1 THE INFORMATION IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS ARE NOT AN OFFER TO SELL THESE SECURITIES AND WE ARE NOT SOLICITING AN OFFER TO BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED. Filed pursuant to Rule 424(b)(5) Registration No. 333-41854 SUBJECT TO COMPLETION PRELIMINARY PROSPECTUS SUPPLEMENT DATED AUGUST 3, 2000 PROSPECTUS SUPPLEMENT - ---------------------------------- (TO PROSPECTUS DATED AUGUST 2, 2000) [DUKE ENERGY FIELD SERVICES LOGO] DUKE ENERGY FIELD SERVICES, LLC $ % NOTES DUE $ % NOTES DUE ---------------------- We are offering and selling an aggregate of $ of our % notes due and an aggregate of $ of our % notes due . Interest on the notes of each series is payable on February and August of each year, beginning on February , 2001. The % notes will mature on August , and the % notes will mature on August , . We may redeem some or all of our notes at any time. We describe the redemption price under the heading "Description of the Notes -- Optional Redemption" on page S-47 of this prospectus supplement. We will also pay accrued interest to the date of any redemption. The notes of each series are unsecured and rank equally with all of our other unsecured and senior indebtedness. The notes will not be entitled to the benefit of any sinking fund. ---------------------- PUBLIC OFFERING UNDERWRITING PROCEEDS, BEFORE PRICE(1) DISCOUNT EXPENSES TO US --------------- ------------ ---------------- Per Note due............................................... % % % Total...................................................... $ $ $ Per Note due............................................... % % % Total...................................................... $ $ $ (1) Plus accrued interest from , 2000, if settlement occurs after that date Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the attached prospectus is truthful or complete. Any representation to the contrary is a criminal offense. The notes of each series will be ready for delivery on or about August , 2000. ---------------------- JOINT BOOK-RUNNING MANAGERS MERRILL LYNCH & CO. J.P. MORGAN & CO. ---------------------- BANC OF AMERICA SECURITIES LLC CHASE SECURITIES INC. LEHMAN BROTHERS MORGAN STANLEY DEAN WITTER ---------------------- The date of this prospectus supplement is August , 2000. 2 OWNERSHIP OF OUR COMPANY We are Duke Energy Field Services, LLC, the issuer of the notes offered by this prospectus supplement. On March 31, 2000, the North American midstream natural gas gathering, processing, marketing and natural gas liquids businesses of Duke Energy Corporation ("Duke Energy") and Phillips Petroleum Company ("Phillips") were combined into our company. The following diagram is a summary of the ownership structure of our company. Each of Duke Energy and Phillips own both common and preferred membership interests in our company. Graph 3 TABLE OF CONTENTS PROSPECTUS SUPPLEMENT PAGE ---- Prospectus Supplement Summary............................... S-4 Use of Proceeds............................................. S-13 Capitalization.............................................. S-13 Management's Discussion and Analysis of Financial Condition and Results of Operations................................. S-14 Business.................................................... S-28 Description of the Notes.................................... S-47 Underwriting................................................ S-50 Validity of the Notes....................................... S-51 Index to Financial Statements............................... F-1 PROSPECTUS PAGE ---- About this Prospectus....................................... 2 Where You Can Find More Information......................... 2 Cautionary Statement about Forward-Looking Statements....... 3 Our Company................................................. 4 Ratio of Earnings to Fixed Charges.......................... 6 Use of Proceeds............................................. 6 Description of Debt Securities.............................. 7 Plan of Distribution........................................ 16 Experts..................................................... 18 Validity of the Securities.................................. 18 --------------------- You should rely only on the information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus. We have not, and the underwriters have not, authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. If this prospectus supplement is inconsistent with the accompanying prospectus, you should rely on this prospectus supplement. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should assume that the information in this prospectus supplement and the accompanying prospectus is accurate only as of the respective dates on the front of those documents or earlier dates specified therein. Our business, financial condition, results of operations and prospects may have changed since those dates. S-3 4 PROSPECTUS SUPPLEMENT SUMMARY This summary highlights information contained elsewhere in this prospectus supplement and the accompanying prospectus. This summary does not contain all of the information that you should consider before investing in our notes. You should read this entire prospectus supplement and the accompanying prospectus carefully, including the historical and pro forma financial statements and related notes, before making an investment decision. Duke Energy Field Services, LLC was recently formed to hold the combined North American midstream natural gas gathering, processing, marketing and natural gas liquids businesses of Duke Energy Corporation and Phillips Petroleum Company. The transaction in which those businesses were combined is referred to in this prospectus supplement as the "Combination." 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 natural gas liquids in Mexico and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our Board of Directors. Unless the context otherwise requires, descriptions of assets, operations and results in this prospectus supplement give effect to the Combination and related transactions, the transfer to us of additional midstream natural gas assets acquired by Duke Energy or Phillips prior to the Combination and the transfer to us of the general partner of TEPPCO Partners, L.P., all of which are described in more detail under "Management's Discussion and Analysis of Financial Condition and Results of Operations -- The Combination." In this prospectus supplement, the terms "we," "us" and "our" refer to Duke Energy Field Services, LLC and our subsidiaries, giving effect to the Combination and related transactions. OUR BUSINESS The midstream natural gas industry is the link between exploration and production of raw natural gas and the delivery of its components to end-use markets. We operate in the two principal segments of the midstream natural gas industry: - natural gas gathering, processing, transportation, marketing and storage; and - natural gas liquids ("NGLs") fractionation, transportation, marketing and trading. We believe that we are one of the largest gatherers of raw natural gas, based on wellhead volume, in North America. We are the largest producer, and we believe that we are one of the largest marketers, of NGLs in North America. In 1999: - we gathered and/or transported an average of approximately 7.3 billion cubic feet per day of raw natural gas; - we produced an average of approximately 400,000 barrels per day of NGLs; and - we marketed and traded an average of approximately 486,000 barrels per day of NGLs. During 1999, our natural gas gathering, processing, transportation, marketing and storage segment produced $981.5 million of gross margin and $592.4 million of EBITDA, excluding general and administrative expenses, and our NGL fractionation, transportation, marketing and trading segment produced $38.3 million of gross margin and $38.1 million of EBITDA, excluding general and administrative expenses. During the six months ended June 30, 2000, our natural gas gathering, processing, transportation, marketing and storage segment produced $657.1 million of gross margin and $484.4 million of EBITDA, excluding general and administrative expenses, and our NGL fractionation, transportation, marketing and trading segment produced $26.5 million of gross margin and $26.1 million of EBITDA, excluding general and administrative expenses. We gather raw natural gas through gathering systems located in seven major natural gas producing regions: Permian Basin, Mid-Continent, East Texas-Austin Chalk-North Louisiana, Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf of Mexico and Western Canada. Our gathering systems consist S-4 5 of approximately 57,000 miles of gathering pipe, with approximately 38,000 active connections to producing wells. Our natural gas processing operations involve the separation of raw natural gas gathered both by our gathering systems and by third-party systems into NGLs and residue gas. We process the raw natural gas at our 70 owned and operated plants and at 13 third-party operated facilities in which we hold an equity interest. The NGLs separated from the raw natural gas by our processing operations are either sold and transported as NGL raw mix or further separated through a process known as fractionation into their individual components (ethane, propane, butanes and natural gasoline) and then sold as components. We fractionate NGL raw mix at our 12 owned and operated processing facilities and at two third-party operated fractionators located on the Gulf Coast in which we hold an equity interest. We sell NGLs to a variety of customers ranging 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 our NGL production that is committed to Phillips under a 15-year contract. We market approximately 370,000 barrels per day of NGLs processed at our owned and operated plants and 40,000 barrels per day of NGLs processed at third-party operated facilities and trade approximately 75,000 barrels per day of NGLs at market centers. The residue gas that results from our processing is sold at market-based prices to marketers or end-users, including large industrial customers and natural gas and electric utilities serving individual consumers. We market residue gas through our wholly owned gas marketing company. We also store residue gas at our 8.5 billion cubic foot natural gas storage facility. On March 31, 2000, we obtained by transfer from Duke Energy the general partner of TEPPCO Partners, L.P. ("TEPPCO"), a publicly traded limited partnership which owns and operates a network of pipelines for refined products and crude oil. The general partner is responsible for the management and operations of TEPPCO. We believe that our ownership of the general partner of TEPPCO improves our business position in the transportation sector of the midstream natural gas industry and provides additional flexibility in pursuing our disciplined acquisition strategy by providing an alternative acquisition vehicle. It also provides us with an opportunity to sell appropriate assets currently held by our company to TEPPCO. Through our ownership of the general partner of TEPPCO we have the right to receive from TEPPCO incentive cash distributions in addition to a 2% share of distributions based on our general partner interest. At TEPPCO's 1999 per unit distribution level, the general partner: - receives approximately 14% of the cash distributed by TEPPCO to its partners, which consists of 12% from the incentive cash distribution and 2% from the general partner interest; and - under the incentive cash distribution provisions, receives 50% of any increase in TEPPCO's per unit cash distributions. On July 21, 2000, TEPPCO acquired, for $318.5 million, Atlantic Richfield Company's ownership interests in a 500-mile crude oil pipeline that extends from a marine terminal at Freeport, Texas to Cushing, Oklahoma, a 416-mile crude oil pipeline that extends from Jal, New Mexico to Cushing, a 400-mile crude oil pipeline that extends from West Texas to Houston, crude oil terminal facilities in Midland, Texas, Cushing and the Houston area and receipt and delivery pipelines centered around Midland. OUR BUSINESS STRATEGY We believe that we are one of the largest gatherers of raw natural gas, based on wellhead volume, in North America. We are the largest producer, and we believe that we are one of the largest marketers, of NGLs in North America. 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. We have significant midstream natural gas operations in five of the largest natural gas S-5 6 producing regions in North America. To take advantage of anticipated growth in natural gas demand in North America, we are pursuing the following strategies: - Capitalize on the size and focus of our existing operations. We intend to use the size, scope and concentration of our assets in our regions of operation to take advantage of growth opportunities and to acquire additional supplies of raw natural gas. Our significant market presence and asset base generally provide us with a competitive advantage in capturing new supplies of raw natural gas because of our resulting lower costs of connection to new wells and of processing additional raw natural gas. In addition, we believe our size and geographic diversity allow us to benefit from the growth of natural gas production in multiple regions while mitigating the adverse effects from a downturn in any one region. - Increase our presence in each aspect of the midstream business. We are active in each significant aspect of the midstream natural gas value chain, including raw natural gas gathering, processing, and transportation, NGL fractionation and NGL and residue gas transportation and marketing. Each link in the value chain provides us with an opportunity to earn incremental income from the raw natural gas that we gather and from the NGLs and residue gas that we produce. We intend to grow our significant NGL market presence by investing in additional NGL infrastructure, including pipelines, fractionators and terminals. - Increase our presence in high growth production areas. According to the Energy Information Administration's report "Annual Energy Outlook 2000" (the "EIA Report"), production from areas such as Western Canada, Onshore Gulf of Mexico, Rocky Mountains and Offshore Gulf of Mexico is expected to increase significantly to meet anticipated increases in demand for natural gas in North America. We intend to use our strategic asset base in these growth areas and our leading position in the midstream natural gas industry as a platform for future growth in these areas. We plan to increase our operations in these areas by following a disciplined acquisition strategy, and by expanding existing infrastructure and constructing new gathering lines and processing facilities. - Capitalize on proven acquisition skills in a consolidating industry. In addition to pursuing internal growth by attracting new raw natural gas supplies, we intend to use our substantial acquisition and integration skills to continue to participate selectively in the consolidation of the midstream natural gas industry. We have pursued a disciplined acquisition strategy focused on acquiring complementary assets during periods of relatively low commodity prices and integrating the acquired assets into our operations. Since 1996, we have completed over 20 acquisitions, increasing our raw natural gas processing capacity by over 275%. These acquisitions demonstrate our ability to successfully identify, acquire and integrate attractive midstream natural gas operations. - Further streamline our low-cost structure. Our economies of scale, operating efficiency and resulting low cost structure enhance our ability to attract new raw natural gas supplies and generate current income. The low-cost provider in any region can more readily attract new raw natural gas volumes by offering more competitive terms to producers. We believe the Combination provides us with a complementary base of assets from which to further extract operating efficiencies and cost reductions, while continuing to provide superior customer service. We are a Delaware limited liability company, and we were formed on December 15, 1999. Our principal executive offices are located at 370 17th Street, Suite 900, Denver, Colorado 80202, and our telephone number is (303) 595-3331. S-6 7 THE OFFERING Offered Securities......... $ principal amount of % notes due $ principal amount of % notes due Maturity Dates............. % notes -- August , % notes -- August , Interest Payment Dates..... February and August of each year, commencing February , 2001. Optional Redemption........ Each series of notes will be redeemable in whole or in part, at our option at any time, at redemption prices as set forth herein under "Description of the Notes -- Optional Redemption." Ranking.................... Each series of notes will be our direct, unsecured and senior obligations and will rank equal in priority with any other series of notes and with our other unsecured and senior indebtedness. Ratings.................... The notes of each series have been assigned ratings of BBB by Standard & Poor's Ratings Services, Baa2 by Moody's Investors Service, Inc. and BBB by Fitch IBCA, Inc. These ratings services will continue to monitor our debt ratings and will make future adjustments to the extent warranted. Each rating reflects only the views of Standard & Poor's Ratings Services, Moody's Investors Service, Inc. or Fitch IBCA, Inc., as the case may be, and is not a recommendation to buy, sell or hold the notes. There is no assurance that any such rating will be retained for any given period of time or that it will not be revised downward or withdrawn entirely by Standard & Poor's Ratings Services, Moody's Investors Service, Inc. or Fitch IBCA, Inc., as the case may be, if, in their respective judgments, circumstances warrant. Any such downward revision or withdrawal of any rating may have an adverse effect on the market price or marketability of the notes. Interest Rates............. Each series of notes will bear interest at the annual rate contained in its title. Certain Covenants.......... The Indenture governing the notes contains certain covenants that, among other things: - limit our ability and the ability of our subsidiaries to create liens and enter into sale and leaseback transactions; and - limit our ability to engage in mergers and consolidations or transfer substantially all of our assets. See "Description of Debt Securities" in the accompanying prospectus. Use of Proceeds............ The net proceeds from the offering of the notes will be used to repay outstanding commercial paper. See "Use of Proceeds." S-7 8 PRESENTATION OF FINANCIAL INFORMATION AND OTHER DATA Duke Energy Field Services, LLC is a new company that holds the combined North American midstream natural gas businesses of Duke Energy and Phillips. Because our operations have only recently been combined and these operations have grown significantly through acquisitions, our historical and pro forma financial information and operating data may not provide an accurate indication of: - what our actual results would have been if the transactions presented on a pro forma basis had actually been completed as of the dates presented; or - what our future results of operations are likely to be. HISTORICAL FINANCIAL AND OTHER DATA 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 Duke Energy Field Services, LLC immediately prior to the Combination on March 31, 2000. For periods prior to the Combination, Duke Energy Field Services, LLC and these former subsidiaries of Duke Energy are collectively referred to in this prospectus supplement as the "Predecessor Company." The historical financial statements and related financial and other data for periods prior to March 31, 2000 included in this prospectus supplement reflect the business of the Predecessor Company. The historical financial information and other data included in this prospectus supplement should be viewed in light of the following: - the Combination is reflected as a March 31, 2000 acquisition of the midstream natural gas business contributed to our company by Phillips in the Combination; - the Predecessor Company's acquisition of Union Pacific Fuels is reflected as a March 31, 1999 acquisition by the Predecessor Company; and - the historical financial statements for periods prior to March 31, 2000 included in this prospectus supplement do not include the results of the general partner of TEPPCO. For your additional information, we have also included the audited financial statements of: - the midstream natural gas business of Phillips that was transferred to us in the Combination; and - Union Pacific Fuels. PRO FORMA FINANCIAL AND OTHER INFORMATION In addition to the historical financial information and other data, this prospectus supplement includes: - unaudited pro forma income statements of our company for 1999 and the six months ended June 30, 2000, each reflecting: - the Combination; - the Predecessor Company's acquisition of Union Pacific Fuels; - the transfer to us of additional midstream natural gas assets acquired by Duke Energy or Phillips prior to consummation of the Combination; - the transfer to us of the general partner of TEPPCO; - the issuance of an aggregate of $300 million of preferred membership interests in our company to affiliates of Duke Energy and Phillips and the application of the proceeds therefrom; and - the issuance of the notes offered hereby and the application of the net proceeds therefrom; in each case as if the transactions had occurred on January 1, 1999; - an unaudited pro forma balance sheet of our company as of June 30, 2000 reflecting: - the issuance of our preferred membership interests to affiliates of Duke Energy and Phillips and the application of the proceeds therefrom; and - the issuance of the notes offered hereby and the application of the net proceeds therefrom; in each case as if the transactions had occurred on June 30, 2000; and - additional financial and other data giving effect to the Union Pacific Fuels acquisition and the Combination, as if each had occurred on January 1, 1995. S-8 9 SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OTHER DATA The following tables set forth selected historical financial and other data. The historical income statement data and cash flow data for each of the three years ended December 31, 1999 and the historical balance sheet data as of December 31 in each of those three years have been derived from the Predecessor Company's audited historical financial statements. The historical financial information for 1995 and 1996 and the six months ended June 30, 1999 and 2000 is derived from unaudited financial statements. The historical data set forth below for periods ending on or prior to March 31, 2000 relates only to the Predecessor Company and does not reflect the results of operations or financial condition of the Phillips businesses transferred to us in the Combination. In addition, the following tables set forth selected pro forma financial and other data, which reflect the historical data, adjusted for: - the acquisition of the midstream natural gas business of Phillips in the Combination; - the acquisition of Union Pacific Fuels; - incurrence of indebtedness to fund the cash distributions to Duke Energy and Phillips in connection with the Combination as described in "Management's Discussion and Analysis of Financial Condition and Results of Operations;" - the transfer to our company of additional midstream natural gas assets acquired by Duke Energy prior to consummation of the Combination; - the transfer to our company of the general partner of TEPPCO; - the issuance of an aggregate of $300 million of preferred membership interests in our company to affiliates of Duke Energy and Phillips and the application of the proceeds therefrom; and - the issuance of the notes offered hereby and the application of the net proceeds therefrom; as if all had occurred as of January 1, 1999 for income statement purposes and June 30, 2000 for balance sheet purposes. The data should be read in conjunction with the financial statements and related notes and other financial information appearing elsewhere in this prospectus supplement. We are a recently combined company, and the pro forma data set forth below are not necessarily indicative of the results that we would have achieved if we had been a combined entity for all periods presented or the results that may occur in the future. HISTORICAL PRO FORMA ------------------------------------------------------------- ---------- 1995 1996 1997 1998 1999(1)(2) 1999(1) -------- ---------- ---------- ---------- ----------- ---------- (IN THOUSANDS) INCOME STATEMENT DATA: Operating revenues: Sales of natural gas and petroleum products........................ $752,880 $1,321,111 $1,700,029 $1,469,133 $ 3,310,260 $5,268,927 Transportation, storage and processing...................... 52,308 70,577 101,803 115,187 148,050 305,653 -------- ---------- ---------- ---------- ----------- ---------- Total operating revenues... 805,188 1,391,688 1,801,832 1,584,320 3,458,310 5,574,580 Costs and expenses: Natural gas and petroleum products........................ 601,533 1,070,805 1,468,089 1,338,129 2,965,297 4,554,776 Operating and maintenance......... 65,458 93,838 104,308 113,556 181,392 393,134 Depreciation and amortization..... 37,281 55,500 67,701 75,573 130,788 243,869 General and administrative........ 20,576 43,871 36,023 44,946 73,685 96,210 Net (gain) loss on sale of assets.......................... (9,029) (2,350) (236) (33,759) 2,377 1,470 -------- ---------- ---------- ---------- ----------- ---------- Total costs and expenses... 715,819 1,261,664 1,675,885 1,538,445 3,353,539 5,289,459 Operating income.................... 89,369 130,024 125,947 45,875 104,771 285,121 Equity in earnings of unconsolidated affiliates........................ 1,660 2,997 9,784 11,845 22,502 27,338 -------- ---------- ---------- ---------- ----------- ---------- Earnings before interest and tax.... 91,029 133,021 135,731 57,720 127,273 312,459 Interest expense.................... 20,115 12,747 51,113 52,403 52,915 183,840 -------- ---------- ---------- ---------- ----------- ---------- Earnings before income tax.......... 70,914 120,274 84,618 5,317 74,358 128,619 Income tax expense.................. 37,299 35,665 33,380 3,289 31,029 2,600 -------- ---------- ---------- ---------- ----------- ---------- Net income.......................... $ 33,615 $ 84,609 $ 51,238 $ 2,028 $ 43,329 $ 126,019 ======== ========== ========== ========== =========== ========== S-9 10 HISTORICAL PRO FORMA ------------------------------------------------------------- ---------- 1995 1996 1997 1998 1999(1)(2) 1999(1) -------- ---------- ---------- ---------- ----------- ---------- (IN THOUSANDS, EXCEPT PER UNIT DATA) OTHER DATA: Cash flow data: Cash flow from operations.......... $ 173,357 $ 40,409 $ 173,136 Cash flow from investing activities....................... (138,021) (203,625) (1,571,446) Cash flow from financing activities....................... (35,061) 162,514 1,398,934 Acquisitions and other capital expenditures....................... $183,531 $ 524,730 $ 121,978 $ 185,479 $ 1,570,083 $ 429,847 EBITDA(3)............................ $128,310 $ 188,521 $ 203,432 $ 133,293 $ 258,061 $ 556,328 Ratio of EBITDA to interest expense(4)......................... 6.38 14.79 3.98 2.54 4.88 3.03 Ratio of earnings to fixed charges(5)......................... 4.10 9.11 2.52 1.07 2.33 1.69 Gas transported and/or processed (TBtu/d)........................... 1.9 2.9 3.4 3.6 5.1 7.3 NGLs production(MBbl/d).............. 55 79 108 110 192 400 MARKET DATA: Average NGLs price per gallon(6)..... $.29 $.39 $.35 $.26 $.34 $.33 Average natural gas price per MMBtu(7)........................... $1.64 $2.59 $2.59 $2.11 $2.27 $2.27 BALANCE SHEET DATA (END OF PERIOD): Total assets......................... $917,831 $1,459,416 $1,649,213 $1,770,838 $ 3,471,835 Long-term debt....................... $101,600 $ 101,600 $ 101,600 $ 101,600 $ 101,600 SIX MONTHS ENDED JUNE 30, -------------------------------------------------- HISTORICAL PRO FORMA ------------------------------ ---------- 1999(8) 2000(8) 2000(8) ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER UNIT DATA) INCOME STATEMENT DATA: Operating revenues: Sales of natural gas and petroleum products........ $1,032,880 $3,542,823 $4,132,807 Transportation, storage and processing............. 75,964 80,748 90,351 ---------- ---------- ---------- Total operating revenues.................... 1,108,844 3,623,571 4,223,158 Costs and expenses: Natural gas and petroleum products................. 916,310 3,115,037 3,539,618 Operating and maintenance.......................... 78,745 140,354 190,739 Depreciation and amortization...................... 56,006 105,359 129,848 General and administrative......................... 30,759 69,976 74,227 Net (gain) loss on sale of assets.................. (9) 337 249 ---------- ---------- ---------- Total costs and expenses.................... 1,081,811 3,431,063 3,934,681 Operating income..................................... 27,033 192,508 288,477 Equity in earnings of unconsolidated affiliates...... 10,275 14,707 17,916 ---------- ---------- ---------- Earnings before interest and tax..................... 37,308 207,215 306,393 Interest expense..................................... 25,535 59,851 91,470 ---------- ---------- ---------- Earnings before income tax........................... 11,773 147,364 214,923 Income tax expense (benefit)......................... 5,618 (306,765) 4,300 ---------- ---------- ---------- Net income........................................... $ 6,155 $ 454,129 $ 210,623 ========== ========== ========== OTHER DATA: EBITDA(3)............................................ $ 93,314 $ 312,574 $ 436,241 Ratio of EBITDA to interest expense(4)............... 3.65 5.22 4.77 Ratio of earnings to fixed charges(5)................ 1.41 3.43 3.33 Gas transported and/or processed (TBtu/d)............ 4.4 7.0 7.9 NGLs production(MBbl/d).............................. 161 316 409 MARKET DATA: Average NGLs price per gallon(6)..................... $.29 $.49 $.49 Average natural gas price per MMBtu(7)............... $1.95 $2.99 $2.99 BALANCE SHEET DATA (END OF PERIOD): Total assets......................................... $3,655,728 $5,975,787 $5,989,262 Long-term debt....................................... -- -- $1,500,000 S-10 11 SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ------------------------------------ ----------------------- 1997 1998 1999(1)(2) 1999(8) 2000(8) ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS) HISTORICAL SEGMENT INFORMATION: Operating revenues: Natural gas.............................. $1,683,483 $1,497,901 $2,483,197 $ 847,782 $2,585,992 NGLs..................................... 423,680 309,380 1,365,577 396,042 1,607,882 Intersegment............................. (305,331) (222,961) (390,464) (134,980) (570,303) ---------- ---------- ---------- ---------- ---------- Total operating revenues.......... $1,801,832 $1,584,320 $3,458,310 $1,108,844 $3,623,571 ========== ========== ========== ========== ========== Margin: Natural gas.............................. $ 334,129 $ 243,787 $ 459,843 $ 184,365 $ 482,066 NGLs..................................... (386) 2,404 33,170 8,169 26,468 ---------- ---------- ---------- ---------- ---------- Total margin...................... $ 333,743 $ 246,191 $ 493,013 $ 192,534 $ 508,534 ========== ========== ========== ========== ========== EBITDA(3): Natural gas.............................. $ 239,841 $ 175,835 $ 298,698 $ 116,464 $ 356,438 NGLs..................................... (386) 2,404 33,048 7,609 26,112 Corporate................................ (36,023) (44,946) (73,685) (30,759) (69,976) ---------- ---------- ---------- ---------- ---------- Total EBITDA...................... $ 203,432 $ 133,293 $ 258,061 $ 93,314 $ 312,574 ========== ========== ========== ========== ========== EBIT(3): Natural gas.............................. $ 174,248 $ 102,365 $ 179,273 $ 62,852 $ 258,771 NGLs..................................... (386) 2,404 23,975 6,360 20,000 Corporate................................ (38,131) (47,049) (75,975) (31,904) (71,556) ---------- ---------- ---------- ---------- ---------- Total EBIT........................ $ 135,731 $ 57,720 $ 127,273 $ 37,308 $ 207,215 ========== ========== ========== ========== ========== Total assets: Natural gas.............................. $1,505,111 $2,754,447 $4,833,083 NGLs..................................... 5,137 225,702 197,624 Corporate................................ 260,590 491,686 945,080 ---------- ---------- ---------- Total assets...................... $1,770,838 $3,471,835 $5,975,787 ========== ========== ========== - --------------- (1) Includes $34.0 million of hedging losses recorded in total operating revenues. Duke Energy commenced risk management activities associated with its midstream natural gas business at the end of 1998. Activity for periods prior to 1999 was not significant. (2) Includes the results of operations of Union Pacific Fuels for the nine months ended December 31, 1999. Union Pacific Fuels was acquired by the Predecessor Company on March 31, 1999. (3) EBITDA consists of income from continuing operations before interest expense, income tax expense, and depreciation and amortization expense, less interest income. EBIT consists of income from continuing operations before interest expense and income tax expense, less interest income. Neither EBITDA nor EBIT is a measurement presented in accordance with generally accepted accounting principles. You should not consider either 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 a measure of our profitability or liquidity. EBITDA is included as a supplemental disclosure because it may provide useful information regarding our ability to service debt and to fund capital expenditures. However, not all EBITDA may be available to service debt. (4) The ratio of EBITDA to interest expense represents a ratio that provides an investor with information as to our company's current ability to meet our financing costs. (5) For purposes of calculating the ratios of earnings to fixed charges, "earnings" means income before extraordinary charges, plus income taxes and fixed charges. Fixed charges include interest on indebtedness, amortization of deferred financing costs, and that portion of lease expense that is deemed to be representative of an interest factor. The ratio includes amounts from our company, all of our majority-owned subsidiaries and our proportionate share of distributed amounts from 50% owned investments that are accounted for using the equity method. (6) Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by our component and location mix for the periods indicated. (7) Based on the NYMEX Henry Hub prices for the periods indicated. (8) Includes $4.4 million of hedging gain and $59.2 million of hedging loss for the six months ended June 30, 1999 and 2000, respectively. S-11 12 ADDITIONAL FINANCIAL AND OTHER DATA The following table sets forth additional financial and other data of our company. The additional financial and other data set forth in the table below give effect to the Combination and the transfer to our company of additional midstream natural gas assets acquired by Duke Energy or Phillips prior to consummation of the Combination, which were completed on March 31, 2000 and to the acquisition of Union Pacific Fuels, which occurred on March 31, 1999, as if each occurred on January 1, 1995. The additional financial and other data set forth in the table below should not be considered to be indicative of: - actual results that would have been realized had the Combination and the acquisition of Union Pacific Fuels actually occurred on January 1, 1995; or - results of our future operations. The data should be read in conjunction with the financial statements and related notes and other financial information appearing elsewhere in this prospectus supplement. SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, -------------------------------------------------------------- ----------------------- 1995 1996 1997 1998 1999(1) 1999(2) 2000(2) ---------- ---------- ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER UNIT DATA) INCOME STATEMENT DATA: Total operating revenues................ $2,413,871 $3,998,273 $4,769,072 $4,302,697 $5,574,580 $2,117,561 $4,223,158 Costs of natural gas and petroleum products...... 1,729,278 2,976,059 3,798,465 3,527,533 4,554,776 1,684,884 3,539,618 OTHER DATA: Gas transported and/or processed (TBtu/d)...... 5.4 6.5 7.5 7.3 7.3 7.1 7.9 NGLs production(MBbl/d)... 277 313 358 373 400 372 409 MARKET DATA: Average NGLs (price per gallon)(3).............. $.29 $.39 $.35 $.26 $.34 $.29 $.49 Average natural gas (price per MMBtu)(4)........... $1.64 $2.59 $2.59 $2.11 $2.27 $1.95 $2.99 - --------------- (1) Includes $34.0 million of losses from risk management activities recorded in total operating revenues. Duke Energy commenced risk management activities for its midstream natural gas business at the end of 1998. Activity for periods prior to 1999 was not significant. (2) Includes $4.4 million of hedging gain and $59.2 million of hedging loss for the six months ended June 30, 1999 and 2000, respectively. (3) Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by our component mix and location mix for the periods indicated. (4) Based on the NYMEX Henry Hub prices for the periods indicated. S-12 13 USE OF PROCEEDS We expect the net proceeds from the offering of the notes to be approximately $1,486 million, after deducting discounts to the underwriters and estimated expenses of the offering that we will pay. We expect to use the net proceeds to repay a portion of our outstanding commercial paper. The proceeds of the commercial paper were used to make one-time cash distributions of approximately $1,525 million to Duke Energy and approximately $1,220 million to Phillips in connection with the Combination and for working capital requirements. At June 30, 2000, our outstanding commercial paper had maturity dates ranging from one day to 60 days, with annual interest rates ranging from 6.7% to 7.2%. CAPITALIZATION The following table sets forth our short-term debt and total capitalization as of June 30, 2000: - on a historical basis; and - on a pro forma basis giving effect to (1) the issuance of the notes offered hereby and the application of the net proceeds therefrom and (2) the issuance of an aggregate of $300 million of preferred membership interests in our company to affiliates of Duke Energy and Phillips in August 2000 and the application of the proceeds therefrom to repay short term debt. You should read the information below in conjunction with "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our historical and pro forma financial statements and related notes included elsewhere in this prospectus supplement. AS OF JUNE 30, 2000 ------------------------ HISTORICAL PRO FORMA ---------- ---------- (IN THOUSANDS) Short-term debt(1).......................................... $2,585,290 $ 799,665 ========== ========== Long-term debt.............................................. $ -- $1,500,000 Equity: Members' interest(2)...................................... 1,695,108 1,995,108 Retained earnings......................................... 627,220 626,320 Other comprehensive loss.................................. (1,117) (1,117) ---------- ---------- Total equity........................................... 2,321,211 2,620,311 ---------- ---------- Total capitalization................................... $4,906,501 $4,919,976 ========== ========== - --------------- (1) Represents outstanding commercial paper issued to pay the distributions to Duke Energy and Phillips. (2) Members' interest represents Duke Energy's and Phillips' common and preferred membership interests in our company. S-13 14 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion details the material factors that affected our historical and pro forma financial condition and results of operations in 1997, 1998 and 1999 and the six months ended June 30, 1999 and 2000. This discussion should be read in conjunction with "Prospectus Supplement Summary -- Selected Historical and Pro Forma Financial and Other Data," "-- Additional Financial and Other Data" and the historical and pro forma financial statements, and, in each case, the notes related thereto, included elsewhere in this prospectus supplement. Unless the context otherwise requires, the 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 from Duke Energy. OVERVIEW We operate in the two principal business segments of the midstream natural gas industry: - natural gas gathering, processing, transportation and storage, from which we generate revenues primarily by providing services such as compression, treating and gathering, processing, local fractionation, transportation of residue gas, storage and marketing. In 1999, approximately 72% of the Predecessor Company's operating revenues and approximately 93% of the Predecessor Company's gross margin were derived from this segment. - NGLs fractionation, transportation, marketing and trading, from which we generate revenues from transportation fees, market center fractionation and the marketing and trading of NGLs. In 1999, approximately 28% of the Predecessor Company's operating revenues and approximately 7% of the Predecessor Company's gross margin were from this segment. Our limited liability company agreement limits the scope of our business to the midstream natural gas industry in the United States and Canada, the marketing of NGLs in Mexico and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our board of directors. This limitation in scope is not currently expected to materially impact the results of our operations. EFFECTS OF COMMODITY PRICES In 1999, approximately 59% of the Predecessor Company's gross margin was generated by arrangements that are commodity price sensitive and 41% of the Predecessor Company's gross margin was generated by fee-based arrangements. Because the gross margin of Phillips' midstream gas business is more heavily weighted towards arrangements that are commodity price sensitive, as a result of the Combination the portion of our gross margin generated by fee-based arrangements has decreased. For example, in January 2000, after giving effect to the Combination, approximately 28% of our gross margin was generated by fee-based arrangements. 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 generally is 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. S-14 15 The following chart sets forth financial data for the Predecessor Company and the weighted average price of NGLs for each of the five years ended December 31, 1999 and demonstrates the relationship of our EBITDA to NGL prices. The chart below should not be viewed as indicating that the level of NGL prices is the only factor affecting our results of operations. In addition to NGL prices, our results of operations reflected in the chart below were primarily affected by: - fluctuations in raw natural gas volumes processed, including increases resulting from our acquisitions and additions; - the Predecessor Company's historical risk management activities; and - gain/(loss) on the sale of assets. [GRAPH] Note: The weighted average NGL prices set forth in the chart above are based on index prices from the Mont Belvieu and Conway market hubs that are weighted by our component and location mix for the years indicated. The gas gathering and processing price environment deteriorated between 1996 and 1997 as prices for NGLs decreased and prices for natural gas increased from 1996 levels. Increases in worldwide crude oil supply and production in 1998 drove a steep decline in crude oil prices. NGL prices also declined sharply in 1998 as a result of the correlation between crude oil and NGL pricing. Natural gas prices also declined during 1998 principally due to mild weather. The lower NGL and natural gas price environment experienced in 1998 prevailed during the first quarter of 1999. However, during the last three quarters of 1999, NGL prices increased sharply as major crude oil exporting countries agreed to maintain crude oil production at predetermined levels and world demand for crude oil and NGLs increased. The lower crude oil and natural gas prices in 1998 and early 1999 caused a significant reduction in the exploration activities of U.S. producers, which in turn had a significant negative effect on natural gas volumes gathered and processed in 1999. During the first six months of 2000, 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 $.49 per gallon. In the near-term, we expect NGL prices to follow changes in crude oil prices generally, 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. 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. The price increases in crude oil, NGLs and natural gas have spurred increased natural gas drilling activity. For example, the number of actively drilling rigs in North America has increased by approximately 57% from approximately 745 in June 1999 to more than 1,165 in S-15 16 June 2000. This drilling activity increase is expected to have a positive effect on natural gas volumes gathered and processed in the near term. EFFECTS OF OUR RAW NATURAL GAS SUPPLY ARRANGEMENTS Our results are affected by the types of arrangements we use to purchase raw natural gas. We obtain access to raw natural gas and provide our midstream natural gas services principally under three types of contracts: - Percentage-of-Proceeds Contracts -- Under these contracts (which also include percentage-of-index contracts), we receive as our fee a negotiated percentage of the residue natural gas and NGLs value derived from our gathering and processing activities, with the producer retaining the remainder of the value. These type of contracts permit us and the producers to share proportionately in price changes. Under these contracts, we share in both the increases and decreases in natural gas prices and NGL prices. In December 1999, after giving effect to the Combination, approximately 57% of our gross margin was generated from percentage-of-proceeds or percentage-of-index contracts. - Fee-Based Contracts -- Under these contracts we receive a set fee for gathering, processing and/or treating raw natural gas. Our revenue stream from these contracts is correlated with our level of gathering and processing activity and is not directly dependent on commodity prices. In December 1999, after giving effect to the Combination, approximately 25% of our gross margin was generated from fee-based contracts. - Keep-Whole Contracts -- Under these contracts we gather raw natural gas from the producer for processing. After we process the raw natural gas, we are obligated to return to the producer residue gas with a Btu content equivalent to the Btu content of the raw natural gas gathered. As a result of our processing, NGLs are extracted from the raw natural gas resulting in a shrinkage in the Btu content of the natural gas. We market the NGLs and purchase natural gas at market prices in order to return to the producer residue gas with a Btu content equivalent to the Btu content of the raw natural gas gathered. Accordingly, under these contracts, we are exposed to increases in the price of natural gas and decreases in the price of NGLs. In December 1999, after giving effect to the Combination, approximately 15% of our gross margin was generated from keep-whole contracts. Our current mix of percentage-of-proceeds and percentage-of-index contracts (where we are exposed to decreases in natural gas prices) and keep-whole contracts (where we are exposed to increases in natural gas prices) significantly mitigates our exposure to increases in natural gas prices, while retaining our exposure to changes in NGL prices. We prefer to enter into percentage-of-proceeds type supply contracts (including percentage-of-index contracts). We believe this type of contract provides the best alignment with our producers and represents the best risk/reward profile for the capital we employ. Notwithstanding this preference, we also recognize from a competitive viewpoint that we will need to offer keep-whole contracts to attract certain supply to our systems. We also employ a fee-type contract, particularly where there is treating and/or transportation involved. Our contract mix and, accordingly, our exposure to natural gas and NGL prices may change as a result of changes in producer preferences, our expansion in regions where some types of contracts are more common and other market factors. Based upon the combined company's portfolio of supply contracts in 1999, and excluding the effect of our commodities risk management program, an increase of $.01 per gallon in the price of NGLs and $.10 per million Btu's in the average price of natural gas throughout such period would have resulted in changes in pre-tax net income of approximately $24 million and ($1) million, respectively. See "-- Quantitative and Qualitative Disclosure About Market Risks." S-16 17 OTHER FACTORS THAT HAVE SIGNIFICANTLY AFFECTED OUR RESULTS Our results of operations also are correlated with increases and decreases in the volume of raw natural gas that we put through our system, which we refer to as throughput volume, and the percentage of capacity at which our processing facilities operate, which we refer to as our asset utilization rate. Throughput volumes and asset utilization rates generally are driven by production on a regional basis and more broadly by demand for residue natural gas and NGLs. Risk management, which has been directed by Duke Energy's centralized program for controlling, managing and coordinating its management of risks, also has affected our results of operations, particularly in 1999 and the first half of 2000. Our 1999 and first half of 2000 results of operations include hedging losses of $34.0 million and $59.2 million, respectively. Since the Combination, we have directed our risk management activities independently of Duke Energy, with goals, policies and procedures that are different from those of Duke Energy. See "-- Quantitative and Qualitative Disclosure about Market Risks." In addition to market factors and production, our results have been affected by our acquisition strategy, including the timing of acquisitions and our ability to integrate acquired operations and achieve operating synergies. THE COMBINATION On March 31, 2000, we combined the gas gathering, processing, marketing and NGLs businesses of Duke Energy and Phillips. In connection with the Combination, Duke Energy and Phillips transferred all of their respective interests in their subsidiaries that conducted their midstream natural gas business to us. In connection with the Combination, Duke Energy and Phillips also transferred to us additional midstream natural gas assets acquired by Duke Energy or Phillips prior to consummation of the Combination, including Mid-Continent gathering and processing assets of Conoco and Mitchell Energy. The acquisition of the Conoco/Mitchell assets is significant in that the assets acquired lie adjacent to and between our current assets, providing future integration opportunities. In addition, concurrently with the Combination, we obtained by transfer from Duke Energy the general partner of TEPPCO. In exchange for the asset contribution, Phillips received 30.3% of the member interests in our company, with Duke Energy holding the remaining 69.7% of the outstanding member interests in our company. In connection with the closing of the Combination, we borrowed approximately $2.8 billion in the commercial paper market and made one-time cash distributions (including reimbursements for acquisitions) of approximately $1.5 billion to Duke Energy and approximately $1.2 billion to Phillips. See "-- Liquidity and Capital Resources." The Combination was accounted for as a purchase of the Phillips midstream natural gas business. The Combination was accounted for as a purchase business combination in accordance with Accounting Principles Board Opinion (APB) No. 16, "Accounting for Business Combinations." The Predecessor Company was the acquiror of Phillips' midstream natural gas business in the Combination. The purchase price allocation associated with the Phillips assets is preliminary. Currently there are no pre-acquisition contingent liabilities reflected in the purchase price allocation. The final purchase price allocation is subject to adjustment pending gathering of additional information regarding certain pre-acquisition contingent liabilities and obtaining appraisals. The effect of any pre-acquisition contingencies is not expected to have a material effect on our operating results, liquidity or financial condition. COMBINED RESULTS OF OPERATIONS The following is a discussion of the combined operating revenues and cost of sales of our company giving effect to the Combination, the transfer to our company of the midstream natural gas businesses acquired by Duke Energy and Phillips prior to the consummation of the Combination and the acquisition of Union Pacific Fuels as if each transaction occurred on January 1, 1995. S-17 18 This discussion should be read in conjunction with the historical and pro forma financial statements and related notes and other financial information appearing elsewhere in this prospectus supplement. The data on which this discussion is based should not be considered indicative of: - the actual results that would have been realized had the Combination and the acquisition of Union Pacific Fuels actually occurred on January 1, 1995; or - the results of our future operations. SIX MONTHS ENDED JUNE 30, 2000 COMPARED WITH SIX MONTHS ENDED JUNE 30, 1999 Operating Revenues. Operating revenues increased $2,106 million, or 99%, from $2,117 million to $4,223 million. Of this increase, approximately $2,050 million is related to increased commodity prices as weighted average NGL prices, based on our component product mix, were approximately $.20 per gallon higher and natural gas prices were approximately $1.05 per million Btus higher. Acquisitions and plant expansions contributed approximately $90 million to the revenue increase. NGL production during the first six months ended June 30, 2000 increased approximately 11,000 barrels per day, or 3% from 391,000 barrels per day to 402,000 barrels per day, and natural gas transported and/or processed increased .9 trillion Btus per day, or 13%, from 7.1 trillion Btus per day to 8.0 trillion Btus per day. Included in the six months ended June 30, 2000 operating revenues is a $59.2 million loss attributable to hedging activity. Cost of Sales. Costs of natural gas and petroleum products increased $1,855 million, or 110%, from $1,685 million to $3,540 million. This increase was primarily due to the interaction of our gas and NGL purchase contracts with higher commodity prices. Higher natural gas and NGLs throughput associated with our acquisitions and plant expansions also increased product purchase costs. 