10-Q 1 h89616e10-q.txt DUKE ENERGY FIELD SERVICES, INC. - 06/30/2001 1 ================================================================================ 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, 2001 COMMISSION FILE NUMBER 0-31095 DUKE ENERGY FIELD SERVICES, LLC (Exact name of registrant as specified in its charter) DELAWARE 76-0632293 (State or other jurisdiction (IRS Employer of incorporation) 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 [ ] ================================================================================ 2 DUKE ENERGY FIELD SERVICES, LLC FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2001 INDEX

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as "may," "could," "project," "believe," "anticipate," "expect," "estimate," "potential," "plan," "forecast" and other similar words. All of such statements other than statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements. These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks include, but are not limited to, the following: o our ability to access the debt and equity markets, which will depend on general market conditions and our credit ratings for our debt obligations; o our use of derivative financial instruments to hedge commodity and interest rate risks; o 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; o the timing and extent of changes in commodity prices, interest rates and demand for our services; i 3 o weather and other natural phenomena; o industry changes, including the impact of consolidations, and changes in competition; o 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 o 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. ii 4 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (IN THOUSANDS)

See Notes to Consolidated Financial Statements. 1 5 DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (IN THOUSANDS)

See Notes to Consolidated Financial Statements. 2 6 DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (IN THOUSANDS)

See Notes to Consolidated Financial Statements. 3 7 DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED BALANCE SHEETS (UNAUDITED) (IN THOUSANDS)

See Notes to Consolidated Financial Statements. 4 8 DUKE ENERGY FIELD SERVICES, LLC CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. GENERAL Duke Energy Field Services, LLC (with its consolidated subsidiaries, "the Company" or "Field Services LLC") operates in the midstream natural gas gathering, marketing and natural gas liquids industries. The Company operates in the two principal segments of the midstream natural gas industry of (1) natural gas gathering, processing, transportation, marketing and storage; and (2) natural gas liquids (NGLs) fractionation, transportation, marketing and trading. 2. ACCOUNTING POLICIES Consolidation - The Consolidated Financial Statements include the accounts of all majority-owned subsidiaries after the elimination of significant intercompany transactions and balances. 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. Accounting for Hedges and Commodity Trading Activities - All derivatives are recognized in the Consolidated Balance Sheets at their fair value as Unrealized Gains or Losses on Trading and Hedging Transactions, as appropriate. On the date the swap, futures or option contracts are entered into, the Company designates the derivative as held for trading (trading instruments), a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedges), or a hedge of a forecasted transaction or future cash flows (cash flow hedges). The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items. The Company currently excludes the extrinsic value of the options when assessing hedge effectiveness. Commodity Trading - Prior to the settlement of any derivative contract held for trading purposes, a favorable or unfavorable price movement is reported as Natural Gas and Petroleum Products Purchases in the Consolidated Statements of Income. An offsetting amount is recorded gross in the Consolidated Balance Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions. When a contract to sell energy 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 Income. Similarly, when a contract to purchase energy is physically settled, the purchase price is included as Natural Gas and Petroleum Products Purchases in the Consolidated Statements of Income. If a contract is not physically settled, the unrealized gain or loss on the balance sheet is reclassified to a receivable or payable account. Fair Value Hedges - Changes in the fair value of a derivative that is designated and qualifies as a fair value hedge and the underlying physical transaction are included in the Consolidated Statements of Income as Sales of Natural Gas and Petroleum Products and Natural Gas and Petroleum Products Purchases, as appropriate, with an offsetting amount recorded gross in the Consolidated Balance Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions. Changes in the fair value of the physical portion of a fair value hedge (i.e., the hedged item) are recorded in the Consolidated Statement of Income 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. Cash Flow Hedges - The fair value of a derivative that is designated and qualifies as a cash flow hedge is included in the Consolidated Balance Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions. The effective portion of the change in fair value of the derivative instrument is included in Other Comprehensive Income (OCI) until earnings are affected by the hedged item. Hedge results are removed from OCI and recorded in the Consolidated Statements of Income in