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, 2003		Commission File Number 0-31095

DUKE ENERGY FIELD SERVICES, LLC

(Exact name of registrant as specified in its charter)


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

370 17th Street, Suite 900
Denver, Colorado 80202
(Address of principal executive offices)
(Zip Code)

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

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

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONSOLIDATED STATEMENTS OF OPERATIONS
		CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		CONSOLIDATED BALANCE SHEETS
		CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosure about Market Risks
	Item 4. Controls and Procedures
PART II. OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURES
EXHIBIT INDEX
EX-10.1 Third Amendment to Contract for Services
EX-31.1 Certification of CEO Pursuant to Sec. 302
EX-31.2 Certification of CFO Pursuant to Sec. 302
EX-32.1 Certification of CEO Pursuant to Sec. 906
EX-32.2 Certification of CFO Pursuant to Sec. 906

DUKE ENERGY FIELD SERVICES, LLC
FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2003

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, 2003 and 2002		1
	Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2003 and 2002		2
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2003 and 2002		3
	Consolidated Balance Sheets as of June 30, 2003 and December 31, 2002		4
	Condensed Notes to Consolidated Financial Statements		5
2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			16
3. Quantitative and Qualitative Disclosure about Market Risks			26
4. Controls and Procedures			30
PART II. OTHER INFORMATION
1. Legal Proceedings			31
6. Exhibits and Reports on Form 8-K			31
Signatures			32

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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

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

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

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

	•		the level of creditworthiness of counterparties to transactions;

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

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

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

	•		weather and other natural phenomena;

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

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

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

	•		the effect of accounting policies issued periodically by accounting standard-setting bodies; and

	•		general economic conditions, including any potential effects arising from terrorist attacks, the situation in Iraq and any consequential hostilities or other hostilities.

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

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


			Three Months Ended,						Six Months Ended,
			June 30,						June 30

			2003			2002			2003			2002

OPERATING REVENUES:
	Sales of natural gas and petroleum products		$	1,230,955		$	670,206		$	2,674,069		$	1,278,630
	Sales of natural gas and petroleum products—affiliates			578,009			564,229			1,502,393			973,969
	Transportation, storage and processing			67,406			62,978			127,931			120,274
	Trading and marketing net margin			1,403			3,519			(32,791	)		10,828

		Total operating revenues		1,877,773			1,300,932			4,271,602			2,383,701

COSTS AND EXPENSES:
	Purchases of natural gas and petroleum products			1,371,225			937,832			3,261,917			1,696,986
	Purchases of natural gas and petroleum products—affiliates			191,394			130,167			392,745			210,659
	Operating and maintenance			114,584			105,695			220,959			210,362
	Depreciation and amortization			76,268			69,160			152,078			140,587
	General and administrative			34,696			33,361			71,414			70,059
	General and administrative—affiliates			5,632			5,752			8,344			8,211
	Other			(60	)		1,907			(158	)		7,095

		Total costs and expenses		1,793,739			1,283,874			4,107,299			2,343,959

OPERATING INCOME				84,034			17,058			164,303			39,742
EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES				11,816			7,836			23,870			13,906
INTEREST EXPENSE, NET				41,759			42,295			84,497			85,604

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES				54,091			(17,401	)		103,676			(31,956	)
INCOME TAX EXPENSE				281			3,313			2,052			5,614

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES				53,810			(20,714	)		101,624			(37,570	)
GAIN (LOSS) FROM DISCONTINUED OPERATIONS				28,709			(630	)		32,357			(774	)
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES				—			—			(22,802	)		—

NET INCOME (LOSS)				82,519			(21,344	)		111,179			(38,344	)
DIVIDENDS ON PREFERRED MEMBERS’ INTEREST				4,750			7,125			9,500			14,250

EARNINGS (DEFICIT) AVAILABLE FOR MEMBERS’ INTEREST			$	77,769		$	(28,469	)	$	101,679		$	(52,594	)

See Notes to Consolidated Financial Statements.

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


			Three Months Ended,						Six Months Ended,
			June 30,						June 30,

			2003			2002			2003			2002

NET INCOME (LOSS)			$	82,519		$	(21,344	)	$	111,179		$	(38,344	)
OTHER COMPREHENSIVE INCOME (LOSS):
	Foreign currency translation adjustment			24,931			13,451			45,059			11,107
	Net unrealized losses on cash flow hedges			(24,858	)		(4,339	)		(61,241	)		(61,439	)
	Reclassification of (gains) losses from cash flow hedges into earnings			24,542			2,542			66,226			(15,992	)

		Total other comprehensive income (loss)		24,615			11,654			50,044			(66,324	)

TOTAL COMPREHENSIVE INCOME (LOSS)			$	107,134		$	(9,690	)	$	161,223		$	(104,668	)

See Notes to Consolidated Financial Statements.

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


					Six Months Ended,
					June 30,

					2003			2002

CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income (loss)				$	111,179		$	(38,344	)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		(Gain) loss on discontinued operations				(32,357	)		774
		Cumulative effect of changes in accounting principles				22,802			—
		Depreciation and amortization				152,078			140,587
		Deferred income tax benefit				(29	)		(710	)
		Equity in earnings of unconsolidated affiliates				(23,870	)		(13,906	)
		Other, net				10,174			6,221
	Change in operating assets and liabilities which provided (used) cash:
		Accounts receivable				(195,252	)		13,441
		Accounts receivable—affiliates				128,009			114,121
		Inventories				23,336			(11,784	)
		Net unrealized loss (gain) on mark-to-market and hedging transactions				(32,467	)		46,103
		Other current assets				(17,954	)		4,313
		Other noncurrent assets				(3,300	)		(1,105	)
		Accounts payable				98,993			(43,712	)
		Accounts payable—affiliates				(64,458	)		(10,737	)
		Accrued interest payable				343			(2,890	)
		Other current liabilities				13,796			15,397
		Other long term liabilities				(260	)		9,256

			Net cash provided by continuing operations			190,763			227,025
			Net cash provided by discontinued operations			8,619			3,684

				Net cash provided by operating activities		199,382			230,709

CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures					(67,650	)		(165,203	)
	Investment expenditures, net of cash acquired					(512	)		7,620
	Investment distributions					31,058			24,040
	Contributions to minority interests, net					(538	)		—
	Proceeds from sales of discontinued operations					90,173			—
	Proceeds from sales of assets					5,484			—

			Net cash provided by (used in) continuing operations			58,015			(133,543	)
			Net cash used in discontinued operations			(2,946	)		(1,190	)

				Net cash provided by (used in) investing activities		55,069			(134,733	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Distributions to members					—			(63,162	)
	Short term debt, net					(115,104	)		(23,930	)
	Payment of debt					(359	)		(152	)
	Payment of dividends					(9,500	)		(14,250	)

			Net cash used in continuing operations			(124,963	)		(101,494	)
			Net cash used in discontinued operations			—			—

				Net cash used in financing activities		(124,963	)		(101,494	)

EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH						(1,225	)		2,007

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS						128,263			(3,511	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD						24,783			4,906

CASH AND CASH EQUIVALENTS, END OF PERIOD					$	153,046		$	1,395

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION –
	Cash paid for interest (net of amounts capitalized)				$	82,164		$	84,402

See Notes to Consolidated Financial Statements.

