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, 2002		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 (XBOX) No (BOX)

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
PART II. OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURES
Exhibit Index
EX-10.1 Second Amendment to Contract for Services
EX-99.1 Certification Pursuant to 18 USC Sec. 1350
EX-99.2 Certification Pursuant to 18 USC Sec. 1350

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

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, 2002 and 2001		1




			Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2002 and 2001		2




			Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2002 and 2001		3




			Consolidated Balance Sheets as of June 30, 2002 and December 31, 2001		4




			Condensed Notes to Consolidated Financial Statements		5




	2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			13




	3.	Quantitative and Qualitative Disclosure about Market Risks			20




		PART II. OTHER INFORMATION




	1.	Legal Proceedings			25




	6.	Exhibits and Reports on Form 8-K			25




		Signatures			26

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

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

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

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

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

	•		the level of creditworthiness of counterparties to transactions;

	•		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 and demand for our services;

	•		weather and other natural phenomena;

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

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

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

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described.

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,

			2002			2001			2002			2001

OPERATING REVENUES:




	Sales of natural gas and petroleum products		$	1,316,749		$	1,892,236		$	2,492,273		$	4,274,119




	Sales of natural gas and petroleum products—affiliates			392,807			582,455			701,643			1,522,754




	Transportation, storage and processing			78,030			61,634			147,607			119,524

		Total operating revenues		1,787,586			2,536,325			3,341,523			5,916,397

COSTS AND EXPENSES:




	Purchases of natural gas and petroleum products			1,421,818			1,994,972			2,626,502			4,694,208




	Purchases of natural gas and petroleum products—affiliates			127,322			205,133			227,971			518,396




	Operating and maintenance			109,712			90,045			217,672			179,536




	Depreciation and amortization			71,286			67,861			145,045			134,717




	General and administrative			33,081			30,368			69,777			58,585




	General and administrative—affiliates			6,032			2,673			8,493			6,862




	Other			1,907			(120	)		7,095			(988	)

		Total costs and expenses		1,771,158			2,390,932			3,302,555			5,591,316

OPERATING INCOME				16,428			145,393			38,968			325,081




EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES				7,836			10,904			13,906			16,080




INTEREST EXPENSE				(42,295	)		(40,375	)		(85,604	)		(82,392	)





INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE				(18,031	)		115,922			(32,730	)		258,769




INCOME TAX EXPENSE				3,313			280			5,614			338





(LOSS) INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE				(21,344	)		115,642			(38,344	)		258,431
CUMULATIVE EFFECTIVE OF ACCOUNTING CHANGE				—			—			—			411

NET (LOSS) INCOME				(21,344	)		115,642			(38,344	)		258,020




DIVIDENDS ON PREFERRED MEMBERS’ INTEREST				7,125			7,125			14,250			14,250





(DEFICIT) EARNINGS AVAILABLE FOR MEMBERS’ INTEREST			$	(28,469	)	$	108,517		$	(52,594	)	$	243,770

See Condensed 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,

			2002			2001			2002			2001

NET (LOSS) INCOME			$	(21,344	)	$	115,642		$	(38,344	)	$	258,020




OTHER COMPREHENSIVE INCOME (LOSS):




	Cumulative effect of change in accounting principle			—			—			—			6,626




	Foreign currency translation adjustment			13,451			3,059			11,107			2,147




	Net unrealized (losses) gains on cash flow hedges			(4,339	)		6,866			(61,439	)		(11,336	)




	Reclassification into earnings			2,542			(2,053	)		(15,992	)		14,941

		Total other comprehensive income (loss)		11,654			7,872			(66,324	)		12,378

TOTAL COMPREHENSIVE INCOME (LOSS)			$	(9,690	)	$	123,514		$	(104,668	)	$	270,398

See Condensed Notes to Consolidated Financial Statements.

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


				Six Months Ended,
				June 30,

				2002			2001

CASH FLOWS FROM OPERATING ACTIVITIES:




	Net (loss) income			$	(38,344	)	$	258,020




	Adjustments to reconcile net (loss) income to net cash provided by operating activities:




		Depreciation and amortization			145,045			134,717




		Equity in earnings of unconsolidated affiliates			(13,906	)		(16,080	)




		Other			5,511			(1,326	)




	Change in operating assets and liabilities (net of effects of acquisitions) which provided (used) cash:




		Accounts receivable			13,441			615




		Accounts receivable—affiliates			114,121			163,184




		Inventories			(11,784	)		15,274




		Net unrealized mark-to-market and hedging transactions			46,103			(25,092	)




		Other current assets			4,313			2,879




		Other noncurrent assets			(1,105	)		(14,785	)




		Accounts payable			(43,712	)		(53,227	)




		Accounts payable—affiliates			(10,737	)		(28,537	)




		Accrued interest payable			(2,890	)		5,726




		Other current liabilities			15,397			(20,072	)




		Other long term liabilities			9,256			(4,659	)

			Net cash provided by operating activities		230,709			416,637

	CASH FLOWS FROM INVESTING ACTIVITIES:




		Expenditures for acquisitions			—			(155,603	)




		Other capital expenditures			(166,393	)		(153,092	)




		Investment expenditures, net of cash acquired			7,620			(1,114	)




		Investment distributions			24,040			28,538




		Proceeds from sales of assets			—			18,852

			Net cash used in investing activities		(134,733	)		(262,419	)

	CASH FLOWS FROM FINANCING ACTIVITIES:




		Distributions to members			(63,162	)		(115,437	)




		Proceeds from issuing debt			—			248,358




		Payment of debt			(152	)		(47,556	)




		Payment of dividends			(14,250	)		(14,250	)




		Debt issuance costs			—			(1,518	)




		Short term debt—net			(23,930	)		(226,428	)

			Net cash used in financing activities		(101,494	)		(156,831	)

	EFFECT OF FOREIGN EXCHANGE RATE CHANGES ON CASH				2,007			2,147

	NET DECREASE IN CASH				(3,511	)		(466	)




	CASH, BEGINNING OF PERIOD				4,906			1,553

	CASH, END OF PERIOD			$	1,395		$	1,087





	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION – Cash paid for interest (net of amounts capitalized)			$	84,402		$	74,085

See Condensed Notes to Consolidated Financial Statements.