the same accounts as the item being hedged. The Company discontinues hedge 5 9 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, the derivative will continue to be carried on the balance sheet 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 accumulated in OCI will remain in OCI until earnings are effected by the hedged item, unless it is no longer probable that the hedged transaction will occur. Under these circumstances, gains and losses that were accumulated in OCI will be recognized immediately in earnings. Cumulative Effect of Change in Accounting Principle - The Company adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," on January 1, 2001. In accordance with the transition provisions of SFAS No. 133, the Company recorded a cumulative-effect adjustment of $0.4 million as a reduction in earnings and a cumulative-effect adjustment increasing OCI and member's equity by $6.6 million. For the six months ended June 30, 2001, the Company reclassified to earnings a $16.4 million loss from OCI for derivatives included in the transition adjustment for hedge transactions that occurred. The amount reclassified out of OCI will be different from the amount included in the transition adjustment due to market price changes since January 1, 2001. Currently, there are ongoing discussions surrounding the implementation and interpretation of SFAS No. 133 by the Financial Accounting Standards Board's (FASB) Derivative Implementation Group (DIG). If the definition of derivative instruments is altered, this may result in another transition adjustment and impact subsequent operating results. In June, the FASB cleared Issue C10, "Scope Exceptions: Can Option Contracts and Forward Contracts with Optionality Features Qualify for the Normal Purchases and Normal Sales Exception." C10 states that normal purchases and normal sales exception applies only to contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period, in the normal course of business. Therefore, purchased option contracts (including net purchased options) and written option contracts (including net written options) that would require delivery of the related asset at an established price under the contract only if exercised are not eligible to qualify for the normal purchases and normal sales exception. The Company is currently evaluating contracts and agreements with embedded optionality features. Those contracts that include options affecting price are eligible for the scope exception, but contracts that include options affecting volume are not. The Company does not believe that the adoption of C10 will have a significant impact on its consolidated results of operations, cash flows or financial position. Income Taxes - At March 31, 2000, the Company converted to a limited liability company which is a pass-through entity for income tax purposes. As a result, income taxes going forward will consist primarily of miscellaneous state, local and franchise taxes. In addition, the Company has Canadian subsidiaries that are levied certain foreign taxes. The Company follows the asset and liability method of accounting for income taxes. Deferred taxes are provided for temporary differences in the tax and financial reporting basis of assets and liabilities. The Company is required to make quarterly distributions to Duke Energy Corporation (Duke Energy) and Phillips Petroleum Company (Phillips) based on allocated taxable income. The distribution is based on the highest taxable income allocated to either member, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 69.7% for Duke Energy and 30.3% for Phillips. New Accounting Standards -In June 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires all business combinations initiated (as defined by the standard) after June 30, 2001 to be accounted for using the purchase method. Companies may no longer use the pooling method for future combinations. 6 10 SFAS No. 142 is effective for fiscal years beginning after December 15, 2001 and will be adopted by the Company as of January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts will be subject to a fair-value-based annual impairment assessment as described by the new standard. SFAS No. 142 also requires acquired intangible assets to be recognized separately and amortized as appropriate. The Company expects that the adoption of SFAS No. 142 will have an impact on future financial statements due to the discontinuation of goodwill amortization expense. For the six months ended June 30, 2001 amortization expense for goodwill was $6.9 million. The Company is conducting an impairment assessment at levels defined in the new standard and currently does not have an estimate of the impact on its consolidated results of operation, cash flows, or financial position. In July 2001, the FASB Board unanimously approved the issuance of FASB Statement No. 143 (FAS No. 143), Accounting for Obligations Associated with the Retirement of Long-Lived Assets. FAS No. 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. FAS No. 143 is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. The Company is currently assessing but has not yet determined the impact of FAS No. 143 on its consolidated results of operations, cash flows, or financial position. Reclassifications - Certain prior period amounts have been reclassified in the Consolidated Financial Statements to conform to the current presentation. 3. DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND CREDIT RISK Commodity price risk - The Company's principal operations of gathering, processing, and storage of natural gas, and the accompanying operations of processing, fractionation, transportation, and marketing of natural gas liquids create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of natural gas liquids. 