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


				June 30,			December 31,
				2003			2002

ASSETS
CURRENT ASSETS:
	Cash and cash equivalents			$	153,046		$	24,783
	Accounts receivable:
		Customers, net			802,131			599,116
		Affiliates			58,568			186,577
		Other			43,613			50,466
	Inventories				57,847			86,559
	Unrealized gains on mark-to-market and hedging transactions				157,942			158,891
	Other				24,033			6,713

			Total current assets		1,297,180			1,113,105

PROPERTY, PLANT AND EQUIPMENT, NET					4,540,213			4,642,204
INVESTMENT IN AFFILIATES					171,326			179,684
INTANGIBLE ASSETS:
	Natural gas liquids sales and purchases contracts, net				85,302			84,304
	Goodwill, net				444,219			435,115

			Total intangible assets		529,521			519,419

UNREALIZED GAINS ON MARK-TO-MARKET AND HEDGING TRANSACTIONS					37,813			21,685
OTHER NONCURRENT ASSETS					91,840			89,504

TOTAL ASSETS				$	6,667,893		$	6,565,601

LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
	Accounts payable:
		Trade		$	764,245		$	656,126
		Affiliates			12,551			77,009
		Other			36,661			45,786
	Short term debt				105,072			215,094
	Unrealized losses on mark-to-market and hedging transactions				203,111			245,469
	Accrued interest payable				59,637			59,294
	Accrued taxes other than income				24,217			31,059
	Other				100,341			89,427

			Total current liabilities		1,305,835			1,419,264

DEFERRED INCOME TAXES					12,883			11,740
LONG TERM DEBT					2,263,236			2,255,508
UNREALIZED LOSSES ON MARK-TO-MARKET AND HEDGING TRANSACTIONS					33,401			15,336
OTHER LONG TERM LIABILITIES					127,828			88,370
MINORITY INTERESTS					122,424			124,820
PREFERRED MEMBERS’ INTEREST					200,000			200,000
COMMITMENTS AND CONTINGENT LIABILITIES
MEMBERS’ EQUITY:
	Members’ interest				1,709,290			1,709,290
	Retained earnings				907,798			806,119
	Accumulated other comprehensive loss				(14,802	)		(64,846	)

			Total members’ equity		2,602,286			2,450,563

TOTAL LIABILITIES AND MEMBERS’ EQUITY				$	6,667,893		$	6,565,601

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

2. Accounting Policies

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

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 and cash flows for the respective periods. Amounts reported in the interim Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods.

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

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

Accounting for Hedges and Commodity Trading and Marketing Activities — All derivatives not qualifying for the normal purchases and sales exception under Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, are recorded in the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. Prior to the implementation of the remaining provisions of EITF Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities” on January 1, 2003, certain non-derivative energy trading contracts were also recorded on the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. See the Cumulative Effect of Changes in Accounting Principles section below for further discussion of the implementation of the provisions of EITF Issue No. 02-03.

Effective January 1, 2003, in connection with the implementation of the remaining provisions of EITF Issue No. 02-03, the Company designates each energy 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 flows (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 remain undesignated.

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

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

Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating the positions held in an orderly manner over a reasonable time period under current conditions. Changes in market 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 a contract is settled, the realized gain or loss is reclassified to a receivable or payable account. Settlement has no revenue presentation effect on the Consolidated Statements of Operations.

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

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

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

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

Income Taxes — The Company is required to make quarterly distributions to Duke Energy and ConocoPhillips based on allocated taxable income. The distributions are based on the highest taxable income allocated to either

member, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 69.7% for Duke Energy and 30.3% for ConocoPhillips.

Stock-Based Compensation — Under Duke Energy’s 1998 Long Term Incentive Plan, stock options for Duke Energy’s common stock may be granted to the Company’s key employees. The Company accounts for stock-based compensation using the intrinsic value recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and FASB Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the date of grant, no compensation cost is recognized in the accompanying Consolidated Statements of Operations. Restricted stock grants, phantom stock awards and stock-based performance awards are recorded over the required vesting period as compensation cost, based on the market value on the date of grant. The following disclosures reflect the provisions of SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of FASB Statement No. 123.”

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


	Three months ended,						Six month ended,
	June 30,						June 30,
Pro Forma Stock-Based Compensation
(in thousands)	2003			2002			2003			2002

Earnings (Deficit) available for members’ interest, as reported	$	77,769		$	(28,469	)	$	101,679		$	(52,594	)
Add: stock-based compensation expense included in reported net income (loss)		387			314			637			615
Deduct: total stock-based compensation expense determined under fair value-based method for all awards		(2,078	)		(2,117	)		(3,240	)		(3,757	)

Pro forma earnings (deficit) available for members’ interest	$	76,078		$	(30,272	)	$	99,076		$	(55,736	)

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


				Net			Accumulated
Accumulated Other Comprehensive	Foreign			Unrealized			Other
Income (Loss)	Currency			(Losses) Gains on			Comprehensive
(in thousands)	Adjustments			Cash Flow Hedges			(Loss) Income

Balance as of December 31, 2002	$	(6,728	)	$	(58,118	)	$	(64,846	)
Other comprehensive income changes during the period		45,059			4,985			50,044

Balance as of June 30, 2003	$	38,331		$	(53,133	)	$	(14,802	)

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

New Accounting Standards — In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 requires that certain financial instruments that could previously be accounted for as equity, be classified as liabilities in statements of financial position and initially recorded at fair value. In addition to its requirements for the classification and measurement of financial instruments in its scope, SFAS No. 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 No. 150 are effective for all financial instruments entered into or modified after May 31, 2003, and are otherwise effective at the beginning of the first interim period beginning after June 15, 2003. Upon adoption on July 1, 2003, the Company will reclassify its preferred members’ interest to long-term liabilities at its fair value of approximately $200 million. Future disbursements previously classified as dividends on these preferred members’ interest will be classified as interest expense.

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

In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities.” FIN 46 requires an entity to consolidate a variable interest entity if it is the primary beneficiary of the variable interest entity’s activities. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. FIN 46 is immediately applicable to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003. For those variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 is required to be applied in the first fiscal year or interim period beginning after June 15, 2003. FIN 46 may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 also requires certain disclosures of an entity’s relationship with variable interest entities. The Company has not identified any variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003 and continues to assess the existence of any interests in variable interest entities created on or prior to January 31, 2003. It is reasonably possible that the Company will disclose information about variable interest entities upon the application of FIN 46, primarily as the result of investments it has in certain unconsolidated affiliates. For all of these unconsolidated affiliates, the Company believes that its maximum exposure to loss would be equal to its investment in these entities, plus its potential obligations under its guarantees of unconsolidated debt. At June 30, 2003, the Company’s total investment in, plus the value of any guaranteed debt for entities that have a reasonable possibility to be determined to be variable interest entities, was approximately $160.7 million. The Company continues to assess FIN 46 but does not anticipate that it will have a material impact on its consolidated results of operations, cash flows or financial position.

also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The Company adopted the initial recognition and measurement provisions of FIN 45 effective January 1, 2003. Adoption of the new interpretation had no material effect on the Company’s consolidated results of operations, cash flows or financial position.