1999 COMPARED WITH 1998 Operating Revenues. Operating revenues increased $1,271.9 million, or 30%, from $4,302.7 million to $5,574.6 million. Of this increase, approximately $1,100 million was due to increases in commodity prices, as weighted average NGL prices, based on our component product mix, were approximately $.08 per gallon higher and natural gas prices were approximately $.16 per million Btus higher. Our acquisitions and plant expansions also contributed to this increase. NGLs production during 1999 increased 27,000 barrels per day, or 7%, from 373,000 barrels per day to 400,000 barrels per day, and natural gas transported and/or processed remained essentially unchanged at 7.3 trillion Btus per day. The recovery of commodity prices during the last three quarters of 1999 encouraged exploration and production activity, which positively affected existing throughput volumes. Included in 1999 operating revenues is approximately $34.0 million of loss on hedging activity. There were no significant hedging activities in 1998. See "-- Quantitative and Qualitative Disclosure About Market Risks." Cost of Sales. Costs of natural gas and petroleum products increased $1,027.3 million, or 29%, from $3,527.5 million to $4,554.8 million. This increase primarily was due to the interaction of our gas and NGL purchase contracts with higher commodity prices. 1998 COMPARED WITH 1997 Operating Revenues. Operating revenues decreased $466.4 million, or 10%, from $4,769.1 million to $4,302.7 million. Lower commodity prices resulted in an approximately $800 million reduction of operating revenues, as weighted average NGL prices, based on our component product mix, were approximately $.09 per gallon lower and natural gas prices were unchanged. Partially offsetting this decrease was approximately $22 million additional revenues attributable to our fourth quarter 1997 acquisition of Highlands Gas Partners and approximately $300 million additional revenues attributable to our increased NGL trading and marketing activities. Natural gas transported and/or processed decreased .2 trillion Btus per day, or 3%, from 7.5 trillion Btus per day to 7.3 trillion Btus per day. This decrease was primarily the result of reduced exploration and production activity caused by depressed commodity prices. This decrease was offset by an increase in NGLs production of 15,000 barrels per day, or 4%, from 358,000 barrels per S-18 19 day to 373,000 barrels per day. NGLs production growth primarily was the result of the Highlands Gas Partners acquisition and the restart of a processing facility in the fourth quarter of 1997. Cost of Sales. Cost of natural gas and petroleum products decreased $271.0 million, or 7%, from $3,798.5 million to $3,527.5 million. This decrease primarily was due to declining NGL prices. Increased NGL trading and marketing activity partially offset this decrease. QUARTERLY COMBINED RESULTS The following table sets forth unaudited combined financial and operating data for our company on a quarterly basis for each of 1998, 1999 and the first half of 2000. COMBINED ------------------------------------------------------------------------------------------------- 1998 1999 2000 ------------------------------------- ------------------------------------- ----------------- FIRST SECOND THIRD FOURTH FIRST SECOND THIRD FOURTH FIRST SECOND QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- (IN MILLIONS, EXCEPT PER UNIT DATA) Total operating revenues.............. $1,113 $1,143 $1,095 $952 $959 $1,158 $1,597 $1,861 $2,051 $2,172 Costs of natural gas and petroleum products.... 902 951 900 775 762 923 1,313 1,557 1,703 1,837 Average NGL price (per gallon)(1)............ .28 .26 .20 .22 .22 .30 .39 .41 .50 .47 - --------------- (1) Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by our component and location mix for the periods indicated. HISTORICAL 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 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 from Duke Energy. SIX MONTHS ENDED JUNE 30, 2000 COMPARED WITH SIX MONTHS ENDED JUNE 30, 1999 Operating Revenues. Operating revenues increased $2,514.8 million, or 227% from $1,108.8 million to $3,623.6 million. Operating revenues from the sale of natural gas and petroleum products accounted for $3,542.8 million of the total and $2,509.9 million of the increase. Of this increase, approximately $600.1 million is related to the addition of the Phillips' midstream natural gas business to our operations in the Combination on March 31, 2000, and approximately $425 million is related to the March 31, 1999 acquisition of Union Pacific Fuels. Increased NGL trading and marketing activity also contributed to the increase. NGL production during the six months ended June 30, 2000 increased 155,200 barrels per day, or 96%, from 161,100 barrels per day to 316,300 barrels per day, and natural gas transported and/or processed increased 2.6 trillion Btus per day, or 59%, from 4.4 trillion Btus per day to 7.0 trillion Btus. Of the 155,200 barrels per day increase, the addition of the Phillips' midstream natural gas business in the Combination contributed approximately 82,900 barrels per day, and the Union Pacific Fuels acquisition contributed approximately 50,300 barrels per day. The combination of our Wilcox plant expansion, completion of our Mobile Bay Plant and the acquisition of Koch's South Texas assets accounted for the remainder of the increase. Of the 2.6 trillion Btus per day increase, the addition of the Phillips' midstream natural gas business in the Combination contributed approximately 1.0 trillion Btus per day, and the Union Pacific Fuels acquisition contributed approximately 1.0 trillion Btus per day. The combination of other acquisitions, plant expansions and completions accounted for the balance of the increase. Commodity prices significantly contributed to higher revenues. Weighted average NGL prices, based on our component product mix, were approximately $.20 per gallon higher and natural gas prices were approximately $1.04 per million Btus higher for the first six months of 2000. These price increases yielded S-19 20 average prices of $.49 per gallon of NGLs and $2.99 per million Btus of natural gas, respectively, as compared with $.29 per gallon and $1.95 per million Btus for the first six months of 1999. Revenues associated with gathering, transportation, storage, processing fees and other increased $4.7 million, or 6%, from $76.0 million to $80.7 million, mainly as a result of the Union Pacific Fuels acquisition. A $59.2 million hedging loss in the first six months of 2000 partially offset total operating revenue increases. See "--Quantitative and Qualitative Disclosure About Market Risks." Costs and Expenses. Costs of natural gas and petroleum products increased $2,198.7 million, or 240%, from $916.3 million to $3,115 million. This increase was due to the addition of the Phillips' midstream natural gas business in the Combination (approximately $450.4 million), the Union Pacific Fuels acquisition (approximately $340 million),and the interaction of our natural gas and NGL purchase contracts with higher commodity prices and increased trading and marketing activity. Operating and maintenance expenses increased $61.7 million, or 78%, from $78.7 million to $140.4 million. Of this increase, approximately $41 million is related to the addition of the Phillips' midstream natural gas business in the Combination and approximately $13 million is related to the Union Pacific Fuels acquisition. General and administrative expenses increased $39.2 million, or 127%, from $30.8 million to $70 million. Of this increase, $12.3 million was due to increased allocated corporate overhead from Duke Energy as a result of our company's growth. The remainder was associated with increased activity resulting from the addition of the Phillips' midstream natural gas business in the Combination, the Union Pacific Fuels acquisition and increased fiscal year 2000 incentive compensation accruals. Depreciation and amortization increased $49.4 million, or 88%, from $56.0 million to $105.4 million. Of this increase, $26.1 million was due to the addition of the Phillips' midstream natural gas business in the Combination and $15.4 million was due to the Union Pacific Fuels acquisition. The remainder was due to ongoing capital expenditures for well connections, facility maintenance/enhancements and acquisitions. Equity Earnings. Equity earning of unconsolidated affiliates increased $4.4 million, or 43%, from $10.3 million to $14.7 million. This increase was largely due to interests in joint ventures and partnerships acquired from Union Pacific Fuels and the acquisition of the general partnership interest in TEPPCO as of March 31, 2000. Interest. Interest expense increased $34.4 million, or 135%, from $25.5 million to $59.9 million. This increase is primarily the result of the issuance of commercial paper to fund the distribution paid to Duke Energy and Phillips in the Combination. 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 ($327 million) was eliminated and a corresponding income tax benefit was recorded. Net Income. Net income increased $447.9 million from $6.2 million to $454.1 million. This increase was largely the result of the tax benefit recognition discussed above, the addition of the Phillip's midstream natural gas business in the Combination and the Union Pacific Fuels acquisition. Higher NGL prices contributed significantly to this increase and were partially offset by higher natural gas prices. A $59.2 million pre-tax loss from hedging activities experienced during the first six months of 2000 partially offset the increase. EBITDA. In addition to the GAAP measures described above, we also use the non-GAAP measure of EBITDA. 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 S-20 21 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 $239.9 million, or 206%, from $116.5 million to $356.4 million. Of this increase, approximately $113.6 was due to the addition of the Phillips' midstream natural gas business in the Combination, approximately $56 million was due to the acquisition of Union Pacific Fuels, and approximately $90 million due to a $.20 per gallon increase in average NGL prices. Additional increases were attributable to the combination of our Wilcox plant expansion, completion of our Mobile Bay plant, the acquisition of Koch's South Texas assets, and the acquisition of the general partnership interest in TEPPCO. These benefits were offset by a $63.6 million decrease from hedging activities ($59.2 million loss in the first six months of 2000 compared to a $4.4 million gain in the comparable period of 1999) and approximately $16 million due to a $1.04 per million Btu increase in natural gas prices. EBITDA for the NGLs fractionation, transportation, marketing and trading segment increased $18.5 million from $7.6 million to $26.1 million due primarily to NGL trading and marketing activity and the acquisition of Union Pacific Fuels. 1999 COMPARED WITH 1998 Operating Revenues. Operating revenues increased $1,874.0 million, or 118%, from $1,584.3 million to $3,458.3 million. Operating revenues from the sale of natural gas and petroleum products accounted for $3,310.3 million of the total and $1,841.2 million of the increase. Of this increase, approximately $1.0 billion was attributable to the March 31, 1999 acquisition of Union Pacific Fuels. Increased NGL trading and marketing activity associated with the Union Pacific Fuels acquisition also contributed to the increase. NGL production during 1999 increased 82,000 barrels per day, or 75%, from 110,000 barrels per day to 192,000 barrels per day. Of the 82,000 barrels per day increase, the Union Pacific Fuels acquisition contributed 71,000 barrels per day, with the combination of our Wilcox plant expansion, completion of our Mobile Bay Plant and the acquisition of Koch's South Texas assets accounting for the remainder of the increase. Raw natural gas transported and/or processed increased 1.5 trillion Btus per day, or 42%, from 3.6 trillion Btus per day to 5.1 trillion Btus per day. The Union Pacific Fuels acquisition accounted for 1.4 trillion Btus per day of the natural gas increase. Commodity prices also contributed to higher revenues. Weighted average NGL prices, based on our component product mix, were approximately $.08 per gallon higher and natural gas prices were approximately $.16 per million Btus higher for 1999, yielding prices of $.34 and $2.27, respectively, as compared with $.26 and $2.11 in 1998. Revenues associated with gathering, transportation, storage, processing fees and other increased $32.8 million, or 28%, from $115.2 million to $148.0 million principally as a result of the Union Pacific Fuels acquisition. Total operating revenue increases were offset by a $34.0 million hedging loss in 1999. See "-- Quantitative and Qualitative Disclosure About Market Risks." Costs and Expenses. Costs of natural gas and petroleum products increased $1,627.2 million, or 122%, from $1,338.1 million to $2,965.3 million. This increase was due primarily to the Union Pacific Fuels acquisition ($800 million), increased NGL trading and marketing activity and the interaction of our natural gas and NGL purchase contracts with higher commodity prices. Operating and maintenance expenses increased $67.8 million, or 60%, from $113.6 million to $181.4 million. Of this increase, approximately $65.0 million was due to the Union Pacific Fuels acquisition. General and administrative expenses increased $28.7 million, or 64%, from $45.0 million to $73.7 million. This increase was due to a $7.0 million increase in allocated corporate overhead from our parent, Duke Energy, and increases resulting from the Union Pacific Fuels acquisition. Depreciation and amortization increased $55.2 million, or 73%, from $75.6 million to $130.8 million. Of this increase, $45.2 million was due to the Union Pacific Fuels acquisition and the remainder was due to ongoing capital expenditures for well connections, facility maintenance/enhancements and acquisitions. S-21 22 Sale of Assets. Net (gain) loss on sales of assets decreased $36.2 million, from a $33.8 million gain to a $2.4 million loss from 1998 to 1999. This decrease was primarily the result of a $38.0 million gain recognized in 1998 on the sale of two fractionators in Weld County, Colorado. Equity Earnings. Equity earnings of unconsolidated affiliates increased $10.7 million, or 91%, from $11.8 million to $22.5 million. This increase was largely due to interests in joint ventures and partnerships acquired from Union Pacific Fuels in 1999. Interest. Interest expense of $52.9 million for 1999 remained almost unchanged from 1998 and was principally related to interest on notes due to Duke Energy. Net Income. Net income increased $41.3 million from $2.0 million to $43.3 million. This increase was largely the result of the acquisition of Union Pacific Fuels and higher average NGL prices experienced during 1999. The benefit of higher NGL prices was partially offset by higher natural gas prices. The increase in net income was largely offset by a pre-tax gain of approximately $38.0 million recognized on the sale of our Weld County fractionators in 1998 and a $34.0 million loss on hedging activity in 1999. EBITDA. EBITDA for the natural gas gathering, processing, transportation and storage segment increased $122.9 million from $175.8 million to $298.7 million. Of the increase, approximately $110 million was due to the acquisition of Union Pacific Fuels and $80.0 million was due to $.08 per gallon higher NGL prices. Additional increases were recognized with the combination of our Wilcox plant expansion, completion of our Mobile Bay Plant and the acquisition of Koch's South Texas assets. These increases were offset by a $38.0 million gain recognized in 1998 on the sale of the Weld County fractionators, hedging losses in 1999 of $34.0 million, an approximately $5 million decrease due to $.16 per million BTU increase in gas prices and a $7.0 million increase in allocated corporate overhead from our parent, Duke Energy. EBITDA for the NGLs fractionation, transportation, marketing and trading segment increased $30.6 million from $2.4 million to $33.0 million due primarily to the acquisition of Union Pacific Fuels. 1998 COMPARED WITH 1997 Operating Revenues. Operating revenues decreased $217.5 million, or 12%, from $1,801.8 million to $1,584.3 million. Operating revenues from the sale of natural gas and petroleum products decreased $230.9 million, or 14%, from $1,700.0 million to $1,469.1 million. This decrease was largely due to commodity prices, as weighted average NGLs prices, based on our component product mix, were approximately $.09 per gallon lower and natural gas prices were approximately $.48 per MMBtu lower for 1998, yielding prices of $.26 and $2.11, respectively, as compared with $.35 and $2.59 in 1997. This NGL price decline was partially offset by an increase in NGL production during 1998 of 2,000 barrels per day, or 2%, from 108,000 barrels per day to 110,000 barrels per day, and by an increase in natural gas gathered, transported and/or processed of .2 trillion Btus per day, or 6%, from 3.4 trillion Btus per day to 3.6 trillion Btus per day, due to increased production on existing facilities. Revenues associated with gathering, transportation, storage, processing fees and other increased $13.4 million, or 13%, from $101.8 million to $115.2 million. This increase was principally the result of increased volumes. Costs and Expenses. Costs of natural gas and petroleum products decreased $130.0 million, or 9%, from $1,468.1 million to $1,338.1 million. This decrease was primarily due to declining NGL prices. The NGL price decline was partially offset by increases in system throughput volumes. Operating and maintenance expenses increased $9.3 million, or 9%, from $104.3 million to $113.6 million. This increase was primarily due to higher property tax accruals associated with property additions and other inflationary factors. General and administrative expenses increased $8.9 million, or 25%, from $36.0 million to $44.9 million. This increase was due primarily to an increase in the incentive bonus accrual and internal growth. S-22 23 Depreciation and amortization increased $7.9 million, or 12%, from $67.7 million to $75.6 million. This increase was primarily due to ongoing capital expenditures for well connections, facility maintenance/enhancements and acquisitions. Sales of Assets. Net (gain) loss on sales of assets increased $33.6 million, from a $.2 million gain to a $33.8 million gain from 1997 to 1998. This increase was primarily due to a $38.0 million gain recognized in March 1998 on the sale of the Weld County fractionators. Equity Earnings. Equity earnings of unconsolidated affiliates increased $2.0 million, or 20%, from $9.8 million to $11.8 million. This increase was largely due to increased earnings from Dauphin Island Gathering and Main Pass Oil in the offshore region. Interest. Interest expense increased $1.3 million, or 3%, from $51.1 million to $52.4 million. Interest expense reflects interest on notes due to affiliated companies. Net Income. Net income decreased $49.2 million, or 96%, from $51.2 million to $2.0 million. This decrease was largely the result of substantially lower commodity prices. A pre-tax gain of approximately $38.0 million recognized on the sale of our Weld County fractionators in March 1998 partially offset the impact of the sharp NGL price decline. EBITDA. EBITDA for the natural gas gathering, processing, transportation and storage segment decreased $64.0 million from $239.8 million to $175.8 million. Of the decrease, approximately $80 million was due to $.09 per gallon lower NGL prices and approximately $18 million was due to increased operating and general and administrative expenses resulting from higher property tax accruals associated with property additions, an increase in the incentive bonus accrual and internal growth. These decreases were partially offset by a $38.0 million gain recognized in March 1998 on the sale of the Weld County fractionators. EBITDA for the NGLs fractionation, transportation, marketing and trading segment increased $2.8 million from $(.4) million to $2.4 million due to increased trading and marketing activity. ENVIRONMENTAL CONSIDERATIONS Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Historically these expenditures have been between $5 million and $15 million annually except for those environmental liabilities identified with the acquisition of Union Pacific Fuels of approximately $63 million. The Union Pacific Fuels environmental liabilities associated with soil and groundwater contamination were transferred to a third party at a cost of approximately $48 million. The outlook for environmental spending, both capitalized and expensed, is not expected to change materially from historical levels of $5 to $15 million annually. LIQUIDITY AND CAPITAL RESOURCES LIQUIDITY PRIOR TO THE COMBINATION The Predecessor Company's capital investments and acquisitions were financed by cash flow from operations and non-interest bearing advances from Duke Energy or its subsidiaries under various arrangements. Under Duke Energy's centralized cash management system, Duke Energy deposited sufficient funds in our bank accounts for us to meet our daily obligations and withdrew excess funds from those accounts. Advances were offset by cash provided by operations to yield net advances from Duke Energy which were included in the historical consolidated balance sheets and statements of cash flows of the Predecessor Company. In 1999, the Predecessor Company had notes to and advances from Duke Energy which were terminated in connection with the Combination. FINANCING TRANSACTIONS IN CONNECTION WITH THE COMBINATION In connection with the Combination, all advances from Duke Energy were capitalized to equity. S-23 24 On March 31, 2000, we entered into a $2.8 billion credit facility with several financial institutions. The credit facility will be used as the liquidity backstop to support a commercial paper program. On April 3, 2000 we borrowed approximately $2.8 billion in the commercial paper market to fund the one-time cash distributions (including reimbursements for acquisitions) of approximately $1.5 billion to Duke Energy and approximately $1.2 billion to Phillips and to cover working capital requirements. At June 30, 2000 we had $2.6 billion in outstanding commercial paper, with maturities ranging from one day to 60 days and annual interest rates ranging from 6.71% and 7.2%. At no time will the amount of our outstanding commercial paper exceed the available amount under the credit facility. The credit facility matures on March 30, 2001 and borrowings bear interest at a rate equal to, at our option, either (1) LIBOR plus .50% per year for the first 90 days following the closing of the credit facility and LIBOR plus .625% per year thereafter or (2) the higher of (a) the Bank of America prime rate and (b) the Federal Funds rate plus .50% per year. The amount available under the bank credit facility and corresponding commercial paper program will be reduced by the amount, if any, of long-term debt we may issue, including the notes offered hereby, but we intend that the credit facility will not be reduced to below $1.0 billion. In the future, our debt levels will vary depending on our liquidity needs, capital expenditures and cash flow. 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 facilities, 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. PREFERRED FINANCING In August 2000, we issued $300 million of preferred member interests to affiliates of Duke Energy and Phillips. The proceeds from this financing were used to repay a portion of our outstanding commercial paper. The preferred member interests are entitled to cumulative preferential distributions of 9.5% per annum payable, unless deferred, semi-annually. We have the right to defer payments of preferential distributions on the preferred member interests, other than certain tax distributions, at any time and from time to time, for up to 10 consecutive semi-annual periods. Deferred preferred distributions will accrue additional amounts based on the preferential distribution rate (plus 0.5% per annum) to the date of payment. The preferred member interests, together with all accrued and unpaid preferential distributions, must be redeemed and paid on the earlier of the thirtieth anniversary date of issuance and consummation of an initial public offering of equity securities. 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 repairs and maintenance of our existing facilities. Our capital expenditure budget for well connections and repair and maintenance of our existing facilities in 2000 is approximately $175 million, of which approximately $115 million was spent in the six months ended June 30, 2000. On March 31, 2000, we acquired gathering and processing assets located in central Oklahoma from Conoco and Mitchell Energy. We paid cash of $99.5 million and exchanged our interest in certain gathering and marketing joint ventures located in southeast Texas having a total fair value of approximately $42 million as consideration for these assets. 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. S-24 25 CASH FLOWS Net cash provided by operating activities for the six months ended June 30, 2000 improved to $324.7 million from $131.2 million for the same period in 1999, primarily due to higher commodity prices and acquisitions. Net cash used in investing activities was $189.3 million for the six months ended June 30, 2000 compared to $1,543.1 million for the same period in 1999. Acquisitions of the Conoco and Mitchell Energy assets in 2000 and the Union Pacific Fuels assets in 1999 were the primary uses of the invested cash. The net cash used in investing activities was financed through operating activities, advances from Duke Energy and proceeds from the issuance of short-term debt. Net cash provided by operating activities for the Predecessor Company in 1999 improved to $173.1 million from $40.4 million in 1998, primarily due to higher commodity prices and acquisitions. Net cash used in investing activities by the Predecessor Company was $1,571.4 million for 1999 compared to $203.6 million for 1998, of which $1,456.5 million was used for acquisitions and the remainder was used principally for capital expenditures. The net cash used in investing activities was financed through operating activities, advances from Duke Energy and proceeds from the issuance of short-term debt. Net cash provided by operating activities for the Predecessor Company was $40.4 million for 1998 compared to $173.4 million for 1997. This decrease was primarily due to the reduction of trade accounts payable to producers for the purchase of raw natural gas at purchase prices lower than those in 1997. Net cash used in investing activities by the Predecessor Company in 1998 increased to $203.6 million from $138.0 million in 1997. In 1998, $185.5 million was used for capital expenditures and $84.9 million was used for investments in affiliates. The net cash used in investing activities was provided by operating activities and advances from Duke Energy. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS 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 Predecessor Company's portfolio of supply contracts in 1999, 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 throughout 1999 would have resulted in changes in pre-tax net income of approximately $(15 million) and $5 million, respectively. Based upon the combined company's portfolio of supply contracts in 1999, and excluding the effects of our commodities risk management program, similar commodities price changes in 1999 would have resulted in changes in pre-tax net income of approximately $(24 million) and $1 million, respectively. Commodity derivatives such as futures and swaps are available to reduce such exposure to fluctuations in commodity prices. Gains and losses related to commodity derivatives are recognized in income when the underlying hedged physical transaction closes, and such gains and losses are included in sales of natural gas and petroleum products in our statement of income. Natural gas and crude oil futures, which are used to hedge NGLs prices, involve the buying and selling of natural gas and crude oil for future delivery at a fixed price. Over-the-counter swap agreements require us to receive or make payments on the difference between a specified price and the actual price of natural gas or crude oil. Historically, the Predecessor Company's commodity price risk was managed by Duke Energy's centralized program for controlling, managing and coordinating its risk management activities. Under this program, the Predecessor Company used futures and swaps to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs. Historically, futures and swaps conducted through Duke Energy were handled through Duke Energy Trading and Marketing, LLC, a partnership in which Duke Energy owns a 60% interest. Under this arrangement, the Predecessor Company did not experience margin requirements. S-25 26 At December 31, 1998 and 1999 the Predecessor Company (through Duke Energy) had outstanding futures and swaps for an absolute notional contract quantity of 10.92 and 7.8 Bcf of natural gas and an absolute notional contract quantity of 59,000 and 32,764,000 barrels of crude oil, respectively, both of which were intended to offset the risk of price fluctuations under fixed-price commitments for delivering and purchasing natural gas and NGLs, respectively. The gains, losses and costs related to those financial instruments that qualify as a hedge are not recognized until the underlying physical transaction occurs. At December 31, 1998 and 1999, the Predecessor Company had current unrecognized net gains (losses) of $1.8 million and $(63.5 million), respectively, related to commodity instruments. All unrecognized gains and losses at March 31, 2000, the date of the Combination, remain with Duke Energy and will not have an impact on our company's future earnings. Losses relating to hedging with commodity derivatives included in the Predecessor Company's statement of income equaled $34.0 million for 1999. There were no corresponding losses in 1997 or 1998. For the six months ended June 30, 1999 and 2000, we recorded a hedging gain of $4.4 million and a hedging loss of $59.2 million, respectively. After the Combination, we began directing our risk management activities independently of Duke Energy. We use commodity-based derivative contracts to reduce the risk in our overall earnings and cash flow with the primary goals of: - maintaining minimum cash flow to fund debt service, dividends, and maintenance type capital projects; - avoiding disruption of our growth capital and value creation process; and - retaining a high percentage of the potential upside relating to commodity price increases. We implemented a risk management policy that provides guidelines for entering into contractual arrangements to manage our commodity price exposure. Our risk management committee has ongoing responsibility for the content of this policy and has principal oversight responsibility for compliance with the policy framework by ensuring proper procedures and controls are in place. In general, we seek to provide downside protection to our business activities while retaining most of the upside potential by using floors and other similar hedging structures. These structures will typically require the payment of a premium to protect the downside while retaining exposure to the upside. Historically, NGLs and related commodity products have shown a mean reverting tendency to long term average prices, which implies that supply and demand for products balance over cycles. Therefore, we may choose to forego price upside in favor of a known, hedged cash flow position as prices rise significantly above historical levels and depending upon existing market drivers. An active forward market for hedging of NGL products is not normally available for hedging a significant amount of our NGL production beyond a one to three month time horizon. With an anticipated hedging horizon of up to 12 months, crude oil derivatives, which historically have had a high correlation with NGL prices, will typically be the mechanism used for longer-term price risk management. As of March 31, 2000, the existing commodity positions under the Duke Energy centralized program were transferred to Duke Energy. In establishing our initial independent commodity risk management position on April 1, 2000, we acquired a portion of Duke Energy's existing commodity derivatives held for non-trading purposes. The absolute notional contract quantity of the positions acquired was 4,607,000 barrels of crude oil. Such positions were acquired at market value. INTEREST RATE RISK Prior to the Combination, we had no material interest rate risk associated with debt used to finance our operations due to limited third party borrowings. As of June 30, 2000, we had approximately $2.6 billion outstanding under a commercial paper program. As a result, we are exposed to market risks S-26 27 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. Assuming none of our outstanding commercial paper is refinanced with long-term fixed rate debt, an increase of .5% in interest rates would result in an increase in annual interest expense of approximately $13.0 million. As of June 30, 2000, we had in place $1,150 million notional amount of treasury rate locks and interest rate swaps to hedge interest rate risk associated with this offering. FOREIGN CURRENCY RISK Currently we have no material foreign currency exposure. ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). SFAS 133 establishes standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as: - a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment; - a hedge of the exposure to variable cash flows of a forecasted transaction; or - a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign-currency-denominated forecasted transaction. The accounting for changes in the fair value of a derivative (gains and losses) depends on the intended use of the derivative and the resulting designation. We are required to adopt SFAS 133 on January 1, 2001. We have not completed the process of evaluating the impact that will result from adopting SFAS 133. S-27 28 BUSINESS OUR BUSINESS The midstream natural gas industry is the link between exploration and production of raw natural gas and the delivery of its components to end-use markets. We operate in the two principal segments of the midstream natural gas industry: - natural gas gathering, processing, transportation, marketing and storage; and - NGL fractionation, transportation, marketing and trading. We believe that we are one of the largest gatherers of raw natural gas, based on wellhead volume, in North America. We are the largest producer, and we believe that we are one of the largest marketers, of NGLs in North America. In 1999: - we gathered and/or transported an average of approximately 7.3 billion cubic feet per day of raw natural gas; - we produced an average of approximately 400,000 barrels per day of NGLs; and - we marketed and traded an average of approximately 486,000 barrels per day of NGLs. During 1999, our natural gas gathering, processing, transportation, marketing and storage segment produced $981.5 million of gross margin and $592.4 million of EBITDA, excluding general and administrative expenses, and our NGL fractionation, transportation, marketing and trading segment produced $38.3 million of gross margin and $38.1 million of EBITDA, excluding general and administrative expenses. During the six months ended June 30, 2000, our natural gas gathering, processing, transportation, marketing and storage segment produced $657.1 million of gross margin and $484.4 million of EBITDA, excluding general and administrative expenses, and our NGL fractionation, transportation, marketing and trading segment produced $26.5 million of gross margin and $26.1 million of EBITDA, excluding general and administrative expenses. We gather raw natural gas through gathering systems located in seven major natural gas producing regions: Permian Basin, Mid-Continent, East Texas-Austin Chalk-North Louisiana, Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf of Mexico and Western Canada. Our gathering systems consist of approximately 57,000 miles of gathering pipe, with approximately 38,000 active connections to producing wells. Our natural gas processing operations involve the separation of raw natural gas gathered both by our gathering systems and by third-party systems into NGLs and residue gas. We process the raw natural gas at our 70 owned and operated plants and at 13 third-party operated facilities in which we hold an equity interest. The NGLs separated from the raw natural gas by our processing operations are either sold and transported as NGL raw mix or further separated through a process known as fractionation into their individual components (ethane, propane, butanes and natural gasoline) and then sold as components. We fractionate NGL raw mix at our 12 owned and operated processing facilities and at two third-party operated fractionators located on the Gulf Coast in which we hold an equity interest. We sell NGLs to a variety of customers ranging 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 our NGL production that is committed to Phillips under an existing 15-year contract. We market approximately 370,000 barrels per day of NGLs processed at our owned and operated plants and 40,000 barrels per day of NGLs processed at third-party operated facilities and trade approximately 75,000 barrels per day of NGLs at market centers. S-28 29 The residue gas that results from our processing is sold at market-based prices to marketers or end-users, including large industrial customers and natural gas and electric utilities serving individual consumers. We market residue gas through our wholly owned gas marketing company. We also store residue gas at our 8.5 billion cubic foot natural gas storage facility. On March 31, 2000, we obtained by transfer from Duke Energy the general partner of TEPPCO, a publicly traded limited partnership which owns and operates a network of pipelines for refined products and crude oil. The general partner is responsible for the management and operations of TEPPCO. We believe that our ownership of the general partner of TEPPCO improves our business position in the transportation sector of the midstream natural gas industry and provides additional flexibility in pursuing our disciplined acquisition strategy by providing an alternative acquisition vehicle. It also provides us with an opportunity to sell appropriate assets currently held by our company to TEPPCO. Through our ownership of the general partner of TEPPCO we have the right to receive from TEPPCO incentive cash distributions in addition to a 2% share of distributions based on our general partner interest. At TEPPCO's 1999 per unit distribution level, the general partner: - receives approximately 14% of the cash distributed by TEPPCO to its partners, which consists of 12% from the incentive cash distribution and 2% from the general partner interest; and - under the incentive cash distribution provisions, receives 50% of any increase in TEPPCO's per unit cash distributions. On July 21, 2000, TEPPCO acquired, for $318.5 million, Atlantic Richfield Company's ownership interests in a 500-mile crude oil pipeline that extends from a marine terminal at Freeport to Cushing, a 416-mile crude oil pipeline that extends from Jal to Cushing, a 400-mile crude oil pipeline that extends from West Texas to Houston, crude oil terminal facilities in Midland, Cushing and the Houston area and receipt and delivery pipelines centered around Midland. INDUSTRY OVERVIEW The midstream natural gas industry in North America is comprised of approximately 150 companies that process approximately 45 billion cubic feet per day of raw natural gas and produce approximately 1.9 million barrels per day of NGLs. The industry generally is characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells. Demand for natural gas in North America has grown significantly in recent years. We believe that demand will continue to increase and will be driven primarily by the growth of natural gas-fired electric generation. According to the EIA Report, U.S. demand for natural gas is expected to increase from 22 trillion cubic feet in 1999 to 32 trillion cubic feet in 2020. We believe that oil and natural gas producers in North America will respond to increased demand by focusing their exploration and drilling efforts on basins where pipeline and processing capacity has been, or is being, built and where there is sufficient capacity to meet the needs of high demand markets. We have a strong presence and significant capacity in several of these areas (including Onshore Gulf of Mexico and Rocky Mountains, where, according to the Oil and Gas Journal's "1999 Worldwide Gas Processing Report," we are among the three largest midstream natural gas companies based on volumes of natural gas gathered and processed or volumes of NGLs produced) that, according to the EIA Report, are forecasted to have significant growth in production between now and 2020. This growth in production, which is expected to be 2.31 trillion cubic feet in Rocky Mountain region and 1.71 trillion cubic feet in Onshore Gulf of Mexico region by 2020, should provide us with opportunities to increase our throughput volumes and asset utilization. The midstream natural gas industry has experienced significant consolidation since the mid-1990s. We believe the following factors have contributed to this consolidation: - significant economies of scale resulting from improved operating efficiencies, throughput volumes and asset utilization rates that can be achieved by strategically growing operations; S-29 30 - decisions by transmission pipelines and by exploration and production companies to divest their gathering, processing and marketing activities and concentrate their businesses on gas transmission and on exploration and production; and - technological improvements. OUR BUSINESS STRATEGY We believe that we are one of the largest gatherers of raw natural gas, based on wellhead volume, in North America. We are the largest producer, and we believe that we are one of the largest marketers, of NGLs in North America. 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. We have significant midstream natural gas operations in five of the largest natural gas producing regions in North America. To take advantage of the anticipated growth in natural gas demand in North America, we are pursuing the following strategies: - Capitalize on the size and focus of our existing operations. We intend to use the size, scope and concentration of our assets in our regions of operation to take advantage of growth opportunities and to acquire additional supplies of raw natural gas. Our significant market presence and asset base generally provide us with a competitive advantage in capturing new supplies of raw natural gas because of our resulting lower costs of connection to new wells and of processing additional raw natural gas. In addition, we believe our size and geographic diversity allow us to benefit from the growth of natural gas production in multiple regions while mitigating the adverse effects from a downturn in any one region. - Increase our presence in each aspect of the midstream business. We are active in each significant aspect of the midstream natural gas value chain, including raw natural gas gathering, processing, and transportation, NGL fractionation and NGL and residue gas transportation and marketing. Each link in the value chain provides us with an opportunity to earn incremental income from the raw natural gas that we gather and from the NGLs and residue gas that we produce. We intend to grow our significant NGL market presence by investing in additional NGL infrastructure, including pipelines, fractionators and terminals. - Increase our presence in high growth production areas. According to the EIA Report, production from areas such as Western Canada, Onshore Gulf of Mexico, Rocky Mountains and Offshore Gulf of Mexico is expected to increase significantly to meet anticipated increases in demand for natural gas in North America. We intend to use our strategic asset base in these growth areas and our leading position in the midstream natural gas industry as a platform for future growth in these areas. We plan to increase our operations in these areas by following a disciplined acquisition strategy, and by expanding existing infrastructure and constructing new gathering lines and processing facilities. - Capitalize on proven acquisition skills in a consolidating industry. In addition to pursuing internal growth by attracting new raw natural gas supplies, we intend to use our substantial acquisition and integration skills to continue to participate selectively in the consolidation of the midstream natural gas industry. We have pursued a disciplined acquisition strategy focused on acquiring complementary assets during periods of relatively low commodity prices and integrating the acquired assets into our operations. Since 1996, we have completed over 20 acquisitions, increasing our raw natural gas processing capacity by over 275%. These acquisitions demonstrate our ability to successfully identify, acquire and integrate attractive midstream natural gas operations. - Further streamline our low-cost structure. Our economies of scale, operating efficiency and resulting low cost structure enhance our ability to attract new raw natural gas supplies and generate current income. The low-cost provider in any region can more readily attract new raw natural gas volumes by offering more competitive terms to producers. We believe the Combination provides us S-30 31 with a complementary base of assets from which to further extract operating efficiencies and cost reductions, while continuing to provide superior customer service. NATURAL GAS GATHERING, PROCESSING, TRANSPORTATION, MARKETING AND STORAGE OVERVIEW At March 31, 2000, our raw natural gas gathering and processing operations consisted of: - approximately 57,000 miles of gathering pipe, with connections to approximately 38,000 active producing wells; and - 70 owned and operated processing plants and ownership interests in 13 additional third-party operated plants, with a combined processing capacity of approximately 7.9 billion cubic feet per day. In 1999, we gathered, processed and/or transported approximately 7.3 billion cubic feet per day of raw natural gas. During 1999, our natural gas gathering, processing, transportation, marketing and storage activities produced $981.5 million of gross margin and $592.4 million of EBITDA, excluding general and administrative expenses. Our raw natural gas gathering and processing operations are located in 11 contiguous states in the United States and two provinces in Western Canada. We provide services in the following key North American natural gas and oil producing regions; Permian Basin, Mid-Continent, East Texas-Austin Chalk-North Louisiana, Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf of Mexico and Western Canada. We have a significant presence in the first five of these producing regions where, according to the Oil and Gas Journal's "1999 Worldwide Gas Processing Report," we are among the three largest midstream natural gas companies based on volumes of natural gas gathered and processed or volumes of NGLs produced. Raw Natural Gas Supply Arrangements. Typically, we take ownership of raw natural gas at the wellhead. Each producer generally dedicates to us the raw natural gas produced from designated oil and natural gas leases for a specific term. The term will typically extend for three to seven years. We currently have more than 15,000 active contracts with over 5,000 producers. We obtain access to raw natural gas and provide our midstream natural gas service principally under three types of contracts: percentage-of-proceeds contracts, fee-based contracts and keep-whole contracts. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Overview -- Effects of Our Raw Natural Gas Supply Arrangements" for a description of these types of contracts. Raw Natural Gas Gathering. As of December 31, 1999, we had approximately 17 trillion cubic feet of raw natural gas supplies attached to our systems. We receive raw natural gas from a diverse group of producers under contracts with varying durations to provide a stable supply of raw natural gas through our processing plants. A significant portion of the raw natural gas that is processed by us is produced by large producers, including ExxonMobil, Union Pacific Resources, BP Amoco and Phillips, which together account for approximately 20% of our processed raw natural gas. We continually seek new supplies of raw natural gas, both to offset natural declines in production from connected wells and to increase throughput volume. Historically, we have been successful in connecting additional supplies to more than offset natural declines in production. We obtain new well connections in our operating areas by contracting for production from new wells or by obtaining raw natural gas that has been released from other gathering systems. Producers may switch raw natural gas from one gathering system to another to obtain better commercial terms, conditions and service levels. We believe our significant asset base and scope of our operations provides us with significant opportunities to add released raw natural gas to our systems. In addition, we have significant processing capacity in the Onshore Gulf of Mexico, Offshore Gulf of Mexico and Rocky Mountain regions, which, S-31 32 according to the EIA Report contain significant quantities of proved natural gas reserves. We also have a presence in other potential high-growth areas such as the Western Canadian Sedimentary Basin. As a result of new connections resulting from both increased drilling and released raw natural gas, we connected approximately 1,300 additional wells in 1998 and 1,500 additional wells in 1999. Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. On gathering systems where it is economically feasible, we operate at a relatively low pressure, which can allow us to offer a significant benefit to raw natural gas producers. Specifically, lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to gathering systems and continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly more difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting gathering system. Field compression is typically used to lower the pressure of a gathering system. If field compression is not installed, then the remaining production in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise would not be produced. Our field compression systems provide the flexibility of connecting a high pressure well to the downstream side of the compressor even though the well is producing at a pressure greater than the upstream side. As the well ages and the pressure naturally declines, the well can be reconnected to the upstream, low pressure side of the compressor and continue to produce. By maintaining low pressure systems with field compression units, we believe that the wells connected to our systems are able to produce longer and at higher volumes before disconnection is required. Raw Natural Gas Processing. Most of our natural gas gathering systems feed into our natural gas processing plants. Our processing plants produced an average of approximately 4.7 billion cubic feet per day of residue gas and an average of approximately 400,000 barrels per day of NGLs during 1999. Our natural gas processing operations involve the extraction of NGLs from raw natural gas, and, at certain facilities, the fractionation of NGLs into their individual components (ethane, propane, butanes and natural gasoline). We sell NGLs produced by our processing operations to a variety of customers ranging from large, multi-national petrochemical and refining companies, including Phillips, to small, regional retail propane distributors. At three plants, we also extract helium from the residue gas stream. Helium is used for medical diagnostics, in arc welding and other metallurgical and chemical processes, in the space exploration program and other scientific applications, for diluting oxygen for breathing (by patients with respiratory ailments and by deep-sea divers) and for inflating lighter-than-air aircraft and balloons. These plants are among the few helium extraction facilities in the United States. We extracted approximately 1.3 billion cubic feet of helium during 1999, producing revenues of approximately $33 million. Hydrogen sulfide also is separated in the treating and processing cycle. During 1999, we produced and sold approximately 93,000 long tons of sulfur, producing revenues of approximately $1.1 million. We also remove off-quality crude oil, nitrogen, carbon dioxide and brine from the raw natural gas stream. The nitrogen and carbon dioxide are released into the atmosphere, and the crude oil and brine are accumulated and stored temporarily at field compressors or the various plants. The brine is transported to licensed disposal wells owned either by us or by third parties. The crude oil is sold in the off-quality crude oil market. Residue Gas Marketing. In addition to our gathering and processing activities discussed above, we are involved in the purchase and sale of residue gas, directly or through our wholly owned gas marketing company. Our gas marketing efforts primarily involve supplying the residue gas demands of end-user customers that are physically attached to our pipeline systems and supplying the gas processing requirements associated with our keep-whole processing agreements. We are focused on extracting the highest possible value for the residue gas that results from our processing and transportation operations. Of the residue gas that we market, we currently sell approximately 25% to various on-system users and approximately 75% to industrial end-users, national S-32 33 wholesale gas marketing companies (including Duke Energy Trading and Marketing, a subsidiary of Duke Energy and one of the largest gas marketers in the United States) and electric utilities. Our Spindletop storage facility plays an important role in our ability to act as a full-service natural gas marketer. We lease approximately two-thirds of the facility's capacity to our customers, and we use the balance to manage relatively constant natural gas supply volumes with uneven demand levels and provide "backup" service to our customers. The natural gas marketing industry is a highly competitive commodity business with a significant degree of price transparency. We provide a full range of natural gas marketing services in conjunction with the gathering, processing, and transportation services we offer on our facilities, which allows us to use our asset infrastructure to enhance our revenues across each aspect of the natural gas value chain. Financial Services. We provide mezzanine financing to producers seeking capital for production enhancement in our core physical and marketing asset areas. We provide financing to operators as part of our efforts to increase utilization of our existing assets, gain access to incremental supplies and generate opportunities for us to expand existing infrastructure and/or construct new gathering lines and processing facilities. The majority of the financing plans we offer are asset-based. This program has created significant gathering and processing opportunities for us. At December 31, 1999, we had $21.9 million in financing outstanding under this program. REGIONS OF OPERATIONS Our operations cover substantially all of the major natural gas producing regions in the United States, as well as portions of Western Canada. In addition, our geographic diversity reduces the impact of regional price fluctuations and regional changes in drilling activity. Our raw natural gas gathering and processing assets are managed in line with the seven geographic regions in which we operate. The following table provides information concerning the raw natural gas gathering systems and processing plants owned or operated by us at March 31, 2000. COMPANY PLANTS GAS GATHERING OPERATED OPERATED NET PLANT REGION SYSTEM(MILES) PLANTS BY OTHERS CAPACITY(MMCF/D) - ------ ------------- -------- --------- ---------------- Permian Basin........ 12,890 19 2 1,417 Mid-Continent........ 30,820 19 2 2,273 East Texas-Austin Chalk-North Louisiana.......... 5,869 10 1 1,555 Onshore Gulf of Mexico............. 3,008 7 1 1,083 Rocky Mountains...... 3,765 10 1 600 Offshore Gulf of Mexico............. 490 2 6 909 Western Canada....... 144 3 0 109 ------ -- -- ----- Total................ 56,986 70 13 7,946 ====== == == ===== 1999 OPERATING DATA -------------------------------------------------------- PLANT INLET RESIDUE GAS NGLS REGION VOLUME(MMCF/D) PRODUCTION(MMCF/D) PRODUCTION(BBLS/D) - ------ -------------- ------------------ ------------------ Permian Basin........ 1,123 816 124,507 Mid-Continent........ 1,459 1,223 120,551 East Texas-Austin Chalk-North Louisiana.......... 1,033 937 69,420 Onshore Gulf of Mexico............. 757 675 37,944 Rocky Mountains...... 387 319 24,708 Offshore Gulf of Mexico............. 736 691 15,148 Western Canada....... 76 72 278 ----- ----- ------- Total................ 5,571 4,733 392,556(1) ===== ===== ======= - --------------- (1) Excludes approximately 7,500 barrels per day processed at third party plants on our behalf. Our key suppliers of raw natural gas in these seven regions include major integrated oil companies, independent oil and gas producers, intrastate pipeline companies and natural gas marketing companies. Our principal competitors in this segment of our business consist of major integrated oil companies, independent oil and gas gathers, and interstate and intrastate pipeline companies. Regional Growth Strategies. Growth of our gas gathering and processing operations is key to our success. Increased raw natural gas supply enables us to increase throughput volumes and asset utilization throughout our entire midstream natural gas value chain. As we develop our regional growth strategies, we evaluate the nature of the opportunity that a particular region presents. The attributes that we evaluate include the nature of the gas reserves and production profile, existing midstream infrastructure including S-33 34 capacity and capabilities, the regulatory environment, the characteristics of the competition, and the competitive position of our assets and capabilities. In a general sense, we employ one or more of the strategies described below: - Growth -- in regions where production is expected to grow significantly and/or there is a need for additional gathering and processing infrastructure, we plan to expand our gathering and processing assets by following a disciplined acquisition strategy, by expanding existing infrastructure, and by constructing new gathering lines and processing facilities. - Consolidation -- in regions that include mature producing basins with flat to declining production or that have excess gathering and processing capacity, we seek opportunities to efficiently consolidate the existing asset base in order to increase utilization and operating efficiencies and realize economies of scale. - Opportunistic -- in regions where production growth is not primarily generated by new exploration drilling activity we intend to optimize our existing assets and selectively expand certain facilities or construct new facilities to seize opportunities to increase our throughput. These regions are generally experiencing stable to increasing production through the application of new drilling technologies like 3-D seismic, horizontal drilling and improved well completion techniques. The application of new technologies is causing the drilling of additional wells in areas of existing production and recompletions of existing wells which create additional opportunities to add new gas supplies. In each region, we plan to apply both our broad overall business strategy and the strategy uniquely suited to each region. We believe this plan will yield balanced growth initiatives, including new construction in certain high growth areas, expansion of existing systems and complementary acquisitions, combined with efficiency improvements and/or asset consolidation. We also plan to rationalize assets and redeploy capital to higher value opportunities. A description of our operations, key suppliers and principal competitors in each region is set forth below: Permian Basin. Our facilities in this region are located in West Texas and Southeast New Mexico. We own majority interests in and are the operator of 19 natural gas processing plants in this region. In addition, we own minority interests in two other natural gas processing plants that are operated by others. Our natural gas processing plants are strategically located to access production of the Permian Basin. Our plants have processing capacity net to our interest of 1.4 billion cubic feet of raw natural gas per day. Operations in this region are primarily focused on gathering and processing, but we also are positioned for marketing residue gas and NGLs. We offer low, intermediate, and high pressure gathering and processing and both high and low NGLs content treating. Three of our processing facilities provide fractionation services. Residue gas sales are enhanced by access to the Waha Hub where multiple pipeline interconnects source gas for virtually every market in the United States. Our older facilities have been modernized to improve product recoveries, and most of our plants offer sulfur removal. During 1999, these plants operated at an overall 79% capacity utilization rate. On average, the raw natural gas from West Texas contains approximately 5.2 gallons of NGLs per thousand cubic feet, while raw natural gas from New Mexico contains approximately 4.6 gallons of NGLs per thousand cubic feet. As we generally pursue a consolidation strategy in this region, our assets will allow us to compete for new gas supplies in most major fields and benefit from the expected increase in drilling and production from technological advances. In addition, our ability to redirect gas between several processing plants allows us to maximize utilization of our processing capacity in this region. Our key suppliers in this region include ExxonMobil, Union Pacific Resources and Yates Petroleum. Our principal competitors in this region include Dynegy, Koch and Texaco. Mid-Continent. Our facilities in this region are located in Oklahoma, Kansas and the Texas Panhandle. In this region, we own and are the operator of 19 natural gas processing plants, 18 in which we S-34 35 own a 100% interest and one in which we own a 50% interest. We also own minority interests in two other natural gas processing plants that are operated by others. We gather and process raw natural gas primarily from the Arkoma, Ardmore, and Anadarko basins, including the prolific Hugoton and Panhandle fields. Our plants have processing capacity net to our interest of 2.3 billion cubic feet of raw natural gas per day. During 1999, our plants operated at an overall 65% capacity utilization rate. On average, the raw natural gas from this region contains from 3 to 5 gallons of NGLs per thousand cubic feet. We also produce approximately 28% of the United States domestic supply of helium from our Mid-Continent facilities. Annual growth in demand for helium over the past 15 years has been approximately 8.5% per year. Because of its unique characteristics and use as an industrial gas, we expect demand for helium to grow well into the future. Existing production in the Mid-Continent region is typically from mature fields with shallow decline profiles that will provide our plants with a dependable source of raw natural gas over a long term. With the development of improved exploration and production techniques such as 3-D seismic and horizontal drilling over the past several years, additional reserves have become economically producible in this region. We hold large acreage dedication positions with various producers who have developed programs to add substantially to their reserve base. The infrastructure of our plants and gathering facilities are uniquely positioned to pursue our consolidation strategy. Our key suppliers in this region include Phillips, OXY USA and Anadarko Petroleum. Our principal competitors in this region include Coastal Field Services, Oneok Field Services and Enogex Inc. East Texas-Austin Chalk-North Louisiana. Our facilities in this region are located in East Texas, North Louisiana and the Austin Chalk formation of East Central Texas and Central Louisiana. We own majority interests in and are the operator of 10 natural gas processing plants in this region. In addition, we own a minority interest in one natural gas processing plant that is operated by another entity. Our plants have processing capacity net to our interest of 1.6 billion cubic feet of raw natural gas per day. During 1999, these plants operated at an overall 66% capacity utilization rate. In this region we also own three intrastate gathering systems, which, in the aggregate, can gather and transport approximately 480 million cubic feet of raw natural gas per day. Our East Texas operations are centered around our East Texas Complex, located near Carthage, Texas. This plant complex is the second largest raw natural gas processing facility in the continental United States, based on liquids recovery, and currently produces approximately 40,000 barrels per day of NGLs. Our 165-mile gathering network aggregates production to the East Texas Complex, which currently gathers approximately 130 million cubic feet of raw natural gas per day. In addition, the plant is connected to and processes raw natural gas from several other gathering systems, including those owned by Koch, Union Pacific Resources and American Central. Substantially all of the raw natural gas processed at the complex is contracted under percent-of-proceeds agreements with an average remaining term of approximately six years. This plant is adjacent to our Carthage Hub, which delivers residue gas to interconnects with 14 interstate and intrastate pipelines. The Carthage Hub, with an aggregate delivery capacity of two billion cubic feet per day, acts as a key exchange point for the purchase and sale of residue gas. We also operate Panola pipeline, with throughput capacity of up to 40,000 barrels per day, which carries NGLs from our East Texas Complex to markets in Mont Belvieu, Texas. In this region, we also own and operate the Fuels Cotton Valley Gathering System, which consists of 76 miles of pipeline and which gathers approximately 30 million cubic feet of raw natural gas per day. As we pursue a combination of opportunistic and consolidation strategies in this diverse region, we intend to leverage our modern processing capacity, intrastate gas pipeline and NGL assets. Our key suppliers in this region include Union Pacific Resources, Devon and Phillips. Our principal competitors in this region include Koch, El Paso Field Services and Southwest Pipeline Corporation. Onshore Gulf of Mexico. Our facilities in this region are located in South Texas and the Southeastern portions of the Texas Gulf Coast. We own a 100% interest in and are the operator of seven natural gas processing plants and the Spindletop gas storage facility in this region. In addition, we own a S-35 36 minority interest in one natural gas processing plant that is operated by another entity. Our plants have processing capacity net to our interest of 1.1 billion cubic feet of raw natural gas per day. During 1999, the plants in this region ran at an overall 70% capacity utilization rate. Our Spindletop natural gas storage facility is located near Beaumont, Texas and has current working natural gas capacity of 8.5 billion cubic feet, plus expansion potential of up to an additional 10 billion cubic feet. We currently have approximately 5.6 billion cubic feet of the available storage capacity under lease with expiration terms out to July 2004. This high deliverability storage facility is positioned to meet the needs of the natural gas-fired electric generation marketplace, currently the fastest growing demand segment of the natural gas industry. The facility interconnects with 12 interstate and intrastate pipelines and is designed to handle the hourly demand needs of power generators. To achieve growth in our Onshore Gulf of Mexico region, we intend to fully integrate our recently acquired assets and use the diversity of our current asset base to provide value-added services to our broad customer base. We will also seek additional opportunities to participate in the anticipated growth in supply from this region. Our key suppliers in this region include Collins & Ware, United Oil and Minerals and TransTexas. Our principal competitors in this region include PG&E Texas Transmission, Tejas Gas Corp. and Houston Pipe Line Company. Rocky Mountains. Our facilities in this region are located in the DJ Basin of Northern Colorado, the Ladder Creek area of Southeast Colorado and the Greater Green River Basin and Overthrust Belt areas of Southwest Wyoming and Northeast Utah. We own a 100% interest in and are the operator of 10 natural gas processing plants in this region. In addition, we own a minority interest in one natural gas processing plant that is operated by another entity. Our plants have processing capacity net to our interest of 600 million cubic feet of raw natural gas per day. During 1999, our plants in this region operated at an overall 65% capacity utilization rate. These assets provide for the gathering and processing of raw natural gas, the transportation and fractionation of NGLs, nitrogen rejection, and helium extraction and liquification services. The Rocky Mountains region has well placed assets with strong competitive positions in areas that are expected to benefit from increased drilling activity, providing us with a platform for growth. In this region, we expect to achieve growth through our existing assets, strategic acquisitions and development of new facilities. In addition, we intend to pursue an opportunistic strategy in areas where new technologies and recovery methods are being employed. Our key suppliers in the region include Patina Oil & Gas, HS Resources and Union Pacific Resources. Our principal competitors in this region include HS Resources, Williams Field Services and Western Gas Resources. Offshore Gulf of Mexico. Our facilities in this region are located along the Gulf Coast areas of Louisiana, Mississippi and Alabama. We own minority interests in and are the operator of two natural gas processing plants in this region. In addition, we own a 50% interest in one natural gas processing plant and minority interests in five other natural gas processing plants, all of which are operated by other entities. The plants have processing capacity net to our interest of 909 million cubic feet of raw natural gas per day. During 1999, our plants in this region operated at an overall 81% capacity utilization rate. Each of these plants straddle offshore pipeline systems delivering a relatively lower NGLs content gas stream than that of our onshore gathering systems, as approximately 50% of the produced NGLs content consists of ethane. As a result, the offshore region's revenues are concentrated in fee-based business arrangements and are less dependent on fluctuating commodity prices. In addition, we own a 37% interest in the Dauphin Island Gathering Partnership, an offshore gathering and transmission system. Dauphin Island has attractive market outlets, including deliveries to Texas Eastern Transmission Corporation, Transco, Koch, Gateway and Florida Gas Transmission for re-delivery to the Southeast, Mid-Atlantic, Northeast and New England natural gas markets. Dauphin Island's leased capacity on Texas Eastern Transmission Corporation's pipeline provides us with a means to S-36 37 cross the Mississippi River to deliver or receive production from the Venice, Louisiana natural gas hub area. Further, the Main Pass Oil Gathering Company system, in which we own a 33% interest, also has access to a variety of markets through existing shallow-water and deep-water interconnections and dual market outlets into Shell's Delta terminal as well as Chevron's Cypress terminal. We believe that the Offshore Gulf of Mexico production area will be one of the most active regions for new drilling in the United States. Our strategic growth plan for this region is to add new facilities to our existing base so that we can capture new offshore development opportunities. Our existing assets in the eastern Gulf of Mexico are positioned to access new and ongoing production developments. Based on our broad range of assets in the region, we intend to capture incremental margins along the natural gas value chain. Our key suppliers in the Offshore Gulf of Mexico region include Coastal, ExxonMobil and CNG Producing Company. Our principal competitors in this region include El Paso Energy, Coral Energy and Williams. Western Canada. We own a majority interest in and are the operator of three natural gas processing plants in Western Canada that are strategically located in the Peace River Arch area of Northwestern Alberta. Our facilities in this region have processing capacity net to our interest of 109 million cubic feet of raw natural gas per day. Our 144-mile gathering system located in this region supports these processing facilities. During 1999, our processing plants in this area operated at an overall 70% capacity utilization rate. Our processing facilities in this area are new, with the majority having been constructed since 1995. Our processing arrangements are primarily fee-based, providing an income stream that is not subject to fluctuations in commodity prices. The Peace River Arch area continues to be an active drilling area with land widely held among several large and small producers. Multiple residue gas market outlets can be accessed from our facilities through connections to TransCanada's NOVA system, the Westcoast system into British Columbia and the Alliance Pipeline, scheduled to be operational in October 2000. According to the EIA Report, less than 20% of the gathering and processing assets in the area are owned by midstream gathering and processing companies. As a result, we believe that significant growth opportunities exist in this region. We anticipate that producers in this area may follow the lead of U.S. producers and divest their midstream assets over the next few years. We are positioned to capitalize on this fundamental shift in the Canadian natural gas processing industry and plan to expand our position in Alberta and British Columbia through additional acquisitions and greenfield projects. Our key suppliers in this region include Star Oil & Gas Ltd., Talisman Energy Inc. and Anderson Exploration Ltd. Our principal competitors in the area include TransCanada Midstream, Talisman Energy Inc. and Westcoast Energy, Inc. NATURAL GAS LIQUIDS TRANSPORTATION, FRACTIONATION AND MARKETING OVERVIEW We market our NGLs and provide marketing services to third party NGL producers and sales customers in significant NGL production and market centers in the United States. During 1999, our NGL transportation, fractionation and marketing activities produced $38.3 million of gross margin and $38.1 million of EBITDA, excluding general and administrative expenses. In 1999, we marketed and traded approximately 486,000 barrels of NGLs per day, of which approximately 85% was production for our own account, ranking us as one of the largest NGLs marketers in the country. Our NGL services include plant tailgate purchases, transportation, fractionation, flexible pricing options, price risk management and product-in-kind agreements. Our primary NGL operations are located in close proximity to our gathering and processing assets in each of the regions in which we operate, other than Western Canada. We own interests in two NGLs fractionators at the Mont Belvieu, Texas market center, the Mont Belvieu I fractionation facility and the Enterprise Products fractionation facility. In S-37 38 addition, we own interests in two major NGLs pipelines serving the Mont Belvieu facilities, the wholly owned Panola Pipeline in East Texas and an interest in the Black Lake Pipeline in Louisiana and East Texas. We also own several regional fractionation plants and NGLs pipelines. We possess a large asset base of NGL fractionators and pipelines that are used to provide value-added services to our refining, chemical, industrial, retail and wholesale propane-marketing customers. We intend to capture premium value in local markets while maintaining a low cost structure by maximizing facility utilization at our 12 regional fractionators and 12 pipeline systems. Our current fractionation capacity is approximately 152,000 barrels per day. STRATEGY Our strategy is to exploit the size, scope and reliability of supply from our raw natural gas processing operations and apply our knowledge of NGL market dynamics to make additional investments in NGL infrastructure. Our interconnected natural gas processing operations provide us with an opportunity to capture fee-based investment opportunities in certain NGL assets, including pipelines, fractionators and terminals. In conjunction with this investment strategy and as an enhancement to the margin generation from our NGL assets, we also intend to focus on the following areas: producer services, local sales and fractionation, market hub fractionation, transportation and market center trading and storage, each of which briefly is discussed below. Producer Services. We plan to expand our services to producers principally in the areas of price risk management and handling the marketing of their products. Over the last several years, we have expanded our supply base significantly beyond our own equity production by providing a long-term market for third-party NGLs at competitive prices. Local Sales and Fractionation. We will seek opportunities to maximize value of our product by expanding local sales. We have fractionation capabilities at 14 of our raw natural gas processing plants. Our ability to fractionate NGLs at regional processing plants provides us with direct access to local NGLs markets. Market Hub Fractionation. We will focus on optimizing our product slate from our two Gulf Coast fractionators, the Mont Belvieu I and Enterprise Products fractionators, where we have a combined owned capacity of 57,000 barrels per day. The control of products from these fractionators complements our market center trading activity. Transportation. We will seek additional opportunities to invest in NGL pipelines and secure favorable third party transportation arrangements. We use company-owned NGL pipelines to transport approximately 94,500 barrels per day of our total NGL pipeline volumes, providing transportation to market center fractionation hubs or to end use markets. We also are a significant shipper on third party pipelines in the Rocky Mountains, Mid-Continent and Permian Basin producing regions and, as a result, receive the benefit of incentive rates on many of our NGLs shipments. Market Center Trading and Storage. We use trading and storage at the Mont Belvieu, Texas and Conway, Kansas NGL market centers to manage our price risk and provide additional services to our customers. We undertake these activities through the use of fixed forward sales, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. We believe there are additional opportunities to grow our price risk management services with our industrial customer base. KEY SUPPLIERS AND COMPETITION The marketing of NGLs is a highly competitive business that involves integrated oil and natural gas companies, mid-stream gathering and processing companies, trading houses, international liquid propane gas producers and refining and chemical companies. There is competition to source NGLs from plant operators for movement through pipeline networks and fractionation facilities as well as to supply large consumers such as multi-state propane, refining and chemical companies with their NGLs needs. Our three largest suppliers are our own plants, Union Pacific Resources and Pacific Gas & Electric. Our largest S-38 39 sales customers are Phillips, Dow Chemical and ExxonMobil, which accounted for 12%, 2% and 1%, respectively, of our total revenues in 1999. Our three principal competitors in the marketing of NGLs are Dynegy, Koch and Enterprise. In 1999, we marketed and traded an average of approximately 486,000 barrels per day, or approximately 19% of the available domestic supply, which includes gas plant production, refinery plant production and imports. TEPPCO On March 31, 2000, we obtained by transfer from Duke Energy, the general partner of TEPPCO, a publicly traded limited partnership. TEPPCO operates in two principal areas: - refined products and liquefied petroleum gases transportation; and - crude oil and NGLs transportation and marketing. TEPPCO is one of the largest pipeline common carriers of refined petroleum products and liquefied petroleum gases in the United States. Its operations in this line of business consist of: - interstate transportation, storage and terminaling of petroleum products; - short-haul shuttle transportation of liquefied petroleum gas at the Mont Belvieu, Texas complex; - sale of product inventory; - fractionation of NGLs; and - ancillary services. TEPPCO's refined products and liquefied petroleum gas pipeline system includes approximately 4,300 miles of pipeline which extend from southeast Texas through the central and midwestern United States to the northeastern United States. TEPPCO's refined products and liquefied petroleum gas pipeline system has storage capacity of 13 million barrels of refined petroleum products and 38 million barrels of liquefied petroleum gas. Through its crude oil and NGLs transportation and marketing business, TEPPCO gathers, stores, transports and markets crude oil, NGLs, lube oil and specialty chemicals, principally in Oklahoma, Texas and the Rocky Mountain region. TEPPCO's crude oil and NGLs assets include approximately 1,950 miles of crude oil pipeline and 1.7 million barrels of crude oil storage and approximately 425 miles of NGL pipeline with an aggregate capacity of 25,000 barrels per day. We believe that our ownership of the general partnership interest of TEPPCO improves our business position in the transportation sector of the midstream natural gas industry and provides us additional flexibility in pursuing our disciplined acquisition strategy by providing an alternative acquisition vehicle. It also provides us with an opportunity to sell appropriate assets currently held by our company to TEPPCO. The general partner of TEPPCO manages and directs TEPPCO under the TEPPCO partnership agreement and the partnership agreements of its operating partnerships. Under the partnership agreements, the general partner of TEPPCO is reimbursed for all direct and indirect expenses it incurs or payments it makes on behalf of TEPPCO. TEPPCO makes quarterly cash distributions of its available cash, which consists generally of all cash receipts less disbursements and cash reserves necessary for working capital, anticipated capital expenditures and contingencies, the amounts of which are determined by the general partner of TEPPCO. The partnership agreements provide for incentive distributions payable to the general partner of TEPPCO out of TEPPCO's available cash in the event quarterly distributions to its unitholders exceed certain specified targets. In general, subject to certain limitations, if a quarterly distribution exceeds a S-39 40 target of $.275 per limited partner unit, the general partner of TEPPCO will receive incentive distributions equal to: - 15% of that portion of the distribution per limited partner unit which exceeds the minimum quarterly distribution amount of $.275 but is not more than $.325, plus - 25% of that portion of the quarterly distribution per limited partner unit which exceeds $.325 but is not more than $.45, plus - 50% of that portion of the quarterly distribution per limited partner unit which exceeds $.45. At TEPPCO's 1999 per unit distribution level, the general partner: - receives approximately 14% of the cash distributed by TEPPCO to its partners, which consists of 12% from the incentive cash distribution and 2% from the general partner interest; and - under the incentive cash distribution provisions, receives 50% of any increase in TEPPCO's per unit cash distributions. During 1999, total cash distributions to the general partner of TEPPCO were $8.3 million. On July 21, 2000, TEPPCO acquired, for $318.5 million, Atlantic Richfield Company's ownership interests in a 500-mile crude oil pipeline that extends from a marine terminal at Freeport, Texas to Cushing, Oklahoma, a 416-mile crude oil pipeline that extends from Jal, New Mexico to Cushing, a 400-mile crude oil pipeline that extends from West Texas to Houston, crude oil terminal facilities in Midland, Texas, Cushing and the Houston area and receipt and delivery pipelines centered around Midland. NATURAL GAS SUPPLIERS We purchase substantially all of our raw natural gas from producers under varying term contracts. Typically, we take ownership of raw natural gas at the wellhead, settling payments with producers on terms set forth in the applicable contracts. These producers range in size from small independent owners and operators to large integrated oil companies, such as Phillips, our largest single supplier. No single producer accounted for more than 10% of our natural gas throughput in 1999. Each producer generally dedicates to us the raw natural gas produced from designated oil and natural gas leases for a specific term. The term will typically extend for three to seven years and in some cases for the life of the lease. We currently have over 15,000 active contracts with over 5,000 producers. We consider our relations with our producers to be good. For a description of the types of contracts we have entered into with our suppliers, see "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Overview -- Effects of Our Raw Natural Gas Supply Arrangements." COMPETITION We face strong competition in acquiring raw natural gas supplies. Our competitors in obtaining additional gas supplies and in gathering and processing raw natural gas include: - major integrated oil companies; - major interstate and intrastate pipelines or their affiliates; - other large raw natural gas gatherers that gather, process and market natural gas and/or NGLs; and - a relatively large number of smaller raw natural gas gatherers of varying financial resources and experience. Competition for raw natural gas supplies is concentrated in geographic regions based upon the location of gathering systems and natural gas processing plants. Although we are one of the largest gatherers and processors in most of the geographic regions in which we operate, most producers in these areas have S-40 41 alternate gathering and processing facilities available to them. In addition, producers have other alternatives, such as building their own gathering facilities or in some cases selling their raw natural gas supplies without processing. Competition for raw natural gas supplies in these regions is primarily based on: - the reputation, efficiency and reliability of the gatherer/processor, including the operating pressure of the gathering system; - the availability of gathering and transportation; - the pricing arrangement offered by the gatherer/processor; and - the ability of the gatherer/processor to obtain a satisfactory price for the producers' residue gas and extracted NGLs. In addition to competition in raw natural gas gathering and processing, there is vigorous competition in the marketing of residue gas. Competition for customers is based primarily upon the price of the delivered gas, the services offered by the seller, and the reliability of the seller in making deliveries. Residue gas also competes on a price basis with alternative fuels such as oil and coal, especially for customers that have the capability of using these alternative fuels and on the basis of local environmental considerations. Also, to foster competition in the natural gas industry, certain regulatory actions of FERC and some states have allowed buying and selling to occur at more points along transmission and distribution systems. Competition in the NGLs marketing area comes from other midstream NGLs marketing companies, international producers/traders, chemical companies and other asset owners. Along with numerous marketing competitors, we offer price risk management and other services. We believe it is important that we tailor our services to the end-use customer to remain competitive. REGULATION Transportation. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978, and the regulations promulgated thereunder by FERC. In the past, the federal government regulated the prices at which natural gas could be sold. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas. Congress could, however, reenact field natural gas price controls in the future, though we know of no current initiative to do so. As a gatherer, processor and marketer of raw natural gas, we depend on the natural gas transportation and storage services offered by various interstate and intrastate pipeline companies to enable the delivery and sale of our residue gas supplies. In accordance with methods required by FERC for allocating the system capacity of "open access" interstate pipelines, at times other system users can preempt the availability of interstate natural gas transportation and storage service necessary to enable us to make deliveries and sales of residue gas. Moreover, shippers and pipelines may negotiate the rates charged by pipelines for such services within certain allowed parameters. These rates will also periodically vary depending upon individual system usage and other factors. An inability to obtain transportation and storage services at competitive rates can hinder our processing and marketing operations and affect our sales margins. The intrastate pipelines that we own are subject to state regulation and, to the extent they provide interstate services under Section 311 of the Natural Gas Policy Act of 1978, also are subject to FERC regulation. We also own an interest in a natural gas gathering system and interstate transmission system located in offshore waters south of Louisiana and Alabama. The offshore gathering system is not a jurisdictional entity under the Natural Gas Act; the interstate offshore transmission system is regulated by FERC. S-41 42 Commencing in April 1992, FERC issued Order No. 636 and a series of related orders that require interstate pipelines to provide open-access transportation on a basis that is equal for all marketers of natural gas. FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. Order No. 636 applies to our activities in Dauphin Island Gathering Partners and how we conduct gathering, processing and marketing activities in the market place serviced by Dauphin Island Gathering Partners. The courts have largely affirmed the significant features of Order No. 636 and the numerous related orders pertaining to individual pipelines, although certain appeals remain pending and FERC continues to review and modify its regulations. For example, the FERC recently issued Order No. 637 which, among other things: - lifts the cost-based cap on pipeline transportation rates in the capacity release market until September 30, 2002 for short-term releases of pipeline capacity of less than one year; - permits pipelines to charge different maximum cost-based rates for peak and off-peak periods; - encourages, but does not mandate, auctions for pipeline capacity; - requires pipelines to implement imbalance management services; - restricts the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow orders; and - implements a number of new pipeline reporting requirements. Order No. 637 also requires the FERC to analyze whether the FERC should implement additional fundamental policy changes, including, among other things, whether to pursue performance-based ratemaking or other non-cost based ratemaking techniques and whether the FERC should mandate greater standardization in terms and conditions of service across the interstate pipeline grid. In addition, the FERC recently implemented new regulations governing the procedure for obtaining authorization to construct new pipeline facilities and has issued a policy statement, which it largely affirmed in a recent order on rehearing, establishing a presumption in favor of requiring owners of new pipeline facilities to charge rates based solely on the costs associated with such new pipeline facilities. We cannot predict what further action FERC will take on these matters. However, we do not believe that we will be affected by any action taken previously or in the future on these matters materially differently than other natural gas gatherers, processors and marketers with which we compete. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. The natural gas industry historically has been heavily regulated; therefore, there is no assurance that the less stringent and pro-competition regulatory approach recently pursued by FERC and Congress will continue. Gathering. The Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of FERC. Interstate natural gas transmission facilities, on the other hand, remain subject to FERC jurisdiction. FERC has historically distinguished between these two types of facilities on a fact-specific basis. We believe that our gathering facilities and operations meet the current tests that FERC uses to grant non-jurisdictional gathering facility status. However, there is no assurance that FERC will not modify such tests or that all of our facilities will remain classified as natural gas gathering facilities. Some states in which we own gathering facilities have adopted laws and regulations that require gatherers either to purchase without undue discrimination as to source or supplier or to take ratably without undue discrimination natural gas production that may be tendered to the gatherer for handling. For example, the states of Oklahoma and Kansas also have adopted complaint-based statutes that allow the Oklahoma Corporation Commission and the Kansas Corporation Commission, respectively, to remedy discriminatory rates for providing gathering service where the parties are unable to agree. In a similar way, the Railroad Commission of Texas sponsors a complaint procedure for resolving grievances about natural gas gathering access and rate discrimination. S-42 43 The FERC recently issued Order No. 639, requiring that virtually all non-proprietary pipeline transporters of natural gas on the outer-continental shelf report information on their affiliations, rates and conditions of service. Among FERC's purposes in issuing these rules was the desire to provide shippers on the outer-continental shelf with greater assurance of open-access services on pipelines located on the outer-continental shelf and non-discriminatory rates and conditions of service on these pipelines. The FERC exempted Natural Gas Act-regulated pipelines, like Dauphin Island Gathering Partners, from the new reporting requirements, reasoning that the information that these pipelines were already reporting was sufficient to monitor conformity with existing non-discrimination mandates. However, pipelines not regulated under the Natural Gas Act, like our gathering lines located on the outer-continental shelf, must comply with the new rules. This could increase our cost of regulatory compliance and place us at a disadvantage in comparison to companies that are not required to satisfy the reporting requirements. Order No. 639 may be altered on rehearing or on appeal, and it is not known at this time what effect these new rules, as they may be altered, will have on our business. We currently believe that Order No. 639 and the related reporting requirements will not have a material adverse effect on our existing business activities. Processing. The primary function of our natural gas processing plants is the extraction of NGLs and the conditioning of natural gas for marketing. FERC has traditionally maintained that a processing plant that primarily extracts NGLs is not a facility for transportation or sale of natural gas for resale in interstate commerce and therefore is not subject to its jurisdiction under the Natural Gas Act. We believe that our natural gas processing plants are primarily involved in removing NGLs and, therefore, are exempt from the jurisdiction of FERC. Transportation and Sales of Natural Gas Liquids. We have non-operating interests in two pipelines that transport NGLs in interstate commerce. The rates, terms and conditions of service on these pipelines are subject to regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that petroleum products (including NGLs) pipeline rates be just and reasonable and non-discriminatory. The FERC allows petroleum pipeline rates to be set on at least three bases, including historic cost, historic cost plus an index or market factors. Sales of Natural Gas Liquids. Our sales of NGLs are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such NGLs are dependent on liquids pipelines whose rates, terms and conditions or service are subject to the Interstate Commerce Act. Although certain regulations implemented by the FERC in recent years could result in an increase in the cost of transporting NGLs on certain petroleum products pipelines, we do not believe that these regulations affect us any differently than other marketers of NGLs with whom we compete. U.S. Department of Transportation. Some of our pipelines are subject to regulation by the U.S. Department of Transportation with respect to their design, installation, testing, construction, operation, replacement and management. Comparable regulations exist in some states where we do business. These regulations provide for safe pipeline operations and include potential fines and penalties for violations. Safety and Health. Certain federal statutes impose significant liability upon the owner or operator of natural gas pipeline facilities for failure to meet certain safety standards. The most significant of these is the Natural Gas Pipeline Safety Act, which regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities. In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whose purpose is to maintain the safety of workers, both generally and within the pipeline industry. We have an internal program of inspection designed to monitor and enforce compliance with pipeline and worker safety requirements. We believe we are in substantial compliance with the requirements of these laws, including general industry standards, recordkeeping requirements, and monitoring of occupational exposure to hazardous substances. Canadian Regulation. Our Canadian assets in the province of Alberta are regulated by the Alberta Energy and Utilities Board. Our West Doe natural gas gathering pipeline, which crosses the Alberta/ British Columbia border, falls under the jurisdiction of the National Energy Board. S-43 44 ENVIRONMENTAL MATTERS The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state, and local levels. These laws and regulations can restrict or prohibit our business activities that affect the environment in many ways, such as: - restricting the way we can release materials or waste products into the air, water, or soils; - limiting or prohibiting construction activities in sensitive areas such as wetlands or areas of endangered species habitat, or otherwise constraining how or when construction is conducted; - requiring remedial action to mitigate pollution from former operations, or requiring plans and activities to prevent pollution from ongoing operations; and - imposing substantial liabilities on us for pollution resulting from our operations, including, for example, potentially enjoining the operations of facilities if it were determined that they were not in compliance with permit terms. In most instances, the environmental laws and regulations affecting our operations relate to the potential release of substances or waste products into the air, water or soils, and include measures to control or prevent the release of substances or waste products to the environment. Costs of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulation and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions and federally authorized citizen suits. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or other waste products to the environment. The following is a discussion of certain environmental and safety concerns that relate to the midstream natural gas and NGLs industry. It is not intended to constitute a complete discussion of all applicable federal, state and local laws and regulations, or specific matters, to which we may be subject. Our operations are regulated by the Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations govern emissions into the air from our activities, for example in relation to our processing plants and our compressor stations, and also impose procedural requirements on how we conduct our operations. Due to the nature or our business, we have numerous permits related to air emissions issued by state governments or the United States Environmental Protection Agency ("EPA"). For example, we have a large number of federal Operating Permits, known as Title V permits, for our facilities that can impart specific emissions limitations as well as specific operational practices or administrative requirements with which we must comply. There are also other state and federal requirements that might relate to our operations, including the federal Prevention of Significant Deterioration permitting requirements for major sources of emissions, and specific New Source Performance Standards or Maximum Achievable Control Technology ("MACT") Standards issued by the EPA that apply specifically to our industry or activities. Our failure to comply with these requirements exposes us to civil enforcement actions from the state agencies and perhaps the EPA, including monetary penalties, injunctions, conditions or restrictions on operations, and, potentially, criminal enforcement actions or federally authorized citizen suits. On June 17, 1999, the EPA published in the Federal Register a final MACT standard under Section 112 of the Clean Air Act to limit emissions of Hazardous Air Pollutants ("HAPs") from oil and natural gas production as well as from natural gas transmission and storage facilities. The MACT standard requires that affected facilities reduce their emissions of HAPs by 95%, and this will affect our various large dehydration units and potentially some of our storage vessels. This new standard will require that we achieve this reduction by either process modifications or installing new emissions control technology. The S-44 45 MACT standard will affect us and our competitors in varying degrees. The rule allows most affected sources until at least June 2002 to comply with the requirements. While additional capital costs are likely to result from this rule or other potential air regulations, we believe that these changes will not have a material adverse effect on our business, financial position or results of operations. Our operations generate wastes, including some hazardous wastes, that are subject to the Resource Conservation and Recovery Act ("RCRA"), as amended and comparable state laws. However, RCRA currently exempts many natural gas gathering and processing plant wastes from being subject to hazardous waste requirements. Specifically, RCRA excludes from the definition of hazardous waste, wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy. Unrecovered petroleum product wastes, however, may still be regulated under RCRA as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated. Natural gas and NGLs transported in pipelines also have the potential to generate some hazardous wastes. Although we believe it is unlikely that the RCRA exemption will be repealed in the near future, repeal would increase costs for waste disposal and environmental remediation at our facilities. Past operations are identified from time to time as having used polychlorinated biphenyls ("PCBs"), for example, in plant air compressor systems, and when identified we are required to address or remediate such a system that might contain PCBs in compliance with the Toxic Substances Control Act, including any contamination that might be associated with a release from that system. Our operations could incur liability under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended ("CERCLA"), also known as "Superfund," and comparable state laws or other federal laws regardless of our fault, in connection with the disposal or other release of hazardous substances or wastes, including those arising out of historical operations conducted by our predecessors. If we were to incur liability under CERCLA, we could be subject to joint and several liability for the costs of cleaning up hazardous substances, for damages to natural resources and for the costs of certain health studies. We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although we used operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination, whether from prior owners or operators or other historic activities or spills) or to perform remedial plugging or pit closure operations to prevent future contamination, in some instances regardless of fault or the amount of waste we sent to the site. EPA Region VIII issued a RCRA administrative cleanup order in 1995 with respect to the operation of the Weld County Waste Disposal, Inc. site near Fort Lupton Colorado, and in 1997 one of our predecessors was identified along with other entities as a potentially responsible party for this site. We are not aware of administrative activity at this site in the last two years. In addition, we have various ongoing remedial matters related to historical operations similar to others in the industry, for the reasons generally described above. These are typically managed in conjunction with the relevant state or federal agencies to address specific conditions, and in some cases are the responsibility of other entities based upon contractual obligations related to the assets. In April 1999, we acquired the midstream natural gas gathering and processing assets of Union Pacific Resources located in several states, which include 18 natural gas plants and 365 gathering facility sites. We have entered into an agreement for pre-April 1999 soil and ground water conditions identified as part of this transaction to a third party environmental/insurance partnership for a one-time premium payment subject to certain deductibles. With respect to these identified environmental conditions, the environmental partner has assumed liability and S-45 46 management responsibility for environmental remediation, and the insurance partner is providing financial management, program oversight, remediation cost cap insurance coverage for a 30 year term, and pollution legal liability coverage for a 20 year term. While we could face liability in the event of default, we believe this innovative approach can promote pro-active site cleanup and closure, reduce internal resource needs for managing remediation, and may improve the marketability of assets based on transferability of this insurance coverage. Also, in August 1996, we acquired certain gas gathering and processing assets in three states from Mobil Corporation. Under the terms of the asset purchase agreement, Mobil has retained the liabilities and costs related to various pre-August 1996 environmental conditions that were identified with respect to those assets. Mobil has formulated or is in the process of developing plans to address certain of these conditions, which we will review and monitor as clean-up activities proceed. Our operations can result in discharges of pollutants to waters. The Federal Water Pollution Control Act of 1972, as amended ("FWPCA"), also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including NGLs or unpermitted wastes, into state waters or waters of the United States. The unpermitted discharge of pollutants such as from spill or leak incidents are prohibited. The FWPCA and regulations implemented thereunder also prohibit discharges of fill material and certain other activities in wetlands unless authorized by an appropriately issued permit. Any unexpected release of NGLs or condensates from our systems or facilities could result in significant remedial obligations as well as FWPCA-related fines or penalties. We make expenditures in connection with environmental matters as part of our normal operations and capital expenses. For each of 2000 and 2001, we estimate that our expensed and capital-related costs will be approximately $13 million. It should be noted, however, that stricter laws and regulations, new interpretations of existing laws and regulations, or new information or developments could significantly increase our compliance costs and remediation obligations. We are subject to inherent environmental and safety risks related to our handling of natural gas and NGL products and historical industry waste disposal practices. We cannot assure you that we will not incur material environmental costs and liabilities. We believe, based on our current knowledge, that we are generally in substantial compliance with all of our necessary and material permits, and that we are generally in substantial compliance with applicable material environmental and safety regulations. We also use contractual measures, such as the environmental/insurance partnership discussed above, where appropriate to mitigate environmental claims or losses but, in the event of a default, we could be exposed to these claims. Insurance provisions and internal reserves are also used or applied where warranted to help mitigate the effect from possible environmental costs and liabilities. Based on current information and taking into account protective mechanisms mentioned here, we do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, process, and transport natural gas and NGLs. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant new costs. Our natural gas gathering pipelines and processing plants in Alberta, Canada operate under permits from and are regulated by Alberta Environment. Our West Doe natural gas gathering pipeline, which crosses the Alberta/British Columbia border, is regulated by the National Energy Board in consultation with the Canadian Environmental Assessment Agency. EMPLOYEES As of June 30, 2000, we had approximately 2,550 employees. We are a party to two collective bargaining agreements which cover an aggregate of approximately 180 of our employees and are bound to negotiate in good faith toward collective bargaining agreements with two other collective bargaining units which cover an aggregate of approximately 80 employees. We believe our relations with our employees are good. S-46 47 DESCRIPTION OF THE NOTES The following description of the % notes and the % notes is only a summary and is not intended to be comprehensive. The description should be read together with the description of the general terms and provisions of Debt Securities provided under the caption "Description of Debt Securities" in the accompanying prospectus. We refer to the % notes and the % notes as the "Notes" in this section. GENERAL The % notes will be limited in principal amount to $ and the % notes will be limited in principal amount to $ , and each will be issued as a series of Debt Securities under the Indenture dated as of August , 2000 between us and The Chase Manhattan Bank, as Trustee. The entire principal amount of the % notes will mature and become due and payable, together with any accrued and unpaid interest, on August , . The entire principal amount of the % notes will mature and become due and payable, together with any accrued and unpaid interest, on August , . The Notes will not be subject to any sinking fund provision. INTEREST Each series of Notes will bear interest from August , 2000 at the annual rate for that series stated on the cover page of this prospectus supplement. We will pay interest semiannually on February and August of each year, beginning February , 2001, to each person in whose name the Notes are registered at the close of business on the fifteenth calendar day before the relevant interest payment date. The amount of interest payable will be computed on the basis of a 360-day year of twelve 30-day months. In the event that any date on which interest is payable is not a Business Day, we will pay that interest on the next Business Day without any interest or other payment due to the delay. OPTIONAL REDEMPTION We will have the right to redeem each series of the Notes, in whole or in part at any time, at a redemption price equal to the greater of (1) 100% of the principal amount of the Notes of such series to be redeemed and (2) the sum of the present values of the remaining scheduled payments of principal and interest on such series of Notes (exclusive of interest accrued to the redemption date) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate plus basis points, plus, in either case, accrued and unpaid interest on the principal amount being redeemed to such redemption date. "Comparable Treasury Issue" means the United States Treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term of the series of Notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such series of Notes. "Comparable Treasury Price" means with respect to any redemption date for a series of Notes (1) the average of the Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest such Reference Treasury Dealer Quotations, or (2) if the Trustee obtains fewer than two such Reference Treasury Dealer Quotations, the average of all such quotations. "Quotation Agent" means the Reference Treasury Dealers appointed by us. "Reference Treasury Dealer" means each of Merrill Lynch Government Securities Inc. and J.P. Morgan Securities Inc. and their respective successors; provided, however, that if any of the foregoing shall cease to be a primary U.S. Government securities dealer in New York City (a "Primary Treasury Dealer"), we will substitute therefor another Primary Treasury Dealer. S-47 48 "Reference Treasury Dealer Quotations" means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Trustee by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third Business Day preceding such redemption date. "Treasury Rate" means, with respect to any redemption date, (1) the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated "H.15 (519)" or any successor publication which is published weekly by the Board of Governors of the Federal Reserve System and which establishes yields on actively traded United States Treasury securities adjusted to constant maturity under the caption "Treasury Constant Maturities," for the maturity corresponding to the Comparable Treasury Issue (if no maturity is within three months before or after the maturity date of the series of Notes to be redeemed, yields for the two published maturities most closely corresponding to the Comparable Treasury Issue shall be determined, and the Treasury Rate shall be interpolated or extrapolated from such yields on a straight-line basis, rounding to the nearest month) or (2) if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per year equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date. The Treasury Rate will be calculated on the third Business Day preceding the redemption date. REDEMPTION PROCEDURES We will provide not less than 30 nor more than 60 days' notice mailed to each registered holder of the series of Notes to be redeemed. If the redemption notice is given and funds deposited as required, then interest will cease to accrue on and after the redemption date on the Notes or portions of such Notes called for redemption. In the event that any redemption date is not a Business Day, we will pay the redemption price on the next Business Day without any interest or other payment due to the delay. RANKING The Notes will be our direct, unsecured and senior obligations. The Notes of each series will rank equal in priority with the Notes of the other series and with all of our other unsecured and senior indebtedness and senior in right of payment to all of our existing and future subordinated debt. At June 30, 2000, we had outstanding approximately $2,585 million of unsecured and senior indebtedness. The Indenture contains no restrictions on the amount of additional indebtedness that we may issue under it. DENOMINATIONS The Notes will be issuable in denominations of $1,000 and integral multiples of $1,000. DEFEASANCE AND COVENANT DEFEASANCE The Notes will be subject to Defeasance and Covenant Defeasance as described in the Indenture. See "Description of Debt Securities -- Defeasance and Covenant Defeasance" in the accompanying prospectus. BOOK-ENTRY ONLY ISSUANCE -- THE DEPOSITORY TRUST COMPANY The Depository Trust Company ("DTC") will act as the initial securities depositary for the Notes of each series. The Notes of each series will be initially issued as fully registered securities registered in the name of Cede & Co., DTC's nominee. One or more fully registered global certificates will be issued, representing the total principal amount of the Notes of each series, and will be deposited with the Trustee as custodian for DTC. S-48 49 DTC is a limited-purpose trust company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code, and a "clearing agency" registered pursuant to the provisions of Section 17A of the Securities Exchange Act of 1934, as amended. DTC holds securities that its participants ("participants") deposit with DTC. DTC also facilitates the settlement among participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in participants' accounts, thereby eliminating the need for physical movement of securities certificates. Direct participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations ("direct participants"). DTC is owned by a number of its direct participants and by the New York Stock Exchange, Inc., the American Stock Exchange, Inc., and the National Association of Securities Dealers, Inc. Access to the DTC system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a direct participant, either directly or indirectly ("indirect participants"). The rules applicable to DTC and its participants are on file with the Securities and Exchange Commission. Purchases of Notes within the DTC system must be made by or through direct participants, which will receive a credit for the Notes on DTC's records. The ownership interest of each actual purchaser of Notes ("beneficial owner") is in turn to be recorded on the direct and indirect participants' records. Beneficial owners will not receive written confirmation from DTC of their purchases, but beneficial owners are expected to receive written confirmations providing details of the transactions, as well as periodic statements of their holdings, from the direct or indirect participants through which the beneficial owners entered into the transaction. Transfers of ownership interests in the Notes are to be accomplished by entries made on the books of participants acting on behalf of beneficial owners. Beneficial owners will not receive certificates representing their ownership interests in the Notes, except in the event that use of the book-entry system for the Notes is discontinued. To facilitate subsequent transfers, all Notes deposited by participants with DTC are registered in the name of DTC's partnership nominee, Cede & Co. The deposit of Notes with DTC and their registration in the name of Cede & Co. effect no change in beneficial ownership. DTC has no knowledge of the actual beneficial owners of the Notes. DTC's records reflect only the identity of the direct participants to whose accounts such Notes are credited, which may or may not be the beneficial owners. The participants will remain responsible for keeping account of their holdings on behalf of their customers. Conveyance of notices and other communications by DTC to direct participants, by direct participants to indirect participants, and by direct participants and indirect participants to beneficial owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time. Redemption notices will be sent to DTC. If less than all of the Notes are being redeemed, DTC will reduce the amount of interest of each direct participant in the Notes in accordance with its procedures. Neither DTC nor Cede & Co. will consent or vote with respect to Notes. Under its usual procedures, DTC would mail an Omnibus Proxy to us as soon as possible after the record date. The Omnibus Proxy assigns Cede & Co.'s consenting or voting rights to those direct participants to whose account Notes are credited on the record date (identified in a listing attached to the Omnibus Proxy). Payments on the Notes will be made to Cede & Co., as nominee of DTC. DTC's practice is to credit direct participants' accounts, upon DTC's receipt of funds and corresponding detailed information, on the relevant payment date in accordance with their respective holdings shown on DTC's records. Payments by participants to beneficial owners will be governed by standing instructions and customary practices, as is the case with securities held for the account of customers in bearer form or registered in "street name," and will be the responsibility of such participants and not of DTC or us, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment to Cede & Co. is the responsibility of our company or of the payment agent, disbursement of such payments to direct S-49 50 participants is the responsibility of Cede & Co. and disbursement of such payments to the beneficial owners is the responsibility of direct and indirect participants. Except as provided herein, a beneficial owner of an interest in a global Note will not be entitled to receive physical delivery of Notes. Accordingly, each beneficial owner must rely on the procedures of DTC to exercise any rights under the Notes. The laws of some jurisdictions require that certain purchasers of securities take physical delivery of securities in definitive form. Such laws may impair the ability to transfer beneficial interests in a global Note. DTC may discontinue providing its services as securities depositary with respect to either series of Notes at any time by giving reasonable notice to us. Under such circumstances, in the event that a successor securities depositary is not obtained within 90 days, certificates representing such series of Notes will be printed and delivered to the holders of record. Additionally, we may decide to discontinue use of the system of book-entry transfers through DTC (or a successor securities depositary) with respect to either series of Notes. In that event, certificates for such series of Notes will be printed and delivered to the holders of record. The information in this section concerning DTC and DTC's book-entry system has been obtained from sources that we believe to be reliable, but neither we nor any Underwriter takes any responsibility for its accuracy. We have no responsibility for the performance by DTC or its participants of their respective obligations, including obligations that they have under the rules and procedures that govern their operations. UNDERWRITING Subject to the terms and conditions of an underwriting agreement dated August , 2000, between us and the several underwriters named below, for whom Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities Inc. are acting as representatives, we have agreed to sell to each of the underwriters named below and each of the underwriters has severally agreed to purchase from us the respective principal amount of each series of notes set forth opposite its name below: PRINCIPAL PRINCIPAL AMOUNT AMOUNT OF OF UNDERWRITER % NOTES % NOTES - ------------------------------------------------------------ --------- --------- Merrill Lynch, Pierce, Fenner & Smith Incorporated................................... J.P. Morgan Securities Inc.................................. Banc of America Securities LLC.............................. Chase Securities Inc........................................ Lehman Brothers Inc......................................... Morgan Stanley & Co. Incorporated........................... -------- -------- Total............................................. $ ======== ======== In the underwriting agreement, the underwriters have agreed, subject to certain conditions, to purchase all of the notes if any of the notes are purchased. The underwriters propose initially to offer each series of notes to the public at the initial public offering price set forth on the cover page of this prospectus supplement and to certain dealers at that price less a concession not in excess of % of the principal amount of the % notes and % of the principal amount of the % notes. The underwriters may allow, and those dealers may reallow, a discount not in excess of % of the principal amount of the % notes and % of the principal amount of the % notes to certain other dealers. After the initial public offering, the public offering price, selling concession and discount with respect to each series of notes may be changed. S-50 51 The notes will not be listed on any securities exchange, and there can be no assurance that there will be a secondary market for the notes. From time to time the underwriters may make a market in the notes. However, at this time no determination has been made as to whether or not the underwriters will make a market in the notes. The underwriters may purchase and sell each series of notes in the open market in connection with the offering. Those transactions may include over-allotment and stabilizing transactions and purchases to cover syndicate short positions created in connection with the offering. Stabilizing transactions consist of certain bids or purchases for the purpose of preventing or retarding a decline in the market price of each series of notes. Syndicate short positions involve the sale by the underwriters of a greater principal amount of notes than they are required to purchase from us in the offering. The underwriters also may impose a penalty bid, by which selling concessions allowed to syndicate members or other broker dealers with respect to the securities sold in the offering for their account may be reclaimed by the syndicate if those notes are repurchased by the syndicate in stabilizing or covering transactions. These activities may stabilize, maintain or otherwise affect the market price of each series of notes, which may be higher than the price that might otherwise prevail in the open market. These activities, if commenced, may be discontinued at any time. We estimate that our expenses in connection with this offering, excluding underwriting discounts and commissions, will be approximately $5.0 million. The underwriters have agreed to reimburse us for certain expenses of the offering. We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933 or to contribute to payments the underwriters may be required to make in respect of such liabilities. Certain of the underwriters and their affiliates engage in transactions with, and, from time to time, have performed services for, us or certain of our affiliates in the ordinary course of business and may do so in the future. VALIDITY OF THE NOTES The validity of the notes will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas and for the underwriters by Sullivan & Cromwell, New York, New York. S-51 52 INDEX TO FINANCIAL STATEMENTS PAGE ---- PRO FORMA DUKE ENERGY FIELD SERVICES, LLC (THE "COMPANY") Unaudited Pro Forma Balance Sheet as of June 30, 2000..... F-3 Notes to the Unaudited Pro Forma Balance Sheet............ F-4 Unaudited Pro Forma Income Statement for the Year Ended December 31, 1999...................................... F-5 Unaudited Pro Forma Income Statement for the Six Months Ended June 30, 2000.................................... F-6 Notes to the Unaudited Pro Forma Income Statements........ F-7 HISTORICAL DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES (THE "PREDECESSOR COMPANIES") Independent Auditors' Report.............................. F-9 Combined Balance Sheets at December 31, 1998 and 1999..... F-10 Combined Statements of Income for the Years Ended December 31, 1997, 1998 and 1999................................ F-11 Combined Statements of Equity for the Years Ended December 31, 1997, 1998 and 1999................................ F-12 Combined Statements of Cash Flows for the Years Ended December 31, 1997, 1998 and 1999....................... F-13 Notes to Combined Financial Statements.................... F-14 Consolidated Balance Sheets as of December 31, 1999 and June 30, 2000 (Unaudited).............................. F-29 Unaudited Consolidated Statements of Income for the Six Months Ended June 30, 1999 and 2000.................... F-30 Unaudited Consolidated Statements of Equity for the Six Months Ended June 30, 2000............................. F-31 Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 1999 and 2000................ F-32 Notes to the Unaudited Consolidated Financial Statements............................................. F-33 PHILLIPS GAS COMPANY ("GPM") Report of Independent Auditors............................ F-40 Consolidated Balance Sheets at December 31, 1998 and 1999................................................... F-41 Consolidated Statements of Income for the Years Ended December 31, 1997, 1998 and 1999....................... F-42 Consolidated Statements of Cash Flows for the Years Ended December 31, 1997, 1998 and 1999............................................... F-43 Consolidated Statements of Changes in Stockholders' Equity/(Deficit) for the Years Ended December 31, 1997, 1998 and 1999.......................................... F-44 Notes to Financial Statements............................. F-45 Unaudited Consolidated Statements of Income for the Three Months Ended March 31, 1999 and 2000................... F-54 Unaudited Consolidated Statements of Cash Flows for the Three Months Ended March 31, 1999 and 2000............. F-55 Notes to Financial Statements............................. F-56 UP FUELS DIVISION OF UNION PACIFIC RESOURCES GROUP INC. ("UP FUELS") Report of Independent Public Accountants.................. F-58 Independent Auditors Report............................... F-59 Combined Statements of Income for the Years Ended December 31, 1997 and 1998 and the Quarter Ended March 31, 1999................................................... F-60 Combined Statements of Cash Flows for the Years Ended December 31, 1997 and 1998 and the Quarter Ended March 31, 1999............................................... F-61 Notes to Combined Financial Statements.................... F-62 F-1 53 UNAUDITED PRO FORMA FINANCIAL STATEMENTS The following unaudited pro forma financial statements (the "Unaudited Pro Forma Financial Statements") of Duke Energy Field Services, LLC were derived by the application of pro forma adjustments to historical combined and consolidated financial statements included elsewhere in this prospectus supplement. On March 31, 2000, the Duke Energy and Phillips midstream natural gas businesses were contributed to Duke Energy Field Services, LLC. Such contribution included the general partner of TEPPCO as well as certain midstream natural gas assets of Conoco, Inc. and Mitchell Energy & Development Corp. which were acquired immediately prior to the contribution. In connection with the contributions, distributions of $1,219.8 million and $1,524.5 million were made to Phillips and Duke Energy, respectively. The distributions were funded through the issuance of commercial paper. The contributions, issuance of commercial paper and distributions have been reflected in the June 30, 2000 historical balance sheet of Duke Energy Field Services, LLC. The Unaudited Pro Forma Balance Sheet gives effect to the subsequent refinancing of a portion of the commercial paper through the issuance of the $1,500 million of notes pursuant to this prospectus supplement (the "Notes Offering") and the issuance of an aggregate of $300 million of preferred membership interests in Duke Energy Field Services, LLC to affiliates of Duke Energy and Phillips, which occurred in August 2000 (the "Preferred Financing") as if each had occurred on June 30, 2000. All of the events above are referred to collectively as the "Transactions." The Unaudited Pro Forma Income Statements give effect to i) the Transactions and ii) acquisition of the midstream natural gas business of Union Pacific Resources (the "UP Fuels Acquisition"), which occurred March 31, 1999, as if such transactions were consummated as of January 1, 1999. The adjustments are described in the accompanying Notes to the Unaudited Pro Forma Balance Sheet and the Notes to the Unaudited Pro Forma Income Statements. The Unaudited Pro Forma Financial Statements should not be considered indicative of the actual results that would have been achieved had the Transactions or the UP Fuels Acquisition been consummated on the dates or for the period indicated and do not purport to indicate balances or results of operations as of any future date or for any future period. The Unaudited Pro Forma Financial Statements should be read in conjunction with the historical combined and consolidated financial statements of the Predecessor Company, UP Fuels, and GPM and the notes thereto included elsewhere in the prospectus supplement. F-2 54 DUKE ENERGY FIELD SERVICES, LLC UNAUDITED PRO FORMA BALANCE SHEET AS OF JUNE 30, 2000 (IN THOUSANDS) COMPANY HISTORICAL ADJUSTMENTS(1) PRO FORMA ----------- -------------- ---------- ASSETS CURRENT ASSETS: Cash and cash equivalents....................... $ 2,593 $ -- $ 2,593 Accounts receivable: Customers, net............................... 722,451 -- 722,451 Affiliates................................... 157,606 -- 157,606 Other........................................ 41,448 -- 41,448 Inventories..................................... 52,566 -- 52,566 Notes receivable................................ 6,502 -- 6,502 Other........................................... 3,111 -- 3,111 ---------- ----------- ---------- Total current assets.................... 986,277 -- 986,277 PROPERTY, PLANT AND EQUIPMENT, NET................ 4,441,160 -- 4,441,160 INVESTMENT IN AFFILIATES.......................... 276,443 -- 276,443 INTANGIBLE ASSETS: Natural gas liquids sales contracts, net........ 101,970 -- 101,970 Goodwill, net................................... 84,735 84,735 OTHER NONCURRENT ASSETS........................... 85,202 14,375(1) 98,677 (900)(2) ---------- ----------- ---------- TOTAL ASSETS............................ $5,975,787 $ 13,475 $5,989,262 ========== =========== ========== LIABILITIES AND EQUITY CURRENT LIABILITIES: Accounts payable: Trade........................................ $ 790,865 $ -- $ 790,865 Affiliates................................... 68,423 -- 68,423 Other........................................ 40,599 -- 40,599 Accrued taxes other than income................. 17,693 -- 17,693 Advances, net................................... 80,879 -- 80,879 Short-term debt................................. 2,585,290 (1,485,625)(3) (300,000)(4) 799,665 Other........................................... 31,904 -- 31,904 ---------- ----------- ---------- Total current liabilities............... 3,615,653 (1,785,625) 1,830,028 LONG TERM DEBT.................................... -- 1,500,000(3) 1,500,000 OTHER LONG TERM LIABILITIES....................... 38,923 38,923 EQUITY............................................ 2,321,211 300,000(4) (900)(2) 2,620,311 ---------- ----------- ---------- TOTAL LIABILITIES AND EQUITY...................... $5,975,787 $ 13,475 $5,989,262 ========== =========== ========== See Notes to the Unaudited Pro Forma Balance Sheet. F-3 55 DUKE ENERGY FIELD SERVICES, LLC NOTES TO THE UNAUDITED PRO FORMA BALANCE SHEET AS OF JUNE 30, 2000 (IN THOUSANDS) In December 1999, Duke Energy Field Services, LLC (Field Services LLC or the Company) was formed to facilitate the combination of the midstream natural gas businesses of Duke Energy and Phillips Petroleum Company (the "Combination"). The Combination occurred on March 31, 2000. As part of the Combination, distributions of $1,524,519 and $1,219,800 to Duke Energy and Phillips, respectively, were paid. In addition to contributing its midstream natural gas business, Duke Energy contributed the general partner of TEPPCO Partners, L.P. a publicly traded limited partnership ("TEPPCO General Partner") and the mid-continent midstream natural gas assets of Conoco, Inc. and Mitchell Energy & Development Corp. acquired immediately prior to the Combination. On April 3, 2000 the Company borrowed $2,790,900 in commercial paper to fund the distributions and fund working capital. The Combination was accounted for as a purchase business combination in accordance with Accounting Principles Board Opinion (APB) No. 16 "Accounting for Business Combinations." The Predecessor Company was the acquiror of Phillips' midstream natural gas business ("GPM") in the Combination. The following Notes to the Unaudited Pro Forma Balance Sheet describe the adjustments to June 30, 2000 historical balances to give effect to the Notes Offering, the Preferred Financing and related transactions. 1. The pro forma financial data have been derived by the application of pro forma adjustments to the historical financial statements of the Company for the period noted. The sources and uses of funds are as follows: TOTAL ---------- Sources of funds: Proceeds from the Preferred Financing..................... $ 300,000 Proceeds from the Notes Offering.......................... 1,500,000 ---------- Total sources..................................... $1,800,000 ---------- Uses of funds: Paydown of short-term debt (commercial paper)............. $1,785,625 Underwriter and other transaction fees.................... 14,375 ---------- Total uses........................................ $1,800,000 ---------- Net adjustment to cash.................................... $ -- ========== 2. Reflects the write-off of a portion of the fees associated with the revolving credit facility, which will be reduced from $2,800,000 to $1,000,000 upon pay-down of short-term debt (commercial paper) with the proceeds of the Preferred Financing and the Notes Offering. 3. To record the Notes Offering and application of the net proceeds of $1,485,625 to reduce short-term debt. The Notes Offering includes notes with two separate maturities with varying terms and assumes a weighted average interest rate of 8%. 4. To record the issuance of the preferred membership interests in our Company to affiliates of Duke Energy and Phillips in the Preferred Financing and application of the proceeds to reduce short-term debt. F-4 56 DUKE ENERGY FIELD SERVICES, LLC UNAUDITED PRO FORMA INCOME STATEMENT FOR THE YEAR ENDED DECEMBER 31, 1999 (IN THOUSANDS) PREDECESSOR CONOCO/ COMPANY UP FUELS GPM MITCHELL TEPPCO GP HISTORICAL ACQUISITION(1) HISTORICAL ACQUISITION(2) CONTRIBUTION(3) ----------- -------------- ---------- -------------- --------------- OPERATING REVENUES Sales of natural gas and petroleum products........ $3,310,260 $228,600 $1,501,178 $228,889 $ Transportation, storage and processing............. 148,050 69,324 88,279 -- -- ---------- -------- ---------- -------- ------ Total operating revenues..................... 3,458,310 297,924 1,589,457 228,889 -- COSTS AND EXPENSES Natural gas and petroleum products................. 2,965,297 252,880 1,148,910 187,689 -- Operating and maintenance.......................... 181,392 22,478 176,864 12,400 -- Depreciation and amortization...................... 130,788 15,125 80,458 6,200 -- General and administrative......................... 73,685 6,965 15,560 -- -- Net (gain) loss on sale of assets.................. 2,377 (907) -- -- ---------- -------- ---------- -------- ------ Total costs and expenses..................... 3,353,539 297,448 1,420,885 206,289 -- ---------- -------- ---------- -------- ------ OPERATING INCOME.................................... 104,771 476 168,572 22,600 -- EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES..... 22,502 4,821 1,048 (8,994) 9,300 ---------- -------- ---------- -------- ------ EARNINGS BEFORE INTEREST AND TAXES.............................................. 127,273 5,297 169,620 13,606 9,300 INTEREST EXPENSE.................................... 52,915 35,643 -- -- ---------- -------- ---------- -------- ------ EARNINGS BEFORE INCOME TAXES........................ 74,358 5,297 133,977 13,606 9,300 INCOME TAX EXPENSE.................................. 31,029 1,900 52,244 5,170 3,534 ---------- -------- ---------- -------- ------ NET INCOME FROM CONTINUING OPERATIONS............... $ 43,329 $ 3,397 $ 81,733 $ 8,436 $5,766 ========== ======== ========== ======== ====== ADJUSTMENTS(4) PRO FORMA -------------- ---------- OPERATING REVENUES Sales of natural gas and petroleum products........ $ $5,268,927 Transportation, storage and processing............. -- 305,653 --------- ---------- Total operating revenues..................... -- 5,574,580 COSTS AND EXPENSES Natural gas and petroleum products................. -- 4,554,776 Operating and maintenance.......................... -- 393,134 Depreciation and amortization...................... 11,298(5) 243,869 General and administrative......................... -- 96,210 Net (gain) loss on sale of assets.................. -- 1,470 --------- ---------- Total costs and expenses..................... 11,298 5,289,459 --------- ---------- OPERATING INCOME.................................... (11,298) 285,121 EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES..... (1,339)(6) 27,338 --------- ---------- EARNINGS BEFORE INTEREST AND TAXES.............................................. (12,637) 312,459 INTEREST EXPENSE.................................... 95,282(7) 183,840 --------- ---------- EARNINGS BEFORE INCOME TAXES........................ (107,919) 128,619 INCOME TAX EXPENSE.................................. (91,277)(8) 2,600 --------- ---------- NET INCOME FROM CONTINUING OPERATIONS............... $ (16,642) $ 126,019 ========= ========== See Notes to the Unaudited Pro Forma Income Statements. F-5 57 DUKE ENERGY FIELD SERVICES, LLC UNAUDITED PRO FORMA INCOME STATEMENT FOR THE SIX MONTHS ENDED JUNE 30, 2000 (IN THOUSANDS) PREDECESSOR GPM CONOCO/MITCHELL TEPPCO GP COMPANY HISTORICAL ACQUISITION(2) CONTRIBUTION(3) ADJUSTMENTS(4) PRO FORMA ----------- ---------- --------------- --------------- -------------- ---------- OPERATING REVENUES Sales of natural gas and petroleum products......................... $3,542,823 $532,762 $57,222 $ -- -- $4,132,807 Transportation, storage and processing....................... 80,748 9,603 -- -- -- 90,351 ---------- -------- ------- ------ --------- ---------- Total operating revenues..... 3,623,571 542,365 57,222 -- -- 4,223,158 COSTS AND EXPENSES Natural gas and petroleum products......................... 3,115,037 377,659 46,922 -- -- 3,539,618 Operating and maintenance.......... 140,354 47,285 3,100 -- -- 190,739 Depreciation and amortization...... 105,359 20,700 1,550 -- 2,239(5) 129,848 General and administrative......... 69,976 4,251 -- -- -- 74,227 Net (gain) loss on sale of assets........................... 337 (88) -- -- -- 249 ---------- -------- ------- ------ --------- ---------- Total costs and expenses..... 3,431,063 449,807 51,572 -- 2,239 3,934,681 ---------- -------- ------- ------ --------- ---------- OPERATING INCOME.................... 192,508 92,558 5,650 -- (2,239) 288,477 EQUITY EARNINGS (LOSS) OF UNCONSOLIDATED AFFILIATES.......... 14,707 (250) (895) 4,700 (346)(6) 17,916 ---------- -------- ------- ------ --------- ---------- EARNINGS BEFORE INTEREST AND TAXES.............................. 207,215 92,308 4,755 4,700 (2,585) 306,393 INTEREST EXPENSE.................... 59,851 17,865 -- -- 13,754(7) 91,470 ---------- -------- ------- ------ --------- ---------- EARNINGS BEFORE INCOME TAXES........ 147,364 74,443 4,755 4,700 (16,339) 214,923 INCOME TAX EXPENSE (BENEFIT)........ (306,765) 29,110 1,807 1,786 278,362(8) 4,300 ---------- -------- ------- ------ --------- ---------- NET INCOME FROM CONTINUING OPERATIONS......................... $ 454,129 $ 45,333 $ 2,948 $2,914 (294,701) $ 210,623 ========== ======== ======= ====== ========= ========== See Notes to the Unaudited Pro Forma Income Statements. F-6 58 DUKE ENERGY FIELD SERVICES, LLC NOTES TO UNAUDITED PRO FORMA INCOME STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 1999 AND THE SIX MONTHS ENDED JUNE 30, 2000 (IN THOUSANDS) The Company's pro forma financial data have been derived by the application of pro forma adjustments to the historical financial statements of the Predecessor Company and other contributed businesses for the period noted. See Note (1) to the Unaudited Pro Forma Balance Sheet. 1. Reflects the historical operating results of UP Fuels for the three month period ended March 31, 1999, the date the UP Fuels Acquisition was consummated by the Predecessor Company. 2. Reflects the results of operations associated with the acquisition of the Conoco and Mitchell businesses, net of the earnings from the Ferguson/Burleson joint venture interest exchanged as part of the consideration for the Conoco and Mitchell businesses. 3. Reflects the equity earnings of TEPPCO General Partnership interest transferred from Duke Energy. 4. The pro forma adjustments exclude non-recurring expenses directly related to the Transactions which the Company anticipates will be reflected in the income statement for the period including the Transactions. 5. The excess purchase cost over the book value of net GPM assets acquired in the Combination has not yet been fully allocated to individual assets and liabilities acquired. However, the Company believes a portion will be allocated to property, plant and equipment and identifiable intangibles, which will be amortized over 20 years. Given its preliminary estimate of the allocation of the purchase cost to net assets acquired, management has estimated a composite life of 20 years. The adjustment to depreciation and amortization was calculated as follows: PERIOD ENDED ------------------------- DECEMBER 31, JUNE 30, 1999 2000 ------------ ---------- Net book value of GPM property at January 1, 1999......... $ 943,302 $ 943,302 Excess purchase price over net assets acquired in Combination Allocated to property and equipment......... 891,808 891,808 ---------- ---------- Subtotal................................................ 1,835,110 1,835,110 Composite life -- 20 years................................ 20 20 Depreciation and amortization calculated.................. 91,756 22,939 Less: GPM historical depreciation and amortization........ (80,458) (20,700) ---------- ---------- Net adjustment............................................ $ 11,298 $ 2,239 ========== ========== 6. Reflects elimination of the equity earnings associated with the Predecessor Company's investment in Westana, which was sold in February 2000 in connection with the Combination. F-7 59 DUKE ENERGY FIELD SERVICES, LLC NOTES TO UNAUDITED PRO FORMA INCOME STATEMENTS--CONTINUED FOR THE YEAR ENDED DECEMBER 31, 1999 AND THE SIX MONTHS ENDED JUNE 30, 2000 (IN THOUSANDS) 7. The pro forma adjustment to interest expense, net is as follows: PERIOD ENDED ------------------------ DECEMBER 31, JUNE 30, 1999 2000 ------------ --------- Estimated interest at a weighted average rate of 8%......... $ 206,823 $ 103,412 Amortization of deferred financing costs over estimated weighted average life of 7.5 years........................ 1,917 958 --------- --------- Subtotal.................................................. 208,740 104,370 Less: historical interest expense........................... (88,558) (77,716) --------- --------- Incremental interest expense before the issuance of preferred membership interests............................ 120,182 26,654 Short-term debt paid down with proceeds of the issuance of preferred membership interests............................ (300,000) (300,000) Estimated weighted average rate............................. 8% 8% --------- --------- Subtotal for the year and six months...................... (24,000) (12,000) Deferred Fees written off as a result of paydown of short-term debt for the one year and six months, respectively.............................................. (900) (900) Reduction of interest expense resulting from pay-down of short-term debt........................................... (24,900) (12,900) --------- --------- Net adjustment.............................................. $ 95,282 $ 13,754 ========= ========= A .125% increase or decrease in the assumed weighted average interest rate would change pro forma interest expense and net income by $2,875 after paydown with the proceeds from issuance of the preferred membership interests in the Preferred Financing on an annual basis. 8. Upon the conversion to a pass-through entity for income tax purposes (LLC) on March 31, 2000, substantially all income taxes were eliminated. F-8 60 INDEPENDENT AUDITORS' REPORT Duke Energy Field Services, LLC and Affiliates We have audited the accompanying combined balance sheets of Duke Energy Field Services, LLC and Affiliates ("the Predecessor Companies") as of December 31, 1998 and 1999, and the related combined statements of income and equity and cash flows for each of the three years in the period ended December 31, 1999. The Predecessor Companies are under common ownership and common management. These financial statements are the responsibility of the Predecessor Companies' management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the combined financial position of the Predecessor Companies as of December 31, 1998 and 1999, and the combined results of their operations and their combined cash flows for each of the three years in the period ended December 31, 1999 in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP February 18, 2000 Denver, Colorado F-9 61 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES COMBINED BALANCE SHEETS AS OF DECEMBER 31, 1998 AND 1999 (IN THOUSANDS) 1998 1999 ---------- ---------- ASSETS CURRENT ASSETS: Cash and cash equivalents................................. $ 168 $ 792 Accounts receivable: Customers (net of allowance for doubtful accounts, 1998, $749 and 1999, $6,743).......................... 155,143 370,139 Affiliates............................................. 57,725 63,927 Other.................................................. 27,246 30,067 Inventories............................................... 23,713 38,701 Notes receivable.......................................... 5,266 13,050 Other..................................................... 531 1,580 ---------- ---------- Total current assets.............................. 269,792 518,256 PROPERTY, PLANT AND EQUIPMENT: Cost...................................................... 1,763,594 3,005,510 Accumulated depreciation and amortization................. (480,296) (596,125) ---------- ---------- Net property, plant, and equipment................ 1,283,298 2,409,385 INVESTMENTS IN AFFILIATES................................... 187,938 343,835 INTANGIBLE ASSETS: Natural gas liquids sales contracts, net.................. 102,382 Goodwill, net............................................. 15,299 85,846 OTHER NONCURRENT ASSETS..................................... 14,511 12,131 ---------- ---------- TOTAL ASSETS................................................ $1,770,838 $3,471,835 ========== ========== LIABILITIES AND EQUITY CURRENT LIABILITIES: Accounts payable: Trade.................................................. $ 200,864 $ 353,977 Affiliates............................................. 10,762 62,370 Other.................................................. 5,556 33,858 Accrued taxes other than income........................... 14,194 15,653 Advances, net -- parents.................................. 334,057 1,579,475 Notes payable -- affiliates............................... 540,000 588,880 Other..................................................... 8,976 6,372 ---------- ---------- Total current liabilities......................... 1,114,409 2,640,585 DEFERRED INCOME TAXES....................................... 222,007 308,308 NOTE PAYABLE TO PARENT...................................... 101,600 101,600 OTHER LONG TERM LIABILITIES................................. 34,871 COMMITMENTS AND CONTINGENT LIABILITIES EQUITY: Common stock.............................................. 3 1 Paid-in capital........................................... 202,523 213,091 Retained earnings......................................... 130,296 173,091 Other comprehensive income................................ 288 ---------- ---------- Total equity...................................... 332,822 386,471 ---------- ---------- TOTAL LIABILITIES AND EQUITY................................ $1,770,838 $3,471,835 ========== ========== See Notes to the Combined Financial Statements. F-10 62 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES COMBINED STATEMENTS OF INCOME YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999 (IN THOUSANDS) 1997 1998 1999 ---------- ---------- ---------- OPERATING REVENUES: Sales of natural gas and petroleum products............ $1,700,029 $1,469,133 $3,310,260 Transportation and storage of natural gas.............. 41,896 50,097 76,604 Other.................................................. 59,907 65,090 71,446 ---------- ---------- ---------- Total operating revenues....................... 1,801,832 1,584,320 3,458,310 ---------- ---------- ---------- COSTS AND EXPENSES: Natural gas and petroleum products..................... 1,468,089 1,338,129 2,965,297 Operating and maintenance.............................. 104,308 113,556 181,392 Depreciation and amortization.......................... 67,701 75,573 130,788 General and administrative............................. 36,023 44,946 73,685 Net (gain) loss on sale of assets...................... (236) (33,759) 2,377 ---------- ---------- ---------- Total costs and expenses....................... 1,675,885 1,538,445 3,353,539 ---------- ---------- ---------- OPERATING INCOME......................................... 125,947 45,875 104,771 EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES.......... 9,784 11,845 22,502 ---------- ---------- ---------- EARNINGS BEFORE INTEREST AND TAXES....................... 135,731 57,720 127,273 INTEREST EXPENSE......................................... 51,113 52,403 52,915 ---------- ---------- ---------- INCOME BEFORE INCOME TAXES............................... 84,618 5,317 74,358 INCOME TAXES............................................. 