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


					June 30,			December 31,
					2002			2001

				ASSETS




CURRENT ASSETS:




	Cash				$	1,395		$	4,906




	Accounts receivable:




		Customers, net				544,849			520,118




		Affiliates				116,400			230,521




		Other				89,337			136,810




	Inventories					94,719			82,935




	Unrealized gains on trading and hedging transactions					76,585			180,809




	Other					4,747			9,060

				Total current assets		928,032			1,165,159

PROPERTY, PLANT AND EQUIPMENT, NET						4,741,901			4,711,960




INVESTMENT IN AFFILIATES						177,286			132,252




INTANGIBLE ASSETS:




	Natural gas liquids sales and purchases contracts, net					88,879			94,019




	Goodwill, net					436,230			421,176

				Total intangible assets		525,109			515,195

UNREALIZED GAINS ON TRADING AND HEDGING TRANSACTIONS						12,828			19,095




OTHER NONCURRENT ASSETS						88,862			86,548

				TOTAL ASSETS	$	6,474,018		$	6,630,209

				LIABILITIES AND MEMBERS’ EQUITY




CURRENT LIABILITIES:




	Accounts payable:




		Trade			$	607,621		$	620,094




		Affiliates				14,883			25,620




		Other				59,441			76,914




	Short term debt					189,025			212,955




	Unrealized losses on trading and hedging transactions					83,897			84,811




	Accrued interest payable					54,527			57,417




	Accrued taxes other than income					22,306			24,646




	Distributions payable to members					—			45,672




	Other					120,431			102,694

				Total current liabilities		1,152,131			1,250,823

DEFERRED INCOME TAXES						11,519			14,362




LONG TERM DEBT						2,242,621			2,235,034




UNREALIZED LOSSES ON TRADING AND HEDGING TRANSACTIONS						32,606			25,188




OTHER LONG TERM LIABILITIES						87,654			15,845




MINORITY INTERESTS						130,855			135,915




PREFERRED MEMBERS’ INTEREST						300,000			300,000




COMMITMENTS AND CONTINGENT LIABILITIES MEMBERS’ EQUITY:




			Members’ interest			1,709,290			1,709,290




			Retained earnings			825,621			895,707




			Accumulated other comprehensive (loss) income			(18,279	)		48,045

				Total members’ equity		2,516,632			2,653,042

TOTAL LIABILITIES AND MEMBERS’ EQUITY					$	6,474,018		$	6,630,209

See Condensed Notes to Consolidated Financial Statements.

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

1. General

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

2. Accounting Policies

Consolidation — The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, after eliminating significant intercompany transactions and balances. Investments in 20% to 50% owned affiliates are accounted for using the equity method. Investments greater than 50% are consolidated unless the Company does not operate these investments and, as a result, does not have the ability to exercise control. These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods.

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

Accounting for Hedges and Commodity Trading Activities — All derivatives are recorded in the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Trading and Hedging Transactions. On the date that swaps or option contracts are entered into, the Company designates the derivative as either held for trading (trading instruments); as a hedge of a recognized asset, liability or firm commitment (fair value hedges); as a hedge of a forecasted transaction or future cash flows (cash flow hedges); or leaves the derivative undesignated and marks it to market.

For hedge contracts, the Company formally assesses, both at the hedge 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 time value of the options when assessing hedge effectiveness.

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

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

Commodity Trading — A favorable or unfavorable price movement of any derivative contract held for trading purposes is reported as Purchases of Natural Gas and Petroleum Products in the Consolidated Statements of Operations. An offsetting amount is recorded in the Consolidated Balance Sheets as Unrealized Gains or Unrealized Losses on

Trading and Hedging Transactions. When a contract to sell is physically settled, the fair value entries are reversed and the gross amount invoiced to the customer is included as Sales of Natural Gas and Petroleum Products in the Consolidated Statements of Operations. Similarly, when a contract to purchase is physically settled, the purchase price is included as Purchases of Natural Gas and Petroleum Products in the Consolidated Statements of Operations. If a contract is not physically settled, the unrealized gain or unrealized loss in the Consolidated Balance Sheets is reclassified to a receivable or payable account. For income statement purposes, financial settlement has no revenue presentation effect on the Consolidated Statements of Operations.

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

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

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

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

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

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


		For the Three					For the six
		Months Ended					Months Ended
		June 30,					June 30,

		2002			2001		2002			2001

		(In Thousands)
Reported net (loss) income		$	(21,344	)	$	115,642	$	(38,344	)	$	258,020




Add: Goodwill amortization			—			5,497		—			10,634

	Adjusted net (loss) income	$	(21,344	)	$	121,139	$	(38,344	)	$	268,654

The changes in the carrying amount of goodwill for the six months ended June 30, 2002 and June 30, 2001 are as follows:

Goodwill (In Thousands)


		Balance		Acquired				Balance
		December 31, 2001		Goodwill		Other		June 30, 2002

Natural gas gathering, processing, transportation, marketing and storage		$	394,054	$	—	$	1,636	$	395,690




NGL fractionation, transportation, marketing and trading			27,122		—		13,418		40,540

	Total consolidated	$	421,176	$	—	$	15,054	$	436,230


		Balance		Acquired					Balance
		December 31, 2000		Goodwill		Other			June 30, 2001

Natural gas gathering, processing, transportation, marketing and storage		$	376,195	$	—	$	(10,634	)	$	365,561




NGL fractionation, transportation, marketing and trading			—		—		—			—

	Total consolidated	$	376,195	$	—	$	(10,634	)	$	365,561

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

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.