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 acquisition 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 such products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sales of commodity-based instruments. 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. Corporate economic risks - From time to time, the Company will enter into debt arrangements that are exposed to market risks related to changes in interest rates. The Company periodically utilizes 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 7 11 attractive interest rates based on historical averages. For the six months ended June 30, 2001, the Company's existing interest rate derivative instruments were not material to its results of operations, cash flows or financial position. Counterparty risks - The Company has credit risk from its extension of credit for sales of energy products and services, and credit risk with its counterparties in terms of settlement risk and performance risk. 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. Fair-value hedges - The Company utilizes 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 (NYMEX or index based). For the six months ended June 30, 2001, the Company's fair-value hedges were effective. As such, the Company did not recognize a gain or loss representing the ineffective portion of all fair-value hedges. 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 a gain or loss. Cash-flow hedges - The Company uses cash flow hedging, 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, and capital expenditures. The Company's primary corporate hedging goals include (1) maintaining minimum cash flows to fund debt service, dividends, production replacement and maintenance capital projects; (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 natural gas liquids. The Company utilizes natural gas, crude oil and NGL futures, over-the-counter swap agreements and options to hedge the impact of market fluctuations in the price of natural gas liquids and other energy-related products. For the six months ended June 30, 2001, the Company recognized a net loss of $14.8 million of which a $0.1 million gain represented the total ineffectiveness of all cash-flow hedges and a $14.9 million loss represented the total derivative settlements. The extrinsic value of the options, $1.6 million for the period ended June 30, 2001, was excluded in the assessment of hedge effectiveness. 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 probable of not 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, 2001, $9.4 million of the deferred net gains on derivative instruments accumulated in OCI are expected to be reclassified as earnings during the next twelve months as the hedge transactions occur. The maximum term over which the Company is hedging its exposure to the variability of future cash-flows is 24 months. 8 12 4. ACQUISITION On May 1, 2001, the Company acquired the outstanding shares of Canadian Midstream Services, Ltd. (CMSL) for a total purchase price of approximately $162.0 million. The purchase price included the assumption of debt of approximately $47.6 million. The acquisition was accounted for under the purchase method of accounting, and the assets and liabilities and results of operations of CMSL have been consolidated in the Company's financial statements since the date of purchase. Revenues and net income for the six months ended June 30, 2001 on a pro forma basis would have increased $7.8 million and $1.4 million respectively, if the acquisition of CMSL had occurred on January 1, 2001. The purchase price has not yet been fully allocated to the individual assets and liabilities acquired. No goodwill has been recorded as a result of the preliminary allocation. On April 30, 2001, the Company acquired in a purchase transaction, Gas Supply Resources, Inc. (GSRI), a propane wholesaler located in the Northeast, for approximately $40.0 million. The proforma impact of the acquisition on the Company's results of operations was not material. 5. FINANCING Credit Facility with Financial Institutions - On March 30, 2001, the Company entered into a new credit facility (the "New Facility"). The New Facility replaces the credit facility that matured on March 30, 2001. 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 29, 2002, 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 $675.0 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, 2001, there were no borrowings against the New Facility. Debt Securities - On February 2, 2001, the Company issued $250.0 million in debt securities. The notes mature and become due and payable on February 1, 2011, and are not subject to any sinking fund provisions. The notes bear interest at 6 7/8%, payable semiannually. The notes are redeemable at the option of the Company. The Company used the proceeds from the issuance of the notes to repay short term debt. 6. COMMITMENTS AND CONTINGENT LIABILITIES Litigation - A judgment has been entered in the case of Chevron U.S.A., Inc. vs. GPM Gas Corporation, a wholly owned subsidiary of Field Services LLC, upholding and construing most favored nations clauses in three 1961 West Texas gas purchase contracts. The U.S. District Court for the Western District of Texas, Midland Division decided in September 1999 that GPM owes Chevron damages, interest and attorney's fees under these contracts. GPM appealed the judgment to the U.S. Court of Appeals