33,380 3,289 31,029 ---------- ---------- ---------- NET INCOME............................................... $ 51,238 $ 2,028 $ 43,329 ========== ========== ========== See Notes to the Combined Financial Statements. F-11 63 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES COMBINED STATEMENTS OF EQUITY YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999 (IN THOUSANDS) ADDITIONAL OTHER COMMON PAID-IN RETAINED COMPREHENSIVE STOCK CAPITAL EARNINGS INCOME TOTAL ------ ---------- -------- ------------- -------- BALANCE, DECEMBER 31, 1996....... $ 3 $200,326 $77,030 $277,359 Contributions.................... Net income....................... 51,238 51,238 --- -------- -------- ---- -------- BALANCE, DECEMBER 31, 1997....... 3 200,326 128,268 328,597 Contributions.................... 2,197 2,197 Net income....................... 2,028 2,028 --- -------- -------- ---- -------- BALANCE, DECEMBER 31, 1998....... 3 202,523 130,296 332,822 Contributions.................... 10,568 10,568 Net income....................... 43,329 43,329 Other............................ (2) (534) $288 (248) --- -------- -------- ---- -------- BALANCE, DECEMBER 31, 1999....... $ 1 $213,091 $173,091 $288 $386,471 === ======== ======== ==== ======== See Notes to the Combined Financial Statements. F-12 64 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES COMBINED STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999 (IN THOUSANDS) 1997 1998 1999 ----------- --------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income........................................... $ 51,238 $ 2,028 $ 43,329 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization..................... 67,701 75,573 130,788 Deferred income tax expense....................... 35,823 45,315 86,301 Equity in undistributed earnings.................. (9,784) (11,846) (22,502) Loss (gain) on sale of assets..................... (236) (33,759) 2,377 Net change in operating assets and liabilities: Accounts receivable............................... (76,679) 133,461 (175,008) Inventories....................................... 5,572 1,762 (5,303) Other current assets.............................. 11,320 10,150 20,356 Accounts payable.................................. 101,763 (177,418) 152,535 Other current liabilities......................... (13,361) (4,857) (4,390) Other long term liabilities....................... (55,347) ----------- --------- ----------- Net cash provided by operating activities.... 173,357 40,409 173,136 CASH FLOWS FROM INVESTING ACTIVITIES: Acquisitions and other capital expenditures.......... (121,978) (185,479) (1,570,083) Investment in affiliates............................. (29,600) (84,884) (62,752) Affiliate distributions.............................. 10,742 15,051 31,999 Proceeds from sales of assets........................ 2,815 51,687 29,390 ----------- --------- ----------- Net cash used in investing activities........ (138,021) (203,625) (1,571,446) CASH FLOWS FROM FINANCING ACTIVITIES: Net increase (decrease) in advances -- parents....... (35,061) 162,514 1,350,054 Notes payable borrowings............................. 48,880 ----------- --------- ----------- Net cash flows provided by (used in) financing activities....................... (35,061) 162,514 1,398,934 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS... 275 (702) 624 CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR........... 595 870 168 ----------- --------- ----------- CASH AND CASH EQUIVALENTS, END OF YEAR................. $ 870 $ 168 $ 792 =========== ========= =========== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION --Cash paid for interest (net of amounts capitalized)....... $ 51,765 $ 52,948 $ 52,915 See Notes to the Combined Financial Statements. F-13 65 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999 1. ACCOUNTING POLICIES SUMMARY Principles of Combining -- The accounting policies are presented to assist the reader in evaluating the combined financial statements of Duke Energy Field Services, LLC, Duke Energy Field Services, Inc. (DEFSI), Panhandle Field Services Company (PFSC), Panhandle Gathering Company (PGC), and Duke Energy Services Canada, Ltd. (DESCL) (together, "Duke Energy Field Services, LLC and Affiliates" or the Predecessor Companies). The Predecessor Companies are indirect subsidiaries of Duke Energy Corporation (Duke Energy). During 1999, PFSC and PGC were contributed to and became wholly-owned subsidiaries of DEFSI. The resulting December 31, 1999 stockholders' equity (1,000 shares authorized and issued, $1.00 par value) reflects that of DEFSI and DESCL. 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 natural gas liquids in Mexico and the transportation, marketing and storage of other petroleum products. The Combination -- On December 16, 1999, Duke Energy and Phillips Petroleum Company (Phillips) entered into an agreement to combine their United States and Canadian midstream natural gas gathering, processing and natural gas liquid operations (the Combination). In connection with the Combination, Duke Energy's midstream natural gas gathering and processing business was transferred to Duke Energy Field Services, LLC and the Combination will be accounted for as an acquisition by the Predecessor Companies of Phillips' midstream business. Use of Estimates -- The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Cash and Cash Equivalents -- All liquid investments with maturities at date of purchase of three months or less are considered cash equivalents. Inventories -- Inventories are recorded at the lower of cost or market using the average cost method. Property, Plant and Equipment -- Property, plant and equipment are stated at cost, which does not purport to represent replacement or realizable value. Assets, including goodwill and other intangibles, are evaluated for potential impairment based on undiscounted cash flows and any impairment recorded is derived based on discounted cash flows. There was no impairment during 1997, 1998 or 1999. Depreciation of property, plant and equipment is computed using the straight-line method (see Note 4). Interest totaling $2.3 million, $1.6 million and $.9 million has been capitalized on construction projects for 1997, 1998 and 1999, respectively. Revenue Recognition -- The Predecessor Companies recognize revenues on sales of natural gas and petroleum products in the period of delivery and transportation revenues in the period service is provided. An allowance for doubtful accounts is established based on agings of accounts receivable and the credit worthiness of our customers. Bad debt expense and writeoffs for each year presented are not significant. Equity in Unconsolidated Affiliates -- Investments in 20% to 50% owned affiliates are accounted for using the equity method. Investments greater than 50% are consolidated unless the Predecessor Companies do not operate these investments and as a result do not have the ability to exercise control or control is considered to be temporary (See Note 5). Derivative Contracts -- The Predecessor Companies use commodity swaps, futures and option contracts in the conduct of their business. Unrealized gains and losses associated with activity other than F-14 66 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED trading are recognized when the underlying physical transaction is recorded. Trading activity is marked-to-market and reflected in the statements of income as sales of natural gas and petroleum products or costs of such. Significant Customers -- Duke Energy Trading and Marketing, L.L.C. (DETM), an affiliated company, is a significant customer. Sales to DETM totaled $567 million, $522 million and $684 million during 1997, 1998 and 1999, respectively. Intangibles Amortization -- Goodwill is amortized over the period of expected benefit. Goodwill is being amortized on a straight-line basis over 15 years related to the 1991 acquisition of MEGA Natural Gas Company and 20 years related to the UP Fuels acquisition (see Note 2). Natural gas liquids sales contracts are amortized on a straight-line basis over the contract lives which average 15 years. Environmental Costs -- Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future benefit, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. Environmental liabilities at the end of 1998 and 1999 were insignificant. Gas Imbalance Accounting -- Quantities of natural gas over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using index prices or the weighted average prices of natural gas at the plant or system. Generally, these balances are settled with deliveries of natural gas. Deferred Income Tax -- The Predecessor Companies follow the asset and liability method of accounting for income tax. Deferred taxes are provided for temporary differences in the tax and financial reporting basis of assets and liabilities. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. Stock Based Compensation -- The Predecessor Companies account for stock-based compensation using the intrinsic method of accounting. Under this method, compensation cost, if any, is measured as the excess of the quoted market price of stock at the date of the grant over the amount an employee must pay to acquire stock. Restricted stock is recorded as compensation cost over the requisite vesting period based on the market value on the date of the grant. Earnings Per Share -- The historical capital structure of the Predecessor Companies is not representative of the future capital structure of DEFSI (see Note 2), as all companies were wholly-owned subsidiaries. Accordingly, the historical net income per share and weighted average number of common shares outstanding are not shown for any of the periods presented. Comprehensive Income -- The Predecessor Companies' only item of other comprehensive income is foreign currency translation. Recently Issued Accounting Pronouncements -- In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). SFAS 133 establishes standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (b) a hedge of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an F-15 67 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED available-for-sale security, or a foreign-currency-denominated forecasted transaction. The accounting for changes in the fair value of a derivative (gains and losses) depends on the intended use of the derivative and the resulting designation. The Predecessor Companies are required to adopt SFAS 133 on January 1, 2001. The Predecessor Companies have not completed the process of evaluating the impact that will result from adopting SFAS 133. 2. BUSINESS COMBINATIONS/DISPOSITIONS In March 1998, the Predecessor Companies sold a fractionator to TEPPCO Colorado, L.L.C., an indirect, wholly-owned subsidiary of TEPPCO Partners, L.P. (TEPPCO), of which Duke Energy, through an indirect, wholly-owned subsidiary, has an equity interest of approximately 18%. The fractionator was sold for $40 million and the Predecessor Companies realized a gain of approximately $38 million. On March 31, 1999, the Predecessor Companies acquired the assets and assumed certain liabilities of Union Pacific Fuels, Inc. (UP Fuels), a wholly-owned subsidiary of Union Pacific Resources Company (UPR), for a total purchase price of $1.359 billion. The acquisition was accounted for under the purchase method of accounting, and the assets and liabilities and results of operations of UP Fuels have been consolidated in the Predecessor Companies' financial statements since the date of purchase. The purchase price has been allocated to the assets acquired and liabilities assumed based on estimated fair value, as follows: (IN THOUSANDS) Property, plant and equipment...................... $1,046,316 Partnerships and other joint venture investments... 116,644 Natural gas liquids sales contracts................ 107,771 Goodwill........................................... 75,548 Gas marketing...................................... 104,843 Deferred tax asset................................. 10,200 Net working capital................................ (8,207) Environmental and other liabilities................ (94,018) ---------- Net.............................................. $1,359,097 ========== The gas marketing component of UP Fuels was immediately transferred to an affiliate of Duke Energy after the acquisition at the above fair value. Revenues and net income for 1998 on a pro forma basis would have increased $1.4 billion and $54.9 million, respectively, if the acquisition had occurred on January 1, 1998. Revenues and net income for 1999 on a pro forma basis would have increased $298 million and $2.8 million, respectively, if the acquisition had occurred on January 1, 1999. 3. INVENTORIES A summary of inventories by category follows: DECEMBER 31, ----------------- 1998 1999 ------- ------- (IN THOUSANDS) Gas held for resale......................................... $13,202 $18,114 NGLs........................................................ 5,962 18,211 Materials and supplies...................................... 4,549 2,376 ------- ------- Total inventories................................. $23,713 $38,701 ======= ======= F-16 68 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED 4. PROPERTY, PLANT AND EQUIPMENT A summary of property, plant and equipment by classification follows: DECEMBER 31, DEPRECIATION ----------------------- RATES 1998 1999 ------------ ---------- ---------- (IN THOUSANDS) Gathering...................................... 4% - 6% $ 923,350 $1,231,050 Processing..................................... 4% 416,572 1,197,993 Transmission................................... 4% 251,079 413,633 Underground storage............................ 2% - 5% 79,875 73,958 General plant.................................. 20% - 33% 36,214 37,614 Construction work in progress.................. 56,504 51,262 ---------- ---------- Total property, plant and equipment.......................... $1,763,594 $3,005,510 ========== ========== 5. INVESTMENTS IN AFFILIATES The Predecessor Companies have investments in the following businesses accounted for using the equity method: DECEMBER 31, ------------------- OWNERSHIP 1998 1999 --------- -------- -------- (IN THOUSANDS) Dauphin Island Gathering Partners................... 37.28% $ 96,869 $ 99,878 Mont Belvieu I...................................... 20.00% 40,440 Mobile Bay Processing Partners...................... 28.81% 30,166 35,906 Black Lake Pipeline................................. 50.00% 35,641 Sycamore Gas System General Partnership............. 48.45% 19,344 21,985 Main Pass Oil Gathering............................. 33.33% 15,762 16,967 Ferguson-Burleson................................... 55.00% 23,631 Other affiliates.................................... Various 12,406 54,141 -------- -------- 174,547 328,589 Westana Gathering Company........................... 50.00% 13,391 15,246 -------- -------- Total investments in affiliates........... $187,938 $343,835 ======== ======== Dauphin Island Gathering Partners -- Dauphin Island Gathering Partners is a partnership which owns the Dauphin Island Gathering system and the Main Pass Gas Gathering system, which are natural gas gathering systems in the Gulf of Mexico. Mont Belvieu I -- Mont Belvieu I operates a 200 MBbl/d fractionation facility in the Mont Belvieu, Texas Market Center. Mobile Bay Processing Partners -- Mobile Bay Processing Partners is a partnership formed to engage in the financing, ownership, construction and operation of one or more natural gas processing facilities onshore in Mobile County, Alabama. Black Lake Pipeline -- Black Lake Pipeline owns a 317 mile long NGL pipeline, with a current capacity of approximately 40 MBbl/d. The pipeline receives NGLs from a number of gas plants in Louisiana and Texas. The NGLs are transported to Mont Belvieu fractionators. F-17 69 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED Sycamore Gas System General Partnership -- Sycamore Gas System General Partnership is a partnership formed for the purpose of constructing, owning and operating a gas gathering and compression system in Carter County, Oklahoma. Main Pass Oil Gathering -- Main Pass Oil Gathering is a joint venture whose primary operation is a crude oil gathering pipeline system of 81 miles in the Main Pass East and Viosca Knoll Block areas in the Gulf of Mexico. Ferguson-Burleson -- Ferguson-Burleson operates two independent gas gathering systems, rich and lean, that are interconnected. The rich gas system is comprised of over 1,450 miles of gathering lines serving six counties in South Central Texas. The lean gas system consists of approximately 100 miles of pipelines in two counties in South Central Texas. We own 55% of the economic interest in Ferguson-Burleson but have only a 50% voting interest. The operator of the assets controls the other 50% voting interest and manages the operations on a daily basis. The Predecessor Companies do not have the ability to control Ferguson-Burleson and therefore do not consolidate its results. Equity in earnings amounted to the following for the years ended December 31: 1997 1998 1999 ------ ------- ------- (IN THOUSANDS) Dauphin Island Gathering Partners........................ $4,250 $ 7,234 $ 5,974 Mont Belvieu I........................................... 440 Mobile Bay Processing Partners........................... 65 2,307 Black Lake Pipeline...................................... 1,141 Sycamore Gas System General Partnership.................. 261 142 Main Pass Oil Gathering.................................. 1,665 2,598 3,638 Ferguson-Burleson........................................ 5,600 Other affiliates......................................... 3,062 1,279 1,921 ------ ------- ------- 8,977 11,437 21,163 Westana Gathering Company................................ 807 409 1,339 ------ ------- ------- Total equity earnings.......................... $9,784 $11,846 $22,502 ====== ======= ======= Distributions in excess of earnings were $1.0 million, $3.2 million and $9.5 million in 1997, 1998 and 1999, respectively. In connection with the Combination, the Predecessor Companies' interest in Westana Gathering Company was sold in February 2000. Proceeds and loss on sale approximated $12 million and $4 million, respectively. F-18 70 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED The following summarizes combined financial information of unconsolidated affiliates excluding Westana for the years ended December 31: 1997 1998 1999 ------- -------- --------- (IN THOUSANDS) Income statement: Operating revenues................................. $54,898 $ 61,618 $ 452,118 Operating expenses................................. 34,281 36,173 374,079 Net income......................................... 21,318 27,878 55,606 Balance sheet: Current assets..................................... $ 57,926 $ 119,506 Noncurrent assets.................................. 388,562 761,270 Current liabilities................................ (25,671) (113,121) Noncurrent liabilities............................. (8,094) (14,853) -------- --------- Net assets................................. $412,723 $ 752,802 ======== ========= 6. TRANSACTIONS WITH AFFILIATES A summary of transactions with affiliates included in the combined statements of income follows: YEARS ENDED DECEMBER 31, -------------------------------- 1997 1998 1999 -------- -------- ---------- (IN THOUSANDS) Sales of natural gas and petroleum products......... $567,800 $536,300 $ 696,700 Natural gas and petroleum products purchased........ 48,900 79,600 128,600 Transportation revenue.............................. 6,400 2,700 Operating expenses -- Billed to affiliates(1)....... 4,200 7,200 General and administrative expenses(1): Billed to affiliates.............................. 1,200 502 Billed from affiliates............................ 11,700 12,100 19,100 Interest expense.................................... 60,100 60,100 53,900 -------------------- (1) Operating, general and administrative expenses are allocated to affiliates based on cost. As of December 31, 1998 and 1999, the Predecessor Companies had a $101.6 million note payable to Duke Energy, scheduled to mature in 2004 bearing interest at 8.5%. Additionally, as of December 31, 1999, the Predecessor Companies had a $540 million note payable to Duke Energy, scheduled to mature December 31, 2000 bearing interest at prime (8.5% at December 31, 1999), adjusted quarterly, and a $44.3 million and $4.6 million note payable to Duke Energy, payable on demand and bearing interest at the Canadian Prime Rate (6.5% at December 31, 1999), plus fifty basis points, adjusted quarterly. Intercompany advances do not bear interest. Advances are carried as open accounts and are not segregated between current and non-current amounts. Increases and decreases in advances result from the movement of funds to provide for operations, capital expenditures, and debt payments of Duke Energy and its subsidiaries. In addition, current income tax balances are recorded in these accounts. Average intercompany advances payable approximated $117.3 million, $203.8 million and $1,410 million for 1997, 1998 and 1999, respectively. Duke Energy supplies the Predecessor Companies with various staff and support services, including information technology products and services, payroll, employee benefits, corporate insurance, cash F-19 71 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED management, ad valorem taxes, treasury and legal functions. These expenditures are allocated to the Predecessor Companies using a cost based method of allocation. Management believes the allocation is reasonable and estimates that such costs approximate the costs for such services that would have been incurred on a stand alone basis. See Notes 5 and 12 for discussion of other specific transactions with affiliates. 7. INCOME TAXES The Predecessor Companies' taxable income is included in a consolidated federal income tax return with Duke Energy. Therefore, income tax has been provided in accordance with Duke Energy's tax allocation policy, which requires subsidiaries to calculate federal income tax as if separate taxable income, as defined, was reported. Foreign income taxes are not material and therefore are not shown separately. Income tax as presented in the combined statements of income is summarized as follows: YEARS ENDED DECEMBER 31, ------------------------------- 1997 1998 1999 ------- -------- -------- (IN THOUSANDS) Current: Federal........................................... $(1,012) $(36,142) $(46,429) State............................................. (1,431) (5,884) (8,843) ------- -------- -------- Total current............................. (2,443) (42,026) (55,272) ------- -------- -------- Deferred: Federal........................................... 30,800 38,961 73,201 State............................................. 5,023 6,354 13,100 ------- -------- -------- Total deferred............................ 35,823 45,315 86,301 ------- -------- -------- Total income tax expense............................ $33,380 $ 3,289 $ 31,029 ======= ======== ======== Total income tax expense differs from the amount computed by applying the federal income tax rate to earnings before income tax. The reasons for this difference are as follows: YEARS ENDED DECEMBER 31, ---------------------------- 1997 1998 1999 ------- ------ ------- (IN THOUSANDS) Federal income tax rate................................ 35.0% 35.0% 35.0% ======= ====== ======= Income tax, computed at the statutory rate............. $29,616 $1,861 $26,025 Adjustments resulting from: State income tax, net of federal income tax effect... 2,962 186 2,863 Non-deductible amortization and other................ 802 1,242 2,141 ------- ------ ------- Total income tax............................. $33,380 $3,289 $31,029 ======= ====== ======= F-20 72 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED The tax effects of temporary differences that resulted in deferred income tax assets and liabilities, and a description of the significant items that created these differences are as follows: YEARS ENDED DECEMBER 31, --------------------------------- 1997 1998 1999 --------- --------- --------- (IN THOUSANDS) Alternative minimum tax credit carryforward....... $ 20,400 $ 20,400 $ -- Other............................................. 2,300 500 7,600 --------- --------- --------- Total deferred income tax assets........ 22,700 20,900 7,600 --------- --------- --------- Property, plant, and equipment.................... (160,200) (209,507) (275,008) Deferred charges.................................. (900) (15,000) (15,300) State deferred income tax, net of federal tax effect.......................................... (14,300) (18,400) (25,600) --------- --------- --------- Total deferred income tax liabilities... (175,400) (242,907) (315,908) --------- --------- --------- Net deferred income tax liability................. $(152,700) $(222,007) $(308,308) ========= ========= ========= 8. BUSINESS SEGMENTS AND RELATED INFORMATION The Predecessor Companies operate in two principal business segments as follows: (1) natural gas gathering, processing, transportation, marketing and storage, and (2) natural gas liquids fractionation, transportation, marketing and trading. These segments are separately monitored by management for performance against its internal forecast and are consistent with the Predecessor Companies internal financial reporting package. These segments have been identified based upon 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 1. Foreign operations are not material and are therefore not separately identified. The following table sets forth the Predecessor Companies' segment information as of and for the years ended December 31, 1997, 1998 and 1999. 1997 1998 1999 ---------- ---------- ---------- (IN THOUSANDS) Operating revenues: Natural gas............................................ $1,683,483 $1,497,901 $2,483,197 NGLs................................................... 423,680 309,380 1,365,577 Intersegment(a)........................................ (305,331) (222,961) (390,464) ---------- ---------- ---------- Total operating revenues....................... 1,801,832 1,584,320 3,458,310 ---------- ---------- ---------- Margin: Natural gas............................................ 334,129 243,787 459,843 NGLs................................................... (386) 2,404 33,170 ---------- ---------- ---------- Total margin................................... 333,743 246,191 493,013 ---------- ---------- ---------- Other operating costs: Natural gas............................................ 104,072 79,797 182,062 NGLs................................................... -- -- 1,707 Corporate.............................................. 36,023 44,946 73,685 ---------- ---------- ---------- Total other operating costs.................... 140,095 124,743 257,454 ---------- ---------- ---------- F-21 73 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED 1997 1998 1999 ---------- ---------- ---------- (IN THOUSANDS) Equity in earnings of unconsolidated affiliates: Natural gas............................................ 9,784 11,845 20,917 NGLs................................................... 1,585 ---------- ---------- ---------- Total equity in earnings of unconsolidated affiliates................................... 9,784 11,845 22,502 ---------- ---------- ---------- EBITDA(b): Natural gas............................................ 239,841 175,835 298,698 NGLs................................................... (386) 2,404 33,048 Corporate.............................................. (36,023) (44,946) (73,685) ---------- ---------- ---------- Total EBITDA................................... 203,432 133,293 258,061 ---------- ---------- ---------- Depreciation and amortization: Natural gas............................................ 65,593 73,470 119,425 NGLs................................................... 9,073 Corporate.............................................. 2,108 2,103 2,290 ---------- ---------- ---------- Total depreciation and amortization............ 67,701 75,573 130,788 ---------- ---------- ---------- EBIT: Natural gas............................................ 174,248 102,365 179,273 NGLs................................................... (386) 2,404 23,975 Corporate.............................................. (38,131) (47,049) (75,975) ---------- ---------- ---------- Total EBIT..................................... 135,731 57,720 127,273 ---------- ---------- ---------- Corporate interest expense............................... 51,113 52,403 52,915 ---------- ---------- ---------- Income before income taxes: Natural gas............................................ 174,248 102,365 179,273 NGLs................................................... (386) 2,404 23,975 Corporate.............................................. (89,244) (99,452) (128,890) ---------- ---------- ---------- Total income before income taxes............... $ 84,618 $ 5,317 $ 74,358 ---------- ---------- ---------- AS OF DECEMBER 31, ----------------------- 1998 1999 ---------- ---------- Total assets: Natural gas............................................... $1,505,111 $2,754,447 NGLs...................................................... 5,137 225,702 Corporate(c).............................................. 260,590 491,686 ---------- ---------- Total assets...................................... $1,770,838 $3,471,835 ========== ========== - --------------- (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, less interest income. EBITDA is not a measurement presented in accordance with generally accepted accounting principles. You should not consider it 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 our profitability or liquidity. EBITDA is F-22 74 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED included as a supplemental disclosure because it may provide useful information regarding our ability to service debt and to fund capital expenditures. However, not all EBITDA may be available to service debt. (c) Includes items such as unallocated working capital, intercompany accounts and intangible and other assets. 9. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS The Predecessor Companies' operations are subject to the volatility of commodity prices, particularly that of NGL prices. The Predecessor Companies manage exposure to risk from existing contractual commitments through forward contracts, futures and over-the-counter swap agreements (collectively, "commodity instruments"). Energy commodity forward contracts involve physical delivery of an energy commodity. Energy commodity futures involve the buying or selling of natural gas, crude oil (used to hedge NGLs prices) and NGLs at a fixed price. Over-the-counter swap agreements require the Predecessor Companies to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity. Commodity Instruments -- Trading -- The Predecessor Companies, through a wholly-owned subsidiary, engage in the trading of NGLs and crude oil commodity instruments, and therefore experience net open positions. The Predecessor Companies manage open positions with policies which limit its exposure to market risk and require daily reporting to management of potential financial exposure. The weighted-average life of the Predecessor Companies commodity risk portfolio was approximately 2 months at December 31, 1999. During 1999 net gains of $9.7 million were recognized from trading NGLs and crude oil derivatives. The Predecessor Companies were not trading NGLs nor crude oil commodity instruments prior to 1999. As of December 31, 1999, the absolute notional contract quantity of NGLs and crude oil commodity derivatives held for trading purposes was 5,826,000 and 6,486,500 barrels, respectively. 1999 --------------------- ASSETS LIABILITIES ------- ----------- (IN THOUSANDS) Fair value at December 31................................... $10,461 $10,079 Average fair value for the year............................. 8,588 8,359 Commodity Derivatives -- Non-Trading -- At December 31, 1998 and 1999, the Predecessor Companies held or issued derivatives that reduce the Predecessor Companies' exposure to market fluctuations in the price and transportation costs of natural gas and NGLs. The Predecessor Companies' market exposure arises from inventory balances and fixed-price purchase and sale commitments that extend for periods of up to 10 years. Futures and swaps are used to manage and hedge prices and location risk related to these market exposures. Futures and swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs. The gains, losses and costs related to those commodity derivatives that qualify as a hedge are not recognized until the underlying physical transaction occurs. At December 31, 1998 and 1999, the Predecessor Companies unrealized net gains (losses) related to commodity derivative hedges was $1.8 million and $(63.5) million, respectively. As of December 31, 1998 and 1999, the absolute notional contract quantity of commodity derivatives held for non-trading purposes was 10.92 and 7.8 billion cubic feet (Bcf) of natural gas and 59,000 and 32,764,000 barrels of crude oil, respectively. Hedging losses in 1999 totaled approximately $34 million. F-23 75 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED Market and Credit Risk -- Most futures and swaps are conducted through either DETM or Duke Energy Merchants (DEM). Under these arrangements the Predecessor Companies do not have margin requirements. New York Mercantile Exchange (Exchange) traded futures contracts are guaranteed by the Exchange and have nominal credit risk. On all other transactions previously described, the Predecessor Companies are exposed to credit risk in the event of nonperformance by the counterparties. For each counterparty, the Predecessor Companies analyze the financial condition prior to entering into an agreement. The change in market value of exchange-traded futures contracts other than those conducted through either DETM or DEM require daily cash settlement in margin accounts with brokers. Swap contracts are generally settled at the expiration of the contract term and may be subject to margin requirements with the counterparty. Gathering, processing, and transportation services are provided to producers, refiners, and a variety of wholesale and retail customers located in the Mid-Continent, Gulf Coast and Rocky Mountain areas as well as in Canada. The principal markets for natural gas marketing services are industrial end-users and utilities located throughout the United States. The Predecessor Companies have a concentration of receivables due from gas and electric utilities and their affiliates, as well as industrial customers throughout the United States. These concentrations of customers may affect the Predecessor Companies' overall credit risk in that certain customers may be similarly affected by changes in economic, regulatory or other factors. Trade receivables are generally not collateralized; however, the Predecessor Companies analyze customers' financial condition prior to extending credit, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. 10. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, "Disclosures about Fair Value of Financial Instruments." The estimated fair value amounts have been determined by the Predecessor Companies, using available market information and appropriate valuation methodologies. However, considerable judgment is necessarily required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that the Predecessor Companies could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. DECEMBER 31, 1998 DECEMBER 31, 1999 --------------------------- ------------------------- CARRYING ESTIMATED FAIR CARRYING ESTIMATED FAIR AMOUNT VALUE AMOUNT VALUE ---------- -------------- -------- -------------- (IN THOUSANDS) Cash and cash equivalents.............. $ 168 $ 168 $ 792 $ 792 Accounts receivable.................... 240,114 240,114 464,133 464,133 Notes receivable....................... 15,096 15,294 21,866 22,582 Accounts payable....................... 217,182 217,182 450,205 450,205 Advances, net -- parents............... 334,057 334,057 1,579,475 1,579,475 Notes payable.......................... 641,600 601,606 690,480 655,843 Natural gas, NGL and oil hedge contracts............................ -- 1,800 -- (63,500) The fair value of cash and cash equivalents, accounts receivable, and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. F-24 76 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED Notes receivable is carried in the accompanying balance sheet at cost. Fair value has been estimated using discounted cash flows assuming current interest rates, similar credit risk and maturities. Related party advances and notes payable are carried at cost. Fair value has been estimated using discounted cash flows of maturities of five years and interest rates of 8.0%. The estimated fair value of the natural gas, NGL and oil hedge contracts is determined by multiplying the difference between the quoted termination prices for natural gas, NGL and oil and the hedge contract prices by the quantities under contract. 11. COMMITMENTS AND CONTINGENT LIABILITIES The midstream natural gas industry has seen an increase in the number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. Many of these cases are now being brought as class actions. The Predecessor Companies are currently named as defendants in certain of these cases. Management believes the Predecessor Companies 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. The Predecessor Companies are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal as well as other environmental matters. The Predecessor Companies are not aware of any material violations and have accrued for the known remediation that is in process. In connection with the UP Fuels acquisition, the Predecessor Companies analyzed water and soil samples surrounding UP Fuels facilities and identified necessary remedial actions. The Predecessor Companies transferred this obligation to a third party for a payment of approximately $48 million. Generally, environmental liabilities are not expected to be recoverable from insurance or other third parties. The Predecessor Companies utilize assets under operating leases in several areas of operation. Combined rental expense amounted to $8.1 million, $8.2 million and $11.8 million in 1997, 1998 and 1999, respectively. Minimum rental payments under the Predecessor Companies' various operating leases for the years 2000 through 2004 are $6.1, $6.0, $5.0, $5.0 and $4.3 million, respectively. Thereafter, payments aggregate $15.4 million through 2011. F-25 77 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED 12. STOCK-BASED COMPENSATION, PENSION AND OTHER BENEFITS Under Duke Energy's 1999 Stock Incentive Plan, stock options of Duke Energy's common stock may be granted to key employees of the Predecessor Companies. Under the plan, the exercise price of each option granted equals the market price of Duke Energy's common stock on the date of grant. Vesting periods range from one to five years with a maximum exercise term of ten years. The following tables set forth information regarding options to purchase Duke Energy's common stock granted to employees of the Predecessor Companies. Stock Option Activity WEIGHTED OPTIONS AVERAGE (IN THOUSANDS) EXERCISE PRICE -------------- -------------- Outstanding at December 31, 1996............................ 254 $20 Granted................................................... 25 44 Exercised................................................. (54) 18 Forfeited................................................. -- -- ----- --- Outstanding at December 31, 1997............................ 225 23 Granted................................................... 279 55 Exercised................................................. (70) 21 Forfeited................................................. -- -- ----- --- Outstanding at December 31, 1998............................ 434 44 Granted................................................... 878 53 Exercised................................................. (33) 25 Forfeited................................................. (18) 55 ----- --- Outstanding at December 31, 1999............................ 1,261 51 Stock Options at December 31, 1999 OUTSTANDING EXERCISABLE ---------------------------------------- ------------------------- WEIGHTED WEIGHTED WEIGHTED RANGE OF AVERAGE AVERAGE AVERAGE EXERCISE NUMBER REMAINING EXERCISE NUMBER EXERCISE PRICES (IN THOUSANDS) LIFE (YEARS) PRICE (IN THOUSANDS) PRICE -------- -------------- ------------ -------- -------------- -------- $10 to $14 16 1.5 $11 16 $ 11 $15 to $20 52 3.9 18 52 18 $21 to $25 25 5.1 23 25 23 $26 to $31 10 6.1 27 10 27 $42 to $50 474 9.8 49 22 44 $55 to $60 684 8.8 56 66 55 ----- --- Total 1,261 191 34 There were 29,646 and 82,050 options exercisable at December 31, 1997 and 1998 with a weighted average exercise price of $21 and $22 per option. No compensation cost related to the stock options has been recorded as the intrinsic method of accounting is used and the exercise price of each option granted equaled the market price on the date of grant. The weighted average fair value of options granted was $10.00, $9.00 and $10.00 per option during 1997, 1998 and 1999, respectively. The fair value of each option granted was estimated on the date of grant using the Black-Scholes option-pricing model. The weighted-average assumptions for option-pricing F-26 78 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED in 1997, 1998 and 1999 were: stock dividend yield of 3.5%, 4.2% and 4.1%, expected stock price volatility of 20.7%, 15.1% and 18.8% and risk-free interest rates of 6.5%, 5.6% and 5.9%, respectively. The expected option life for 1997, 1998 and 1999 was seven years. Stock-based compensation expense calculated using the Black-Scholes option-pricing model for 1997, 1998 and 1999 would have been $0.1 million, $0.8 million and $2.5 million, respectively and net income would have been $51.1 million, $1.5 million and $41.8 million, respectively. In addition, Duke Energy granted restricted shares of Duke Energy common stock to key employees of the Predecessor Companies under Duke Energy stock incentive plans. Grants under the plans vest over periods ranging from one to seven years. In 1997 and 1999 Duke Energy awarded 2,817 shares (fair value at grant dates of approximately $168,000) and 36,300 shares (fair value at grant dates of approximately $2 million) to key employees of the Predecessor Companies. No restricted shares were awarded in 1998. Compensation expense for the stock grants is charged to the earnings of the Predecessor Companies over the vesting period, and amounted to approximately $168,000, $0 and $488,000 in 1997, 1998 and 1999, respectively. Duke Energy has, and the Predecessor Companies' participate in, a non-contributory trustee pension plan which covers eligible employees with a minimum of one year vesting service. The plan provides pension benefits for eligible employees of the Predecessor Companies that are generally based on the employee's actual eligible earnings and accrued interest. Through December 31, 1998, for certain eligible employees, a portion of their benefit may also be based on the employee's years of benefit accrual service and highest average eligible earnings. Effective January 1, 1999, the benefit formula under the plan for all eligible employees was changed to a cash balance formula. Duke Energy's policy is to fund amounts, as necessary, on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan members. Aspects of the plan specific to the Predecessor Companies is as follows: COMPONENTS OF NET PERIODIC PENSION COSTS YEARS ENDED DECEMBER 31, --------------------------- 1997 1998 1999 ------- ------- ------- (IN THOUSANDS) Service cost................................................ $ 950 $ 911 $ 1,280 Interest cost............................................... 681 794 1,375 Expected return on plan assets.............................. (1,227) (1,391) (2,307) Amortization of transition (asset)/liability................ (86) (86) (85) Amortization of prior service cost.......................... 29 43 34 Amortization of (gains)/losses.............................. 6 Settlement gain............................................. (40) ------- ------- ------- Net periodic pension cost................................... $ 347 $ 231 $ 303 ======= ======= ======= F-27 79 DUKE ENERGY FIELD SERVICES, LLC AND AFFILIATES NOTES TO COMBINED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999--CONTINUED RECONCILIATION OF FUNDED STATUS TO PRE-FUNDED PENSION COSTS DECEMBER 31, ----------------- 1998 1999 ------- ------- (IN THOUSANDS) CHANGE IN BENEFIT OBLIGATION Benefit obligation at beginning of year..................... $ 9,219 $14,651 Service cost................................................ 911 1,280 Interest cost............................................... 794 1,375 Intercompany transfers...................................... 802 8,519 Benefits paid............................................... (250) (190) Actuarial (gains)/losses.................................... 3,261 (3,789) Plan amendments............................................. (86) ------- ------- Benefit obligation at end of year........................... $14,651 $21,846 ======= ======= DECEMBER 31, ----------------- 1998 1999 ------- ------- (IN THOUSANDS) CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of year.............. $16,868 $20,211 Intercompany transfers...................................... 743 8,519 Actual return on plan assets................................ 2,580 4,985 Employer contributions...................................... 270 302 Benefits paid............................................... (250) (190) ------- ------- Fair value of plan assets at end of year.................... $20,211 $33,827 ======= ======= Funded status............................................... $ 5,563 $11,982 Unrecognized net transition asset........................... (510) (425) Unrecognized prior service cost............................. 302 268 Unrecognized gains.......................................... (794) (7,267) ------- ------- Pre-funded pension costs.................................... $ 4,561 $ 4,558 ======= ======= Intercompany transfers relate to benefit obligations and plan assets associated with employees transferring between the Predecessor Companies and other Duke Energy affiliates. ASSUMPTIONS USED FOR PENSION BENEFIT ACCOUNTING YEARS ENDED DECEMBER 31, -------------------- 1997 1998 1999 ---- ---- ---- Discount rate............................................... 7.25% 6.75% 7.50% Rate of increase in compensation levels..................... 4.75% 4.67% 4.50% Expected long-term rate of return on plan assets............ 9.25% 9.25% 9.25% The Predecessor Companies also sponsor an employee savings plan which covers substantially all employees. During 1997, 1998 and 1999, the Predecessor Companies expensed plan contributions of $1.6 million, $1.8 million and $3.6 million, respectively. The Predecessor Companies' postretirement benefits, in conjunction with Duke Energy, consist of certain health care and life insurance benefits for certain retired employees. Postretirement benefits costs were not material in 1997, 1998 and 1999. F-28 80 DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED BALANCE SHEETS (IN THOUSANDS) DECEMBER 31, JUNE 30, 1999 2000 ------------ ----------- (UNAUDITED) ASSETS CURRENT ASSETS: Cash and cash equivalents................................. $ 792 $ 2,593 Accounts receivable: Customers, net......................................... 370,139 722,451 Affiliates............................................. 63,927 157,606 Other.................................................. 30,067 41,448 Inventories............................................... 38,701 52,566 Notes receivable.......................................... 13,050 6,502 Other..................................................... 1,580 3,111 ---------- ---------- Total current assets.............................. 518,256 986,277 PROPERTY, PLANT AND EQUIPMENT, NET.......................... 2,409,385 4,441,160 INVESTMENT IN AFFILIATES.................................... 343,835 276,443 INTANGIBLE ASSETS: Natural gas liquids sales contracts, net.................. 102,382 101,970 Goodwill, net............................................. 85,846 84,735 OTHER NONCURRENT ASSETS..................................... 12,131 85,202 ---------- ---------- TOTAL ASSETS...................................... $3,471,835 $5,975,787 ========== ========== LIABILITIES AND EQUITY CURRENT LIABILITIES: Accounts payable: Trade.................................................. $ 353,977 $ 790,865 Affiliates............................................. 62,370 68,423 Other.................................................. 33,858 40,599 Short-term debt........................................... -- 2,585,290 Accrued taxes other than income........................... 15,653 17,693 Advances, net............................................. 1,579,475 80,879 Notes payable -- affiliates............................... 588,880 -- Other..................................................... 6,372 31,904 ---------- ---------- Total current liabilities......................... 2,640,585 3,615,653 DEFERRED INCOME TAXES....................................... 308,308 -- NOTE PAYABLE TO PARENT...................................... 101,600 -- OTHER LONG TERM LIABILITIES................................. 34,871 38,923 COMMITMENTS AND CONTINGENT LIABILITIES EQUITY: Common stock.............................................. 1 -- Paid-in capital........................................... 213,091 -- Members' interest......................................... -- 1,695,108 Retained earnings......................................... 173,091 627,220 Other comprehensive income (loss)......................... 288 (1,117) ---------- ---------- Total equity...................................... 386,471 2,321,211 ---------- ---------- TOTAL LIABILITIES AND EQUITY................................ $3,471,835 $5,975,787 ========== ========== See Notes to Consolidated Financial Statements. F-29 81 DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF INCOME JUNE 30, 1999 AND 2000 (UNAUDITED) (IN THOUSANDS) SIX MONTHS ENDED ----------------------- JUNE 30, JUNE 30, 1999 2000 ---------- ---------- OPERATING REVENUES: Sales of natural gas and petroleum products............... $1,032,880 $3,542,823 Transportation, storage and processing.................... 75,964 80,748 ---------- ---------- Total operating revenues.......................... 1,108,844 3,623,571 ---------- ---------- COSTS AND EXPENSES: Natural gas and petroleum products........................ 916,310 3,115,037 Operating and maintenance................................. 78,745 140,354 Depreciation and amortization............................. 56,006 105,359 General and administrative................................ 30,759 69,976 Net (gain) loss on sale of assets......................... (9) 337 ---------- ---------- Total costs and expenses.......................... 1,081,811 3,431,063 ---------- ---------- OPERATING INCOME............................................ 27,033 192,508 EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES............. 10,275 14,707 ---------- ---------- EARNINGS BEFORE INTEREST AND TAXES.......................... 37,308 207,215 INTEREST EXPENSE............................................ 25,535 59,851 ---------- ---------- INCOME BEFORE INCOME TAXES.................................. 11,773 147,364 INCOME TAX EXPENSE (BENEFIT)................................ 5,618 (306,765) ---------- ---------- NET INCOME.................................................. $ 6,155 $ 454,129 ========== ========== See Notes to Consolidated Financial Statements. F-30 82 DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF EQUITY SIX MONTHS ENDED JUNE 30, 2000 (UNAUDITED) (IN THOUSANDS) OTHER ADDITIONAL COMPREHENSIVE COMMON PAID-IN MEMBERS' RETAINED INCOME STOCK CAPITAL INTEREST EARNINGS (LOSS) TOTAL ------ ---------- ----------- -------- ------------- ----------- Balance, January 1, 2000............. $ 1 $ 213,091 $ -- $173,091 $ 288 $ 386,471 Combination at March 31, 2000 -- see Note 2: Contribution of TEPPCO general partnership interest........... 1,443 1,443 Contribution of DEFS Inc. and DEFSCL to DEFS, LLC............ (1) (214,534) 214,535 -- Contribution of notes and advances payable............... 2,305,092 2,305,092 Contribution of GPM assets and liabilities.................... 