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

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

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

In October 2002, the EITF also reached a consensus on Issue No. 02-03 that, effective for periods beginning after December 15, 2002, all gains and losses on all derivative instruments held for trading purposes should be shown on a net basis in the income statement. Gains and losses on non-derivative energy trading contracts should similarly be presented on a gross or net basis in connection with the guidance in Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Upon application of this presentation, comparative financial statements for prior periods are required to be reclassified to conform to the consensus other than for energy trading contracts that were shown on a net basis under Issue No. 98-10. Accordingly, for the three and six months ended June 30, 2003, derivative instruments that are held for trading and marketing purposes and are accounted for under mark-to-market accounting are included in Trading and Marketing Net Margin on the Consolidated Statements of Operations. For the three and six months ended June 30, 2002, Trading and Marketing Net Margin also includes the net margin on non-derivative energy trading contracts (primarily gas storage inventories and the related physical purchases and sales) that no longer qualify for net presentation after the rescission of Issue No. 98-10. The new gross versus net revenue presentation requirements had no impact on operating income or net income.

asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. The Company adopted the provisions of SFAS No. 143 as of January 1, 2003. In accordance with the transition provisions of SFAS No. 143, the Company recorded a cumulative-effect adjustment of $17.4 million as a reduction in 2003 earnings.

In May 2003, the EITF reached consensus in EITF Issue No. 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 Issue No. 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 Company is currently assessing the impact EITF Issue No. 01-08 will have on its consolidated results of operations, cash flows or financial position.

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

3. Derivative Instruments, Hedging Activities, Credit and Risk

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

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

Corporate economic risks — The Company enters into debt arrangements that are exposed to market risks related to changes in interest rates. The Company periodically uses interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with debt. The Company’s primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for the Company’s debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates.

Counterparty risks — The Company sells various commodities (i.e., natural gas, NGLs and crude oil) to a variety of customers. The natural gas customers include local utilities, industrial consumers, independent power producers and merchant energy trading organizations. The NGLs customers range from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of the Company’s NGLs sales are made at market-based prices, including approximately 40% of NGLs production that is committed to ConocoPhillips and Chevron Phillips Chemical LLC, under a contract with a primary term that expires on January 1, 2015. This concentration of credit risk may affect the Company’s overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. On transactions where the Company is exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. The corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure.

The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreements also provide that the failure to post collateral is sufficient cause to terminate a contract and liquidate all positions.

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

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

The Company uses natural gas, crude oil and NGLs swaps and options to hedge the impact of market fluctuations in the prices of NGLs, natural gas and other energy-related products. For the six months ended June 30, 2003, the Company recognized a net loss of $63.2 million, of which a $3.0 million gain represented the total ineffectiveness of all cash flow hedges and a $66.2 million loss represented the total derivative settlements. 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, 2003, $51.4 million of the deferred net losses on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedge transactions occur; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings. The maximum term over which the Company is hedging its exposure to the variability of future cash flows is three years.

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

For the six months ended June 30, 2003, the gains or losses representing the ineffective portion of the Company’s fair value hedges were not significant. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. The Company did not have any firm commitments that no longer qualified as fair value hedge items and therefore, did not recognize an associated gain or loss.

Interest rate fair value hedge — In October 2001, the Company entered into an interest rate swap to convert the fixed interest rate of $250.0 million of debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on a six-month London Interbank Offered Rate (“LIBOR”), which is re-priced semiannually through 2005. The swap meets conditions which permit the assumption of no ineffectiveness, as defined by SFAS No. 133. As such, for the life of the swap no ineffectiveness will be recognized. As of June 30, 2003, the fair value of the interest rate swap of $16.3 million was included in the Consolidated Balance Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions with an offset to the underlying debt included in Long Term Debt.

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

4. Asset Retirement Obligations

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

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

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

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

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


Pro forma Asset Retirement Obligation	(in thousands)

January 1, 2000	$	13,493
December 31, 2000		31,561
December 31, 2001		38,879
December 31, 2002		42,549

The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The following table rolls forward the asset retirement obligation from the balance at December 31, 2002 to June 30, 2003.


Reconciliation of Asset Retirement Obligation	(in thousands)

Balance as of January 1, 2003	$	42,549
Accretion expense		1,713
Other		(1,761	)

Balance as of June 30, 2003	$	42,501

5. Financing

Credit Facility with Financial Institutions — On March 28, 2003, the Company entered into a new credit facility (the “Facility”). The Facility replaces the credit facility that matured on March 28, 2003. The Facility is used to support the Company’s commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 26, 2004, however, any outstanding loans under the Facility at maturity may, at the Company’s option, be converted to a one-year term loan. The Facility is a $350.0 million revolving credit facility, of which $100.0 million can be used for letters of credit. The Facility requires the Company to maintain at all times a debt to total capitalization ratio of less than or equal to 53%; and maintain at the end of each

fiscal quarter an interest coverage ratio (defined to be the ratio of 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, as defined by the Facility, is defined to be earnings before interest, taxes and depreciation and amortization and other adjustments); and contains various restrictions applicable to dividends and other payments to the Company’s members. The Facility bears interest at a rate equal to, at the Company’s option and based on the Company’s current debt rating, either (1) LIBOR plus 1.25% per year or (2) the higher of (a) the JP Morgan Chase Bank prime rate plus 0.25% per year and (b) the Federal Funds rate plus 0.75% per year. At June 30, 2003, there were no borrowings against the Facility.

On March 28, 2003, the Company also entered into a $100.0 million funded short-term loan with a bank (the “Short-Term Loan”). The Short-Term Loan is used for working capital and other general corporate purposes. The Short-Term Loan matures on September 30, 2003, and may be repaid at any time. The Short-Term Loan has the same financial covenants as the Facility. The Short-Term Loan bears interest at a rate equal to, at the Company’s option, either (1) LIBOR plus 1.35% per year or (2) the higher of (a) the bank’s prime rate and (b) the Federal Funds rate plus 0.50% per year. Subsequent to June 30, 2003, the Company repaid the entire Short-Term Loan with funds generated from asset sales and operations.