for the Fifth Circuit, and on June 1, 2001, the Fifth Circuit affirmed the judgment against GPM. The judgment, including interest, attorney's fees and costs, totaled approximately $16.5 million as of the date of the Fifth Circuit's ruling. On June 15, 2001, GPM filed petitions for rehearing and rehearing en banc with the Fifth Circuit which were denied on July 6, 2001. The Company had previously provided an adequate reserve for this case. In December 1998, Williams Field Services ("Williams") sued Union Pacific Resources Company ("UPRC") and certain affiliates of the Company in Carbon County, Wyoming District Court to enforce its rights under a preferential purchase right. Williams is majority owner and operator of the Echo Springs Gas Plant and Wamsutter Gathering System in which the Company acquired an interest from UPRC (the "Acquired Assets"). Williams' suit claims that they believe a change of control of the corporate entity that held the UPRC interest in the Acquired Assets occurred at the time of the merger between the Company and UPRC and triggered Williams' preferential purchase right. On November 22, 1999, the District Court granted UPRC and the Company's motion for 9 13 summary judgment. Williams appealed this decision on March 23, 2000 to the Wyoming Supreme Court and on June 20, 2001, the Wyoming Supreme Court reversed the District Court's summary judgment ruling and ordered that on summary judgement be entered for Williams. A request for rehearing was denied. At this time, the Company is evaluating its alternatives and the impact, if any, this decision will have on the Company. Environmental - The Company has resolved non-compliance issues with the Texas Natural Resources Conservation Commission associated with the timing of air permit annual compliance certifications submitted to the agency in 1999 and 1998. This matter, a large portion of which was voluntarily self-disclosed to the agency, involves approximately 120 of the Company's facilities that did not meet specific administrative filing deadlines for required air permit paperwork. In addition, the Company resolved with the New Mexico Environment Department alleged non-compliance with various air permit requirements at four of the Company's New Mexico facilities. These matters, the majority of which were also voluntarily self-disclosed to the agency, generally involve document preparation and submittal as required by permits, compliance testing requirements at two facilities, and compliance with permit emissions limits at one facility. These issues with the Texas and New Mexico agencies under relevant air programs resulted in total penalty settlements of approximately $470,000. 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 alleges specific permit non-compliance at eleven facilities that occurred periodically between 1996 and 1999. Allegations under this order relate primarily to emissions from certain compressor engines in excess of what were then new operating permit limits. The other order alleges 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. NMED has initiated settlement discussions and offered to resolve these matters for an amount lower than the calculated penalties. The Company will continue to negotiate with NMED to resolve all issues relating to the alleged violations. Management believes that the final deposition of these proceedings will not have a material adverse effect on the consolidated results of operations, cash flows or financial position of the Company. 7. 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 utilized by management to monitor the business of each segment. The accounting policies for the segments are the same as those described in Note 2. Foreign operations are not material and are therefore not separately identified. 10 14 The following table sets forth the Company's segment information.

11 15

(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, intercompany accounts and other assets. 8. SUBSEQUENT EVENTS On July 10, 2001, the Company acquired additional interests in Mobile Bay Processing Partners, Gulf Coast NGL Pipeline, L.L.C. and Dauphin Island Gathering Partners for approximately $67.4 million. As a result of this acquisition, the Company will consolidate these affiliates due to the Company's control. 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, 2001 and 2000. This discussion should be read in conjunction with the Consolidated Financial Statements and related notes included elsewhere in this report. Duke Energy Field Services, LLC holds the combined North American midstream natural gas gathering, processing, marketing and natural gas liquids business of Duke Energy Corporation (Duke Energy) and Phillips Petroleum Company (Phillips). The transaction in which those businesses were combined on March 31, 2000 is referred to as the "Combination." In this report, the terms "the Company," "we," "us" and "our" refer to Duke Energy Field Services, LLC and our subsidiaries giving effect to the Combination and related transactions. 