1,919,800 1,919,800 Distributions.................... (2,744,319) (2,744,319) Net income......................... 454,129 454,129 Other.............................. (1,405) (1,405) --- --------- ----------- -------- ------- ----------- Balance, June 30, 2000............... $-- $ -- $ 1,695,108 $627,220 $(1,117) $ 2,321,211 === ========= =========== ======== ======= =========== See Notes to Consolidated Financial Statements. F-31 83 DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF CASH FLOWS JUNE 30, 1999 AND 2000 (UNAUDITED) (IN THOUSANDS) SIX MONTHS ENDED -------------------------- JUNE 30, JUNE 30, 1999 2000 ----------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 6,155 $ 454,129 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization.......................... 56,006 105,359 Deferred income tax expense (benefit).................. 24,311 (308,230) Equity in earnings of unconsolidated affiliates........ (10,275) (14,707) Loss (gain) on sale of assets.......................... (9) 337 Net change in operating assets and liabilities: Accounts receivable.................................... (2,980) (236,018) Inventories............................................ 1,556 (39,532) Other current assets................................... (1,482) 43,583 Other non-current assets............................... 3,774 (2,232) Accounts payable....................................... 64,729 343,424 Other current liabilities.............................. (8,612) (7,155) Other long term liabilities............................ (2,018) (14,215) ----------- ----------- Net cash provided by operating activities......... 131,155 324,743 CASH FLOWS FROM INVESTING ACTIVITIES: Acquisitions and other capital expenditures............... (1,519,053) (214,269) Investment expenditures................................... (34,187) (1,327) Investment distributions.................................. 9,939 12,093 Proceeds from sales of assets............................. 225 14,220 ----------- ----------- Net cash used in investment activities............ (1,543,076) (189,283) CASH FLOWS FROM FINANCING ACTIVITIES: Net increase (decrease) in advances -- parents............ 1,369,761 25,370 Distributions............................................. -- (2,744,319) Proceeds from issuing debt................................ 47,857 2,790,900 Payment of debt........................................... (5,488) (205,610) ----------- ----------- Net cash flows provided by (used in) financing activities..................................... 1,412,130 (133,659) NET INCREASE IN CASH AND CASH EQUIVALENTS:.................. 209 1,801 CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD.............. 168 792 ----------- ----------- CASH AND CASH EQUIVALENTS, END OF PERIOD.................... $ 377 $ 2,593 =========== =========== See Notes to Consolidated Financial Statements. F-32 84 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 2000 (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. Effective March 31, 2000, and in connection with the Combination (see Note 2), Duke Energy Field Services, Inc. (DEFS Inc.) was converted to a limited liability company, and was contributed by Duke Energy Corporation (Duke Energy) to the Company as a wholly-owned subsidiary. Also on March 31, 2000, Duke Energy contributed Duke Energy Field Services Canada, Ltd. (DEFSCL) to Field Services LLC. As a result of these contributions to the Company, the June 30, 2000 financial statements are reflected as consolidated. The interim consolidated financial statements presented herein should be read in conjunction with the 1999 combined financial statements and notes thereto of Duke Energy Field Services, LLC and Affiliates. In the opinion of management, all adjustments necessary for a fair presentation of the results for the unaudited interim periods have been made. Except as explicitly noted, these adjustments consist solely of normal recurring accruals. 2. COMBINATION On March 31, 2000, the natural gas gathering, processing and natural gas liquid assets, operations, and subsidiaries of Duke Energy were contributed to Field Services LLC. In connection with the contribution of assets and subsidiaries at March 31, 2000, notes and advances payable to Duke Energy were eliminated and contributed to equity. Also on March 31, 2000, Phillips Petroleum Company (Phillips) contributed its midstream natural gas gathering, processing and natural gas liquid operations to Field Services LLC. This contribution and Duke Energy's contribution to Field Services LLC are referred to as the "Combination." In connection with the Combination, the Company made one-time distributions to Phillips of $1,219.8 million and to Duke Energy of $1,524.5 million. In exchange for the contributions, and after the one-time distributions, Duke Energy received a 69.7% member interest in Field Services LLC, with Phillips holding the remaining 30.3% member interest. The Combination has been accounted for as a purchase business combination in accordance with Accounting Principles Board Opinion (APB) No. 16 "Accounting for Business Combinations". The Phillips assets, net of liabilities, have been valued at $1,919.8 million. Following is a summary of the preliminary allocation of purchase price (in millions): Property, plant and equipment............................... $1,878.4 Other assets, net........................................... 41.4 -------- Total purchase price.............................. $1,919.8 ======== The purchase price has not yet been fully allocated to the individual assets and liabilities acquired. The final allocation will be determined based on independent appraisals. Working Capital Adjustments -- In connection with the Combination, Duke Energy and Phillips each were to make contributions to Field Services LLC, or receive distributions from Field Services LLC so that each of Duke Energy and Phillips would have contributed to Field Services LLC net working capital positions equal to zero as of March 31, 2000. As of June 30, 2000, Field Services LLC had advances F-33 85 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) payable to Duke Energy and Phillips of $80.9 million representing distributions payable to net the working capital positions as of March 31, 2000. Pro Forma Disclosures -- Revenues for the six months ended June 30, 1999 and 2000, on a pro forma basis would have increased $618.0 million and $542.4 million, respectively, and net income for the six months ended June 30, 1999 and 2000, on a pro forma basis would have decreased by $15.6 million and increased by $65.7 million, respectively, if the acquisition of the Phillips midstream business had occurred at the beginning of the period presented. TEPPCO General Partner Interest -- On March 31, 2000, and in connection with the Combination, Duke Energy contributed the general partner interest of TEPPCO Partners L.P. to Field Services LLC. In connection with the contribution of the general partner interest in TEPPCO, the Company recorded an investment in TEPPCO of $1.4 million and increased stockholders' equity by $1.4 million. TEPPCO is a publicly traded limited partnership that owns and operates a network of pipelines for refined products and crude oil. The general partner is responsible for the management and operations of TEPPCO. Through the ownership of the general partner of TEPPCO, Field Services LLC has the right to receive from TEPPCO incentive cash distributions in addition to a 2% share of distributions based on the general partner interest. At TEPPCO's 1999 per unit distribution level, the general partner received approximately 14% of the cash distributed by TEPPCO to its partners. Due to the general partner's share of unit distributions and control exercised through its management of the partnership, the Company's investment in TEPPCO is accounted for under the equity method. 3. INCOME TAXES At March 31, 2000 the Company converted to the limited liability company which is a pass-through entity for income tax purposes. As a result, substantially all of the existing net deferred tax liability ($327 million) was eliminated with a corresponding income tax benefit recorded. 4. ACQUISITIONS Union Pacific Fuels, Inc. -- On March 31, 1999, the Company acquired the assets and assumed certain liabilities of Union Pacific Fuels, Inc. (UP Fuels), a wholly-owned subsidiary of Union Pacific Resources Corporation, for a total purchase price of $1,359 million. The acquisition was accounted for under the purchase method of accounting, and the assets and liabilities and results of operations of UP Fuels 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, 1999 on a pro forma basis would have increased $298 million and $3.4 million respectively, if the acquisition of UP Fuels had occurred on January 1, 1999. Conoco and Mitchell Assets -- On March 31, 2000, Field Services LLC acquired gathering and processing facilities located in central Oklahoma from Conoco, Inc. and Mitchell Energy & Development Corp. Field Services LLC paid cash of $99.5 million, and exchanged its interests in certain gathering and marketing joint ventures located in southeast Texas having a total fair value of $42.0 million as consideration for these facilities. A $3.9 million gain was recorded in connection with the exchange. 5. AGREEMENTS AND TRANSACTIONS WITH DUKE ENERGY Services Agreement with Duke Energy -- Effective with the Combination, the Company entered into a services agreement with Duke Energy ("the Duke Energy Services Agreement"). Under the Duke Energy Services Agreement, Duke Energy will provide the Company with various staff and support services, including information technology products and services, payroll, employee benefits, corporate insurance, cash management, ad valorem taxes, treasury and legal functions and shareholder services. These services F-34 86 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) will be priced on the basis of a monthly charge approximating market prices. The Duke Energy Services Agreement expires on December 31, 2000. Transactions between Duke Energy and the Company -- Through June 30, 2000, the Company has conducted a series of transactions with Duke Energy in which the Company has sold a portion of its residue gas and NGLs to, purchased raw natural gas and other petroleum products from, and provided gathering and transportation services over its gathering systems and pipelines to, Duke Energy and its subsidiaries at contractual prices that have approximated market prices in the ordinary course of the Company's business. The Company anticipates continuing these transactions in the ordinary course of business. 6. AGREEMENTS AND TRANSACTIONS WITH PHILLIPS Services Agreement with Phillips -- Effective with the Combination, the Company entered into a services agreement with Phillips ("the Phillips Services Agreement"). Under the Phillips Services Agreement, Phillips will provide the Company with various staff and support services, including information technology products and services, cash management, real estate and property tax services. These services will be priced on a basis of a monthly charge equal to Phillips' fully-burdened cost of providing the services. The Phillips Services Agreement expires on December 31, 2000. Long-Term NGLs Purchases Contract with Phillips -- In connection with the Combination, the Company has agreed to maintain the NGL Output Purchase and Sale Agreement ("Phillips NGL Agreement") between Phillips and the midstream natural gas assets that were contributed by Phillips to the Company in the Combination. Under the Phillips NGL Agreement, Phillips 66 Company, a wholly-owned subsidiary of Phillips, has the right to purchase at index-based prices substantially all NGLs produced by the processing plants which were acquired by Field Services LLC from Phillips in the Combination. The Phillips NGL Agreement also grants Phillips 66 Company the right to purchase at index-based prices certain quantities of NGLs produced at processing plants that are acquired and/or constructed by the Company in the future in various counties in the Mid-Continent and Permian Basis regions, and the Austin Chalk area. The primary term of the agreement is effective until December 31, 2014. Transactions between Phillips and the Midstream Business Acquired from Phillips -- Through June 30, 2000, the Phillips' businesses (the "Phillips Combined Subsidiaries") that owned the midstream natural gas assets that were contributed to the Company in the Combination had conducted a series of transactions with Phillips in which the Phillips Combined Subsidiaries sold a portion of their residue gas and other by-products to Phillips at contractual prices that approximated market prices. In addition, Phillips Combined Subsidiaries purchased raw natural gas from Phillips at contractual prices that have approximated market prices. The Company anticipates continuing these transactions in the ordinary course of business. 7. FINANCING Credit Facility with Financial Institutions -- In March 2000, Field Services LLC entered into a $2,800 million credit facility with several financial institutions. The credit facility will be used to support a commercial paper program for short-term financing requirements. In April, 2000, Field Services LLC borrowed $2,790.9 million in the commercial paper market to fund one-time cash distributions of $1,524.5 million to Duke Energy, and $1,219.8 million to Phillips, and to meet working capital requirements. The credit facility matures on March 30, 2001, and bears interest at a rate equal to, at Field Services LLC's option, either (1) the London Interbank Offered Rate (LIBOR) plus .50% per year for the first 90 days following March 31, 2000 and LIBOR plus .625% per year thereafter, or (2) the higher of (a) the Bank of America prime rate and (b) the Federal Funds rate plus .50% per year. F-35 87 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 8. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Historically, the Company's commodity price risk management program had been directed by Duke Energy under its centralized program for controlling, managing and coordinating its management of risks. During the six months ended June 30, 1999, and the three months ended March 31, 2000, the Company recorded a hedging gain of $4.4 million and a hedging loss of $46.7 million under Duke Energy's centralized program. As of March 31, 2000, the commodity positions then held under the Duke Energy centralized program were transferred to Duke Energy. Effective April 1, 2000, the Company began directing its risk management activities, including commodity price risk for market fluctuations in the price of NGLs, independently of Duke Energy. The Company plans to use commodity-based derivative contracts to reduce the risk in the Company's overall earnings and cash flow with the primary goals of: (1) maintaining minimum cash flow to fund debt service, dividends and maintenance type capital projects; (2) avoiding disruption of the Company's growth capital and value creation process; and (3) retaining a high percentage of the potential upside relation to commodity price increases. The Company has implemented a risk management policy that provides guidelines for entering into contractual arrangements to manage commodity price exposure. Futures and swaps will be used to manage and hedge prices related to these market exposures. During the three months ended June 30, 2000, the Company recorded a hedging loss of $12.5 million under the Company's self-directed risk management program. In establishing its initial independent commodity risk management position, on April 1, 2000 the Company acquired a portion of Duke Energy's existing commodity derivatives held for non trading purposes. The absolute notional contract quantity of the positions acquired was 4,607,000 barrels of crude oil. Such positions were acquired at market value. Interest Rate Derivatives -- In the second quarter of 2000, the Company issued derivatives that reduce the Company's exposure to market fluctuations in the interest rates that will be included in the proposed public offering of debt securities to be sold in the third quarter of 2000. The Company's interest rate market exposure arises from changes in the effective interest rates at the inception of long-term financing between the date that the Company has decided to sell debt securities and the date the debt securities are actually sold. Locks and swaps are used to manage and hedge interest rates related to these market exposures. The gains, losses, and costs related to these interest rate derivatives that qualify as a hedge will not be recognized until debt securities are actually sold, and then will be recognized over the estimated life of the debt securities. At June 30, 2000, the Company's net realized and unrealized losses related to the interest rate hedges was $1.9 million. At June 30, 2000, the absolute notional contract quantity of interest rate derivatives held for hedging purposes for the effective interest rates at the inception of long-term financing was $1,150.0 million. 9. COMMITMENTS AND CONTINGENT LIABILITIES The midstream natural gas industry has seen an increase in the number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. Many of these cases are now being brought as class actions. The Company and its subsidiaries are currently named as defendants in certain of these cases. Management believes the Company and its subsidiaries have meritorious defenses to these cases, and therefore will continue to defend them vigorously. However, these class actions can be costly and time consuming to defend. F-36 88 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) A judgment has been entered in the case of Chevron U.S.A., Inc. versus GPM Gas Corporation (GPM), a wholly owned subsidiary of Field Services LLC, upholding and construing most favored nations clauses in three 1961 West Texas gas purchase contracts. Although a federal district court decided that GPM owes Chevron damages in the amount of $13,828,030 through July 31, 1998, plus 6 percent interest from that date and attorneys' fees in the amount of $329,994. GPM has appealed the judgment to the U.S. Court of Appeals for the Fifth Circuit. 10. STOCK-BASED COMPENSATION, PENSION AND OTHER BENEFITS Effective March 31, 2000, participation by the Company's employees in Duke Energy's non-contributory trustee pension plan and employee savings plan were terminated. Effective April 1, 2000, the Company's employees began participation in the Company's employee savings plan, in which the Company contributes 4% of each eligible employee's qualified wages. Additionally, the Company matches employees' contributions to the plan up to 6% of qualified wages. In June 2000, the Company granted approximately 37,000 restricted shares of Duke Energy common stock to key employees of the Company under Duke Energy's stock incentive plans. These restricted shares vest over periods ranging from two to three years. Under the grant terms of the restricted shares, when the Company completes its initial public stock offering, these restricted shares in Duke Energy common stock will be converted to restricted shares of the Company's common stock under a formula that equates the value of the Company's common shares at the initial public offering to the value of the Duke Energy restricted common shares at the grant date. Also in June 2000, the Company granted approximately 105,000 stock options of Duke Energy's common stock under Duke Energy's 1999 Stock Incentive Plan. The exercise price for these stock options is $59. Under the grant terms of the stock options, when the Company completes its initial public stock offering, these stock options in Duke Energy common stock will be converted to stock options of the Company's common stock under a formula that equates the value of the Company's stock options at the initial public offering to the value of the Duke Energy stock options at the grant date. 11. BUSINESS SEGMENTS The Company operates in two principal business segments as follows: (1) natural gas gathering, processing, transportation, marketing and storage, and (2) natural gas liquids 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 1. Foreign operations are not material and are therefore not separately identified. F-37 89 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) The following table sets forth the Company's segment information for the six months ended June 30, 1999 and 2000 and as of December 31, 1999 and June 30, 2000. FOR THE SIX MONTH PERIODS ENDED ------------------------------- JUNE 30, JUNE 30, 1999 2000 -------------- -------------- (IN THOUSANDS) Operating revenues: Natural gas............................................... $ 847,782 $2,585,992 NGLs...................................................... 396,042 1,607,882 Intersegment(a)........................................... (134,980) (570,303) ---------- ---------- Total operating revenues.......................... 1,108,844 3,623,571 ---------- ---------- Margin: Natural gas............................................... 184,365 482,066 NGLs...................................................... 8,169 26,468 ---------- ---------- Total margin...................................... 192,534 508,534 ---------- ---------- Other operating costs: Natural gas............................................... 78,176 139,516 NGLs...................................................... 560 1,175 Corporate................................................. 30,759 69,976 ---------- ---------- Total other operating costs....................... 109,495 210,667 ---------- ---------- Equity in earnings of unconsolidated affiliates: Natural Gas............................................... 10,275 13,888 NGLs...................................................... 819 ---------- ---------- Total equity in earnings of unconsolidated affiliates...................................... 10,275 14,707 ---------- ---------- EBITDA(b): Natural gas............................................... 116,464 356,438 NGLs...................................................... 7,609 26,112 Corporate................................................. (30,759) (69,976) ---------- ---------- Total EBITDA...................................... 93,314 312,574 ---------- ---------- Depreciation and amortization: Natural gas............................................... 53,612 97,667 NGLs...................................................... 1,249 6,112 Corporate................................................. 1,145 1,580 ---------- ---------- Total depreciation and amortization............... 56,006 105,359 ---------- ---------- EBIT: Natural gas............................................... 62,852 258,771 NGLs...................................................... 6,360 20,000 Corporate................................................. (31,904) (71,556) ---------- ---------- Total EBIT........................................ 37,308 207,215 ---------- ---------- Corporate interest expense.................................. 25,535 59,851 F-38 90 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) FOR THE SIX MONTH PERIODS ENDED ------------------------------- JUNE 30, JUNE 30, 1999 2000 -------------- -------------- (IN THOUSANDS) ---------- ---------- Income before income taxes: Natural gas............................................... 62,852 258,771 NGLs...................................................... 6,360 20,000 Corporate................................................. (57,439) (131,407) ---------- ---------- Total income before income taxes.................. $ 11,773 $ 147,364 ========== ========== AS OF ------------------------------ DECEMBER 31, JUNE 30, 1999 2000 -------------- ------------- (IN THOUSANDS) Total assets: Natural gas............................................... $2,754,447 $4,833,083 NGLs...................................................... 225,702 197,624 Corporate(c).............................................. 491,686 945,080 ---------- ---------- Total assets...................................... $$3,471,835 $5,975,787 ========== ========== - --------------- (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, less interest income. EBITDA is not a measurement presented in accordance with generally accepted accounting principles. You should not consider it 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 our profitability or liquidity. EBITDA is included as a supplemental disclosure because it may provide useful information regarding our ability to service debt and to fund capital expenditures. However, not all EBITDA may be available to service debt. (c) Includes items such as unallocated working capital, intercompany accounts and intangible and other assets. F-39 91 REPORT OF INDEPENDENT AUDITORS The Board of Directors and Stockholder Phillips Gas Company We have audited the accompanying consolidated balance sheets of Phillips Gas Company as of December 31, 1998 and 1999, and the related consolidated statements of income, changes in stockholders' equity (deficit) and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Phillips Gas Company at December 31, 1998 and 1999, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. ERNST & YOUNG LLP Tulsa, Oklahoma March 6, 2000 F-40 92 PHILLIPS GAS COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS) AT DECEMBER 31, ----------------------- 1998 1999 ---------- ---------- ASSETS Cash and cash equivalents................................... $ 27,045 $ 164,078 Accounts receivable Affiliate................................................. 51,415 104,159 Trade (less allowances: 1998 -- $648; 1999 -- $329)....... 93,764 104,555 Inventories................................................. 4,957 3,066 Deferred income taxes....................................... 2,160 30,293 Prepaid expenses and other current assets................... 2,916 3,407 ---------- ---------- Total Current Assets.............................. 182,257 409,558 Investments and long-term receivables....................... 13,013 9,585 Properties, plants and equipment (net)...................... 943,302 995,406 Deferred gathering fees..................................... 43,531 50,662 ---------- ---------- Total............................................. $1,182,103 $1,465,211 ========== ========== LIABILITIES Accounts payable Affiliate................................................. $ 23,946 $ 106,410 Trade..................................................... 139,729 178,891 Deferred purchase obligation due within one year............ -- 8,300 Accrued income and other taxes.............................. 8,363 12,140 Other accruals.............................................. 212 63 ---------- ---------- Total Current Liabilities......................... 172,250 305,804 Long-term debt due to affiliate............................. 560,000 1,350,000 Other liabilities and deferred credits...................... 4,908 3,065 Deferred income taxes....................................... 68,160 128,907 Deferred gain on sale of assets............................. 16,237 15,154 ---------- ---------- Total Liabilities................................. 821,555 1,802,930 ---------- ---------- STOCKHOLDER'S EQUITY/(DEFICIT) Common stock -- 1,000 shares authorized at $.01 par value; issued and outstanding -- 1,000 shares Par value................................................. -- -- Capital in excess of par.................................. 142,917 -- Retained earnings/(accumulated deficit)..................... 217,631 (337,719) ---------- ---------- Total Stockholder's Equity/(Deficit).............. 360,548 (337,719) ---------- ---------- Total............................................. $1,182,103 $1,465,211 ========== ========== See Notes to Financial Statements. F-41 93 PHILLIPS GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS) YEARS ENDED DECEMBER 31, ------------------------------------ 1997 1998 1999 ---------- ---------- ---------- REVENUES Natural gas liquids...................................... $ 711,785 $ 514,758 $ 714,439 Residue gas.............................................. 923,376 722,931 786,739 Other.................................................... 80,994 68,919 90,234 ---------- ---------- ---------- Total Revenues................................. 1,716,155 1,306,608 1,591,412 ---------- ---------- ---------- COSTS AND EXPENSES Gas purchases............................................ 1,268,570 940,464 1,148,910 Operating expenses....................................... 190,385 186,572 176,864 Selling, general and administrative expenses............. 14,990 13,290 15,560 Depreciation............................................. 76,737 77,240 80,458 Interest expense......................................... 20,468 36,194 35,643 ---------- ---------- ---------- Total Costs and Expenses....................... 1,571,150 1,253,760 1,457,435 ---------- ---------- ---------- Income before income taxes............................... 145,005 52,848 133,977 Provision for income taxes............................... 54,998 21,535 52,244 ---------- ---------- ---------- NET INCOME............................................... 90,007 31,313 81,733 Preferred stock dividend requirements.................... 30,813 -- -- ---------- ---------- ---------- NET INCOME APPLICABLE TO COMMON STOCK.................... $ 59,194 $ 31,313 $ 81,733 ========== ========== ========== See Notes to Financial Statements. F-42 94 PHILLIPS GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) YEARS ENDED DECEMBER 31, --------------------------------- 1997 1998 1999 --------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES Net income................................................ $ 90,007 $ 31,313 $ 81,733 Adjustments to reconcile net income to net cash provided by operating activities Non-working capital adjustments Depreciation......................................... 76,737 77,240 80,458 Deferred taxes....................................... 38,700 41,550 60,747 Deferred gathering fees.............................. (7,803) (7,231) (7,131) Gain on sale of assets............................... (1,965) (9,848) (907) Other................................................ (2,119) (6,795) 644 Working capital adjustments Decrease (increase) in accounts receivable........... 70,180 27,847 (63,465) Decrease (increase) in inventories................... (798) 2,259 1,891 Decrease (increase) in prepaid expenses and other current assets, including deferred taxes........... (1,654) 3,084 (28,624) Increase (decrease) in accounts payable.............. (30,027) (98,776) 121,626 Increase (decrease) in taxes and other accruals...... (12,712) (6,191) 3,628 --------- --------- --------- Net Cash Provided by Operating Activities................. 218,546 54,452 250,600 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures and investments...................... (116,520) (83,152) (124,009) Proceeds from asset dispositions.......................... 5,499 17,611 442 --------- --------- --------- Net Cash Used for Investing Activities.................... (111,021) (65,541) (123,567) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Preferred stock dividends................................. (34,922) -- -- Redemption of preferred stock............................. (345,000) -- -- Issuance of debt.......................................... 345,000 -- 10,000 Repayment of debt......................................... -- (95,000) -- Payment of note payable................................... (18,500) -- -- --------- --------- --------- Net Cash Provided by (Used for) Financing Activities...... (53,422) (95,000) 10,000 --------- --------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS...... 54,103 (106,089) 137,033 CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR.............. 79,031 133,134 27,045 --------- --------- --------- CASH AND CASH EQUIVALENTS, END OF YEAR.................... $ 133,134 $ 27,045 $ 164,078 ========= ========= ========= See Notes to Financial Statements. F-43 95 PHILLIPS GAS COMPANY CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY/(DEFICIT) (IN THOUSANDS) SHARES COMMON STOCK RETAINED -------------------- --------------------- EARNINGS/ PREFERRED COMMON PREFERRED PAR CAPITAL IN (ACCUMULATED STOCK STOCK STOCK VALUE EXCESS OF PAR DEFICIT) ----------- ------ --------- ----- ------------- ------------ December 31, 1996............ 13,800,000 1,000 $ 345,000 -- $ 142,917 $ 131,233 Net income................... 90,007 Cash dividends paid on preferred stock............ (34,922) Redemption of preferred stock...................... (13,800,000) (345,000) ----------- ----- --------- -- --------- --------- December 31, 1997............ -- 1,000 -- -- 142,917 186,318 Net income................... 31,313 ----------- ----- --------- -- --------- --------- December 31, 1998............ -- 1,000 -- -- 142,917 217,631 Net income................... 81,733 Dividend declared............ (142,917) (637,083) ----------- ----- --------- -- --------- --------- December 31, 1999............ -- 1,000 $ -- -- $ -- $(337,719) =========== ===== ========= == ========= ========= See Notes to Financial Statements. F-44 96 PHILLIPS GAS COMPANY NOTES TO FINANCIAL STATEMENTS 1. ACCOUNTING POLICIES Consolidation Principles and Basis of Presentation -- Phillips Gas Company (PGC or the company) is a subsidiary of Phillips Petroleum Company (Phillips). Phillips owns 100 percent of the company's outstanding common stock. Majority-owned, controlled subsidiaries are consolidated. Investments in affiliates in which the company owns 20 percent to 50 percent of voting control are accounted for using the equity method. Use of Estimates -- The preparation of financial statements in conformity with generally accepted accounting principles requires Management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from the estimates and assumptions used. Cash and Cash Equivalents -- Cash and cash equivalents are held by Phillips as part of its centralized cash management system. Interest is paid monthly based on the average daily balance of funds invested at a rate equal to the weighted-average rate earned by Phillips or at the applicable federal funds rate. Cash equivalents are highly liquid short-term investments that are readily convertible to known amounts of cash and have original maturities within three months from their date of purchase. Inventories -- Helium inventory is valued at cost, which is lower than market, mainly on the last-in, first-out (LIFO) basis. Materials and supplies are valued at, or below, average cost. Derivative Contracts -- The company uses commodity swap and option contracts. Commodity option contracts are recorded at market value through monthly adjustments for unrealized gains and losses; however, swaps are not marked to market. Gains and losses are recognized during the same period in which the gains and losses from the underlying exposures being hedged are recognized. In 1998 and 1999, the net realized and unrealized gains and losses from derivative contracts were not material to the company's financial statements. Revenue Recognition -- Revenues associated with sales of natural gas, natural gas liquids, and all other items are recorded when title passes to the customer upon delivery. Gas Exchanges and Imbalances -- Quantities of gas over-delivered or under-delivered related to exchange or imbalance agreements are recorded monthly as receivables or payables using the index price or the average price of gas at the plant or system. Generally, these balances are settled with deliveries of gas. Depreciation -- Depreciation of plants and systems is determined using the group composite straight-line method over an estimated life of 20 years for most of the assets. Plants and systems are grouped for this purpose based on their relative similarity and the degree of physical and economic interdependence between individual pieces of equipment. Other relatively insignificant properties and equipment are depreciated using the straight-line method over the estimated useful lives of the individual assets. Impairment of Assets -- Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows are less than the carrying value of the asset group, the carrying value is written down to estimated fair value. The expected future cash flows used for impairment reviews and related fair value calculations are based on the production volumes, prices and costs considering all available evidence at the date of the review. F-45 97 PHILLIPS GAS COMPANY NOTES TO FINANCIAL STATEMENTS--CONTINUED Property Dispositions -- When complete units of depreciable property are retired or sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in income. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation with no recognition of gain or loss. Retirements or sales of equipment, whether complete units of depreciable property or less than complete units of depreciable property, have been infrequent and not significant to the financial statements. Environmental Costs -- Environmental expenditures are expensed or capitalized as appropriate, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. Income Taxes -- Deferred taxes are computed using the liability method and provided on all temporary differences between the financial reporting basis and the tax basis of the assets and liabilities. Allowable tax credits are applied currently as reductions of the provision for income taxes. The company's results of operations for 1998 and 1999 were included in the consolidated federal income tax return of Phillips, with any resulting tax liability or refund settled with Phillips on a current basis. Income tax expense represents amounts due Phillips for federal income taxes as if the company were filing a separate return, except that the same principles and elections used in the consolidated return were applied. Results of operations for 1997 were included in the separate federal income tax return of Phillips Gas Company. Income Per Share of Common Stock -- Income per share of common stock has been omitted from the consolidated statement of income because all common stock is owned by Phillips. Comprehensive Income -- The company does not have any items of other comprehensive income, as defined in Financial Accounting Standards Board (FASB) Statement No. 130, "Reporting Comprehensive Income." 2. THE COMPANY'S BUSINESS The company owns and operates natural gas gathering systems and processing facilities concentrated in four major gas-producing areas in the Southwest. The company's core gathering and processing regions are concentrated in the Permian Basin area of West Texas and southeastern New Mexico, the Panhandle areas of Texas and Oklahoma, and central and western Oklahoma. Under FASB Statement No. 131, "Disclosures about Segments of an Enterprise and Related Information," the four regions have been aggregated into a single segment for financial reporting purposes. At December 31, 1999, the company wholly owned 15 natural gas liquids extraction plants, and had an interest in another. The plants are located in Texas (9), Oklahoma (3), and New Mexico (4). During 1999, the company purchased a co-venturer's interest in the Artesia plant and gathering system in New Mexico that the company had operated under a construction and operating agreement since 1959. The company sells substantially all of its natural gas liquids to Phillips. The company is able to interconnect to major gas transmission pipelines in each of its regions in order to sell residue gas to local distribution companies, electric utilities, various other business and industrial users and marketers. The company's major residue gas markets are located primarily in Texas, Oklahoma and the midwestern United States. F-46 98 PHILLIPS GAS COMPANY NOTES TO FINANCIAL STATEMENTS--CONTINUED 3. INVENTORIES Inventories at December 31 consisted of the following: 1998 1999 ------ ------ (IN THOUSANDS) Helium...................................................... $1,027 $ -- Materials, supplies and other............................... 3,930 3,066 ------ ------ $4,957 $3,066 ====== ====== The company's helium inventory was sold in March 1999 for $4,989,000, resulting in after-tax income of $2,575,000. 4. INVESTMENTS AND LONG-TERM RECEIVABLES Components of investments and long-term receivables at December 31 were as follows: 1998 1999 ------- ------ (IN THOUSANDS) Investment in affiliated company............................ $ 3,328 $3,421 Long-term receivables....................................... 9,685 6,164 ------- ------ $13,013 $9,585 ======= ====== In 1993 the company formed GPM Gas Gathering L.L.C. (GGG), a limited liability company in which PGC invested approximately $4 million in exchange for a 50 percent equity interest. In December 1993, the company sold a portion of its gas gathering assets in the West Texas region of the Permian Basin to GGG for $138 million. GGG is providing gas gathering services to the company under a twenty-year contract. This contract does not represent a take-or-pay or unconditional purchase obligation. Because of the company's continuing involvement in GGG, a $22 million gain from the sale of the assets was deferred and is being recognized over the economic life of the gathering assets. The deferred gain recognized during 1998 and 1999 was $1,082,000 and $1,083,000, respectively. Distributions received from GGG during 1998 and 1999 were $1,153,000 and $955,000 respectively. See Note 10 for the gathering fees paid by the company to GGG under this contract. 5. PROPERTIES, PLANTS AND EQUIPMENT Properties, plants and equipment (net) at December 31 included the following: USEFUL LIFE 1998 1999 ----------- ---------- ---------- (IN THOUSANDS) Gathering.................................... 15-20 Years $1,529,026 $1,657,605 Processing................................... 15-20 Years 561,170 591,127 Work in progress............................. 42,694 6,484 Other........................................ 3-5 Years 10,670 11,788 ---------- ---------- Total property, plant & equipment (at cost)...................................... 2,143,560 2,267,004 Less accumulated depreciation and amortization............................... 1,200,258 1,271,598 ---------- ---------- $ 943,302 $ 995,406 ========== ========== F-47 99 PHILLIPS GAS COMPANY NOTES TO FINANCIAL STATEMENTS--CONTINUED 6. DEBT Long-term debt due to affiliate at December 31 was: 1998 1999 -------- ---------- (IN THOUSANDS) Note due 2001............................................... $215,000 $ 225,000 Note due 2002............................................... -- 780,000 Note due 2005............................................... 345,000 345,000 -------- ---------- $560,000 $1,350,000 ======== ========== On December 9, 1999, Phillips Gas Company declared and distributed a dividend to Phillips in the form of a note payable in the amount of $780 million. The note payable is due in full at maturity on December 9, 2002, bears interest at a rate of 5.74 percent per annum, and may be paid prior to maturity at any time without penalty or premium. The amount of the dividend exceeded the company's historical-cost-based net assets, resulting in a negative balance in stockholder's equity. The declaration and payment of dividends is at the discretion of the company's Board of Directors. In connection with each dividend declaration, the Board of Directors makes a determination that, based upon its familiarity with the company's business, prospects and financial condition, the company's recent earnings history and forecast, an appraisal of the company's assets and discussions with the company's executive officers, attorneys and accountants, the dividend is a permitted dividend under Delaware law. This determination was made prior to the declaration of the $780 million dividend made on December 9, 1999. The note due 2001 bears interest at LIBOR plus 1/2 percent per annum (6.33 percent at December 31, 1999). Any amount repaid may be reborrowed as long as the agreement is in effect. The note due 2005 bears interest at the applicable federal mid-term rate (6.03 percent monthly rate for December 1999). The carrying amount of the floating-rate debt approximates fair value. 7. FINANCIAL INSTRUMENTS Concentrations of Credit Risk The company's financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, accounts receivable and over-the-counter derivative contracts. Derivative contracts are immaterial to the financial statements of the company. The company's cash and cash equivalents are held by Phillips as part of its centralized cash management system. Cash equivalents are in high-quality securities placed with major international banks and financial institutions. Phillips' investment policy limits the company's exposure to concentrations of credit risk with respect to its cash equivalent investments. The company's affiliate receivables result primarily from its sales of natural gas liquids and residue gas to Phillips. The company's trade receivables result primarily from domestic sales of residue gas to local distribution companies, electric utilities, various other business and industrial end-users, and marketers. The company routinely assesses the financial strength of its unaffiliated residue-gas customers. The company considers its concentrations of credit risk, other than those with Phillips, to be limited. F-48 100 PHILLIPS GAS COMPANY NOTES TO FINANCIAL STATEMENTS--CONTINUED Fair Values of Financial Instruments The following methods and assumptions were used by the company in estimating the fair value of its financial instruments: Cash and cash equivalents: The carrying amount reported in the balance sheet approximates fair value because of the short-term nature of these investments. Deferred purchase obligation due within one year: The carrying amount reported in the balance sheet approximates fair value because of the short-term nature of the obligation. Long-term debt: The carrying amount of the company's floating- and fixed-rate debt approximates fair value based on current market rates. 8. PREFERRED STOCK On December 15, 1997, the company redeemed its 13,800,000 shares of Series A 9.32% Cumulative Preferred Stock at par. The liquidation value for each Series A preferred share was $25, plus $.2006 for unpaid dividends. 9. CONTINGENT LIABILITIES The company is a party to a number of legal proceedings pending in various courts or agencies for which no provision has been made. Costs related to contingencies are provided when a loss is probable and the amount can be reasonably estimated. These accruals are not discounted for delays in future payment and are not reduced for potential insurance recoveries. If applicable, undiscounted receivables are accrued for probable insurance recoveries. A judgment has been entered in the case of Chevron U.S.A., Inc. versus GPM Gas Corporation (GPM), a wholly owned subsidiary of the company, upholding and construing most favored nations clauses in three 1961 West Texas gas purchase contracts. Although a federal district court decided that GPM owes Chevron damages in the amount of $13,828,030 through July 31, 1998, plus 6 percent interest from that date and attorneys' fees in the amount of $329,994, GPM has appealed the judgment to the U.S. Court of Appeals for the Fifth Circuit. Based on currently available information, after taking into consideration amounts already accrued and the pending appeal in the Chevron litigation, PGC believes that any liability resulting from any of the above matters will not have a material adverse effect on its financial statements. However, such matters could have a material effect on results of operations in a particular quarter or fiscal year as they develop or as new issues are identified. 10. RELATED PARTY TRANSACTIONS Significant transactions with affiliated parties were: 1997 1998 1999 -------- -------- -------- (IN THOUSANDS) Operating revenues(a)................................ $758,700 $537,528 $725,478 Gas purchases(b)..................................... 118,827 76,617 100,253 Operating expenses(c)(e)(h).......................... 115,698 113,475 110,897 Selling, general and administrative expenses(c)(d)(e).................................. 12,828 10,059 13,306 Interest income(f)................................... 2,701 2,430 2,487 Interest expense(g).................................. 20,340 35,880 35,610 F-49 101 PHILLIPS GAS COMPANY NOTES TO FINANCIAL STATEMENTS--CONTINUED - ------------ (a) The company sells a portion of its residue gas and other by-products to Phillips at contractual prices that approximate market prices. The company sells substantially all of its natural gas liquids to Phillips at prices based upon quoted market prices for fractionated natural gas liquids, less charges for transportation, fractionation and quality-adjustment fees. Effective January 1, 2000, the pricing formula contained in the natural gas liquids supply arrangement with Phillips was renegotiated, as allowed under the contract, to reflect current market conditions. The new arrangement will be maintained for an initial term of 15 years. PGC believes that the loss of Phillips as a natural gas liquids customer would have a material, adverse effect on its revenues and operating results. (b) The company purchases raw gas from Phillips at contractual prices that approximate market prices. During 1999, Phillips provided the company with approximately 8 percent of its raw gas throughput, under long-term supply contracts, making Phillips its largest single supplier. PGC believes that the loss of Phillips as a raw gas supplier would have a material adverse effect on its dedicated raw gas supplies and its operating results. (c) Phillips provides the company with various field services (costs included in operating expenses) and other general administrative services (costs included in selling, general and administrative expenses) including insurance, personnel administration, office space, communications, data processing, engineering, automotive and other field equipment, and other miscellaneous services. Charges for these services and benefits are based on usage and actual costs or other allocation methods the company considers reasonable. (d) Phillips charges the company a portion of its corporate indirect overhead costs including executive, legal, treasury, planning, tax, auditing and other corporate services, under an administrative services agreement. Charges for these services and benefits are based on usage and actual costs or other allocation methods the company considers reasonable. (e) All operational and staff personnel requirements are met by Phillips' employees, most of whom are associated with the GPM Gas Services Company division of Phillips. All services provided by Phillips, including (c) and (d) above, are priced to reimburse Phillips for its actual costs. Charges for these services and benefits are based on usage and actual costs or other allocation methods the company considers reasonable. Selling, general and administrative expenses included a severance charge reversal of $2 million in 1998, and a $2 million severance charge in 1999. (f) The company earns interest from participation in Phillips' centralized cash management system. (g) The company incurs interest expense on borrowings from and debt to Phillips. (h) Beginning January 1, 1994, the company began paying GGG a fee for gas gathering services under a long-term contract. The gas gathering fee structure in the long-term contract contains a component that is paid to GGG in an accelerated manner. Because GGG is providing the same gas gathering services to the company over the contract period, recognition of expenses related to this component of the gathering fee is deferred and recognized on a straight-line basis through the remaining period of the long-term contract. In 1997, 1998 and 1999, the total gathering fees were $42,755,000, $42,951,000 and $41,447,000, respectively, of which $34,952,000, $35,720,000 and $34,316,000, respectively, were expensed. The company provides Phillips with other minor administrative services. Costs allocated to Phillips for these services have been netted against the above direct charges from Phillips and were $120,000, $79,000 and $72,000 in 1997, 1998 and 1999, respectively. The company periodically buys from, or sells to, Phillips various assets used in the operations of the business. These net acquisitions were recorded at the assets' historical net book values, which generally approximated fair market value, and totaled $22,000, $60,000 and $239,000 in 1997, 1998 and 1999, F-50 102 PHILLIPS GAS COMPANY NOTES TO FINANCIAL STATEMENTS--CONTINUED respectively. Prior to such acquisition or sale, the company paid or received a fee based on usage of such assets (included in operating expenses above). In addition, the company purchases plastic pipe from Phillips, which is used in the construction of gathering systems. Purchases in 1997, 1998 and 1999 were $3,942,000, $2,276,000 and $2,175,000, respectively. 