6. Commitments and Contingent Liabilities

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

7. Business Segments

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

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


			Three						Six
			Months Ended						Months Ended
			June 30,						June 30,

			2003			2002			2003			2002

			(in thousands)
Operating revenues (b):
	Natural Gas, including trading and marketing net margin		$	1,916,801		$	1,335,959		$	4,353,905		$	2,361,192
	NGLs, including trading and marketing net margin			447,931			317,412			952,105			639,212
	Intersegment (a)			(486,959	)		(352,439	)		(1,034,408	)		(616,703	)

		Total operating revenues	$	1,877,773		$	1,300,932		$	4,271,602		$	2,383,701

Margin:
	Natural Gas, including trading and marketing net margin		$	308,933		$	222,319		$	592,766		$	449,387
	NGLs, including trading and marketing net margin			6,221			10,614			24,174			26,669

		Total margin	$	315,154		$	232,933		$	616,940		$	476,056

Other operating and administrative costs:
	Natural Gas		$	112,664		$	105,338		$	216,481		$	212,682
	NGLs			1,861			2,315			4,320			4,775
	Corporate			40,327			39,062			79,758			78,270

		Total other operating costs	$	154,852		$	146,715		$	300,559		$	295,727

Depreciation and amortization:
	Natural Gas		$	67,890		$	65,309		$	136,738		$	131,015
	NGLs			3,471			2,305			6,677			5,623
	Corporate			4,907			1,546			8,663			3,949

		Total depreciation and amortization	$	76,268		$	69,160		$	152,078		$	140,587

Equity in earnings of unconsolidated affiliates:
	Natural Gas		$	11,416		$	6,870		$	24,255		$	12,519
	NGLs			400			966			(385	)		1,387

		Total equity in earnings of unconsolidated affiliates	$	11,816		$	7,836		$	23,870		$	13,906

		Total corporate interest expense	$	41,759		$	42,295		$	84,497		$	85,604

Income (loss) from continuing operations before income taxes:
	Natural Gas		$	139,795		$	58,542		$	263,802		$	118,209
	NGLs			1,289			6,960			12,792			17,658
	Corporate			(86,993	)		(82,903	)		(172,918	)		(167,823	)

		Total income (loss) from continuing operations before income taxes	$	54,091		$	(17,401	)	$	103,676		$	(31,956	)

Capital expenditures:
	Natural Gas		$	31,421		$	46,998		$	65,421		$	149,426
	NGLs			25			6,717			52			6,896
	Corporate			1,292			5,285			2,177			8,881

		Total capital expenditures	$	32,738		$	59,000		$	67,650		$	165,203


			As of

			June 30,		December 31,
			2003		2002

			(in thousands)
Total assets:
	Natural Gas		$	5,157,262	$	5,187,704
	NGLs			259,713		293,398
	Corporate (c)			1,250,918		1,084,499

		Total assets	$	6,667,893	$	6,565,601

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

(b)		As a result of the Company’s review of its segment information, the Company has reclassified certain operating revenues from the NGLs Segment to the Natural Gas Segment and Intersegment for the three and six months ended June 30, 2002. These reclassifications had no effect on segment margin. For the three months ended June 30, 2002, these reclassifications resulted in an increase to the

		Natural Gas Segment revenues of approximately $336.9 million, a decrease to the NGLs Segment revenues of approximately $386.9 and an increase to Intersegment revenues of approximately $50.0 million. For the six months ended June 30, 2002, these reclassifications resulted in an increase to the Natural Gas Segment revenues of approximately $508.8 million, a decrease to the NGLs Segment revenues of approximately $572.5 and an increase to Intersegment revenues of approximately $63.7 million.

(c)		Includes items such as unallocated working capital, intercompany accounts and intangible and other assets.

8. Guarantor’s Obligations Under Guarantees

At June 30, 2003, the Company was the guarantor of approximately $94.1 million of debt associated with non-consolidated entities, of which $84.6 million is related to our 33.33% ownership interest in Discovery Producer Services, LLC (“Discovery”), and $9.5 million is related to our 50.0% ownership interest in GPM Gas Gathering, LLC (“GGG”). The guaranteed debt related to Discovery is due December 31, 2003, and is expected to be refinanced. The guaranteed debt related to GGG is scheduled to be repaid in full by January 31, 2004. In the event that the unconsolidated subsidiaries default on the debt payments, the Company would be required to pay the debt. Assets of the unconsolidated subsidiaries are pledged as collateral for the debt. At June 30, 2003, the Company had no liability recorded for the guarantees of the debt associated with the unconsolidated subsidiaries.

The Company periodically enters into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities related to the assets being acquired or divested. Typically, claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The survival periods on these indemnification provisions generally have terms of one to five years, although some are longer. The Company’s maximum potential exposure under these indemnification agreements can range depending on the nature of the claim and the particular transaction. The Company is 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, 2003, the Company had an approximate $1.5 million liability recorded for these outstanding indemnification provisions.

9. Accounting Adjustments

During 2002, the Company completed a comprehensive account reconciliation project to review and analyze its balance sheet accounts. This account reconciliation project identified the following five categories where account adjustments were necessary: operating expense accruals; gas inventory adjustments; gas imbalances; joint venture and investment accounting; and other balance sheet accounts. As a result of this account reconciliation project, the Company recorded numerous adjustments in 2002. For the three and six months ended June 30, 2002, adjustments totaling approximately $18 million and $29 million may be related to corrections of accounting errors in prior periods. However, management has determined that the charges related to error corrections are immaterial both individually and in the aggregate on both a quantitative and qualitative basis to the trends in the financial statements for the periods presented, the prior periods affected and to a fair presentation of the Company’s financial statements. In addition, numerous items identified in the account reconciliation project resulted from system conversions and otherwise unsupportable balance sheet amounts. Due to the nature of certain of these account reconciliation adjustments, it would be impractical to determine what periods such adjustments relate to. Accordingly, the corrections were made in the first six months 2002 financial statements.

10. Asset Sales

In the second quarter of 2003, the Company sold various gathering, transmission and processing assets, plus a minority interest in a partnership owning a gas processing plant, to two separate buyers for a combined sales price of approximately $90.2 million. These assets were included in the Company’s Natural Gas Segment as disclosed in Note 7. 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 these assets accounted for as discontinued operations.


		Three					Six
		Months Ended					Months Ended
		June 30,					June 30,

		2003		2002			2003		2002

				(in thousands)
Revenues		$	66,581	$	48,779		$	160,096	$	85,445
Operating income (loss)		$	2,502	$	(630	)	$	6,150	$	(774	)
Gain on sale			26,207		—			26,207		—

	Gain (loss) from discontinued operations	$	28,709	$	(630	)	$	32,357	$	(774	)

11. Subsequent Events

In July 2003, the Company entered into an agreement to sell approximately 900 vehicles for approximately $14 million. This is a sale-leaseback transaction whereby the Company sold the vehicles but will lease them back over a one year lease term. The lease expires in July 2004, with annual extensions exercisable at the Company’s option. The future minimum lease payments under the lease are approximately $15 million. The Company does not have an option to purchase the leased vehicles at the end of the minimum lease term. As the proceeds from the sale of the vehicles are equal to the net book value of the vehicles, no gain or loss has been recognized.

In August 2003, the Company entered into a purchase and sale agreement to sell certain gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million, plus or minus various adjustments that will be made at closing. The Company anticipates closing the transaction on September 30, 2003 with no significant book gain or loss.

For information on subsequent events related to financing matters, see Note 5, Financing.

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, 2003 and 2002. This discussion should be read in conjunction with the Consolidated Financial Statements and related notes included elsewhere in this report.