12 16 From a financial reporting perspective, we are the successor to Duke Energy's North American midstream natural gas business. The subsidiaries of Duke Energy that conducted this business were contributed to us immediately prior to the Combination. For periods prior to the Combination, Duke Energy Field Services and these subsidiaries of Duke Energy are collectively referred to herein as the "Predecessor Company." The historical financial statements and discussion of our business contained in this section for periods ending on or prior to March 31, 2000 relates solely to the Predecessor Company on an historical basis and does not give effect to the Combination, the transfer to our company of additional midstream natural gas assets acquired by Duke Energy or Phillips prior to consummation of the Combination or the transfer to our company of the general partner of TEPPCO Partners, L.P. (TEPPCO) from Duke Energy. OVERVIEW We operate in the two principal business segments of the midstream natural gas industry: o natural gas gathering, processing, transportation 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; o 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 During the six months ended June 30, 2001, the weighted average NGL price (based on index prices from the Mont Belvieu and Conway market hubs that are weighted by our component and location mix) was approximately $0.54 per gallon. Historically, NGL prices have generally followed changes in crude oil prices. However, during the first quarter of 2001, NGL prices departed from this trend and followed the sharp increase in natural gas prices. Despite the impact of the natural gas price spike experienced during the first quarter, we expect that NGL prices will generally follow changes in crude oil prices, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. We also believe that should the recent rise in natural gas prices be sustained, certain NGL component prices will generally remain higher than historical levels. In contrast, we believe that future natural gas prices will be influenced by supply deliverability, the severity of winter weather and the level of U.S. economic growth. We believe that weather will be the strongest determinant of near-term natural gas prices. Price increases in crude oil, NGLs and natural gas have continued to spur increased natural gas drilling activity. For example, the number of active drilling rigs in North America has increased by approximately 35% from approximately 1,169 in June 2000 to approximately 1,573 in June 2001. This drilling activity increase is expected to have a positive effect on natural gas volumes gathered and processed in the near term. 13 17 RESULTS OF OPERATIONS The following is a discussion of our historical results of operations. The discussion for periods ending on or prior to March 31, 2000 relates solely to the Predecessor Company and does not give effect to the Combination, the transfer to our company of additional midstream natural gas assets acquired by Duke Energy or Phillips prior to consummation of the Combination or the transfer to our company of the general partner interest of TEPPCO from Duke Energy. THREE MONTHS ENDED JUNE 30, 2001 COMPARED WITH THREE MONTHS ENDED JUNE 30, 2000 Operating Revenues. Operating revenues increased $363.9 million, or 17%, from $2,172.4 million for the second quarter 2000 to $2,536.3 million for the same period in 2001. Operating revenues from the sale of natural gas and petroleum products accounted for $2,474.7 million of the total and $347.3 million of the increase. NGL production during the second quarter increased 5,200 barrels per day, or 1%, from 401,500 barrels per day in 2000 to 406,700 barrels per day in 2001. Commodity prices were the main factor contributing to higher revenues during the second quarter. Weighted average NGL prices, based on our component product mix, were approximately $.01 per gallon higher and natural gas prices were approximately $1.20 per million British thermal units (Btus) higher for the second quarter of 2001. These price increases yielded average prices of $.48 per gallon and $4.67 per million Btus, respectively, as compared with $.47 per gallon and $3.47 per million Btus for the second quarter of 2000. Revenues associated with gathering, transportation, storage, processing fees and other increased $16.6 million, or 37%, from $45.0 million for the second quarter 2000 to $61.6 million for the same period in 2001. This increase was mainly the result of the December 31, 2000 purchase of the Guadalupe Pipeline System, increased fee based processing and storage activities and the May 1, 2001 purchase of Canadian Midstream Services, Ltd. A $1.2 million hedging loss in the second quarter of 2001 partially offset operating revenue increases. See "--Quantitative and Qualitative Disclosure About Market Risks." Costs and Expenses. Costs of natural gas and petroleum products increased $363.6 million, or 20%, from $1,836.5 million for the second quarter 2000 to $2,200.1 million for the same period in 2001. This increase was primarily due to the interaction of our natural gas and NGL purchase contracts with higher natural gas prices. Operating and maintenance expenses decreased $1.3 million, or 1%, from $91.3 million for the second quarter of 2000 to $90.0 million for the same period in 2001. General and administrative expenses decreased $7.3 million, or 18%, from $40.3 million for the second quarter of 2000 to $33.0 million for the same period in 2001. These decreases were primarily the result of cost reduction efforts, plant consolidation and decreased centralized service charges from our parents. Depreciation and amortization increased $0.6 million from $67.3 million for the second quarter of 2000 to $67.9 million for the same period in 2001. This slight increase was due to ongoing capital expenditures for well connections, facility maintenance/enhancements and acquisitions. Equity Earnings. Equity earnings of unconsolidated affiliates increased $3.0 million, or 38%, from $7.9 million for the second quarter of 2000 to $10.9 million for the same period in 2001. This increase was due primarily to