11. EMPLOYEE BENEFIT PLANS Substantially all employees of Phillips' GPM Gas Services Company division participate in Phillips' benefit plans, including pension plans, defined contribution plans, stock option plans and health and life insurance plans. Costs are allocated to the company based principally on base payroll costs of participating employees. Total benefit plan costs charged to the company were $22,095,000, $22,522,000 and $21,005,000 for the years ended 1997, 1998 and 1999, respectively. 12. INCOME TAXES Taxes charged to income were: 1997 1998 1999 ------- -------- ------- (IN THOUSANDS) Federal Current.............................................. $17,117 $(23,339) $19,072 Deferred............................................. 31,114 40,747 25,646 State Current.............................................. 443 215 558 Deferred............................................. 6,324 3,912 6,968 ------- -------- ------- $54,998 $ 21,535 $52,244 ======= ======== ======= Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Major components of the company's deferred taxes at December 31 were: 1998 1999 -------- -------- (IN THOUSANDS) Deferred Tax Liabilities Depreciation................................................ $164,065 $188,829 Prepaid gas gathering fees.................................. 17,612 20,374 -------- -------- Total deferred tax liabilities.............................. 181,677 209,203 -------- -------- Deferred Tax Assets Alternative minimum tax credit carryforward................. 55,385 55,385 Net operating loss carryforwards............................ 45,104 36,312 Deferred gain on sale of assets............................. 6,495 6,062 Investment in partnerships.................................. 3,553 4,549 Contingency accruals........................................ 2,973 4,924 Benefit plan accruals....................................... 1,715 2,030 Other (net)................................................. 452 1,327 -------- -------- Total deferred tax assets................................... 115,677 110,589 -------- -------- Net deferred tax liabilities................................ $ 66,000 $ 98,614 ======== ======== F-51 103 PHILLIPS GAS COMPANY NOTES TO FINANCIAL STATEMENTS--CONTINUED The tax bases in the company's assets were increased as a result of the 1992 transfer of substantially all of its assets to GPM Gas Corporation and the subsequent issuance and sale of preferred stock. The net operating loss carryforwards and the alternative minimum tax credit carryforwards resulted primarily from tax depreciation on the increased bases in the company's assets. The company believes it is more likely than not that it will fully realize its deferred tax assets, and, accordingly, a valuation allowance has not been provided. Management expects that the deferred tax assets will be realized as reductions in future taxable operating income or by utilizing available tax planning strategies. Uncertainties that may affect the realization of these assets include tax law changes, change in control as discussed in Note 16, and the future level of product costs. Therefore, the company periodically reviews its ability to realize these assets and will establish a valuation allowance if needed. At December 31, 1999, the company had net operating loss carryforwards of $71 million for U.S. income tax purposes, and $221 million for state income tax purposes. The U.S. income tax carryforwards begin expiring in 2009, and the state income tax carryforwards begin expiring in 2000. The alternative minimum tax credit can be carried forward indefinitely to reduce the company's regular tax liability. The reconciliation of income tax at the federal statutory rate with the provision for income taxes follows: PERCENT OF PRETAX INCOME ------------------ 1997 1998 1999 1997 1998 1999 ------- ------- ------- ---- ---- ---- (IN THOUSANDS) Federal statutory income tax....... $50,752 $18,497 $46,892 35.0% 35.0% 35.0% State income tax................... 4,399 2,683 4,893 3.0 5.1 3.7 Other.............................. (153) 355 459 (0.1) 0.6 0.3 ------- ------- ------- ---- ---- ---- $54,998 $21,535 $52,244 37.9% 40.7% 39.0% ======= ======= ======= ==== ==== ==== 13. KEEP WELL REPLACEMENT AGREEMENT The redemption of the company's outstanding shares of Series A 9.32% Cumulative Preferred Stock on December 15, 1997, cancelled the previous Keep Well Agreement and triggered the need for a Keep Well Replacement Agreement between Phillips and PGC. The Keep Well Replacement Agreement provides for Phillips to maintain PGC's consolidated tangible net worth in an amount not less than $50 million, or to irrecoverably and unconditionally guaranty the full and timely performance, payment and discharge by PGC of all its obligations and liabilities. Effective February 1, 2000, Phillips furnished a guaranty to GGG assuring payment by PGC of all its existing or future obligations and liabilities to GGG. F-52 104 PHILLIPS GAS COMPANY NOTES TO FINANCIAL STATEMENTS--CONTINUED 14. CASH FLOW INFORMATION 1997 1998 1999 ------- ------- -------- (IN THOUSANDS) Non-Cash Investing and Financing Activities Liquidating dividend to parent company in the form of a promissory note...................................... $ -- $ -- $780,000 Deferred payment obligation to purchase property, plant and equipment........................................ -- -- 8,300 Cash Payments Interest............................................... 20,452 36,108 32,789 Income taxes, including payments to Phillips........... 25,432 123 20,773 The deferred purchase obligation resulted from the company's July 1, 1999, purchase of American Liberty Oil Company's interest in the Artesia plant and gathering system in New Mexico. At the time of closing, a partial cash payment was made. A second and final payment was made on January 3, 2000. 15. OTHER FINANCIAL INFORMATION 1997 1998 1999 ------- ------- ------- (IN THOUSANDS) Taxes other than income and payroll taxes............... $10,765 $10,772 $12,626 16. PROPOSED BUSINESS COMBINATION On December 16, 1999, Phillips and Duke Energy Corporation (Duke Energy) announced that they had signed definitive agreements to combine the two companies' gas gathering, processing and marketing businesses to form a new midstream company to be called Duke Energy Field Services, LLC (Field Services LLC). The definitive agreements have been unanimously approved by both companies' Boards of Directors. Subject to regulatory approval, the transaction is expected to close by the end of the first quarter of 2000. If the transaction closes as expected, the subsidiaries of PGC will be contributed to Field Services LLC in a partially tax-free exchange, and those subsidiaries will cease to be wholly owned subsidiaries of Phillips. As part of the transaction, the existing natural gas liquids purchase contract between Phillips and the company will be maintained by the new company for an initial term of 15 years. At closing, Duke Energy will own about 70 percent of Field Services LLC, and Phillips will own about 30 percent. 17. IMPACT OF TRANSITION TO YEAR 2000 (UNAUDITED) PGC relies on Phillips for computer systems, hardware and software for operation of its facilities and business support systems. PGC's operations and facilities were included as part of Phillips' companywide Year 2000 Project that addressed the issue of computer programs and embedded computer chips being unable to distinguish between the year 1900 and the year 2000. That project is now complete. With the rollover into 2000, neither PGC nor Phillips experienced any significant Year 2000 failures. Some minor Year 2000 issues occurred and were resolved, but none have had a material impact on PGC's results of operations, liquidity, financial condition or safety record. The total costs associated with Year 2000 issues were not material to PGC's or Phillips' financial position. Phillips continues to monitor its mission-critical computer applications and those of its suppliers and vendors throughout the year 2000 to ensure that any latent Year 2000 matters that may arise are addressed promptly. F-53 105 PHILLIPS GAS COMPANY CONSOLIDATED STATEMENT OF INCOME (IN THOUSANDS) THREE MONTHS ENDED MARCH 31, --------------------- 1999 2000 -------- -------- (UNAUDITED) REVENUES Natural gas liquids......................................... $104,035 $286,961 Residue gas................................................. 141,706 224,524 Other....................................................... 19,910 33,345 -------- -------- Total Revenues......................................... 265,651 544,830 -------- -------- COSTS AND EXPENSES Gas purchases............................................... 189,421 377,659 Operating expenses.......................................... 42,741 47,285 Selling, general and administrative expenses................ 4,880 4,251 Depreciation................................................ 19,262 20,700 Interest expense............................................ 7,255 20,492 -------- -------- Total Costs and Expenses............................... 263,559 470,387 -------- -------- Income before income taxes.................................. 2,092 74,443 Provision for income taxes.................................. 851 29,110 -------- -------- NET INCOME.................................................. $ 1,241 $ 45,333 ======== ======== See Notes to Financial Statements. F-54 106 PHILLIPS GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) THREE MONTHS ENDED MARCH 31, --------------------- 1999 2000 -------- -------- (UNAUDITED) CASH FLOWS FROM OPERATING ACTIVITIES Net Income.................................................. $ 1,241 $ 45,333 Adjustments to reconcile net income to net cash provided by operating activities Non-working capital adjustments Depreciation......................................... 19,262 20,700 Deferred taxes....................................... 5,783 13,891 Deferred gathering fees.............................. (1,679) (1,651) Gain on sale of assets............................... (212) (88) Other................................................ 337 1,896 Working capital adjustments Decrease (increase) in accounts receivable........... 4,028 (13,646) Decrease (increase) in inventories................... 1,000 (298) Decrease in prepaid expenses and other current assets, including deferred taxes.................. 555 14,338 Decrease in accounts payable......................... (17,224) (64,535) Decrease in taxes and other accruals................. (1,875) (753) -------- -------- Net Cash Provided by Operating Activities................... 11,216 15,187 -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures and investments........................ (13,532) (11,985) Proceeds from asset dispositions............................ 55 673 -------- -------- Net Cash Used for Investing Activities...................... (13,477) (11,312) -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES Payment of note payable..................................... -- (8,300) -------- -------- Net Cash Used for Financing Activities...................... -- (8,300) -------- -------- NET CHANGE IN CASH AND CASH EQUIVALENTS..................... (2,261) (4,425) Cash and cash equivalents at beginning of period............ 27,045 164,078 -------- -------- Cash and Cash Equivalents at End of Period.................. $ 24,784 $159,653 ======== ======== See Notes to Financial Statements. F-55 107 PHILLIPS GAS COMPANY NOTES TO FINANCIAL STATEMENTS 1. INTERIM FINANCIAL INFORMATION The financial information for the interim periods presented in the financial statements included in this report is unaudited and includes all known accruals and adjustments that Phillips Gas Company (PGC or the company) considers necessary for a fair statement of the results for such periods. All such adjustments are of a normal and recurring nature. 2. BUSINESS COMBINATION On March 31, 2000, Phillips Petroleum Company (Phillips) combined its gas gathering, processing and marketing business with Duke Energy Corporation's (Duke Energy) gas gathering, processing and marketing business to form a new midstream company called Duke Energy Field Services LLC (DEFS). PGC contributed its holdings in its limited-liability-company subsidiaries to DEFS in a partially tax-free exchange. The operations of these subsidiaries comprise substantially all of the operations of PGC. Effective March 31, 2000, the company is accounting for its investment in DEFS using the equity method. In connection with the combination DEFS borrowed approximately $2.75 billion of short-term debt. In April 2000, the proceeds of the debt were used to make one-time cash distributions of approximately $1,525 million to Duke Energy and $1,220 million to Phillips. Duke Energy owns about 70 percent of DEFS, and Phillips, through PGC, owns about 30 percent. 3. INCOME TAXES The company's effective tax rate for the first three months of 1999 was 41 percent, compared with 39 percent for the same period of 2000. Deferred income taxes are computed using the liability method and provided on all temporary differences between the financial reporting basis and the tax basis of the assets and liabilities. Allowable tax credits are applied currently as reductions of the provision for income taxes. The results of operations for 1999 and 2000 are included in the consolidated federal income tax return of Phillips, with any resulting tax liability or refund settled with Phillips on a current basis. Income tax expense represents PGC on a separate return basis, except that the same principles and elections used in the consolidated return were applied. 4. RELATED PARTY TRANSACTIONS Significant transactions with affiliated parties were: THREE MONTHS ENDED MARCH 31, --------------------- 1999 2000 -------- -------- (IN THOUSANDS) Operating revenues.......................................... $110,613 $287,294 Gas purchases............................................... 17,970 35,499 Operating expenses.......................................... 27,363 29,509 Selling, general and administrative expenses................ 4,361 3,750 Interest income............................................. 452 2,618 Interest expense............................................ 7,224 20,474 Prior to the contribution of its subsidiaries to DEFS on March 31, 2000, the company purchased raw gas from, and sold a portion of its residue gas and substantially all of its natural gas liquids to, Phillips. F-56 108 PHILLIPS GAS COMPANY NOTES TO FINANCIAL STATEMENTS -- CONTINUED Phillips also provided the company with various field and general administrative services. In addition, the company purchased Phillips' plastic pipe, which is used in the construction of gathering systems. The company earns interest from participation in Phillips' centralized cash management system and incurs interest expense on its borrowings from Phillips. The company paid gathering fees to GPM Gas Gathering L.L.C. (GGG) until it contributed its equity interest in GGG into DEFS on March 31, 2000. In the first three months of 1999 and 2000, net fees paid to GGG for gas gathering services were $10,334,831 and $10,101,951, respectively; $8,655,478 and $8,450,827 were expensed. Selling, general and administrative expenses included a $2 million severance charge during the first three months of 1999. 5. CASH FLOW INFORMATION NON-CASH INVESTING ACTIVITIES On March 31, 2000, the company contributed its holdings in its limited-liability-company subsidiaries to DEFS. The contribution included property, plant and other assets and liabilities held by these companies, except for cash invested with Phillips, deferred taxes and current taxes payable. Other non-cash investing activities and cash payments for the three-month periods ended March 31 were as follows: 1999 2000 ------ ------- (IN THOUSANDS) CASH PAYMENTS Interest.................................................... $7,296 $20,477 Income taxes, including payments to Phillips................ 1,432 21 F-57 109 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Management of Duke Energy Field Services Denver, Colorado We have audited the accompanying combined statements of income and cash flows of the UPFuels Division of Union Pacific Resources Group Inc. (a Utah Corporation) for the year ended December 31, 1998 and the three-month period ended March 31, 1999. These financial statements are the responsibility of the UPFuels Division's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the combined financial statements referred to above present fairly, in all material respects, the combined results of operations and cash flows of the UPFuels Division for the year ended December 31, 1998, and the three-month period ended March 31, 1999, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Fort Worth, Texas March 10, 2000 F-58 110 INDEPENDENT AUDITORS' REPORT To the Board of Directors Union Pacific Resources Group Inc. Fort Worth, Texas We have audited the accompanying combined statements of income and cash flows for the year ended December 31, 1997 of the UPFuels Division of Union Pacific Resources Group Inc. (as restated). These financial statements are the responsibility of the UPFuels Division's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, such combined financial statements present fairly, in all material respects, the combined results of operations and cash flows of the UPFuels Division for the year ended December 31, 1997, in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Fort Worth, Texas June 12, 1998 F-59 111 UPFUELS DIVISION COMBINED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1997 AND 1998 AND FOR THE QUARTER ENDED MARCH 31, 1999 DECEMBER 31, MARCH 31, 1997 1998 1999 ------ -------- --------- (MILLIONS OF DOLLARS) Operating revenues: Gathering and processing.................................. $321.7 $ 227.2 $ 54.5 Pipelines................................................. 401.2 305.0 75.8 Marketing................................................. 2,761.6 3,062.8 784.0 Intersegment.............................................. (269.3) (188.6) (45.2) ------ -------- -------- Total operating revenues............................ 3,215.2 3,406.4 869.1 ------ -------- -------- Product purchases: Gathering and processing.................................. 157.1 119.6 30.9 Pipelines................................................. 312.4 198.4 44.9 Marketing................................................. 2,728.5 2,986.3 757.9 Intersegment.............................................. (269.3) (188.6) (45.2) ------ -------- -------- Total product purchases............................. 2,928.7 3,115.7 788.5 ------ -------- -------- Gross margin: Gathering and processing.................................. 164.6 107.6 23.6 Pipelines................................................. 88.8 106.6 30.9 Marketing................................................. 33.1 76.5 26.1 ------ -------- -------- Total gross margin.................................. 286.5 290.7 80.6 ------ -------- -------- Operating expenses: Gathering and processing.................................. 57.9 66.4 17.7 Pipelines................................................. 27.3 37.3 7.8 Marketing................................................. -- -- -- ------ -------- -------- Total operating expenses............................ 85.2 103.7 25.5 ------ -------- -------- General & administrative expenses: Gathering and processing.................................. 6.0 8.0 1.9 Pipelines................................................. 1.3 2.9 0.7 Marketing................................................. 13.0 13.0 3.0 Corporate................................................. 7.0 7.2 2.0 ------ -------- -------- Total general & administrative expenses............. 27.3 31.1 7.6 ------ -------- -------- Depreciation and amortization expense Gathering and processing.................................. 44.0 41.6 11.8 Pipelines................................................. 29.4 32.7 8.0 Marketing................................................. 1.1 6.2 4.1 ------ -------- -------- Total depreciation and amortization expense......... 74.5 80.5 23.9 ------ -------- -------- Operating income (loss): Gathering and processing.................................. 56.7 (8.4) (7.8) Pipelines................................................. 30.8 33.7 14.4 Marketing................................................. 19.0 57.3 19.0 Corporate................................................. (7.0) (7.2) (2.0) ------ -------- -------- Total operating income.............................. 99.5 75.4 23.6 ------ -------- -------- Other income................................................ -- 0.6 -- Minority interest........................................... (9.8) (7.6) (2.1) ------ -------- -------- Income before income taxes.................................. 89.7 68.4 21.5 Income taxes................................................ 33.2 25.3 8.0 ------ -------- -------- Net income.................................................. $ 56.5 $ 43.1 $ 13.5 ====== ======== ======== The accompanying accounting policies and notes to the combined financial statements are an integral part of these statements. F-60 112 UPFUELS DIVISION COMBINED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1997 AND 1998 AND FOR THE QUARTER ENDED MARCH 31, 1999 DECEMBER 31, MARCH 31, 1997 1998 1999 ------- ------- --------- (MILLIONS OF DOLLARS) Cash provided by operations: Net income................................................ $ 56.5 $ 43.1 $ 13.5 Depreciation and amortization.......................... 74.5 80.5 23.9 Deferred income taxes.................................. 15.1 (24.0) 10.8 Minority interest earnings............................. 9.8 7.6 2.1 Other non-cash charges (credits) -- net................ 8.1 (1.0) (0.4) Changes in current assets and liabilities................. 14.6 (35.8) 18.0 ------- ------- ------ Cash provided by operations....................... 178.6 70.4 67.9 ------- ------- ------ Investing activities: Capital expenditures...................................... (168.5) (143.8) (32.0) Acquisition of Highlands Gas Corporation.................. (179.4) -- -- Acquisition of certain assets of Norcen................... -- (83.2) -- ------- ------- ------ Cash used by investing activities................. (347.9) (227.0) (32.0) ------- ------- ------ Financing activities: Capital contributions by/(distributions to) Union Pacific Resources Group Inc. .................................. 187.4 170.0 (39.9) Distributions to minority interest owners................. (20.2) (11.3) (1.5) ------- ------- ------ Cash provided by (used in) financing activities... 167.2 158.7 (41.4) ------- ------- ------ Net change in cash and temporary investments................ (2.1) 2.1 (5.5) Balance at beginning of period.............................. 9.5 7.4 9.5 ------- ------- ------ Balance at end of period.................................... $ 7.4 $ 9.5 $ 4.0 ======= ======= ====== Changes in current assets and liabilities: Accounts receivable....................................... 1.4 13.1 35.7 Inventories............................................... (15.2) (10.4) 12.7 Other current assets...................................... (5.2) 11.3 0.7 Accounts payable.......................................... 30.5 (45.9) (29.4) Other current liabilities................................. 3.1 (3.9) (1.7) ------- ------- ------ Total............................................. $ 14.6 $ (35.8) $ 18.0 ======= ======= ====== The accompanying accounting policies and notes to the combined financial statements are an integral part of these statements. F-61 113 UPFUELS DIVISION NOTES TO COMBINED FINANCIAL STATEMENTS SIGNIFICANT ACCOUNTING POLICIES Principles of Combination. The combined financial statements include the accounts of certain gathering, processing, transporting and marketing operations of companies which are wholly-owned subsidiaries of Union Pacific Resources Group Inc. ("UPR"), a Utah Corporation. In addition, the combined financial statements include the operations of certain gathering and processing assets owned by wholly-owned subsidiaries of UPR that are not included in their entirety herein. Collectively, these wholly-owned subsidiaries and assets are considered and referred to herein as the "UPFuels Division" of UPR. All material intra-divisional transactions have been eliminated. The UPFuels Division accounts for its investments in pipeline partnerships and joint ventures under the equity method of accounting for entities owned 20%-50% by the UPFuels Division and fully consolidates entities owned greater than 50% by the UPFuels Division. The minority interest recorded by the UPFuels Division represents the ownership of other parties in entities in which the UPFuels Division owns greater than 50% but less than 100%. Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Management believes its estimates and assumptions are reasonable; however, there are a number of risks and uncertainties which may cause actual results to differ materially from the estimates. Depreciation and amortization. Provisions for depreciation of property, plant and equipment are computed on the straight-line method based on estimated service lives which range from three to 30 years. The cost of acquired gas purchase and marketing contracts are amortized using the straight-line method over the applicable period. Goodwill is being amortized using the straight-line method over 20 years. Amortization of goodwill was $2.0 million, $4.5 million and $1.1 million for the years ended December 31, 1997 and 1998 and for the quarter ended March 31, 1999, respectively. The value of goodwill is periodically evaluated based on the expected future undiscounted operating cash flows to determine whether any potential impairment exists. Revenue Recognition. The UPFuels Division recognizes revenues as gas and natural gas liquids are delivered and services are rendered. Revenues are recorded on an accrual basis, including an estimate for gas and natural gas liquids delivered but unbilled at the end of each accounting period. Derivative Financial Instruments. Unrealized gains/losses on derivative financial instruments used for hedging purposes are not recorded. Recognition of realized gains/losses and option premium payments/receipts are deferred and recorded in the combined statement of income when the underlying physical product is purchased or sold. The cash flow impact of derivative and other financial instruments is reflected in cash provided by operations in the combined statements of cash flows. Income Taxes. The UPFuels Division is included in the consolidated Federal income tax return of UPR. The consolidated Federal income tax liability of UPR is allocated among all corporate entities on the basis of the entity's contributions to the consolidated Federal income tax liability. Full benefit of tax losses and credits made available and utilized in UPR's consolidated Federal income tax returns are being allocated to the individual companies generating such items. Income tax expense represents federal income taxes as if the company were filing a separate return. Environmental Expenditures. Environmental expenditures related to treatment or cleanup are expensed when incurred, while environmental expenditures which extend the life of the property or prevent future contamination are capitalized in accordance with generally accepted accounting principles. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and F-62 114 UPFUELS DIVISION NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED the amounts can be reasonably estimated, based on current law and existing technologies. Environmental accruals are recorded at undiscounted amounts and exclude claims for recoveries from insurance or other third parties. Earnings Per Share. Earnings per share have been omitted from the combined statements of income as the UPFuels Division was wholly owned by UPR for all periods presented. 1. NATURE OF OPERATIONS The UPFuels Division owns and operates natural gas and natural gas liquids gathering and pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, processing, transporting, storing and marketing natural gas and natural gas liquids. Through a related party transaction, the UPFuels Division markets a substantial portion of UPR's natural gas and natural gas liquid production together with significant volumes of natural gas and natural gas liquids produced by others. The UPFuels Division has a diverse customer base for its hydrocarbon products. The UPFuels Division's results of operations are largely dependent on the difference between the prices received for its hydrocarbon products and the cost to acquire and market such resources. Hydrocarbon prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond the control of the UPFuels Division. These factors include worldwide political instability, the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand and the price and availability of alternative fuels. Historically, the UPFuels Division has been able to manage a portion of the operating risk relating to hydrocarbon price volatility through hedging activities. 2. ACQUISITION OF THE UPFUELS DIVISION BY DUKE ENERGY FIELD SERVICES INC. In November 1998, UPR reached an agreement with Duke Energy Field Services, Inc. whereby Duke Energy Field Services would acquire certain gathering, processing, pipeline and marketing assets of UPR. The sale transaction closed effective March 31, 1999, with the purchase price being $1.35 billion. Certain liabilities primarily income tax and retiree benefits obligations, were not assumed by Duke Energy Field Services in connection with the sale transaction. 3. RELATED PARTY TRANSACTIONS The UPFuels Division enters into certain natural gas and crude hedging transactions on behalf of UPR. Services performed by UPR on behalf of the UPFuels Division include cash management, internal audit and tax and employee benefits administration. In the UPFuels Division originally issued financial statements, there was no cost allocated for these services. The UPFuels Division management subsequently determined that $2.0 million, $2.0 million and $0.5 million for 1997, 1998 and the three months ended March 31, 1999, respectively, should have been allocated. As a result, the accompanying financial statements have been revised from their original presentation. Other general and administrative expenses have been allocated to the UPFuels Division, including office rent expense. Since treasury is considered to be a UPR corporate function, no interest expense has been allocated to the UPFuels Division in the accompanying combined statements of income. The UPFuels Division has a buy/sell agreement with UPR. Under this agreement, the UPFuels Division gathers, transports, processes and sells natural gas and natural gas liquids for UPR and purchases natural gas and natural gas liquids from UPR. The charges for allocated services are based on estimated full time equivalent headcount at fully burdened rates. The buy/sell arrangements are based on prevailing market conditions in each regional area. Accordingly, these transactions reflect UP Fuels results as if they were on a stand alone basis. F-63 115 UPFUELS DIVISION NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED The following table reflects the intercompany balance outstanding at each period end as well as the high and low balance for each period. AVERAGE BALANCE HIGH LOW OUTSTANDING BALANCE BALANCE ----------- ------- ------- ($ IN MILLIONS) 1997...................................................... $ 93.7 $187.4 $ 0 1998...................................................... $272.4 $357.4 $187.5 First Quarter 1999........................................ $337.5 $357.4 $317.5 The following table summarizes product purchases, in volumes and dollars, made by the UPFuels Division from UPR during each of the years ended December 31, 1997 and 1998 and the quarter ended March 31, 1999: DECEMBER 31, MARCH 31, 1997 1998 1999 ------ ------ --------- (VOLUMES) Gas (MMcf/day).............................................. 860.8 923.1 846.2 Natural gas liquids (Mbbls/day)............................. 68.8 68.5 63.1 (MILLIONS OF DOLLARS) Gas......................................................... $628.4 $630.1 $140.1 Natural gas liquids......................................... $281.3 $203.5 $ 43.3 4. SIGNIFICANT ACQUISITION Highlands Gas Corporation. In August 1997, the UPFuels Division acquired 100% of the outstanding stock of Highlands Gas Corporation ("Highlands") for an adjusted purchase price of approximately $179.4 million. Highlands is in the business of gathering, purchasing, processing and transporting natural gas and natural gas liquids. The acquisition included three natural gas processing plants, five gathering systems with over 700 miles of gas and natural gas liquids gathering pipeline and 400 miles of transportation pipeline located in Western Texas and Eastern New Mexico. Results of operations for Highlands subsequent to the acquisition date are included in the consolidated statements of income. The following unaudited pro forma combined results of operations for the year ended December 31, 1997 are presented as if the Highlands acquisition had been made at the beginning of the year. The unaudited pro forma information is not necessarily indicative of either the results of operations that would have occurred had the purchase been made during the periods presented or the future results of the combined operations. PRO FORMA RESULTS 1997 --------------------- (MILLIONS OF DOLLARS) Revenues........................................ $3,376.8 Operating income................................ 96.3 Net income...................................... $ 54.5 F-64 116 UPFUELS DIVISION NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED 5. FINANCIAL INSTRUMENTS Hedging. The UPFuels Division has established policies and procedures for managing risk within its organization. It is balanced by internal controls and governed by a risk management committee. The level of risk assumed by the UPFuels Division is based on its objectives and earnings, and its capacity to manage risk. Limits are established for each major category of risk, with exposures monitored and managed by UPFuels Division management, and reviewed semi-annually by the risk management committee. Major categories of the UPFuels Division's risk are defined as follows: Commodity Price Risk -- Non-Trading Activities. The UPFuels Division uses derivative financial instruments for non-trading purposes in the normal course of business to manage and reduce risks associated with contractual commitments, price volatility, and other market variables in conjunction with transportation, storage, and customer service programs. These instruments are generally put in place to limit risk of adverse price movements, however, when this is done, these same instruments usually limit future gains from favorable price movements. Such risk management activities are generally accomplished pursuant to exchange-traded contracts or over-the-counter options. Recognition of realized gains/losses and option premium payments/receipts are also deferred in the combined statements of income until the underlying physical product is sold. Unrealized gains/losses on derivative financial instruments are not recorded. The cash flow impact of derivative and other financial instruments is reflected as cash flows provided from operations in the combined statements of cash flows. Commodity Price Risk -- Trading Activities. Periodically, the UPFuels Division may enter into transactions involving a wide range of energy related derivative financial transactions that are not the result of hedging activities. These instruments are generally put into place based on the UPFuels Division's analysis and expectations with respect to price movement or changes in other market variables. As of March 31, 1999, there were no transactions in place which would materially affect the results of operations or financial condition of the UPFuels Division. Credit Risk. Credit risk is the risk of loss as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. Because the loss can occur at some point in the future, a potential exposure is added to the current replacement value to arrive at a total expected credit exposure. The UPFuels Division has established methodologies to establish limits, monitor and report creditworthiness and concentrations of credit to reduce such credit risk. At March 31, 1999, the UPFuels Division's largest credit risk associated with any single counterparty, represented by the net fair value of open contracts with such counterparty was $2.2 million. Performance Risk. Performance risk results when a counterparty fails to fulfill its contractual obligations such as commodity pricing or volume commitments. Typically, such risk obligations are defined within the trading agreements. The UPFuels Division utilizes its credit risk methodology to manage performance risk. Concentrations of Credit Risk. Financial instruments which subject the UPFuels Division to concentrations of credit risk consist principally of trade receivables and short-term cash investments. A significant portion of the UPFuels Division's trade receivables relate to customers in the energy industry, and, as such, the UPFuels Division is directly affected by the economy of that industry. However, excluding the relationship with UPR, the credit risk associated with trade receivables is minimized by the UPFuels Division's diverse customer base which includes local gas distribution companies, power generation facilities, pipelines, industrial plants and other wholesale marketing companies. Ongoing procedures are in place to monitor the creditworthiness of customers. The UPFuels Division generally requires no collateral from its customers and historically has not experienced significant losses on trade receivables. F-65 117 UPFUELS DIVISION NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED 6. INCOME TAXES The UPFuels Division is included in the consolidated Federal income tax return of UPR. The consolidated Federal income tax liability of UPR is allocated among all corporate entities on the basis of the entity's contributions to the consolidated Federal income tax liability. Full benefit of tax losses and credits made available and utilized in UPR's consolidated Federal income tax returns are being allocated to the individual companies generating such items. Components of income tax expense for the years ended December 31, 1997 and 1998 and for the quarter ended March 31, 1999. 1997 1998 1999 ----- ------ ----- (MILLIONS OF DOLLARS) Current: Federal.................................................. $17.2 $ 46.7 $(2.7) State.................................................... .9 2.6 (0.1) ----- ------ ----- Total current.................................... 18.1 49.3 (2.8) Deferred: Federal.................................................. 14.2 (22.7) 10.2 State.................................................... 0.9 (1.3) 0.6 ----- ------ ----- Total deferred...................................... 15.1 (24.0) 10.8 ----- ------ ----- Total............................................ $33.2 $ 25.3 $ 8.0 ===== ====== ===== A reconciliation between statutory and effective tax rates for the years ended December 31, 1997 and 1998 and for the quarter ended March 31, 1999 is as follows: 1997 1998 1999 ---- ---- ---- Statutory tax rate.......................................... 35.0% 35.0% 35.0% State taxes -- net.......................................... 2.0% 2.0% 2.0% ---- ---- ---- Effective tax rate........................................ 37.0% 37.0% 37.0% ==== ==== ==== All tax years prior to 1986 have been closed with the Internal Revenue Service ("IRS"). On behalf of the UPFuels Division, UPR, through Union Pacific Corporation ("UPC"), is negotiating with the Appeals Office concerning 1986 through 1989. The IRS is examining UPR's returns for 1990 through 1994 in connection with the IRS' examination of UPC's returns. The UPFuels Division believes it has adequately provided for Federal and state income taxes. F-66 118 UPFUELS DIVISION NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED 7. LEASES The UPFuels Division leases certain compressors and other property. Future minimum lease payments for operating leases with initial non-cancelable lease terms in excess of one year as of March 31, 1999, are as follows: (MILLIONS OF DOLLARS) 1999............................................ $ 1.9 2000............................................ 2.5 2001............................................ 2.4 2002............................................ 1.5 2003............................................ 1.2 Later years..................................... 5.4 ----- Total minimum payments................ $14.9 ===== Rent expense for operating leases with terms exceeding one year was $1.1 million and $1.3 million for the years ended December 31, 1997 and 1998, respectively, and $0.5 million for the quarter ended March 31, 1999. Currently there is no sublease income for the next five years or thereafter. 8. EMPLOYEE STOCK OPTION PLANS Stock Option and Retention Stock Plans. Pursuant to the UPR's stock option and retention stock plans, UPR stock options under the plans are granted at 100% of fair market value at the date of grant, become exercisable no earlier than one year after grant and are exercisable for a period of up to eleven years from grant date. Option grants have been made to directors, officers and employees and vest over a period up to ten years from the grant date. Retention shares of UPR common stock are awarded under the plans to eligible employees, subject to forfeiture if employment terminates during the prescribed retention period, generally one to five years from grant. Multi-year retention stock awards also have been made, with vesting two to five years from grant. Expense related to these stock option and retention stock programs of UPR, which pertain to UPFuels Division employees, amounted to $1.2 million, $1.3 million and $.7 million for the years ended 1997 and 1998 and the quarter ended March 31, 1999, respectively. Since UPR applies the intrinsic value method in accounting for its stock option and retention stock plans, it generally records no compensation cost for its stock option plans. Had compensation cost for UPR's stock option plan been determined based on the fair value at the grant dates for awards to UPFuels Division employees under the plan and for options that were converted at the times of the initial public offering and spin-off of UPR from UPC, the UPFuels Division's net income would have been reduced by $.6 million, $1.9 million and $0.1 million for the years ended December 31, 1997 and 1998 and the quarter ended March 31, 1999, respectively. Employee Stock Ownership Plan. Effective January 2, 1997, UPR instituted an employee stock ownership plan ("ESOP"). The ESOP purchased 3.7 million shares or $107.3 million of newly issued common stock (the "ESOP Shares") from UPRG, which will be used to fund UPR's matching obligation under its 401(k) Thrift Plan. All regular employees of the UPFuels Division are eligible to participate in the ESOP. During the years ended December 31, 1997 and 1998, and the quarter ended March 31, 1999, compensation cost related to the allocation of ESOP shares to participants' accounts was $1.4 million, $1.6 million and $0.4 million, respectively, for the UPFuels Division. F-67 119 UPFUELS DIVISION NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED 9. ENVIRONMENTAL EXPOSURE The UPFuels Division generates and disposes of hazardous and nonhazardous waste in its current and former operations and is subject to increasingly stringent Federal, state and local environmental regulations. Certain Federal legislation imposes joint and several liability for the remediation of various sites; consequently, the UPFuels Division's ultimate environmental liability may include costs relating to other parties in addition to costs relating to its own activities at each site. In addition, the UPFuels Division is or may be liable for certain environmental remediation matters involving existing or former facilities. The UPFuels Division has recorded environmental reserves related to future costs of all sites where the UPFuels Division's obligation is probable and where such costs reasonably can be estimated. This accrual includes future costs for remediation and restoration of sites, as well as for ongoing monitoring costs, but excludes any anticipated recoveries from third parties. The UPFuels Division also is involved in reducing emissions, spills and migration of hazardous materials. Remediation of identified sites and control of environmental exposures required $1.2 million in 1998 and no spending for the quarter ended March 31, 1999. 10. COMMITMENTS AND CONTINGENCIES The UPFuels Division is party to several long-term firm gas transportation agreements, the largest of which are with Kern River Gas Transportation Company ("Kern River"), Texas Gas Transmission Corporation ("Texas Gas"), and Pacific Gas Transmission ("PGT"). At December 31, 1997, the UPFuels Division had a keep whole agreement with UPR which expired at the end of 2003 whereby UPR reimbursed the UPFuels Division for the excess of the contractual fixed price over the prevailing market price for the transportation. Conversely, the UPFuels Division, under the keep whole agreement, was to pay UPR when the prevailing market price exceeded the contractual fixed price. Accordingly, at December 31, 1997, the UPFuels Division recorded a reserve for the fair value of the difference between the fixed rate under the firm transportation agreements and the estimated market rates for the period from 2004 to the end of the respective contract periods. At December 31, 1997, the reserves, which were included in other long-term liabilities, were $13.0 million, $5.5 million, and $7.6 million for the Kern River, Texas Gas, and PGT agreements, respectively. In conjunction with the sale of the UPFuels Division to Duke Energy Field Services, Inc. during 1998 the UPFuels Division extended the keep whole agreement with UPR to cover a 10 year period commencing March 1, 1999 or through the expiration of the contract, whichever is earlier. In addition, UPR retained the transportation contract with Kern River. Accordingly, no reserves for the Kern River and Texas Gas Agreements were recorded at December 31, 1998 or March 31, 1999 and $17.6 million was recorded at December 31, 1998 and March 31, 1999 for the PGT agreement, reflecting additional liabilities for volumes acquired in 1998, partially offset by the extension of the keep whole agreement. During 1998, $8.5 million was recorded as a change in divisional equity for the change in the keep whole agreement. A detailed explanation of the three major long-term firm transportation agreements are as follows: Under the Kern River transportation agreement which expires in 2007, the UPFuels Division has the right to transport 75 MMcfd of gas on the Kern River Pipeline system which extends from Opal, Wyoming, to an interconnection with the Southern California Gas Company pipeline system in southern California. Nine years remain on the primary term of the agreement, and the current transportation rate is $0.69 per Mcf. Thereafter, this rate can change based on Kern River's cost of service and upon rate regulation policies of the Federal Energy Regulatory Commission ("FERC"). Under a 1993 ruling of the FERC, the UPFuels Division is obligated to pay all of the fixed costs included in the transportation rate, F-68 120 UPFUELS DIVISION NOTES TO COMBINED FINANCIAL STATEMENTS--CONTINUED whether or not the UPFuels Division actually uses Kern River's pipeline to transport gas. Those fixed costs presently amount to $0.61 per Mcf. The undiscounted amount of the nine year fixed cost commitment, assuming no future changes in the rate, is $136 million. The 1993 FERC ruling was issued notwithstanding a provision in the transportation agreement between Kern River and the UPFuels Division in which the parties agreed that a portion of the fixed costs would be paid by the UPFuels Division only if and to the extent that the UPFuels Division uses the pipeline. In light of recent changes in the regulatory policies of FERC, the UPFuels Division is seeking reinstatement of the contractually agreed rate structure, but there is no assurance that such efforts will be successful. The UPFuels Division is a party to an additional agreement under which it may acquire, in 2001, at its option, an additional 25 MMcfd of transportation rights on the Kern River system beginning in 2002. Under the Texas Gas transportation agreement, which expires in 2008, the UPFuels Division has the rights to transport 90 MMcfd of gas from the UPFuels Division's East Texas plant. The UPFuels Division is obligated to pay a fixed transportation rate of $0.33 per Mmbtu regardless of the volumes transported under the agreement. The undiscounted amount of this commitment is $104 million. Under the PGT transportation agreement, which expires in 2023, the UPFuels Division has the rights to transport 25 MMcfd of gas from Kingsgate, British Columbia to the California/Oregon border. The UPFuels Division is obligated to pay a fixed transportation rate of $0.33 per Mmbtu regardless of the volumes transported under the agreement. However, the UPFuels Division has third party agreements that reimburse the UPFuels Division for 90 percent of the firm transportation cost until October 2002. As part of the third party agreements, the UPFuels Division assigned 50 percent of the firm transportation capacity. The term for the keep whole agreement for this contract commences on November 1, 2002 and terminates on February 28, 2009. The undiscounted amount of this commitment, net of the third party reimbursements, is $64 million. During 1998, the UPFuels Division assumed responsibility for additional long-term firm transportation agreements with PGT to transport gas from Kingsgate, British Columbia to the California/Oregon border. Under the transportation agreements, the UPFuels Division has the rights to transport 106 Mmbtu per day of which 47 Mmbtu per day will expire in October 2007 and the balance of the contract commitment will expire in October 2023. The UPFuels Division does have a third party agreement that recovers all the transportation cost for 20 Mmbtu per day through June 2011. The UPFuels Division is a defendant in a number of lawsuits and is involved in governmental proceedings arising in the ordinary course of business, including contract claims, personal injury claims and environmental claims. While management of the UPFuels Division cannot predict the outcome of such litigation and other proceedings, management does not expect those matters to have a materially adverse effect on the consolidated financial condition or results of operations of the UPFuels Division. F-69 121 PROSPECTUS $2,000,000,000 DUKE ENERGY FIELD SERVICES, LLC --------------------- DEBT SECURITIES --------------------- This prospectus contains summaries of the general terms of these securities. You will find the specific terms of any securities offered, and the manner in which they are being offered, in supplements to this prospectus. You should read this prospectus and any prospectus supplement carefully before you invest. Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense. The date of this prospectus is August 2, 2000. 122 TABLE OF CONTENTS About This Prospectus....................................... 2 Where You Can Find More Information......................... 2 Cautionary Statement About Forward-Looking Statements....... 3 Our Company................................................. 4 Ratio Of Earnings To Fixed Charges.......................... 6 Use Of Proceeds............................................. 6 Description Of Debt Securities.............................. 7 Plan Of Distribution........................................ 16 Experts..................................................... 18 Validity Of The Securities.................................. 