Overview

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

	•		natural gas gathering, processing, transportation and storage, from which we generate revenues primarily by providing services such as compression, gathering, treating, processing, transportation of residue gas, storage, and trading and marketing (the “Natural Gas Segment”). In the first six months of 2003, approximately 82% of our operating revenues prior to intersegment revenue elimination and approximately 96% of our gross margin were derived from this segment.

	•		NGLs fractionation, transportation, marketing and trading, from which we generate revenues from transportation fees, market center fractionation and the marketing and trading of NGLs (the “NGLs Segment”). In the first six months of 2003, approximately 18% of our operating revenues prior to intersegment revenue elimination and approximately 4% of our gross margin were derived from this segment.

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

Effects of Commodity Prices

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

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

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

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

We generally expect NGLs 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 by the demand generated by growth in the world economy. However, the relationship or correlation between crude oil prices and NGLs prices declined significantly during 2001 and 2002. In late 2002, this relationship strengthened and remained near historical trend levels during the first two quarters of 2003.

We believe that future natural gas prices will be influenced by supply deliverability, the severity of weather and the level of United States economic growth. The price increases in crude oil, NGLs and natural gas experienced during 2000 and first half of 2001 spurred increased natural gas drilling activity. However, a decline in commodity prices in late 2001, continuing into 2002, negatively affected drilling activity. The average number of active natural gas rigs drilling in the United States of America increased to 857 during the second quarter of 2003 from 670 during the second quarter of 2002. This increase is mainly attributable to recent significant increases in natural gas prices which could result in sustained increases in drilling activity during 2003. However, energy market uncertainty could negatively impact North American drilling activity in the short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

To better address the risks associated with volatile commodity prices, we employ a comprehensive commodity price risk management program. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and

NGLs contracts to hedge the value of our assets and operations from such price risks. See “Item 3. Quantitative and Qualitative Disclosure About Market Risk.” Our second quarter 2003 and 2002 results of operations include a hedging loss of $23.6 million and a hedging loss of $8.3 million, respectively. During the first six months of 2003 and 2002 our hedging activities resulted in a loss of $63.2 million and a loss of $0.9 million, respectively. The hedging losses incurred relate to hedges placed during periods of lower prices.

Results of Operations


			Three Months Ended June 30,					Six Months Ended June 30,

			2003		2002			2003			2002

			(in thousands)
Operating revenues:
	Sales of natural gas and petroleum products		$	1,808,964	$	1,234,435		$	4,176,462		$	2,252,599
	Transportation, storage and processing			67,406		62,978			127,931			120,274
	Trading and marketing net margin			1,403		3,519			(32,791	)		10,828

		Total operating revenues		1,877,773		1,300,932			4,271,602			2,383,701
	Purchases of natural gas and petroleum products			1,562,619		1,067,999			3,654,662			1,907,645

Gross margin (1)				315,154		232,933			616,940			476,056
Cost and expenses				231,120		215,875			452,637			436,314
Equity in earnings of unconsolidated affiliates				11,816		7,836			23,870			13,906
Gain (loss) from discontinued operations				28,709		(630	)		32,357			(774	)
Cumulative effect of changes in accounting principles				—		—			(22,802	)		—

EBIT (2)				124,559		24,264			197,728			52,874
Interest expense, net				41,759		42,295			84,497			85,604
Income tax expense				281		3,313			2,052			5,614

Net income (loss)			$	82,519	$	(21,344	)	$	111,179		$	(38,344	)

(1)		Gross margin consists of operating income before operating and maintenance expense, depreciation and amortization expense, general and administrative expense, and other expense. Gross margin is included as a supplemental disclosure because it may provide useful information regarding the impact of key drivers such as commodity prices and supply contract mix on our earnings.

(2)		EBIT consists of net income before net interest expense and income tax expense. EBIT is viewed as a non-Generally Accepted Accounting Principles (“GAAP”) measure under the rules of the Securities and Exchange Commission, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results 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, 2003 compared with three months ended June 30, 2002

Operating Revenues — Total operating revenues increased $576.9 million, or 44%, to $1,877.8 million in the second quarter of 2003 from $1,300.9 million in 2002. Of this increase, approximately $574.6 million was the result of higher sales of natural gas and petroleum products due to higher commodity prices. Other increases were attributable to transportation, storage and processing fees of approximately $4.4 million. These increases were partially offset by a decrease in trading and marketing net margin of $2.1 million.

Purchases of Natural Gas and Petroleum Products — Purchases of natural gas and petroleum products increased $494.6 million, or 46%, to $1,562.6 million in the second quarter of 2003 from $1,068.0 million in 2002. Purchases increased by approximately $520.6 million primarily due to higher commodity prices. This increase was offset by approximately $26 million of non-recurring charges from the second quarter of 2002 as discussed below.

Gross Margin — Gross margin increased $82.3 million or 35%, to $315.2 million in the second quarter of 2003 from $232.9 million in 2002. Of this increase, approximately $59 million (net of hedging) was the result of a $.12 per gallon increase in average NGLs prices. This increase was offset by an approximately $28 million decrease in gross margin due to a $2.01 per million British thermal units (“Btus”) increase in natural gas prices. During the second quarter of 2003, we elected to reduce levels of keep-whole processing activities from time to time due to

less profitable processing margins. These elections increased gross margin by approximately $20 million and are not reflected in the above pricing impacts. Average prices in the second quarter of 2003 were $.49 per gallon for NGLs and $5.41 per million Btus for natural gas as compared with $.37 per gallon for NGLs and $3.40 per million Btus for natural gas during the same period in 2002. Partially offsetting the increase in gross margin was a $2.1 million decrease in trading and marketing net margin. Other increases of approximately $3 million relate to our natural gas marketing based trading activity as discussed below.

Other increases in gross margin of approximately $32 million resulted from non-recurring charges during the second quarter of 2002 for reserves for gas imbalances with suppliers and customers of $12 million, storage inventory writedown of $6 million and miscellaneous other charges including items related to resolution of disputed receivables and payables of $14 million.

Gross margin associated with the Natural Gas Segment increased $86.6 million, or 39%, to $308.9 million from $222.3 million, mainly as a result of higher commodity prices. Commodity sensitive processing arrangements accounted for approximately $51 million (net of hedging) of this increase due mainly to the increase in average NGLs prices along with our election to reduce levels of keep-whole processing activities offset by the increase in average natural gas prices. Also contributing to this increase was a $0.4 million increase in trading and marketing net margin associated with derivative settlements and marked to market valuations of unsettled contracts related to our gas trading and marketing activities. Natural gas trading and marketing net margin excludes approximately $3 million of increases in gross margin realized during the second quarter of 2003 on our physical natural gas asset based marketing activity which, prior to January 1, 2003, was recorded in trading and marketing net margin. As a result of the rescission of EITF 98-10, this activity is now presented on a gross basis in gas sales and purchases (see Note 2 to Consolidated Financial Statements). Gross margin associated with this segment was also positively affected by the second quarter of 2002 charges totaling $32 million related to reserves for gas imbalances with suppliers and customers, a writedown of storage inventory and charges related to completion of our account reconciliation project as discussed above.