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

The Company is required to adopt the provisions of SFAS No. 143 as of January 1, 2003. To accomplish this, the Company must identify any legal obligations for asset retirement obligations, and determine the fair value of these obligations on the date of adoption. The determination of fair value is complex and requires gathering market information and developing cash flow models. Additionally, the Company will be required to develop processes to track and monitor these obligations. Because of the effort needed to comply with the adoption of SFAS No. 143, the

Company is currently assessing the new standard but has not yet determined the impact on its consolidated results of operations, cash flows or financial position.

On June 20, 2002, the FASB’s Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” and EITF No. 00-17, “Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10.” The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Income. Comparative financial statements for prior periods must be reclassified to reflect presentation on a net basis. Also, companies must disclose volumes of physically settled energy trading contracts. The Company is evaluating the impact of this new consensus on the presentation of its Consolidated Statement of Operations, but has not yet determined the impact it will have on total revenues and product purchases. The partial consensus will have no impact on net income.

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

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

3. Derivative Instruments, Hedging Activities and Credit Risk

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

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

Corporate economic risks — The Company enters into debt arrangements that are exposed to market risks related to changes in interest rates. The Company periodically uses interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with new debt issuances. The Company’s primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for the Company’s debt rating; (2) reducing volatility 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 NGL customers range from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of the Company’s NGL sales are made at market-based prices, including approximately 40% of NGL production that is committed to Phillips and Chevron Phillips Chemical LLC, under a contract with a primary term that expires on January 1, 2015. This concentration of credit risk may affect the Company’s overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. On all transactions where the Company is exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. The corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure. The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions.

Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. However, financial derivatives are generally subject to margin agreements with the majority of our counterparties.

Commodity cash flow hedges — The Company uses cash flow hedges, as specifically defined by SFAS No. 133, to reduce the potential negative impact that commodity price changes could have on the Company’s earnings, and its ability to adequately plan for cash needed for debt service, dividends, capital expenditures and tax distributions. The Company’s primary corporate hedging goals include (1) maintaining minimum cash flows to fund debt service, dividends, production replacement, maintenance capital projects and tax distributions; (2) avoiding disruption of the Company’s growth capital and value creation process; and (3) retaining a high percentage of potential upside relating to price increases of NGLs.

The Company uses natural gas, crude oil and NGL swaps and options to hedge the impact of market fluctuations in the price of NGLs, natural gas and other energy-related products. For the six months ended June 30, 2002, the Company recognized a net loss of $0.9 million, of which a $12.4 million loss represented the total ineffectiveness of all cash flow hedges and an $16.0 million gain represented the total derivative settlements. The time value of options, a recognized $4.5 million loss for the six months ended June 30, 2002, was excluded in the assessment of hedge effectiveness. The time value of options is included in Sales of Natural Gas and Petroleum Products in the Consolidated Statements of Operations. No derivative gains or losses were reclassified from OCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

Gains and losses on derivative contracts that are reclassified from accumulated OCI to current period earnings are included in the line item in which the hedged item is recorded. As of June 30, 2002, $13.4 million of deferred net losses on derivative instruments accumulated in OCI are expected to be reclassified as earnings during the next 12 months as the hedge transactions occur; however, due to the volatility of the commodities markets, the corresponding value in OCI is subject to change prior to its reclassification into earnings. The maximum term over which the Company is hedging its exposure to the variability of future cash flows is three years.

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

For the six months ended June 30, 2002, the gains or losses representing the ineffective portion of the Company’s fair value hedges were not material. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. The Company did not have any firm commitments that no

longer qualified as fair value hedge items and therefore, did not recognize an associated gain or loss.

Interest rate fair value hedge — In October 2001, the Company entered an interest rate swap to convert the fixed interest rate of $250.0 million of debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on a six-month London Interbank Offered Rate (“LIBOR”), which is re-priced semiannually through 2005. The swap meets conditions which permit the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swap no ineffectiveness will be recognized. As of June 30, 2002, the fair value of the interest rate swap of $1.9 million gain was included in the Consolidated Balance Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions with an offset to the underlying debt included in Long Term Debt.

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

4. Financing

Credit Facility with Financial Institutions — On March 29, 2002, the Company entered into a new credit facility (the “New Facility”). The New Facility replaces the credit facility that matured on March 29, 2002. The New Facility is used to support the Company’s commercial paper program and for working capital and other general corporate purposes. The New Facility matures on March 28, 2003, however, any outstanding loans under the New Facility at maturity may, at the Company’s option, be converted to a one-year term loan. The New Facility is a $650.0 million revolving credit facility, of which $150.0 million can be used for letters of credit. The New Facility requires the Company to maintain at all times a debt to total capitalization ratio of less than or equal to 53%. The New Facility bears interest at a rate equal to, at the Company’s option and based on the Company’s current debt rating, either (1) LIBOR plus 0.75% per year or (2) the higher of (a) the Bank of America prime rate and (b) the Federal Funds rate plus 0.50% per year. At June 30, 2002, there were no borrowings against the New Facility.

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

At June 30, 2002 the Company was the guarantor of approximately $107.0 million of debt associated with unconsolidated subsidiaries. Assets of the unconsolidated subsidiaries are pledged as collateral for the debt.

5. Commitments and Contingent Liabilities

Litigation — The midstream natural gas industry has seen a number of lawsuits involving royalty disputes, mismeasurement, pricing and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. Some of these cases are now being brought as class actions. The Company and its subsidiaries are currently named as defendants in a number of these types of cases, including the referenced class actions and other similar types of cases impacting the midstream natural gas industry. Management believes the Company and its subsidiaries have meritorious defenses to these cases, and therefore will continue to defend them vigorously. However, these class actions can be costly and time consuming to defend.

