash and cash equivalents as of June 30, 2004 was approximately $28 million held by our Canadian subsidiaries for their operations. The remaining cash balance was primarily available for general corporate purposes. Current assets exceeded current liabilities by $135 million at June 30, 2004 and current liabilities exceeded current assets by $73 million at December 31, 2003. We rely upon cash flows from operations and borrowings to fund our liquidity and capital requirements. A material adverse change in operations or available financing may impact our ability to fund our requirements for liquidity and capital resources.

Operating Cash Flows

During the first six months of 2004, cash provided by operating activities was $427 million, an increase of $206 million from $221 million in the first six months of 2003. This increase was due primarily to a $153 million increase in net income. The increase in net income is due largely to the favorable effects of commodity prices, net of hedging, improved results from trading and marketing activities, and decreased operating expenses, partially offset by lower volumes. Additional increases were the result of changes in working capital balances and unrealized mark-to-market and hedging activity.

Cash distributions received from unconsolidated affiliates were $38 million in the first six months of 2004 and $31 million in the first six months of 2003. These distributions were in excess of earnings from unconsolidated affiliates by $7 million in each period.

Volatility in crude oil, NGL and natural gas prices and the structure of our commodity supply contracts have a direct impact on our generation and use of cash from operations due to its impact on net income as described in the Effects of Commodity Prices section above, along with the resulting changes in working capital.

Investing Cash Flows

During the first six months of 2004, cash used in investing activities was $62 million, a decrease of $90 million from cash provided by investing activities of $28 million in the first six months of 2003. Our capital expenditures consist of expenditures for construction and acquisition of additional gathering systems, processing plants, fractionators and other facilities and infrastructure in addition to well connections and upgrades to our existing facilities. For the first six months of 2004, we spent approximately $132 million on capital expenditures for continuing operations compared to $66 million in the first six months of 2003. The increase is due to the acquisition of gathering, processing and transmission assets in Southeast New Mexico, partially offset by reduced well connections and plant upgrades in the first six months of 2004, as compared to the same period in 2003. The cash used for capital expenditures is partially offset by proceeds of $62 million from the sale of discontinued operations.

Our level of capital expenditures for acquisitions and construction and other investments depends on many factors, including industry conditions, the availability of attractive acquisition opportunities and construction projects, the level of commodity prices and competition. We expect to finance our capital expenditures with our cash on hand, cash flow from operations, asset sales, our credit facility or other available sources of financing. Our capital expenditures forecast for the year ending December 31, 2004 is approximately $220 million. Depending on cash flow results, redeployment of capital from divestitures and opportunities in the marketplace, 2004 acquisition and capital expenditures may vary from the forecast.

Financing Cash Flows

Bank Financing and Commercial Paper

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

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

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

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

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

Distributions

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

In 2003, our board of directors approved a plan to consider the payment of a quarterly dividend to our members. Our board of directors may consider net income, cash flow or any other criteria deemed appropriate for determining the amount of the quarterly dividend to be paid. Our LLC Agreement restricts making distributions, which would include these dividends, except with the approval of both members. During the six months ended June 30, 2004, with the approval of both members, we paid total dividends of $137 million to the members, allocated in accordance with their respective ownership percentages.

Contractual Obligations, Commercial Commitments and Off-Balance Sheet Arrangements

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

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

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

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

New Accounting Standards

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

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

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

Acquisitions and Dispositions

In February 2004, we entered into a purchase and sale agreement to sell gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million. The transaction closed in the first quarter of 2004 with no significant book gain or loss.

Item 3. Quantitative and Qualitative Disclosure about Market Risks

Risk and Accounting Policies

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

Commodity Price Risk

We are exposed to the impact of market fluctuations primarily in the price of NGL that we own as a result of our processing activities. We employ established policies and procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including forward contracts, swaps, futures and options. (See Notes 2 and 4 to the Consolidated Financial Statements.)

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

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

Daily Value at Risk (millions)

Estimated Average

High One-Day

Low One-Day

One-Day Impact

Impact on EBIT

on EBIT for the

for the three

three months ended

months ended

June 30, 2004

June 30, 2003

June 30, 2004

Calculated DVaR

—

Daily Value at Risk (millions)

Estimated Average

High One-Day

Low One-Day

One-Day Impact

Impact on EBIT

on EBIT for the

for the six

six months ended

months ended

June 30, 2004

June 30, 2003

June 30, 2004

Calculated DVaR

—

DVaR is an estimate based on historical price volatility. Actual volatility can exceed predicted results. DVaR also assumes a normal distribution of price changes, thus if the actual distribution is not normal, the DVaR may understate or overstate actual results. DVaR is used to estimate the risk of the entire portfolio, and for locations that do not have daily trading activity, it may not accurately estimate risk due to limited price information. Stress tests may be employed in addition to DVaR to measure risk where market data information is limited. In the current DVaR methodology, options are modeled in a manner equivalent to forward contracts which may understate the risk.