Gross margin associated with the NGLs Segment decreased $4.4 million, or 42% to $6.2 million in the second quarter of 2003 from $10.6 million in the same period of 2002. This decrease was primarily the result of a $2.6 million decrease in trading and marketing net margin.

Costs and Expenses — Operating and maintenance expenses increased $8.9 million, or 8%, to $114.6 million in the second quarter of 2003 from $105.7 million in the same period of 2002. Contributing to this increase were increased expenditures for facility maintenance and pipeline repair of $4 million, environmental compliance of $2 million, and accretion expense associated with SFAS No. 143 implementation (see Notes 2 and 4 to Consolidated Financial Statements) of $1 million. General and administrative expenses increased $1.2 million, or 3%, to $40.3 million in the first quarter of 2003, from $39.1 million in the same period of 2002.

Depreciation and amortization expenses increased $7.1 million, or 10%, to $76.3 million in the second quarter of 2003 from $69.2 million in the same period of 2002. This increase was due primarily to ongoing capital expenditures for well connections, facility maintenance and enhancements, and the implementation of SFAS No. 143.

Other costs and expenses decreased $2.0 million to a gain of $0.1 million in the second quarter of 2003 from a $1.9 million charge in the second quarter of 2002. This decrease is due primarily to the $1.9 million of impairment of investments in offshore Gulf of Mexico partnerships in the second quarter of 2002.

Equity in Earnings of Unconsolidated Affiliates — Equity in earnings of unconsolidated affiliates increased $4.0 million, or 51%, to $11.8 million in the second quarter of 2003 from $7.8 million in the second quarter of 2002. This increase is primarily the result of increased earnings from the 2002 acquisition of an interest in the Discovery Pipeline located in offshore Gulf of Mexico of $1.5 million, our general partnership interest in TEPPCO Partners, L.P. (“TEPPCO”) of $0.8 million and other equity investments.

Interest Expense, net — Interest expense, net decreased $0.5 million, or 1% to $41.8 million in the second quarter of 2003 from $42.3 million in the same period of 2002. This decrease was primarily the result of lower outstanding debt levels and higher cash investments in the second quarter of 2003.

Income Taxes — We are structured as a limited liability company, which is a pass-through entity for U.S income tax purposes. Income tax expense decreased $3.0 million to $0.3 million in the second quarter of 2003 from $3.3 million in the same period of 2002 due primarily to lower earnings associated with tax-paying subsidiaries.

Gain (Loss) From Discontinued Operations — Gain (Loss) from discontinued operations increased $29.3 million, to $28.7 million in the second quarter of 2003 from a loss of $0.6 million in the second quarter of 2002. This increase is primarily the result of the gain on the sale of various natural gas gathering and processing assets (see Note 11 to the Consolidated Financial Statements).

Six months ended June 30, 2003 compared with six months ended June 30, 2002

Operating Revenues — Total operating revenues increased $1,887.9 million, or 79%, to $4,271.6 million in the first six months of 2003 from $2,383.7 million in 2002. Of this increase, approximately $1,923.9 million was the result of higher sales of natural gas and petroleum products due to higher commodity prices Other increases were attributable to transportation, storage and processing fees of approximately $7.6 million. These increases were partially offset by a decrease in trading and marketing net margin of $43.6 million.

Purchases of Natural Gas and Petroleum Products — Purchases of natural gas and petroleum products increased $1,747.1 million, or 92%, to $3,654.7 million in the second quarter of 2003 from $1,907.6 million in 2002. Purchases increased by approximately $1,773.1 million primarily due to higher commodity prices. This increase was offset by approximately $26 million of non-recurring charges from the second quarter of 2002 as discussed below.

Gross Margin — Gross margin increased $140.8 million or 30%, to $616.9 million in the first six months of 2003 from $476.1 million in 2002. Of this increase, approximately $196 million (net of hedging) was the result of a $.20 per gallon increase in average NGLs prices. This increase was offset by an approximately $90 million decrease in gross margin due to a $3.14 per million British thermal units (“Btus”) increase in natural gas prices. During the first six months of 2003, we elected to reduce levels of keep-whole processing activities from time to time due to less profitable processing margins. These elections increased gross margin by approximately $26 million and are not reflected in the above pricing impacts. Average prices in the first six months of 2003 were $.54 per gallon for NGLs and $6.00 per million Btus for natural gas as compared with $.34 per gallon for NGLs and $2.86 per million Btus for natural gas during the same period in 2002. Partially offsetting the increase in gross margin was a $43.6 million decrease in trading and marketing net margin. Other increases of approximately $23 million relate to our natural gas asset based marketing activity as discussed below.

Other increases in gross margin of approximately $32 million resulted from non-recurring charges during the first six months of 2002 for reserves for gas imbalances with suppliers and customers of $12 million, storage inventory writedown of $6 million and miscellaneous other charges including items related to resolution of disputed receivables and payables of $14 million.

Gross margin associated with the Natural Gas Segment increased $143.4 million, or 32%, to $592.8 million from $449.4 million, mainly as a result of higher commodity prices. Commodity sensitive processing arrangements accounted for approximately $126 million (net of hedging) of this increase due mainly to the increase in average NGLs prices along with our election to reduce levels of keep-whole processing activities offset by the increase in average natural gas prices. Offsetting this increase was a $32.4 million decrease in trading and marketing net margin associated with derivative settlements and marked to market valuations of unsettled contracts related to our gas trading and marketing activities. Natural gas trading and marketing net margin excludes approximately $23 million of increases in gross margin realized during the first six months of 2003 on our physical natural gas asset based marketing activity which, prior to January 1, 2003, was recorded in trading and marketing net margin. As a result of the rescission of EITF 98-10, this activity is now presented on a gross basis in gas sales and purchases (see Note 2 to Consolidated Financial Statements). Gross margin associated with this segment was also positively affected by the second quarter of 2002 charges totaling $32 million related to reserves for gas imbalances with suppliers and customers, a writedown of storage inventory and charges related to completion of our account reconciliation project as discussed above.

Gross margin associated with the NGLs Segment decreased $2.5 million, or 9% to $24.2 million in the first six months of 2003 from $26.7 million in the same period of 2002. This decrease was comprised of an $11.2 million decrease in trading and marketing net margin offset by increases in northeast wholesale propane marketing and terminals margin of $1 million, a $1 million increase in margin relating to the sale of inventory resulting from renegotiation of certain pipeline operating agreements, a $1 million increase from the operation of a newly constructed pipeline in south Texas and higher margins from other NGLs assets.

Costs and Expenses — Operating and maintenance expenses increased $21.6 million, or 11%, (excluding $11 million in first six months 2002 accounting adjustments – see Note 9 to Consolidated Financial Statements) to $221.0 million in the first six months of 2003 from $199.4 million in the same period of 2002. Contributing to this increase were increased expenditures for facility maintenance and pipeline repair of $10 million, environmental compliance of $5 million, accretion expense associated with SFAS No. 143 implementation (see Notes 2 and 4 to Consolidated Financial Statements) of $1 million, higher utilities of $1 million and increased Canadian costs. General and administrative expenses increased $1.5 million, or 2%, to $79.8 million in the first six months of 2003, from $78.3 million in the same period of 2002.