Management believes that the final disposition of these proceedings will not have a material adverse effect on the consolidated results of operations or financial position of the Company.

Environmental — On June 13, 2001, the Company received two administrative Compliance Orders from the New Mexico Environment Department (“NMED”) seeking civil penalties for primarily historic air permit matters. One order alleged specific permit non-compliance at 11 facilities that occurred periodically between 1996

and 1999. Allegations under this order related primarily to emissions from certain compressor engines in excess of what were then new operating permit limits. The other order alleged numerous unexcused excursions from an hourly permit limit arising from upset events at the Company’s Dagger Draw facility’s sulfur recovery unit between 1997 and 2001. NMED applied its civil penalty policy to the alleged violations and calculated the penalties to be $10.4 million in the aggregate. On May 31, 2002, the Company and NMED entered into a Settlement Agreement which resolves all aspects of the June 2001 Compliance Orders. Under the terms of the Settlement Agreement, no penalty will be assessed, and the Company has agreed to undertake upgrades at several of its facilities in New Mexico that will significantly reduce emissions and will also ensure those facilities are achieving state ambient air quality standards.

The Company was in discussion with the Oklahoma Department of Environmental Quality (“ODEQ”) regarding apparent non-compliance issues relating to the Company’s Title V Clean Air Act Operating permits at its Oklahoma facilities, primarily consisting of compliance issues disclosed to the ODEQ pursuant to permit requirements or otherwise voluntarily disclosed to the ODEQ in 2001. These non-compliance issues relate to various specific and detailed terms of the Title V permits, including, separate filing requirements, engine testing procedural requirements, certification requirements, and quarterly emissions testing obligations. On May 20, 2002, the Company and ODEQ entered into a Consent Order to address and resolve all of the items of non-compliance with Title V permits as discussed above. Under the Consent Order, the Company agreed to pay a civil penalty of $85,050 and install pollution control equipment on certain of its compressor engines to achieve significant emissions reductions at a cost of $481,950. The items of non-compliance have been corrected, and the installation of the pollution controls is presently underway.

6. Business Segments

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

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


					For the Three						For the six
					Months Ended						Months Ended
					June 30,						June 30,

					2002			2001			2002			2001

					(In Thousands)
Operating revenues:




	Natural gas				$	1,066,583		$	1,211,835		$	1,971,500		$	3,955,248




	NGLs					1,123,518			1,867,100			2,050,391			3,094,930




	Intersegment (a)					(402,515	)		(542,610	)		(680,368	)		(1,133,781	)

				Total operating revenues	$	1,787,586		$	2,536,325		$	3,341,523		$	5,916,397

Margin:




	Natural gas				$	227,832		$	319,350		$	460,381		$	675,107




	NGLs					10,614			16,870			26,669			28,686

		Total margin			$	238,446		$	336,220		$	487,050		$	703,793

Other operating costs:




	Natural gas				$	109,238		$	88,551		$	219,985		$	176,301




	NGLs					2,381			1,374			4,782			2,247




	Corporate					39,113			33,041			78,270			65,447

			Total other operating costs		$	150,732		$	122,966		$	303,037		$	243,995


			For the Three						For the six
			Months Ended						Months Ended
			June 30,						June 30,

			2002			2001			2002			2001

			(In Thousands)
Equity in earnings of unconsolidated affiliates:




	Natural Gas		$	6,870		$	11,434		$	12,519		$	16,122




	NGLs			966			(530	)		1,387			(42	)

		Total equity in earnings of unconsolidated affiliates	$	7,836		$	10,904		$	13,906		$	16,080

EBITDA (b):




	Natural gas		$	125,464		$	242,233		$	252,915		$	514,928




	NGLs			9,199			14,966			23,274			26,397




	Corporate			(39,113	)		(33,041	)		(78,270	)		(65,447	)

		Total EBITDA	$	95,550		$	224,158		$	197,919		$	475,878

Depreciation and amortization:




	Natural gas		$	68,387		$	64,728		$	137,574		$	128,209




	NGLs			2,305			2,083			5,623			4,378




	Corporate			594			1,050			1,848			2,130

		Total depreciation and amortization	$	71,286		$	67,861		$	145,045		$	134,717

EBIT (b):




	Natural gas		$	57,077		$	177,505		$	115,341		$	386,719




	NGLs			6,894			12,883			17,651			22,019




	Corporate			(39,707	)		(34,091	)		(80,118	)		(67,577	)

		Total EBIT	$	24,264		$	156,297		$	52,874		$	341,161

Corporate interest expense			$	42,295		$	40,375		$	85,604		$	82,392

Income before income taxes:




	Natural gas		$	57,077		$	177,505		$	115,341		$	386,719




	NGLs			6,894			12,883			17,651			22,019




	Corporate			(82,002	)		(74,466	)		(165,722	)		(149,969	)

		Total income before income taxes	$	(18,031	)	$	115,922		$	(32,730	)	$	258,769

Capital expenditures:




	Natural gas		$	47,606		$	195,371		$	150,616		$	256,256




	NGLs			6,717			40,641			6,896			41,181




	Corporate			5,285			9,565			8,881			11,258

		Total acquisitions and other capital expenditures	$	59,608		$	245,577		$	166,393		$	308,695


			As of

			June 30,		December 31,
			2002		2001

			(In Thousands)
Total assets:




	Natural gas		$	5,325,892	$	5,326,889




	NGLs			251,180		258,177




	Corporate (c)			896,946		1,045,143

		Total assets	$	6,474,018	$	6,630,209

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




(b)		EBITDA consists of income from continuing operations before interest expense, income tax expense, and depreciation and amortization expense. EBIT is EBITDA less depreciation and amortization. These measures

		are not a measurement presented in accordance with generally accepted accounting principles and should not be considered in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as a measure of the Company’s profitability or liquidity. The measures are included as a supplemental disclosure because it may provide useful information regarding the Company’s ability to service debt and to fund capital expenditures. However, not all EBITDA or EBIT may be available to service debt.