increased earnings associated with the general partnership interest in TEPPCO. Interest. Interest expense decreased $5.0 million, or 11%, from $45.4 million for the second quarter 2000 to $40.4 million for the same period in 2001. This decrease was primarily the result of issuance of commercial paper and the subsequent third quarter 2000 and first quarter 2001 debt offerings. Income Taxes. At March 31, 2000, the Predecessor Company converted to a limited liability company which is a pass-through entity for income tax purposes. As a result, substantially all of the Predecessor Company's existing net 14 18 deferred tax liability of $327.0 million was eliminated and a corresponding income tax benefit was recorded. Ongoing tax expenses relate to various state, local and foreign taxes that are not significant. Net Income. Net income increased $23.4 million from $92.2 million for the second quarter 2000 to $115.6 million for the same period in 2001. This increase was primarily the result of increased equity earnings from TEPPCO, cost reduction efforts, and increased fee based services. EBITDA. In addition to the generally accepted accounting principles (GAAP) measures described above, we also use the non-GAAP measure of EBITDA. EBITDA consists of income from continuing operations before interest expense, income tax expense, and depreciation and amortization expense. EBITDA is a measure used to provide information regarding our ability to cover fixed charges such as interest, taxes, dividends and capital expenditures. In addition, EBITDA provides a comparable measure to evaluate our performance relative to that of our competitors by eliminating the capitalization structure and depreciation charges, which may vary significantly within our industry. Although the GAAP financial statement measure of net income or loss, in total and by segment, is indicative of our profitability, net income does not necessarily reflect our ability to fund our fixed charges on a periodic basis. We therefore use GAAP and non-GAAP measures in evaluating our overall performance as well as that of our related segments. In addition, we use both types of measures to evaluate our performance relative to other companies within our industry. EBITDA for the natural gas gathering, processing, transportation and storage segment increased $1.9 million from $239.8 million for the second quarter 2000 to $241.7 million for the same period in 2001. This increase was primarily the result of higher earnings for the general partnership interest in TEPPCO, partially offset by the interaction of our gas purchase contracts with higher natural gas prices. Cost reduction initiatives and decreased centralized service charges from our parents contributed $7.3 million to EBITDA during the second quarter of 2001. EBITDA for the NGL's fractionation, transportation, marketing and trading segment increased $2.9 million from $12.6 million for the second quarter 2000 to $15.5 million for the same period in 2001 due primarily to higher margins associated with NGL trading, partially offset by the disposition of two NGL pipelines effective January 1, 2001. SIX MONTHS ENDED JUNE 30, 2001 COMPARED WITH SIX MONTHS ENDED JUNE 30, 2000 Operating Revenues. Operating revenues increased $2,292.8 million, or 63%, from $3,623.6 million for the six months ended June 30, 2000 to $5,916.4 million for the same period in 2001. Operating revenues from the sale of natural gas and petroleum products accounted for $5,796.9 million of the total and $2,254.1 million of the increase. Of this increase, approximately $1,064.1 million was related to the addition of the Phillips' midstream natural gas business to our operations in the Combination on March 31, 2000. NGL production during the six months ended June 30, 2001 increased 72,600 barrels per day, or 23%, from 316,300 barrels per day in 2000 to 388,900 barrels per day in 2001. The primary cause of this increase was the addition of Phillips' midstream natural gas business, offset by reduced recoveries at certain facilities resulting from tightened fractionation spreads driven by high natural gas prices. Commodity prices also contributed to higher revenues. Weighted average NGL prices, based on our component product mix, were approximately $.05 per gallon higher and natural gas prices were approximately $2.89 per million British thermal units (Btus) higher for the six months ended June 30, 2001. These price increases yielded average prices of $.54 per gallon and $5.88 per million Btus, respectively, as compared with $.49 per gallon and $2.99 per million Btus for the same period in 2000. Revenues associated with gathering, transportation, storage, processing fees and other increased $38.8 million, or 48%, from $80.7 million for the six months ended June 30, 2000 to $119.5 million for the same period in 2001, mainly as a result of the Combination and increased fee based activities associated with acquisitions and processing arrangements. A $15.8 million hedging loss during the six months ended June 30, 2001 partially offset operating revenue increases. See "--Quantitative and Qualitative Disclosure About Market Risks." 