Our exposure to commodity price risk is influenced by a number of factors, including contract size, length of contract, market liquidity, location and unique or specific contract terms. Effective January 1, 2003, in connection with the implementation of EITF 02-03, the Company designates each commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or sale contract, while certain non-trading derivatives, which are related to our asset based marketing, are non-trading mark-to-market derivatives. For each of the Company’s derivatives, the accounting method and presentation of gains and losses or revenue and expense in the Consolidated Statements of Operations are as follows:


Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Trading Derivatives	Mark-to-market^a	Net basis in Trading and marketing net margin
Non-Trading Derivatives:
Cash Flow Hedge	Hedge method^b	Gross basis in the same income statement category as the related hedged item
Fair Value Hedge	Hedge method^b	Gross basis in the same income statement category as the related hedged item
Normal Purchase or Normal Sale	Accrual method^c	Gross basis upon settlement in the corresponding income statement category based on commodity type
Non-Trading Mark-to- Market	Mark-to-market^a	Net basis in Trading and marketing net margin

The fair value of our mark-to-market contracts is expected to be realized in future periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events that could impact the amount and/or realization of these values.

When available, quoted market prices are used to record a contract’s fair value. However, market values for energy trading contracts may not be readily determinable because the duration of the contracts could exceed the liquid activity in a particular market. If no active trading market exists for a commodity or for a contract’s duration, holders of these contracts must calculate fair value using internally developed valuation techniques or models. Key components used in these valuation techniques include price curves, volatility, correlation, interest rates, and tenor. Of these components, volatility and correlation are the most subjective. Internally developed valuation techniques include the use of interpolation, extrapolation, and fundamental analysis in the calculation of a contract’s fair value. All risk components for new and existing transactions are valued using the same valuation technique and market data and discounted using a LIBOR based interest rate. Valuation adjustments for performance, market risk and administration costs are used to adjust the fair value of the contract to the gain or loss ultimately recognized in the Consolidated Statements of Operations.

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


	Fair Value of Mark-to-Market Contracts as of June 30, 2004 (millions)
	Maturity in			Maturity in			Maturity in			Maturity in 2007			Total
Sources of Fair Value	2004			2005			2006			and Thereafter			Fair Value
Trading:
Prices supported by quoted market prices and other external sources	$	11		$	6		$	(2	)	$	—		$	15
Prices based on models and other valuation methods		—			—			—			(2	)		(2	)

Total Trading		11			6			(2	)		(2	)		13

Non-Trading:
Prices supported by quoted market prices and other external sources		(1	)		(3	)		—			—			(4	)
Prices based on models and other valuation methods		—			—			—			—			—

Total Non-Trading		(1	)		(3	)		—			—			(4	)

Total Mark-to-Market	$	10		$	3		$	(2	)	$	(2	)	$	9

The “Prices supported by quoted market prices and other external sources” category includes our New York Mercantile Exchange (“NYMEX”) swap positions in natural gas and crude oil. The NYMEX has currently quoted prices for the next 32 months. In addition, this category includes our forward positions and options in natural gas and natural gas basis swaps at points for which over-the-counter (“OTC”) broker quotes are available. On average, OTC quotes for natural gas forwards and swaps extend 22 and 32 months into the future, respectively. OTC quotes for natural gas options extend 12 months into the future, on average. We value these positions against internally developed forward market price curves that are validated and recalibrated against OTC broker quotes. This category also includes “strip” transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate.

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

Hedging Strategies — We are exposed to market fluctuations in the prices of energy commodities related to natural gas gathering, processing and marketing activities. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, may use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge the value of our assets and operations from such price risks. Our hedging program has historically reduced the potential negative impact that commodity price changes could have on our earnings and has improved our ability to adequately plan for cash needed for debt service and

capital expenditures. However, we do not currently anticipate using cash flow hedges in 2005 because management believes cash flows will be sufficient to fund the Company’s business.