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

7. Acquisition

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

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

The following discussion details the material factors that affected our historical financial condition and results of operations during the three months and six months ended June 30, 2002 and 2001. This discussion should be read in conjunction with the Consolidated Financial Statements and related notes included elsewhere in this report.

Overview

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

	•		natural gas gathering, processing, transportation, marketing and storage, from which we generate revenues primarily by providing services such as compression, treating and gathering, processing, local fractionation, transportation of residue gas, storage and marketing;

	•		natural gas liquids (“NGLs”) fractionation, transportation, marketing and trading, from which we generate revenues from transportation fees, market center fractionation and the marketing and trading of NGLs.

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

Effects of Commodity Prices

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

During 2001 and the first and second quarters of 2002, approximately 75% of our gross margin was generated by commodity sensitive arrangements and approximately 25% of our gross margin was generated by fee-based arrangements. The commodity exposure is actively managed by the Company as discussed below.

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

We generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, during the last two quarters of 2001 and first two quarters of 2002, the relationship or correlation between crude oil value and NGL prices declined significantly. During the second quarter of 2002, NGL prices strengthened while the relationship between NGL prices and crude remained weak.

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

To better address the risks associated with volatile commodity prices, the Company employs a comprehensive commodity price risk management program. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge the value of our assets and operations from such price risks. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Our second quarter 2001 and 2002 results of operations include hedging losses of $1.2 million and $8.3 million, respectively. During the first six months of 2001 and 2002 our hedging activities resulted in losses of $15.8 million and $0.9 million, respectively. The hedging losses incurred in the second quarter of 2001 and 2002 relate to hedges placed during periods of higher prices.

Results of Operations


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

			2002		2001		2002		2001

			(In Thousands)
Operating revenues:




	Sales of natural gas and petroleum products		$	1,709,556	$	2,474,691	$	3,193,916	$	5,796,873




	Transportation, storage and processing			78,030		61,634		147,607		119,524

		Total operating revenues		1,787,586		2,536,325		3,341,523		5,916,397




	Purchases of natural gas and petroleum products			1,549,140		2,200,105		2,854,473		5,212,604

Gross margin				238,446		336,220		487,050		703,793




Equity earnings of unconsolidated affiliates				7,836		10,904		13,906		16,080

Total gross margin and equity earnings of Unconsolidated affiliates (1)			$	246,282	$	347,124	$	500,956	$	719,873

(1)

Gross margin and equity in earnings (“Gross Margin”) consists of income from continuing operations before operating and general and administrative expense, interest expense, income tax expense, and depreciation and amortization expense plus equity earnings of unconsolidated affiliates. Gross Margin as defined is not a measurement presented in accordance with generally accepted accounting principles. You should not consider this measure in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as an isolated measure of our profitability or liquidity. 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 the Company’s earnings.

Three months ended June 30, 2002 compared with three months ended June 30, 2001

Gross Margin. Gross Margin decreased $100.8 million, or 29% from $347.1 million in the second quarter of 2001 to $246.3 million in 2002. This decrease was primarily the result of lower NGL prices of approximately $76.0 million (net of hedging) due to an $0.11 per gallon decrease in average NGL prices. These decreases were partially offset by approximately $13.0 million due to a $1.27 per million British thermal unit (“Btu”) decrease in natural gas prices. Average prices for the three months ended June 30, 2002 were $0.37 per gallon for NGLs and $3.40 per million Btus for natural gas, respectively, as compared with $0.48 per gallon and $4.67 per million Btus during the same period 2001. Throughput volumes and NGL trading declines contributed another $7.0 million and $8.9 million, respectively, to the Gross Margin decrease.

Gross Margin was negatively impacted further in the second quarter by a $12.0 million reserve as a result of the Company’s ongoing analysis of its gas imbalances with suppliers and customers. Furthermore, the Company recorded a writedown of storage inventory in southeast Texas of $6.0 million and recorded miscellaneous other charges of $14.0 million, including charges associated with the resolution of disputed receivables and payables.

Partially offsetting these decreases were increases of approximately $10.3 million attributable to the combination of our acquisitions of Canadian Midstream, northeast propane terminal and marketing assets, and additional interests in three Offshore Gulf of Mexico partnerships.

Gross Margin associated with the natural gas gathering, processing, transportation and storage segment decreased $96.1 million, or 29%, from $330.8 million to $234.7 million, mainly as a result of lower NGL prices. Commodity sensitive processing arrangements accounted for approximately $63.0 million (net of hedging) of this decrease due mainly to the $0.11 per gallon decrease in average NGL prices. This reduction was the result of the interaction of commodity prices and our gas supply arrangements. Gross Margin was also negatively affected by

charges related to reserves for gas imbalances with suppliers and customers, the writedown of storage inventory and miscellaneous other charges, as noted above.

Gross Margin associated with the natural gas liquids fractionation, transportation, marketing and trading segment decreased $4.7 million, or 29%, from $16.3 million to $11.6 million. This reduction was primarily the result of lower margin from NGL trading, offset by increases from the acquisition of northeast propane terminal and marketing assets in 2001.

NGL production during the second quarter of 2002 decreased 14,700 barrels per day, or 4%, from 406,700 barrels per day to 392,000 barrels per day, and natural gas transported and/or processed decreased 0.1 trillion Btus per day, or 1%, from 8.5 trillion Btus per day to 8.4 trillion Btus per day. The primary cause of the decrease in NGL production was the decreased keep-whole processing activity due to tightened processing margins in the second quarter of 2002 and reduced volumes associated with lower North American drilling activity.