Depreciation and amortization expenses increased $11.5 million, or 8%, to $152.1 million in the first six months of 2003 from $140.6 million in the same period of 2002. This increase was due primarily to ongoing capital expenditures for well connections, facility maintenance and enhancements, and the implementation of SFAS No. 143.

Other costs and expenses decreased $7.3 million to a gain of $0.2 million in the first six months of 2003 from a $7.1 million charge in the first six months of 2002. This decrease is due primarily to the first six months 2002 accounting adjustment of $5.3 million for the recognition of a loss on the sale of assets associated with a partnership investment (see Note 9 to Consolidated Financial Statements), and the $1.9 million impairment of investments in offshore Gulf of Mexico partnerships.

Equity in Earnings of Unconsolidated Affiliates — Equity in earnings of unconsolidated affiliates increased $10.0 million, or 72%, to $23.9 million in the first six months of 2003 from $13.9 million in the first six months of 2002. This increase is primarily the result of increased earnings from our general partnership interest in TEPPCO of $4.6 million and increased earnings from the 2002 acquisition of an interest in the Discovery Pipeline located in offshore Gulf of Mexico of $4.3 million, and other equity investments.

Interest Expense, net — Interest expense, net decreased $1.1 million, or 1%, to $84.5 million in the first six months of 2003 from $85.6 million in the same period of 2002. This decrease was primarily the result of lower outstanding debt levels and higher cash investments in the first six months of 2003.

Income Taxes — We are structured as a limited liability company, which is a pass-through entity for U.S income tax purposes. Income tax expense decreased $3.5 million to $2.1 million in the first six months of 2003 from $5.6 million in the same period of 2002 due primarily to lower earnings associated with tax-paying subsidiaries.

Gain (Loss) From Discontinued Operations — Gains from discontinued operations increased $33.2 million, to a gain of $32.4 million in the first six months of 2003 from a $0.8 million loss in the first six months of 2002. This increase is primarily the result of the gain on the sale of various natural gas gathering and processing assets (see Note 10 to the Consolidated Financial Statements).

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

Liquidity and Capital Resources

As of June 30, 2003, we had $153.0 million in cash and cash equivalents compared to $24.8 million as of December 31, 2002. Our working capital was a $8.7 million deficit as of June 30, 2003, compared to a $306.2 million deficit as of December 31, 2002. We rely upon cash flows from operations and borrowings to fund our liquidity and capital requirements. A material adverse change in operations or available financing may impact our ability to fund our current liquidity and capital resource requirements.

Operating Cash Flows

During the first six months of 2003, funds of $199.4 million were provided by operating activities, a decrease of $31.3 million from $230.7 million in the first six months of 2002. The decrease is primarily due to changes in working capital balances, unrealized mark-to-market and hedging activity offset by an increase in net income.

Price volatility in crude oil, NGLs and natural gas prices has a direct impact on our 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 resulting changes in working capital.

Investing Cash Flows

During the first six months of 2003, funds of $55.1 million were provided by investing activities, an increase of $189.8 million from $134.7 million of funds used in investing activities during the first six months of 2002. The increase is partially related to proceeds of $90.2 million from sales of discontinued operations. Our capital expenditures consist of expenditures for construction of additional gathering systems, processing plants, fractionators and other facilities and infrastructure in addition to well connections and upgrades to our existing facilities and acquisitions. For the first six months of 2003, we spent approximately $67.7 million on capital expenditures of continuing operations compared to $165.2 million in the first six months of 2002.

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

Investments in unconsolidated affiliates provided $31.1 million in cash distributions to us during the first six months of 2003 compared with $24.0 million during the first six months of 2002.

Financing Cash Flows

On March 28, 2003, we entered into a new credit facility (the “Facility”). The Facility replaces the credit facility that matured on March 28, 2003. The Facility is used to support our commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 26, 2004, however; any outstanding loans under the Facility at maturity may, at our option, be converted to a one-year term loan. The Facility is a $350.0 million revolving credit facility, of which $100.0 million 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); and contains various restrictions applicable to dividends and other payments to our members. The Facility bears interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 1.25% per year or (2) the higher of (a) the JP Morgan Chase Bank prime rate plus 0.25% per year and (b) the Federal Funds rate plus 0.75% per year. At June 30, 2003, there were no borrowings against the Facility.

On March 28, 2003, we also entered into a $100.0 million funded short-term loan with a bank (the “Short-Term Loan”). The Short-Term Loan is used for working capital and other general corporate purposes. The Short-Term Loan matures on September 30, 2003, and may be repaid at any time. The Short-Term Loan has the same

financial covenants as the Facility. The Short-Term Loan bears interest at a rate equal to, at our option, either (1) LIBOR plus 1.35% per year or (2) the higher of (a) the bank’s prime rate and (b) the Federal Funds rate plus 0.50% per year. Subsequent to June 30, 2003, we repaid this entire loan with funds generated from asset sales and operations.

At June 30, 2003, we had no outstanding commercial paper. At no time has the amount of our outstanding commercial paper exceeded the available amount under the Facility. In the future, our debt levels will vary depending on our liquidity needs, capital expenditures and cash flow.

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

Based on current and anticipated levels of operations, we believe that our cash on hand and cash flow from operations, combined with borrowings available under the commercial paper program and the 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 that we may make. Our ability to meet current and anticipated operating requirements will depend on our future performance.

Contractual Obligations and Commercial Commitments

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

At June 30, 2003, we were the guarantor of approximately $94.1 million of debt associated with nonconsolidated entities, of which $84.6 million related to our 33.33% ownership interest in Discovery Producer Services, LLC, (“Discovery”) and $9.5 million is related to our 50.0% ownership interest in GPM Gas Gathering, LLC (“GGG”). The guaranteed debt related to Discovery is due December 31, 2003, and is expected to be refinanced. The guaranteed debt related to GGG is scheduled to be repaid in full by January 31, 2004. In the event that the unconsolidated subsidiaries default on the debt payments, we would be required to pay the debt. Assets of the unconsolidated subsidiaries are pledged as collateral for the debt. At June 30, 2003, we had no liability recorded for the guarantees of the debt associated with the unconsolidated subsidiaries.

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. Typically, claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The survival 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 range 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, 2003, we had an approximate $1.5 million liability recorded for these outstanding indemnification provisions.

New Accounting Standards

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 requires that certain financial instruments that could previously be accounted for as equity, be classified as liabilities in statements of financial position and initially recorded at fair value. In addition to its requirements for the classification and measurement of financial instruments in its scope, SFAS No. 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 No. 150 are effective for all financial instruments entered into or modified after May 31, 2003, and are otherwise effective at the beginning of the first interim period beginning after June 15, 2003. Upon adoption on July 1, 2003, we will reclassify our preferred members’ interest to long-term liabilities at its fair value of approximately $200 million. Future disbursements previously classified as dividends on these preferred members’ interest will be classified as interest expense.