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

We have utilized derivative instruments not only to hedge commodity exposures, but also to hedge interest rate exposures (as discussed in the Interest Rate Risk section on page 31). As mentioned previously, the effective portion of the gains and losses for any of our hedging contracts are not recognized in earnings until the contracts mature at their future market price. Therefore, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to contract maturity for the effective portion of these hedges.

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


	Fair Value of Hedging Contracts as of June 30, 2004 (millions)
								Maturity in
	Maturity in			Maturity in		Maturity in		2007 and			Total Fair
Sources of Fair Value	2004			2005		2006		Thereafter			Value
Prices supported by quoted market prices and other external sources	$	(12	)	$	5	$	2	$	(6	)	$	(11	)
Prices based on models or other valuation techniques		—			—		—		—			—

Total	$	(12	)	$	5	$	2	$	(6	)	$	(11	)

Based upon our portfolio of supply contracts, without giving effect to hedging activities that would reduce the impact of commodity price decreases, a decrease of $0.01 per gallon in the price of NGL and $0.10 per million Btus in the average price of natural gas would result in changes in annual pre-tax net income of approximately $(19) million and $1 million, respectively. In addition, a decrease of $1 per barrel in the average price of crude oil would result in a change to annual pre-tax net income of approximately $(5) million.

Credit Risk

Our principal customers in the Natural Gas Segment are large, natural gas marketing services and industrial end-users. In the NGL segment, our principal customers range from large multi-national petrochemical and refining companies to small regional propane distributors. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 40% of our NGL production is committed to ConocoPhillips and ChevronPhillips; under an existing 15-year contract which expires in 2015. This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. The

corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure. Collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, the Company’s standard gas and NGL sales contracts contain adequate assurance provisions which allow the Company to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment in a form satisfactory to the Company.

As of June 30, 2004, we held cash or letters of credit of $74 million to secure future performance by counterparties, and had deposited with counterparties $3 million of such collateral to secure our obligations to provide future services or to perform under financial contracts. Collateral amounts held or posted may be fixed or may vary depending on the value of the underlying contracts and could cover normal purchases and sales, trading and hedging contracts. In many cases, we and our counterparties’ publicly disclosed credit ratings impact the amounts of collateral requirements.

Interest Rate Risk

We enter into debt arrangements that are exposed to market risks related to changes in interest rates. We periodically utilize interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with debt. Our primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for our debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical averages. As of June 30, 2004, the fair value of our interest rate swaps was an asset of $6 million.

As of June 30, 2004, we had no outstanding commercial paper. As a result of our debt and interest rate swaps, we are exposed to market risks related to changes in interest rates. In the future, we intend to manage our interest rate exposure using a mix of fixed and floating interest rate debt. An increase of 0.5% in interest rates would result in an increase in annual interest expense of approximately $2 million.

Foreign Currency Risk

Our primary foreign currency exchange rate exposure at June 30, 2004 was the Canadian dollar. Foreign currency risk associated with this exposure was not significant.

Item 4. Controls and Procedures

Our management, including the Chief Financial Officer and the Chief Executive Officer, have evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and concluded that, as of the end of the period covered by this report, the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this quarterly report has been made known to them in a timely fashion. The required information was effectively recorded, processed, summarized and reported within the time period necessary to prepare this quarterly report. Our disclosure controls and procedures are effective in ensuring that information required to be disclosed in our reports under the Exchange Act are accumulated and communicated to management, including the Chief Financial Officer and the Chief Executive Officer, as appropriate to allow timely decisions regarding required disclosure.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information concerning litigation and other contingencies, see Part I. Item 1, Note 8 to the Consolidated Financial Statements, “Commitments and Contingent Liabilities,” of this report and Item 3, “Legal Proceedings,” included in our Form 10-K for December 31, 2003, which are incorporated herein by reference.

Management believes that the resolution of the matters referred to above will not have a material adverse effect on the consolidated results of operations or financial position of the Company.

Item 6. Exhibits and Reports on Form 8-K

(a)

Exhibits


	31.1			Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2			Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1			Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2			Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b)		Reports on Form 8-K

		None.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		DUKE ENERGY FIELD SERVICES, LLC

August 10, 2004

		/s/ Rose M. Robeson

		Rose M. Robeson
		Vice President and Chief Financial Officer
		(On Behalf of the Registrant and as
		Principal Financial and Accounting Officer)

EXHIBIT INDEX


Exhibit
No.		Description
	31.1	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32.2	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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DUKE ENERGY FIELD SERVICES LLC 10-Q