Costs and Expenses. Operating and maintenance expenses increased $19.7 million, or 22%, from $90.0 million in the second quarter of 2001 to $109.7 million in the same period of 2002. This increase is primarily the result of acquisitions of approximately $6.0 million and increased maintenance, cost of labor and pipeline integrity projects. General and administrative expenses increased $6.1 million, or 18%, from $33.0 million in the second quarter of 2001 to $39.1 million in the same period of 2002. This increase is primarily the result of increased costs for core business process improvements, allocated costs from Duke Energy due to increased service levels and expanded business activity resulting from 2001 acquisitions.

Depreciation and amortization increased $8.9 million (excluding $5.5 million of goodwill amortization in 2001), or 14%, from $62.4 million in the second quarter of 2001 to $71.3 million in the same period of 2002. This increase was due primarily to acquisitions, ongoing capital expenditures for well connections and facility maintenance and enhancements.

Other costs and expenses of $1.9 million were due mainly to impairment of investments in offshore Gulf of Mexico partnerships.

Interest. Interest expense increased $1.9 million, or 5%, from $40.4 million in the second quarter of 2001 to $42.3 million in the same period of 2002. This increase was primarily the result of higher outstanding debt levels, partially offset by lower interest rates.

Income Taxes. The Company is structured as a limited liability company, which is a pass-through entity for income tax purposes. Second quarter 2002 income tax expense of $3.3 million is mainly the result of other miscellaneous taxes associated with tax-paying subsidiaries.

Net Income. Net income decreased $136.9 million from $115.6 million in the second quarter of 2001 to a loss of $21.3 million in the second quarter of 2002. This decrease was largely the result of decreased NGL prices and increases in operating and general and administrative expenses, slightly offset by lower natural gas prices and acquisition activity. Net income was also negatively affected by charges related to reserves for gas imbalances, reduced storage inventory, impairments of partnership investments and miscellaneous other charges.

Six months ended June 30, 2002 compared with six months ended June 30, 2001

Gross Margin. Gross Margin decreased $218.9 million, or 30%, from $719.9 million for the six months ended June 30, 2001 to $501.0 million in 2002. This decrease was primarily the result of lower NGL prices of approximately $237.0 million (net of hedging) due to a $0.20 per gallon decrease in average NGL prices. These decreases were partially offset by approximately $49.0 million due to a $3.02 per million Btu decrease in natural gas prices. Average prices for the six months ended June 30, 2002 were $0.34 per gallon for NGLs and $2.86 per million Btus for natural gas, respectively, as compared with $0.54 per gallon and $5.88 per million Btus during the same

period in 2001. Throughput volumes and NGL trading activity declines contributed another $16.0 million and $8.0 million, respectively, to the Gross Margin decrease.

Gross Margin was negatively impacted further in the six months ended June 30, 2002, by a $12.0 million reserve as a result of the Company’s ongoing analysis of its gas imbalances with suppliers and customers. Furthermore, the Company recorded a writedown of storage inventory in southeast Texas of $6.0 million and recorded miscellaneous other charges of $14.0 million, including charges associated with the resolution of disputed receivables and payables.

Partially offsetting these decreases were increases of approximately $25.0 million attributable to the combination of our acquisitions of Canadian Midstream, northeast propane terminal and marketing assets, and additional interests in three Offshore Gulf of Mexico partnerships.

Gross Margin associated with the natural gas gathering, processing, transportation and storage segment decreased $218.3 million, or 32%, from $691.2 million for the six months ended June 30, 2001 to $472.9 million for the same period 2002, mainly as a result of the lower NGL prices. Commodity sensitive processing arrangements accounted for approximately $188.0 million (net of hedging) of this decrease due mainly to the $0.20 per gallon decrease in average NGL prices. This reduction was the result of the interaction of commodity prices and our gas supply arrangements. Gross Margin was also negatively affected by charges related to reserves for gas imbalances with suppliers and customers, the writedown of storage inventory and miscellaneous other charges, as noted above.

Gross Margin associated with the natural gas liquids fractionation, transportation, marketing and trading segment decreased $0.5 million, or 2%, from $28.6 million to $28.1 million. The decrease is mainly the result of lower NGL trading margins, offset by increases due to the acquisition of northeast propane terminal and marketing assets in 2001.

NGL production during the six months ended June 30, 2002 increased 1,500 barrels per day, or less than 1%, from 388,900 barrels per day to 390,400 barrels per day, and natural gas transported and/or processed remained unchanged at 8.4 trillion Btus per day through the first two quarters of both 2001 and 2002. The primary cause of the slight increase in NGL production was the increase in keep-whole processing activity due to more profitable processing margins experienced during the first quarter of 2002, as compared to very poor processing and keep-whole margins in the first quarter of 2001.

Costs and Expenses. Operating and maintenance expenses increased $38.2 million, or 21%, from $179.5 million for the six months ended June 30, 2001 to $217.7 million in the same period of 2002. This increase is primarily the result of acquisitions of $12.0 million, first quarter 2002 accrual increases of $10.0 million and increased maintenance, cost of labor and pipeline integrity projects. General and administrative expenses increased $12.9 million, or 20%, from $65.4 million for the six months ended June 30, 2001 to $78.3 million in the same period of 2002. This increase is primarily the result of increased costs for core business process improvements, allocated costs from Duke Energy due to increased service levels and expanded business activity resulting from 2001 acquisitions.

Depreciation and amortization increased $20.9 million (excluding $10.6 million of goodwill amortization in 2001), or 17%, from $124.1 million for the six months ended June 30, 2001 to $145.0 million in the same period of 2002. This increase was due primarily to acquisitions, ongoing capital expenditures for well connections and facility maintenance and enhancements.