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

In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities.” FIN 46 requires an entity to consolidate a variable interest entity if it is the primary beneficiary of the variable interest entity’s activities. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. FIN 46 is immediately applicable to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003. For those variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 is required to be applied in the first fiscal year or interim period beginning after June 15, 2003. FIN 46 may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 also requires certain disclosures of an entity’s relationship with variable interest entities. We have not identified any variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003 and continue to assess the existence of any interests in variable interest entities created on or prior to January 31, 2003. It is reasonably possible that we will disclose information about variable interest entities upon the application of FIN 46, primarily as the result of investments we has in certain unconsolidated affiliates. For all of these unconsolidated affiliates, we believe that our maximum exposure to loss would be equal to our investment in these entities, plus our potential obligations under our guarantees of unconsolidated debt. At June 30, 2003, our total investment in, plus the value of any guaranteed debt for entities that have a reasonable possibility to be determined to be variable interest entities, was approximately $160.7 million. We continue to assess FIN 46 but do not anticipate that it will have a material impact on our consolidated results of operations, cash flows or financial position.

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

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

recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized.

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

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

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. We are currently assessing the impact EITF Issue No. 01-08 will have on our consolidated results of operations, cash flows or financial position.

Subsequent Events

In July 2003, we entered into an agreement to sell approximately 900 vehicles for approximately $14 million. This is a sale-leaseback transaction whereby we sold the vehicles but will lease them back over a one year lease term. The lease expires in July 2004, with annual extensions exercisable at our option. The future minimum lease payments under the lease are approximately $15 million. We do not have an option to purchase the leased vehicles at the end of the minimum lease term. As the proceeds from the sale of the vehicles are equal to the net book value of the vehicles, no gain or loss has been recognized.

In August 2003, we entered into a purchase and sale agreement to sell certain gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million, plus or minus various adjustments that will be made at closing. We anticipate closing the transaction on September 30, 2003 with no significant book gain or loss.

For information on subsequent events related to financing matters, see the Financing Cash Flows section above.

Item 3. Quantitative and Qualitative Disclosure about Market Risks

Risk Policies

We are exposed to market risks associated with commodity prices, credit exposure, interest rates and foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Our 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 our positions and exposures as well as periodic updates from and consultations with the Duke Energy Chief Risk Officer (“CRO”) and other expert resources at Duke Energy regarding market risk positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of commodity price risk and various other risks, including monitoring exposure limits.

Commodity Price Risk

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

Commodity Derivatives — Trading 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 Earnings at Risk (“DER”) as described below. DER is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor the risk in the commodity trading 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.

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

Daily Earnings at Risk (in thousands)

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, 2003

June 30, 2002

June 30, 2003

Calculated DER

774

2,488

2,260

363

Daily Earnings at Risk (in thousands)

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, 2003

June 30, 2002

June 30, 2003

Calculated DER

1,294

2,387

6,692

363

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

Our exposure to commodity price risk is influenced by a number of factors, including contract size, length of contract, market liquidity, location and unique or specific contract terms. The unrealized fair value of trading and marketing instruments outstanding at June 30, 2003 and December 31, 2002 was a gain of $3.7 million and a loss of $28.0 million, respectively.

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

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

The following table shows the fair value of our mark-to-market trading and marketing portfolios as of June 30, 2003.


	Fair Value of Contracts as of June 30, 2003 (in thousands)

										Maturity in
	Maturity in			Maturity in			Maturity in			2006 and			Total Fair
Sources of Fair Value	2003			2004			2005			Thereafter			Value

Prices supported by quoted market prices and other external sources	$	(472	)	$	(1,251	)	$	1,854		$	(234	)	$	(103	)
Prices based on models and other valuation methods		1,661			6,635			(737	)		(3,790	)		3,769

Total	$	1,189		$	5,384		$	1,117		$	(4,024	)	$	3,666

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, (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, and (iii) the value of structured transactions. 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, use various commodity instruments such as natural gas, crude oil and NGLs contracts to hedge the value of our assets and operations from such price risks. In accordance with SFAS No. 133, our primary use of commodity derivatives is to hedge the output and production of assets we physically own. Contract terms are up to three years, however, since these contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets owned by us, 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 Loss (“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, in accordance with SFAS No. 133. Amounts deferred 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.

The following table shows when gains and losses deferred on the Consolidated Balance Sheets for derivative instruments qualifying as effective hedges of firm commitments or anticipated future transactions will be

recognized into earnings. Contracts with terms extending several years are generally valued using models and assumptions developed internally or by industry standards. However, as mentioned previously, the effective portion of the gains and losses for these contracts are not recognized in earnings until settlement at their then market price. Therefore, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement 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 settle.


	Fair Value of Contracts as of June 30, 2003 (in thousands)

									Maturity in
	Maturity in			Maturity in			Maturity in		2006 and		Total Fair
Sources of Fair Value	2003			2004			2005		Thereafter		Value

Prices supported by quoted market prices and other external sources	$	(46,083	)	$	(2,333	)	$	4,731	$	—	$	(43,685	)
Prices based on models and other valuation methods		(528	)		(210	)		—		—		(738	)

Total	$	(46,611	)	$	(2,543	)	$	4,731	$	—	$	(44,423	)

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 $.01 per gallon in the price of NGLs and $.10 per million Btus in the average price of natural gas would result in changes in annual pre-tax net income of approximately $(25) million and $5 million, respectively.

Credit Risk

Our principle customers in the Natural Gas Segment are large, natural gas marketing services and industrial end-users. In the NGLs segment, our principle customers are large multi-national petrochemical and refining companies to small regional propane distributors. Substantially all of our natural gas and NGLs sales are made at index, market-based prices. Approximately 40% of our NGLs production is committed to ConocoPhillips and Chevron Phillips Chemical LLC, under a contract with a primary term that expires on January 1, 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 the corporate credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. Substantially all other agreements contain adequate assurance provisions, which would allow us, at our discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to us.

Despite the current credit environment in the energy sector, management believes that the credit risk management process described above is operating effectively. As of June 30, 2003, we had cash or letters of credit of $17.3 million to secure future performance by counterparties, and had deposited with counterparties $9.5 million of such collateral to secure our obligations to provide future services. 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.

Generally speaking, all physical and financial derivative contracts are settled in cash at the expiration of the contract term.

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, 2003, the fair value of our interest rate swap was an asset of $16.3 million. As of June 30, 2003, we had no outstanding commercial paper.

As a result of our debt and our interest rate swap, 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 $1.8 million.

Foreign Currency Risk

Our primary foreign currency exchange rate exposure at June 30, 2003 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 Rule 13a-14 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. There have been no significant changes in our internal controls over financial reporting that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information concerning litigation and other contingencies, see Part I. Item 1, Note 6 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, 2002, 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

	10.1	Third Amendment to Contract for Services between Duke Energy Field Services, LP and William W. Slaughter dated as of April 16, 2003.

	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 14, 2003

		/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


Exhibits
No.		Description

10.1		Third Amendment to Contract for Services between Duke Energy Field Services, LP and William W. Slaughter dated as of April 16, 2003.

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