15 19 Costs and Expenses. Costs of natural gas and petroleum products increased $2,097.6 million, or 67%, from $3,115.0 million for the six months ended June 30, 2000 to $5,212.6 million for the same period in 2001. This increase was due to the addition of the Phillips' midstream natural gas business in the Combination (approximately $881.4) and the interaction of our natural gas and NGL purchase contracts with higher commodity prices. Operating and maintenance expenses increased $39.1 million, or 28%, from $140.4 million for the six months ended June 30, 2000 to $179.5 million for the same period in 2001. Of this increase, approximately $35.6 million was related to the addition of the Phillips' midstream natural gas business. General and administrative expenses decreased $4.6 million, or 7%, from $70.0 million for the six months ended June 30, 2000 to $65.4 million for the same period in 2001. This decrease was primarily the result of cost savings initiatives and decreased centralized service charges from our parents, partially offset by increased activity resulting from the addition of the Phillips' midstream natural gas business in the Combination. Depreciation and amortization increased $29.3 million, or 28%, from $105.4 million for the six months ended June 30, 2000 to $134.7 million for the same period in 2001. Of this increase, $21.8 million was due to the addition of the Phillips' midstream natural gas business in the Combination. The remainder was due to ongoing capital expenditures for well connections, facility maintenance/enhancements and acquisitions. Equity Earnings. Equity earnings of unconsolidated affiliates increased $1.4 million, or 10%, from $14.7 million for the six months ended June 30, 2000 to $16.1 million for the same period in 2001. This increase was due to higher earnings from our general partnership interest in TEPPCO, partially offset by the combination of the divestiture of certain joint venture (JV) interests in the Conoco/Mitchell transaction, divestiture of the Westana JV and reduced earnings from keep whole supply contracts in South Texas and offshore processing partnerships. Interest. Interest expense increased $22.5 million, or 38%, from $59.9 million for the six months ended June 30, 2000 to $82.4 million for the same period in 2001. This increase was primarily the result of issuance of commercial paper and the subsequent third quarter 2000 and first quarter 2001 debt offerings. Income Taxes. At March 31, 2000, the Predecessor Company converted to a limited liability company which is a pass-through entity for income tax purposes. As a result, substantially all of the Predecessor Company's existing net deferred tax liability of $327.0 million was eliminated and a corresponding income tax benefit was recorded. Ongoing tax expenses relate to various state, local and foreign taxes that are not significant. Net Income. Net income decreased $196.1 million from $454.1 million for the six months ended June 30, 2000 to $258.0 million for the same period in 2001. This decrease was the result of the elimination of the predecessor Company's net deferred tax liability of $327.0 million in 2000, offset by a $107.5 million increase resulting from the addition of the Phillips' midstream natural gas business in the Combination, increased commodity prices, cost savings and other acquisitions. EBITDA for the natural gas gathering, processing, transportation and storage segment increased $169.4 million from $345.5 million for the six months ended June 30, 2000 to $514.9 million for the same period in 2001. Of this increase, approximately $152.3 million was due to the addition of the Phillips' midstream natural gas business in the Combination, and approximately $65.0 million was due to a $.05 per gallon increase in average NGL prices. Additional increases were attributable to the Conoco/Mitchell transaction and the acquisition of the general partnership interest in TEPPCO as of March 31, 2000. These benefits were offset by approximately $44.9 million due to a $2.99 per million Btu increase in natural gas prices, and hedging losses of $15.8 million. EBITDA for the NGL's fractionation, transportation, marketing and trading segment decreased $10.7 million from $37.1 million for the six months ended June 30, 2000 to $26.4 million for the same period in 2001 due primarily to lower first quarter margins associated with NGL trading and the disposition of two NGL pipelines effective January 1, 2001. 16 20 LIQUIDITY AND CAPITAL RESOURCES CREDIT FACILITY WITH FINANCIAL INSTITUTIONS On March 30, 2001, we entered into a new credit facility (the "New Facility"). The New Facility replaces the credit facility that matured on March 30, 2001. 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 29, 2002, 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 $675.0 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, 2001, there were no borrowings against the New Facility. On February 2, 2001, the Company issued $250.0 million in debt securities. The notes mature and become due and payable on February 1, 2011, and are not subject to any sinking fund provisions. The notes bear interest at 6 7/8%, payable semiannually. The notes are redeemable at the option of the Company. The Company used the proceeds from the issuance of the notes to repay short term debt. 