Other costs and expenses increased $8.1 million from income of $1.0 million for the six months ended June 30, 2001, to expense of $7.1 million in the same period in 2002. This increase is mainly due to impairment of the Brigham partnership investment in the first quarter of 2002 and the impairment of investments in offshore Gulf of Mexico partnerships of $1.9 million in the second quarter of 2002.

Interest. Interest expense increased $3.2 million, or 4%, from $82.4 million for the six months ended June

30, 2001 to $85.6 million in the same period of 2002. This increase was primarily the result of higher outstanding debt levels, partially offset by lower interest rates.

Income Taxes. The Company is structured as a limited liability company, which is a pass-through entity for income tax purposes. Income tax expense for the six months ended June 30, 2002 of $5.6 million is mainly the result of other miscellaneous taxes associated with tax-paying subsidiaries.

Net Income. Net income decreased $296.3 million from $258.0 million for the six months ended June 30, 2001 to a loss of $38.3 million in the same period of 2002. This decrease was largely the result of decreased NGL prices and increases in operating and general and administrative expenses, slightly offset by lower natural gas prices and acquisition activity. Net income was also negatively affected by charges related to reserves for gas imbalances, reduced storage inventory, impairment of partnership investments, and miscellaneous other charges, as well as increased operating and maintenance and general and administrative costs.

Liquidity and Capital Resources

Operating Cash Flows

During the first six months of 2002, funds of $230.7 million were provided by operating activities, a decrease of $185.9 million from the same period of 2001. The decrease is due primarily to a $296.3 million decrease in net income partially offset by non-cash transactions and unrealized mark-to-market and hedging activity. The decrease in net income is due largely to lower NGL prices and increased operating and general and administrative expenses.

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

Investing Cash Flows

Our capital expenditures consist of expenditures for acquisitions and construction of additional gathering systems, processing plants, fractionators and other facilities and infrastructure in addition to well connections and upgrades to our existing facilities. For the six months ended June 30, 2002, we spent approximately $166.4 million on capital expenditures. These capital expenditures were primarily for plant expansions, well connections and plant upgrades.

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.

Financing Cash Flows

Bank Financing and Commercial Paper

In March 2002, we entered into a $650.0 million credit facility (the “Facility”), of which $150.0 million can be used for letters of credit. The Facility is used to support our commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 28, 2003, however, any outstanding loans under the Facility at maturity may, at our option, be converted to a one-year term loan. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 53%. The Facility bears interest at a rate equal to, at our option, either (1) the London Interbank Offered Rate (“LIBOR”) plus 0.75% per year or (2) the higher of (a) the Bank of America prime rate and (b) the Federal Funds rate plus 0.50% per year. At June 30, 2002, there were no borrowings against the Facility.

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

At June 30, 2002 we had $189.0 million in outstanding commercial paper, with maturities ranging from one day to 19 days and annual interest rates ranging from 2.00% to 2.20%. At no time did the amount of our outstanding commercial paper exceed 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 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.

At June 30, 2002 we were the guarantor of approximately $107.0 million of debt associated with unconsolidated subsidiaries. Assets of the unconsolidated subsidiaries are pledged as collateral for the debt.

Accounting Pronouncements

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

We are required and plan to adopt the provisions of SFAS No. 143 for the quarter ending March 31, 2003. To accomplish this, we must identify any legal obligations for asset retirement obligations, and determine the fair value of these obligations on the date of adoption. The determination of fair value is complex and requires gathering market information and developing cash flow models. Additionally, we will be required to develop processes to track and monitor these obligations. Because of the effort needed to comply with the adoption of SFAS No. 143, we are currently assessing the new standard but have not yet determined the impact on our consolidated results of operations, cashflows or financial position.

On June 20, 2002, the FASB’s Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” and EITF No. 00-17, “Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10.” The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Income. Comparative financial statements for prior periods must be reclassified to reflect presentation on a net basis. Also, companies must disclose volumes of physically settled energy trading contracts. We are evaluating the impact of this new consensus on the presentation of our Consolidated Statement of Operations, but have not yet determined the impact it will have on total revenues and expenses. The partial consensus will have no impact on net income.

Item 3. Quantitative and Qualitative Disclosure about Market Risks

Risk and Accounting 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 (“RMC”) oversees risk exposure including fluctuations in commodity prices. The RMC ensures that proper policies and procedures are in place to adequately manage our commodity price risks and is responsible for the overall management of commodity price and other risk exposures.

Mark-to-Market Accounting (“MTM accounting”) — Under the MTM accounting method, an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in earnings during the current period. This accounting method has been used by other industries for many years, and in 1998 the Financial Accounting Standards Board’s (“FASB”) Emerging Issues Task Force (“EITF”) issued guidance 98-10 that required MTM accounting for energy trading contracts. MTM accounting reports contracts at their “fair value,” (the value a willing third party would pay for the particular contract at the time a valuation is made).

When available, quoted market prices are used to record a contract’s fair value. However, market values for energy trading contracts may not be readily determinable because the duration of the contracts exceeds the liquid activity in a particular market. If no active trading market exists for a commodity or for a contract’s duration, holders of these contracts must calculate fair value using pricing models or matrix pricing based on contracts with similar terms and risks. This is validated by an internal group independent of the Company’s trading area. Holders of thinly traded securities or investments (mutual funds, for example) use similar techniques to price such holdings.

Correlation and volatility are two significant factors used in the computation of fair values. We validate our internally developed fair values by comparing locations/durations that are highly correlated, using forecasted market intelligence and mathematical extrapolation techniques. While we use industry best practices to develop our pricing models, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values, income recognition and realization in future periods.