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 credit 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. CAPITAL EXPENDITURES 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 refurbishment of our existing facilities. For the six months ended June 30, 2001, we spent approximately $308.7 million on capital expenditures. On April 30, 2001, the Company acquired in a purchase transaction, Gas Supply Resources, Inc. (GSRI), a propane wholesaler located in the Northeast, for approximately $40.0 million. On May 1, 2001, the Company acquired the outstanding shares of Canadian Midstream Services, Ltd. (CMSL) for a total purchase price of approximately $162.0 million. The purchase price included the assumption of debt of approximately $47.6 million. Our level of capital expenditures for acquisitions and construction depends on many factors, including industry conditions, the availability of attractive acquisition candidates 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. CASH FLOWS Net cash from operating activities for the six months ended June 30, 2001 improved to $419.4 million, from net cash from operating activities of $324.7 million for the same period in 2000, primarily due to higher commodity prices and acquisitions. Net cash used in investing activities was $262.4 million for the six months ended June 30, 2001 compared to $189.3 million for the same period in 2000. The acquisition of Canadian Midstream Services, Ltd. and ongoing system development and maintenance in 2001 were the primary uses of the invested cash. The net cash used in investing activities was financed through operating activities and proceeds from the issuance of short term debt. Net cash used in financing activities was $157.5 million for the six months ended June 30, 2001 compared to $133.7 million for the same period in 2000. Tax related distributions to parents and repayment of the Company's short term debt were 17 21 the primary uses of this cash, offset by issuance of $250 million of 6 7/8% Senior Unsecured Notes due 2011 in February 2001. NEW ACCOUNTING STANDARDS In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires all business combinations initiated (as defined by the standard) after June 30, 2001 to be accounted for using the purchase method. Companies may no longer use the pooling method for future combinations. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001 and will be adopted by the Company as of January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts will be subject to a fair-value-based annual impairment assessment as described by the new standard. SFAS No. 142 also requires acquired intangible assets to be recognized separately and amortized as appropriate. We expect that the adoption of SFAS No. 142 will have an impact on future financial statements due to the discontinuation of goodwill amortization expense. For the six months ended June 30, 2001 amortization expense for goodwill was $6.9 million. We are conducting an impairment assessment at levels defined by the new standard and currently do not have an estimate of the impact on our consolidated results of operation, cash flows, or financial position. In July 2001, the FASB Board unanimously approved the issuance of FASB Statement No. 143 (FAS No. 143), Accounting for Obligations Associated with the Retirement of Long-Lived Assets. FAS No. 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. FAS No. 143 is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. We are currently assessing but have not yet determined the impact of FAS No. 143 on our consolidated results of operations, cash flows, or financial position. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS We are exposed to market risks associated with interest rates, commodity prices, and equity prices. Management has established comprehensive risk management policies to monitor and manage these market risks. The Company's 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 comprised of management personnel who receive periodic updates from standing personnel in the Company's marketing and trading operations, corporate hedging operations, mid-office function, and back office control group on commodity price risks and energy marketing and trading operations. The Company's treasury department manages the Company's credit risks. There have been no material changes in the Company's market risk since December 31, 2000. 18 22 COMMODITY PRICE RISK We are subject to significant risks due to fluctuations in commodity prices, primarily with respect to the prices of NGLs that we own as a result of our processing activities. Based upon the Company's 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 $(26.0) million and $3.0 million, respectively. After considering the effects of commodity hedge positions in place at June 30, 2001, it is estimated that if NGL prices average $.01 per gallon less in the next twelve months pre-tax net income would decrease $18.7 million. Conversely, it is estimated that if NGL prices average $.01 per gallon more in the next twelve months pre-tax net income would increase $18.7 million. INTEREST RATE RISK As of June 30, 2001, we had approximately $119.9 million outstanding under a commercial paper program and no outstanding bank borrowings. 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 $0.6 million. FOREIGN CURRENCY RISK Our primary foreign currency exchange rate exposure at June 30, 2001 was the Canadian dollar. Foreign currency risk associated with this exposure was not material. 19 23 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, 2000, 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 consolidated results of operations or financial position. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits 10.1 364-Day Credit Facility among Duke Energy Field Services, LLC, Duke Energy Field Services Corporation, Bank of America, N.A., as Agent and the Lenders named therein, dated March 30, 2001 (b) Reports on Form 8-K None. 20 24 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 13, 2001 /s/ JOHN E. JACKSON ---------------------------------------------- John E. Jackson Vice President and Chief Financial Officer (On Behalf of the Registrant and as Principal Financial and Accounting Officer) 21 25 EXHIBIT INDEX

DUKE ENERGY FIELD SERVICES LLC 10-Q