Hedge Accounting — Hedging typically refers to the mechanism that the Company uses to mitigate the impact of volatility associated with price fluctuations. Hedge accounting treatment is used when we contract to buy or sell a commodity such as natural gas at a fixed price for future delivery corresponding with the anticipated physical sale or purchase of natural gas (cash flow hedge). In addition, hedge accounting treatment is used when the Company holds firm commitments or asset positions, and enters into transactions that “hedge” the risk that the price of natural gas may change between the contract’s inception and the physical delivery date of the commodity ultimately affecting the underlying value of the firm commitment or position (fair value hedge). While the majority of our hedging transactions are used to protect the value of future cash flows related to our physical assets, to the extent the hedge is effective, we recognize in earnings the value of the contract when the commodity is purchased or sold, or the hedged transaction occurs or settles.

Commodity Price Risk

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

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

DER computations are based on a historical simulation, which uses price movements over a specified period (generally ranging from seven to 14 days) to simulate forward price curves in the energy markets to estimate the potential favorable or unfavorable impact of one day’s price movement on the existing portfolio. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for crude oil, NGLs, gas and other energy-related products. DER computations utilize several key assumptions, including 95% confidence level for the resultant price movement and the holding period specified for the calculation. The Company’s DER amounts for commodity derivatives instruments held for trading purposes are shown in the following table.

Daily Earnings at Risk

Estimated Average

High One-Day

Low One-Day

One-Day Impact

Impact on EBIT

on EBIT for the

for the six

Six months ended

six months ended

months ended

June 30, 2002

June 30, 2001

June 30, 2002

(In millions)

Calculated DER

2.4

1.4

4.8

1.3

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

June 30, 2002

June 30, 2001

30, 2002

(In millions)

Calculated DER

2.5

1.1

3.7

1.8

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

Our exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms. The following table illustrates the movements in the fair value of our trading instruments during the six months ending June 30, 2002.

Changes in Fair Value of Trading Contracts


	(In millions)
Fair value of contracts outstanding at the beginning of the period	$	37.4




Contracts realized or otherwise settled during the period		(55.0	)




Net mark-to-market changes in fair values		24.7

Fair value of contracts outstanding at the end of the period	$	7.1

For the six months ended June 30, 2002, the unrealized net loss recognized in operating income was $30.3 million as compared to an unrealized $26.2 million net gain for the same period in 2001. 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, we use observable market prices for valuing our trading instruments. When quoted market prices are not available, we use established guidelines for the valuation of these contracts. We may use a variety of reasonable methods to assist in determining the valuation of a trading instrument, including analogy to reliable quotations of similar trading instruments, pricing models, matrix pricing and other formula-based pricing methods. These methodologies incorporate factors for which published market data may be available. All valuation methods employed by us are approved by an internal corporate risk management committee and are applied on a consistent basis.

The following table shows the fair value of our trading portfolio as of June 30, 2002.


		Fair Value of Contracts as of June 30, 2002

											Maturity in
		Maturity in			Maturity in			Maturity in			2005 and
Sources of Fair Value		2002			2003			2004			Thereafter			Total Fair Value

		(In millions)
Prices supported by quoted market prices and other external sources		$	17.4		$	(4.5	)	$	1.3		$	(0.3	)	$	13.9




Prices based on models and other valuation methods			(6.0	)		0.7			(1.1	)		(0.4	)		(6.8	)

	Total	$	11.4		$	(3.8	)	$	0.2		$	(0.7	)	$	7.1

The “prices supported by quoted market prices and other external sources” category includes Duke Energy Field Services’ 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. It is important to understand that 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 have 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 NGL 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 OCI 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 OCI 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 OCI through the date of de-designation remain in OCI 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 value realized when such contracts settle.


		Contract Value as of June 30, 2002

											Maturity in
		Maturity in			Maturity in			Maturity in			2005 and			Total Fair
Sources of Fair Value		2002			2003			2004			Thereafter			Value

		(In millions)
Quoted market prices		$	(14.0	)	$	(15.8	)	$	(2.8	)	$	—		$	(32.6	)




Prices based on models or other valuation techniques			(0.5	)		2.4			(1.3	)		(2.2	)		(1.6	)

	Total	$	(14.5	)	$	(13.4	)	$	(4.1	)	$	(2.2	)	$	(34.2	)

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

($25.0) million and $5.0 million, respectively.

Credit Risk

We sell various commodities (i.e. natural gas, NGLs and crude oil) to a variety of customers. Our natural gas customers include local utilities, industrial consumers, independent power producers and merchant energy trading organizations. Our NGL customers range from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of our NGL sales are made at market-based prices, including approximately 40% of NGL production that is committed to Phillips and Chevron Phillips Chemical LLC, under a contract with a primary term that expires on January 1, 2015. 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. On all transactions where we are 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. The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions.

At June 30 2002, we held cash or letters of credit of $9.5 million to secure future performance, and had no amounts deposited with counterparties. Collateral amounts held or posted vary depending on the value of the underlying contracts and cover trading and hedging contracts outstanding. We may be required to return held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions.

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 new debt issuances. Our 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 averages. As of June 30, 2002, the fair value of our interest rate swap was an asset of $1.9 million.

As of June 30, 2002, we had approximately $189.0 million outstanding under a commercial paper program. As a result, 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 .5% in interest rates would result in an increase in annual interest expense of approximately $2.2 million.

Foreign Currency Risk

Our primary foreign currency exchange rate exposure at June 30, 2002 was the Canadian dollar. Foreign currency risk associated with this exposure was not material.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For information concerning litigation and other contingencies, see Part I. Item 1, Note 5 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, 2001, 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









	Exhibit 10.1: Second Amendment to Contract for Services dated as of June 28, 2002 between Duke Energy Field Services, LP and William W. Slaughter.









	Exhibit 99.1: Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.









	Exhibit 99.2: Certification 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, 2002









		/s/ Rose M. Robeson

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

Exhibit Index

			Exhibit 10.1: Second Amendment to Contract for Services dated as of June 28, 2002 between Duke Energy Field Services, LP and William W. Slaughter.

			Exhibit 99.1: Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

			Exhibit 99.2: Certification 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