18 123 ABOUT THIS PROSPECTUS This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission using the "shelf" registration process. Under this shelf registration process, we may issue the debt securities described in this prospectus in one or more offerings up to a total dollar amount of $2,000,000,000 (or its equivalent in foreign currencies). This prospectus constitutes part of a registration statement on Form S-3 filed with the SEC under the Securities Act of 1933. It omits some of the information contained in the registration statement, and reference is made to the registration statement for further information with respect to us and the securities we are offering. Any statement contained in this prospectus concerning the provisions of any document filed as an exhibit to the registration statement or otherwise filed with the SEC is not necessarily complete, and in each instance reference is made to the copy of the document filed. This prospectus provides you with a general description of the debt securities that we may offer. Each time we sell debt securities, we will provide a prospectus supplement that will contain specific information about the terms of that offering and the debt securities to be sold. The prospectus supplement may also add, update or change information contained in this prospectus. Any statement that we make in this prospectus will be modified or superseded by any inconsistent statement made by us in a prospectus supplement. The registration statement filed with the SEC includes exhibits that provide more details about the matters discussed in this prospectus. You should read this prospectus, the related exhibits filed with the SEC and any prospectus supplement, together with the additional information described under "Where You Can Find More Information." WHERE YOU CAN FIND MORE INFORMATION We have filed with the SEC a Form 10 for the registration of our member interests pursuant to Section 12(g) of the Securities Exchange Act of 1934. As a result, we are now required to comply with the informational requirements of the Securities Exchange Act of 1934, and, accordingly, we will file annual, quarterly and special reports, proxy statements and other information with the SEC. Our SEC filings are available to the public over the Internet at the SEC's web site at http://www.sec.gov. You may also read and copy any document we file at the SEC's Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. You may obtain information on the operation of the SEC's Public Reference Room in Washington, D.C. by calling the SEC at 1-800-SEC-0330. The SEC allows us to "incorporate by reference" the information we file with it, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is an important part of this prospectus, and information that we file later with the SEC will automatically update and supersede this information. We incorporate by reference the document listed below and any future filings made with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 until we sell all of the securities being registered or until we terminate this registration statement: - Our Form 10 filed with the SEC. If you ask us by phone or in writing, we will give you a free copy of any or all of the information incorporated by reference (other than exhibits, unless they are specifically incorporated by reference). Please direct your request by mail to Duke Energy Field Services, LLC, Attention: Vice President, Investor Relations, 370 17th Street, Suite 900, Denver, Colorado 80202 or by telephone at (303) 595-3331. You should rely only on the information incorporated by reference or provided in this prospectus or any prospectus supplement. We have not authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. You should not assume that the information in this prospectus, any prospectus supplement or 2 124 any document incorporated by reference is accurate as of any date other than the date of those documents. Our business, financial condition, results of operations and prospects may have changed since those dates. CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS This prospectus contains or incorporates by reference statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements." You can typically identify forward-looking statements by the use of forward-looking words, such as "may," "could," "project," "believe," "anticipate," "expect," "estimate," "potential," "plan," "forecast" and other similar words. All statements other than statements of historical facts contained in this prospectus, 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. The forward-looking statements in this prospectus 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: - volatility in the market demand for oil and natural gas and NGLs (which directly affects our results of operations); - demand for natural gas and natural gas liquids may not increase as rapidly or as much as we expect; - the timing and extent of changes in commodity prices and demand for our services; - competition for raw natural gas supply; - integration of the Phillips and Duke Energy assets that comprise our business; - our ability to grow through acquisitions; - our use of derivative financial instruments to hedge commodity and interest rate risks; - our ability to access the debt and equity markets during the periods covered by the forward-looking statements, which will depend on general market conditions and the credit ratings for our debt obligations; - changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment or the increased regulation of the gas gathering and processing industry; - weather and other natural phenomena; - industry changes, including the impact of consolidations, and changes in competition; and - 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 of building, environmental and other permits, the availability of specialized contractors and work force and prices of and demand for products. In light of these risks, uncertainties and assumptions, the forward-looking events referred to in this prospectus or in any prospectus supplement might not occur or might occur to a different extent or at a different time than described in this prospectus or in any prospectus supplement. We undertake no obligation to update or revise our forward-looking statements, whether as a result of new information, future events or otherwise. 3 125 OUR COMPANY Duke Energy Field Services, LLC is a new company that holds the combined North American midstream natural gas gathering, processing, marketing and natural gas liquids businesses of Duke Energy Corporation ("Duke Energy") and Phillips Petroleum Company ("Phillips"). The transaction in which those businesses were combined is referred to in this prospectus as the "Combination." 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 natural gas liquids in Mexico and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our Board of Directors. Unless the context otherwise requires, descriptions of assets, operations and results in this prospectus give effect to the Combination and related transactions, the transfer to us of additional midstream natural gas assets acquired by Duke Energy or Phillips prior to the Combination and the transfer to us of the general partner of TEPPCO Partners, L.P. In this prospectus, the terms "we," "us" and "our" refer to Duke Energy Field Services, LLC and our subsidiaries, giving effect to the Combination and related transactions. The midstream natural gas industry is the link between the exploration and production of raw natural gas and the delivery of its components to end-use markets. We are involved in the two principal segments of the midstream natural gas industry: - natural gas gathering, processing, transportation, marketing and storage; and - natural gas liquids ("NGLs") fractionation, transportation, marketing and trading. We believe that we are one of the largest gatherers of raw natural gas, based on wellhead volume, in North America. We are the largest producer, and we believe that we are one of the largest marketers, of NGLs in North America. In 1999: - we gathered and/or transported an average of approximately 7.3 billion cubic feet per day of raw natural gas; - we produced an average of approximately 400,000 barrels per day of NGLs; and - we marketed and traded an average of approximately 486,000 barrels per day of NGLs. We gather raw natural gas through gathering systems located in seven major natural gas producing regions: Permian Basin, Mid-Continent, East Texas -- Austin Chalk -- North Louisiana, Onshore Gulf of Mexico, Rocky Mountains, Offshore Gulf of Mexico and Western Canada. Our gathering systems consist of approximately 57,000 miles of gathering pipe, with approximately 38,000 active connections to producing wells. Our natural gas processing operations involve the separation of raw natural gas gathered both by our gathering system and by third party systems into NGLs and residue gas. We process the raw natural gas at our 70 owned and operated plants and at 13 third-party operated facilities in which we hold an equity interest. The NGLs separated from the raw natural gas by our processing operations are either sold and transported as "NGL raw mix" or further separated through a process known as fractionation into their individual components (ethane, propane, butanes and natural gasoline) and then sold as components. We fractionate NGL raw mix at our 12 owned and operated processing facilities and at two third-party operated fractionators in which we hold an equity interest. We sell NGLs to a variety of customers ranging 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 our NGL production that is committed to Phillips under an existing 15-year contract. We market approximately 370,000 barrels per day of our NGLs processed at our owned and operated facilities and approximately 40,000 barrels per day of NGLs 4 126 processed at third-party operated facilities and trade approximately 75,000 barrels per day of NGLs at market centers. The residue gas that results from our processing is sold at market-based prices to marketers or end users including large industrial customers and natural gas and electric utilities serving individual consumers. We market residue gas through our wholly owned gas marketing company. We also store residue gas at our 8.5 billion cubic foot natural gas storage facility. On March 31, 2000, we obtained by transfer from Duke Energy the general partner of TEPPCO Partners, L.P. ("TEPPCO"), a publicly traded limited partnership which owns and operates a network of pipelines for refined products and crude oil. The general partner is responsible for the management and operations of TEPPCO. We believe that our ownership of the general partner of TEPPCO improves our business position in the transportation sector of the midstream natural gas industry and provides additional flexibility in pursuing our disciplined acquisition strategy by providing an alternative acquisition vehicle. It also provides us with an opportunity to sell appropriate assets currently held by our company to TEPPCO. Through our ownership of the general partner of TEPPCO we have the right to receive from TEPPCO incentive cash distributions in addition to a 2% share of distributions based on our general partner interest. At TEPPCO's 1999 per unit distribution level, the general partner: - receives approximately 14% of the cash distributed by TEPPCO to its partners, which consists of 12% from the incentive cash distribution and 2% from the general partner interest; and - under the incentive cash distribution provisions, receives 50% of any increase in TEPPCO's per unit cash distributions. On July 21, 2000, TEPPCO acquired, for $318.5 million, Atlantic Richfield Company's ownership interests in a 500-mile crude oil pipeline that extends from a marine terminal at Freeport, Texas to Cushing, Oklahoma, a 416-mile crude oil pipeline that extends from Jal, New Mexico to Cushing, a 400-mile crude oil pipeline that extends from West Texas to Houston, crude oil terminal facilities in Midland, Texas, Cushing and the Houston area and receipt and delivery pipelines centered around Midland. Our principal executive offices are located at 370 17th Street, Suite 900, Denver, Colorado 80202, and our telephone number is (303) 595-3331. 5 127 RATIO OF EARNINGS TO FIXED CHARGES The following table contains our consolidated ratio of earnings to fixed charges for the periods indicated. 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 in March 2000 immediately prior to the Combination. For periods prior to the Combination, Duke Energy Field Services, LLC and these former subsidiaries of Duke Energy collectively are referred to in this prospectus as the "Predecessor Company." PREDECESSOR COMPANY HISTORICAL -------------------------------------------------------------- THREE MONTHS YEARS ENDED DECEMBER 31, ENDED -------------------------------------------------- MARCH 31, 1995 1996 1997 1998 1999 2000 ------- -------- -------- ------- -------- --------- RATIO OF EARNINGS TO FIXED CHARGES....................... 4.10 9.11 2.52 1.07 2.33 4.23 For purposes of calculating the ratios of earnings to fixed charges: (1) "earnings" means income before extraordinary changes plus income taxes and fixed charges, and (2) "fixed charges" include interest on indebtedness, amortization of deferred financing costs, and that portion of lease expense that is deemed to be representative of an interest factor. The ratio includes amounts from our company, all of our majority-owned subsidiaries and our proportionate share of distributed amounts from 50% owned investments accounted for using the equity method. USE OF PROCEEDS Unless the applicable prospectus supplement states otherwise, we will use the net proceeds from the sale of the debt securities offered by this prospectus and any prospectus supplement for general corporate purposes, which may include repayment of indebtedness, capital expenditures, future acquisitions, advances to subsidiaries and additions to our working capital. If we do not use the net proceeds immediately, we may temporarily invest them in short-term interest-bearing obligations or deposit them with banks. 6 128 DESCRIPTION OF DEBT SECURITIES Any debt securities issued using this prospectus ("Debt Securities") will be our direct unsecured general obligations. The Debt Securities will be senior debt securities. The Debt Securities will be issued under an Indenture (the "Indenture") between us and The Chase Manhattan Bank (the "Trustee"). The Debt Securities may be issued from time to time in one or more series. The particular terms of each series that is offered by a prospectus supplement will be described in the prospectus supplement. We have summarized selected provisions of the Indenture below. The summary is not complete. The form of the Indenture has been filed as an exhibit to the registration statement, and you should read the Indenture for provisions that may be important to you. Whenever we refer in this prospectus or in any prospectus supplement to particular sections or defined terms of the Indenture, such sections or defined terms are incorporated by reference herein or therein, as applicable. Capitalized terms used in this summary have the meanings specified in the Indenture. GENERAL The Indenture provides that Debt Securities in separate series may be issued from time to time without limitation as to aggregate principal amount. We may specify a maximum aggregate principal amount for the Debt Securities of any series. We will determine the terms and conditions of the Debt Securities, including the maturity, principal and interest, but those terms must be consistent with the Indenture. Debt Securities of a series need not be issued at the same time, bear interest at the same rate or mature on the same date. Each series of Debt Securities will rank equally with every other series of Debt Securities and with all of our other unsecured and unsubordinated debt. A prospectus supplement relating to any series of Debt Securities being offered will include specific terms related to the offering, including the price or prices at which the Debt Securities to be offered will be issued. These terms will include some or all of the following: - the title of the Debt Securities; - the total principal amount of the Debt Securities; - the date or dates on which the principal of the Debt Securities will be payable or the method for determining the date or dates, and any right that we have to change the date on which principal is payable; - the interest rate or rates of the Debt Securities, if any, or the method for determining the rate or rates, and the date or dates from which interest will accrue; - any interest payment dates and the regular record date for the interest payable on each interest payment date, if any; - whether we may extend the interest payment periods and, if so, the terms of the extension; - the places where payments on the Debt Securities will be payable; - whether we have the option to redeem the Debt Securities and, if so, the terms of our redemption option; - any obligation we have to redeem the Debt Securities through a sinking fund or to purchase the Debt Securities through a purchase fund or at the option of the holder; - whether the Debt Securities are defeasible; - the currency in which payments will be made if other than U.S. dollars, and the manner of determining the equivalent of those amounts in U.S. dollars; 7 129 - if payments may be made, at our election or at the holder's election, in a currency other than that in which the Debt Securities are stated to be payable, then the currency in which those payments may be made, the terms and conditions of the election and the manner of determining those amounts; - the portion of the principal payable upon acceleration of maturity, if other than the entire principal; - whether the Debt Securities will be issuable as global securities and, if so, the securities depositary; - any index or formula used for determining principal, premium or interest; - if the principal payable on the maturity date will not be determinable on one or more dates prior to the maturity date, the amount which will be deemed to be such principal amount or the manner of determining it; - any addition to or change in the events of default in the Indenture; - any addition to or change in the covenants in the Indenture; and - any other terms of the Debt Securities not inconsistent with the provisions of the Indenture. Unless we state otherwise in the prospectus supplement, we will issue the Debt Securities only in fully registered form, without coupons, and there will be no service charge for any registration of transfer or exchange of the Debt Securities. We may, however, require payment to cover any tax or other governmental charge payable in connection with any transfer or exchange. Subject to the terms of the Indenture and the limitations applicable to global securities, Debt Securities may be transferred or exchanged at the corporate trust office of the Trustee or at any other office or agency maintained by us for such purpose. The Debt Securities of each series will be issuable in denominations of $1,000 and any integral multiples of $1,000, unless we state otherwise in the prospectus supplement. We may offer and sell Debt Securities, including original issue discount Debt Securities, at a substantial discount below their principal amount. The applicable prospectus supplement will describe special U.S. federal income tax and any other considerations applicable to those securities. In addition, the applicable prospectus supplement may describe certain special U.S. federal income tax or other considerations, if any, applicable to any Debt Securities that are denominated in a currency other than U.S. dollars. RANKING Each series of Debt Securities will be unsecured senior obligations and will rank equally with every other series of Debt Securities and with all of our other unsecured and unsubordinated debt. The Debt Securities will, however, be effectively subordinated in right of payment to any secured indebtedness to the extent of the value of the assets securing that indebtedness. Except as provided in the Indenture or specified in any authorizing resolution or supplemental indenture relating to a series of Debt Securities to be issued, the Indenture will not limit the amount of additional indebtedness that may rank equally with the Debt Securities or the amount of indebtedness, secured or otherwise, that may be incurred or preferred stock that may be issued by any of our subsidiaries. GLOBAL SECURITIES We may issue some or all of the Debt Securities as book-entry securities. Any such book-entry securities will be represented by one or more fully registered global certificates. We will register each global security with, or on behalf of, a securities depositary identified in the applicable prospectus supplement. Each global certificate will be deposited with the securities depositary or its nominee or a custodian for the securities depositary. 8 130 As long as the securities depositary or its nominee is the registered holder of a global security representing Debt Securities, that person will be considered the sole owner and holder of the global security and the Debt Securities it represents for all purposes. Except in limited circumstances, owners of beneficial interests in a global security: - may not have the global security or any Debt Securities it represents registered in their names; - may not receive or be entitled to receive physical delivery of certificated Debt Securities in exchange for the global security; and - will not be considered the owners or holders of the global security or any Debt Securities it represents for any purposes under the Debt Securities or the Indenture. We will make all payments of principal and any premium and interest on a global security to the securities depositary or its nominee as the holder of the global security. The laws of some jurisdictions require that certain purchasers of securities take physical delivery of securities in definitive form. These laws may impair the ability to transfer beneficial interests in a global security. Ownership of beneficial interests in a global security will be limited to institutions having accounts with the securities depositary or its nominee, which are called "participants" in this discussion, and to persons that hold beneficial interests through participants. When a global security representing Debt Securities is issued, the securities depositary will credit on its book-entry, registration and transfer system the principal amounts of Debt Securities the global security represents to the accounts of its participants. Ownership of beneficial interests in a global security will be shown only on, and the transfer of those ownership interests will be effected only through, records maintained by: - the securities depositary, with respect to participants' interests; and - any participant, with respect to interests the participant holds on behalf of other persons. Payments participants make to owners of beneficial interests held through those participants will be the responsibility of those participants. The securities depositary may from time to time adopt various policies and procedures governing payments, transfers, exchanges and other matters relating to beneficial interests in a global security. None of the following will have any responsibility or liability for any aspect of the securities depositary's or any participant's records relating to beneficial interests in a global security representing Debt Securities, for payments made on account of those beneficial interests or for maintaining, supervising or reviewing any records relating to those beneficial interests: - our company; - the Trustee under the Indenture; or - an agent of either our company or the Trustee. REDEMPTION Any provisions relating to the redemption of Debt Securities will be set forth in the applicable prospectus supplement. Unless we state otherwise in the applicable prospectus supplement, we may redeem Debt Securities only upon notice mailed at least 30 but not more than 60 days before the date fixed for redemption. Unless we state otherwise in the applicable prospectus supplement, that notice may state that the redemption will be conditional upon the Trustee or the paying agent receiving sufficient funds to pay the principal, premium and interest on those Debt Securities on the date fixed for redemption and that if the Trustee or the paying agent does not receive those funds, the redemption notice will not apply, and we will not be required to redeem those Debt Securities. 9 131 We will not be required to: - issue, register the transfer of, or exchange any Debt Securities of a series during the period beginning 15 days before the date the notice is mailed identifying the Debt Securities of that series that have been selected for redemption; or - register the transfer of, or exchange any Debt Security of that series selected for redemption except the unredeemed portion of a Debt Security being partially redeemed. CONSOLIDATION, MERGER, CONVEYANCE OR TRANSFER The Indenture provides that we may consolidate or merge with or into, or convey or transfer all or substantially all of our properties and assets to, another corporation or other entity. Any successor must, however, assume our obligations under the Indenture and the Debt Securities, and we must deliver an officers' certificate and an opinion of counsel to the Trustee that affirms compliance with all conditions in the Indenture. When those conditions are satisfied, the successor will succeed to and be substituted for us under the Indenture, and we will be relieved of our obligations under the Indenture and the Debt Securities. EVENTS OF DEFAULT Unless otherwise specified in the applicable prospectus supplement, each of the following will constitute an event of default under the Indenture: - failure to pay principal of or premium on any Debt Security of that series when due; - failure to pay when due any interest on any Debt Security of that series that continues for 60 days; for this purpose, the date on which interest is due is the date on which we are required to make payment following any deferral of interest payments by us under the terms of Debt Securities that permit such deferrals; - failure to make any sinking fund payment when required for any Debt Security of that series that continues for 60 days; - failure to perform any covenant in the applicable Indenture (other than a covenant expressly included solely for the benefit of other series) that continues for 90 days after the Trustee or the holders of at least 33% of the outstanding Debt Securities of that series give us written notice of the default; - certain events of bankruptcy, insolvency or reorganization affecting us; and - any other event of default that may be provided with respect to Debt Securities of that series. In the case of the fourth event of default listed above, the Trustee may extend the grace period. In addition, if holders of a particular series have given a notice of default, then holders of at least the same percentage of Debt Securities of that series, together with the Trustee, may also extend the grace period. The grace period will be automatically extended if we have initiated and are diligently pursuing corrective action. If an event of default with respect to Debt Securities of a series occurs and is continuing, then the Trustee or the holders of at least 33% of the outstanding Debt Securities of that series may declare the principal amount of all Debt Securities of that series to be immediately due and payable. However, that event of default will be considered waived at any time after the declaration but before a judgment for payment of the money due has been obtained, if: - we have paid or deposited with the Trustee all overdue interest, the principal and any premium due otherwise than by the declaration and any interest on such amounts, and any interest on overdue 10 132 interest, to the extent legally permitted, in each case with respect to that series, and all amounts due to the Trustee; and - all events of default with respect to that series, other than the nonpayment of the principal that became due solely by virtue of the declaration, have been cured or waived. The Trustee is under no obligation to exercise any of its rights or powers at the request or direction of any holders of Debt Securities unless those holders have offered the Trustee security or indemnity against the costs, expenses and liabilities that it might incur as a result. The holders of a majority in principal amount of the outstanding Debt Securities of any series have, with certain exceptions, the right to direct the time, method and place of conducting any proceedings for any remedy available to the Trustee or the exercise of any power of the Trustee with respect to those Debt Securities. The Trustee may withhold notice of any default, except a default in the payment of principal or interest, from the holders of any series if the Trustee in good faith considers it in the interest of the holders to do so. The holder of any Debt Security will have an absolute and unconditional right to receive payment of the principal, any premium and, within certain limitations, any interest on that Debt Security on its maturity date or redemption date and to enforce those payments. If certain payments on a series of Debt Securities are insured by a financial guaranty insurance policy or other policy, terms other than those that are described in the preceding three paragraphs may apply to that series. We will be required to furnish to the Trustee annually a statement by certain of our officers to the effect that we are not in default under the Indenture, or if there has been a default, specifying the default and its status. PAYMENTS; PAYING AGENT The paying agent will pay the principal of any Debt Securities only if those Debt Securities are surrendered to it. Unless we state otherwise in the applicable prospectus supplement, the paying agent will pay interest on Debt Securities, subject to such surrender, where applicable, at its office or, at our option: - by wire transfer to an account at a banking institution in the United States that is designated in writing to the Trustee at least 16 days prior to the date of payment by the person entitled to that interest; or - by check mailed to the address of the person entitled to that interest as that address appears in the security register for those Debt Securities. Unless we state otherwise in the applicable prospectus supplement, the Trustee will act as paying agent for that series of Debt Securities, and the principal corporate trust office of the Trustee will be the office through which the paying agent acts. We may, however, change or add paying agents or approve a change in the office through which a paying agent acts. Any money that we have paid to a paying agent for principal or interest on any Debt Securities that remains unclaimed at the end of two years after that principal or interest has become due will be repaid to us at our request. After repayment to us, holders should look only to us for those payments. NEGATIVE PLEDGE While any of the Debt Securities remain outstanding, we will not, and will not permit any Principal Subsidiary (as defined below) to, create, or permit to be created or to exist, any mortgage, lien, pledge, security interest or other encumbrance upon any Principal Property (as defined below) of ours or of a Principal Subsidiary, or upon any shares of stock of any Principal Subsidiary, whether such Principal Property is, or shares of stock are, owned on or acquired after the date of the Indenture, to secure any of 11 133 our indebtedness for borrowed money, unless the Debt Securities then outstanding are equally and ratably secured for so long as any such indebtedness is so secured. The foregoing restriction does not apply with respect to, among other things: - purchase money mortgages, or other purchase money liens, pledges, security interests or encumbrances upon property that we or any Principal Subsidiary acquired after the date of the Indenture; mortgages, liens, pledges, security interests or other encumbrances existing on any property or shares of stock at the time we or any Principal Subsidiary acquired it or them, including those which exist on any property or shares of stock of an entity with which we or any Principal Subsidiary are consolidated or merged or which transfers or leases all or substantially all of its properties to us or any Principal Subsidiary; or conditional sales agreements or other title retention agreements and leases in the nature of title retention agreements with respect to any property that we or any Principal Subsidiary acquired after the date of the Indenture; provided, however, that no such mortgage, lien, pledge, security interest or other encumbrance shall extend to or cover any other property that we or any Principal Subsidiary owns. - mortgages, liens, pledges, security interests or other encumbrances upon any of our property or the property of any Principal Subsidiary or shares of stock of any Principal Subsidiary that existed on the date of the initial issuance of Debt Securities or upon the property or shares of stock of any corporation existing at the time that entity became a Principal Subsidiary; - pledges or deposits to secure performance in connection with bids, tenders, contracts (other than contracts for the payment of money) or leases to which we are, or any Principal Subsidiary is, a party; - liens created by or resulting from any litigation or proceeding which at the time is being contested in good faith by appropriate proceedings; - liens incurred in connection with repurchase, swap or other similar agreements (including commodity price, currency exchange and interest rate protection agreements); - mortgages, liens, pledges, security interests or other encumbrances on any property arising in connection with any defeasance, covenant defeasance or in-substance defeasance of our or any Principal Subsidiary's indebtedness, including the Debt Securities; - mortgages, liens, pledges, security interests or other encumbrances in favor of the United States of America, any State, any foreign country or any department, agency or instrumentality or political subdivision of any such jurisdiction, to secure partial, progress, advance or other payments pursuant to any contract or statute or to secure any indebtedness incurred for the purpose of financing all or any part of the purchase price or the cost of constructing or improving the property subject to such mortgages, including, without limitation, mortgages to secure indebtedness of the pollution control or industrial revenue bond type; - indebtedness which may be issued by us or any of our Principal Subsidiaries in connection with our consolidation or merger or the consolidation or merger of any of our Principal Subsidiaries with or into any other entity in exchange for or otherwise in substitution for secured indebtedness of that entity ("Third Party Debt") which by its terms (1) is secured by a mortgage on all or a portion of the property of that entity, (2) prohibits secured indebtedness from being incurred by that entity, unless the Third Party Debt is secured equally and ratably with such secured indebtedness, or (3) prohibits secured indebtedness from being incurred by that entity; - indebtedness of any entity which we or any Principal Subsidiary are required to assume in connection with a consolidation or merger of that entity, with respect to which any of our or any Principal Subsidiary's property is subjected to a mortgage, lien, pledge, security interest or other encumbrance; 12 134 - mortgages, liens, pledges, security interests or other encumbrances on property held or used by us or any Principal Subsidiary in connection with the gathering, processing, transportation or marketing of natural gas, oil or other minerals; - mortgages, liens, pledges, security interests or other encumbrances in favor of us, one or more Principal Subsidiaries, one or more wholly owned Subsidiaries (as defined below) or any of the foregoing in combination; - mortgages, liens, pledges, security interests or other encumbrances upon any property acquired, constructed, developed or improved by us or any Principal Subsidiary after the date of the Indenture which are created before, at the time of, or within 18 months after such acquisition (or in the case of property constructed, developed or improved, after the completion of the construction, development or improvement and commencement of full commercial operation of that property, whichever is later) to secure or provide for the payment of any part of its purchase price or cost; provided that, in the case of such construction, development or improvement, the mortgages, liens, pledges, security interests or other encumbrances shall not apply to any property that we or any Principal Subsidiary own other than real property that is unimproved until that time; and - the replacement, extension or renewal of any mortgage, lien, pledge, security interest or other encumbrance described above or the replacement, extension or renewal (not exceeding the principal amount of indebtedness so secured together with any premium, interest, fee or expense payable in connection with any such replacement, extension or renewal) of the indebtedness so secured; provided that such replacement, extension or renewal is limited to all or a part of the same property that secured the mortgage, lien, pledge, security interest or other encumbrance replaced, extended or renewed, plus improvements on it or additions or accessions to it. In addition, we or any Principal Subsidiary may create or assume any other mortgage, lien, pledge, security interest or other encumbrance not excepted in the Indenture without us equally and ratably securing the Debt Securities, if immediately after that creation or assumption, our principal amount of indebtedness for borrowed money that all such other mortgages, liens, pledges, security interests and other encumbrances secure does not exceed an amount equal to 10% of our Consolidated Adjusted Net Assets as shown on our consolidated balance sheet for the accounting period occurring immediately before the creation or assumption of that mortgage, lien, pledge, security interest or other encumbrance. For purposes of the preceding paragraphs, the following terms have these meanings: "Principal Property" means any natural gas pipeline, natural gas gathering system, natural gas storage facility, natural gas processing plant or other plant or facility located in the United States that in the opinion of our Board of Directors or our management is of material importance to our business and the business of our consolidated subsidiaries taken as a whole; "Principal Subsidiary" means any of our Subsidiaries that owns a Principal Property; and "Subsidiary" means, as to any entity, an entity of which more than 50% of the outstanding capital stock having ordinary voting power (other than capital stock having such power only by reason of contingency) is at the time owned, directly or indirectly, through one or more intermediaries, or both, by such entity. LIMITATION ON SALES AND LEASEBACKS Neither we nor any Principal Subsidiary may enter into any Sale and Leaseback Transaction unless: - we or that Principal Subsidiary would be entitled to incur indebtedness in a principal amount equal to the Attributable Debt with respect to such Sale and Leaseback Transaction, secured by a mortgage, lien, pledge, security interest or other encumbrance on the property subject to such Sale and Leaseback Transaction without equally and ratably securing the Debt Securities pursuant to the covenant described above under "Negative Pledge"; - after the date on which the Debt Securities are originally issued and within a period beginning 12 months prior to the consummation of such Sale and Leaseback Transaction and ending 12 13 135 months after the consummation of such Sale and Leaseback Transaction, we or any Subsidiary shall have expended for property used or to be used in our business or the business our Subsidiaries an amount equal to all or a portion of the net proceeds from such Sale and Leaseback Transaction and we shall have elected to designate such amount as a credit against such Sale and Leaseback Transaction (with any amount not being so designated to be applied as set forth in the following bullet point); - during the 12-month period after the effective date of such Sale and Leaseback Transaction, we shall have applied to the voluntary defeasance or retirement of Debt Securities or any other indebtedness an amount equal to the greater of the net proceeds of the sale or transfer of the property leased in such Sale and Leaseback Transaction and the fair value, as determined by our Board of Directors, of such property at the time such Sale and Leaseback Transaction was entered into (in either case adjusted to reflect the remaining term of the lease and any amount we expend as set forth in the preceding bullet point), less an amount equal to the principal amount of such Debt Securities or other indebtedness voluntarily defeased or retired within such 12-month period and not designated as a credit against any other Sale and Leaseback Transaction that we or any of our Subsidiaries enter into during such period; or - such Sale and Leaseback Transaction is with one of our Affiliates. This restriction will not apply to certain Sale and Leaseback Transactions between us and a Principal Subsidiary or between Principal Subsidiaries. For purposes of the preceding paragraph, the following terms have these meanings: "Sale and Leaseback Transaction" means an arrangement with any lender or investor or to which such lender or investor is a party providing for the leasing for a term of greater than three years of any property or asset which has been or is being sold or transferred more than 18 months after its acquisition or the completion of construction or beginning of operation thereof to such lender or investor or to any entity to whom funds have been or are to be advanced by such lender or investor on the security of the property or asset; "Affiliate" of a specified person or entity means any other person or entity directly or indirectly controlling or controlled by or under direct or indirect common control with such specified person or entity; "Attributable Debt" means the total net amount of rent (discounted at the rate per year indicated in the Indenture) required to be paid during the remaining term of any lease; and "Consolidated Adjusted Net Assets" means the total amount of assets after deducting: - all current liabilities (excluding any which are by their terms extendible or renewable at the option of the obligor to a time more than 12 months after the time as of which the amount is being computed); and - total prepaid expenses and deferred charges. MODIFICATION AND WAIVER The Indenture may be modified with the consent of the holders of a majority in principal amount of the outstanding Debt Securities of all series affected by the modification (voting as one class). The consent of the holder of each outstanding Debt Security affected is, however, required to: - change the maturity date of the principal, or any installment of principal or interest on that Debt Security; - reduce the principal amount, the interest rate or any premium payable upon redemption of that Debt Security; - reduce the amount of principal due and payable upon acceleration of maturity; - change the currency of payment of principal, premium or interest on that Debt Security; 14 136 - impair the right to institute suit to enforce any such payment on or after the maturity date or redemption date; - reduce the percentage in principal amount of Debt Securities of any series required to amend or modify the Indenture, waive compliance with certain restrictive provisions of the Indenture or waive certain defaults; or - with certain exceptions, modify the provisions of the Indenture governing amendments of the Indenture or governing waiver of covenants or past defaults. In addition, we may supplement the Indenture to create new series of Debt Securities and for certain other purposes, without the consent of any holders of Debt Securities. The holders of a majority in principal amount of the outstanding Debt Securities of any series may waive, for that series, our compliance with certain restrictive provisions of the Indenture, including the covenants described under "Negative Pledge" and "Limitation on Sales and Leasebacks". The holders of a majority in principal amount of the outstanding Debt Securities of all series with respect to which a default has occurred and is continuing, voting as one class, may waive that default for all those series, except a default in the payment of principal or any premium or interest on any Debt Security or a default with respect to a covenant or provision that cannot be amended or modified without the consent of the holder of each outstanding Debt Security of the series affected. If certain payments on a series of Debt Securities are insured by a financial guaranty insurance policy or other policy, terms other than those that are described in the preceding paragraph may apply to that series. DEFEASANCE AND COVENANT DEFEASANCE If, and to the extent, indicated in the applicable prospectus supplement, we may elect, at our option at any time, to have the provisions of the Indenture relating to defeasance or covenant defeasance applied to the Debt Securities of any series or to any part of a series. The Indenture provides that we may be: - discharged from our obligations, with certain limited exceptions, with respect to any series of Debt Securities, as described in the Indentures, such a discharge being called a "defeasance" in this prospectus; and - released from our obligations under the covenants described in "Negative Pledge" and "Limitations on Sales and Leasebacks" and any restrictive covenants that may be especially established with respect to any series of Debt Securities, such a release being called a "covenant defeasance" in this prospectus. We must satisfy certain conditions to effect a defeasance or covenant defeasance. Those conditions include the irrevocable deposit with the Trustee, in trust, of money or government obligations that through their scheduled payments of principal and interest would provide sufficient money to pay the principal and any premium and interest on those Debt Securities on the maturity dates of those payments or upon redemption. Additional conditions, if any, to exercising defeasance or covenant defeasance with respect to any series of Debt Securities will be described in the applicable prospectus supplement. Following a defeasance, payment of the Debt Securities defeased may not be accelerated because of an event of default. Following a covenant defeasance, the payment of Debt Securities may not be accelerated by reference to the covenants from which we have been released. A defeasance may occur after a covenant defeasance. Under current U.S. federal income tax laws, a defeasance would be treated as an exchange of the relevant Debt Securities in which holders of those Debt Securities might recognize gain or loss. In addition, the amount, timing and character of amounts that holders would thereafter be required to include in income might be different from that which would be includible in the absence of that defeasance. We 15 137 urge investors to consult their own tax advisors as to the specific consequences of a defeasance, including the applicability and effect of tax laws other than U.S. federal income tax laws. Under current U.S. federal income tax laws, unless accompanied by other changes in the terms of the Debt Securities, a covenant defeasance should not be treated as a taxable exchange. CONCERNING THE TRUSTEE The Trustee will perform only those duties that are specifically set forth in the Indenture unless an event of default occurs and is continuing. In case an event of default occurs and is continuing, the Trustee will exercise the same degree of care as a prudent individual would exercise in the conduct of his or her own affairs. Subject to those provisions, the Trustee is under no obligation to exercise any of its powers under the Indenture at the request of any holder of Debt Securities unless that holder offers reasonable indemnity to the Trustee against the costs, expenses and liabilities that it might incur as a result. NOTICE Notice to holders of Debt Securities will be given by mail to such holders as they may appear in the security register. TITLE We, the Trustee and any agent of our company or of the Trustee may treat the person in whose name a Debt Security is registered as the absolute owner of the Debt Security, whether or not such Debt Security may be overdue, for the purpose of making payment and for all other purposes. GOVERNING LAW The Indenture and the Debt Securities will be governed by, and construed in accordance with, the laws of the State of New York. PLAN OF DISTRIBUTION We may sell the Debt Securities: - through underwriters or dealers; - through agents; - directly to a limited number of institutional purchasers or to a single purchaser; or - through a combination of any of these methods of sale. The applicable prospectus supplement will describe the terms under which the offered Debt Securities are offered, including: - the names of any underwriters, dealers or agents; - the purchase price and the net proceeds from the sale; - any underwriting discounts and other items constituting underwriters' compensation; - any initial public offering price; and - any discounts or concessions allowed, re-allowed or paid to dealers. Any underwriters or dealers may from time to time change any initial public offering price and any discounts or concessions allowed, re-allowed or paid to dealers. 16 138 If underwriters participate in the sale of the offered Debt Securities, those underwriters will acquire the Debt Securities for their own account and may resell them in one or more transactions, including negotiated transactions, at a fixed public offering price or at varying prices determined at the time of the sale. If the Debt Securities are sold through underwriters, the applicable prospectus supplement will state the names and any compensation that may be paid to the underwriters. Unless we state otherwise in the applicable prospectus supplement, the obligations of any underwriter to purchase the offered Debt Securities will be subject to conditions, and the underwriter will be obligated to purchase all the Debt Securities offered, except that in some cases involving a default by an underwriter, less than all of the Debt Securities offered may be purchased. If the offered Debt Securities are sold through an agent, the applicable prospectus supplement will state the name and any compensation that may be paid to the agent. Unless we state otherwise in the applicable prospectus supplement, that agent will be acting on a best-efforts basis for the period of its appointment. We may have agreements with the underwriters, dealers and agents to indemnify them against certain civil liabilities, including liabilities under the Securities Act, or to contribute with respect to payments that the underwriters, dealers or agents may be required to make. Underwriters, dealers, agents and their affiliates may engage in transactions with us or our affiliates, and may from time to time perform services for us or our affiliates in the ordinary course of their business. We may authorize agents, underwriters or dealers to solicit offers by certain institutional investors to purchase offered Debt Securities providing for payment and delivery on a future date specified in the applicable prospectus supplement. Institutional investors to which such offers may be made, when authorized, include commercial and savings banks, insurance companies, pension funds, investment companies, education and charitable institutions and such other institutions as may be approved by us. The obligations of any such purchasers under such delayed delivery and payment arrangements will be subject to the condition that the purchase of the offered Debt Securities will not at the time of delivery be prohibited under applicable law. The underwriters and such agents will not have any responsibility with respect to the validity or performance of such contracts. The Debt Securities may or may not be listed on a national securities exchange. 17 139 EXPERTS The combined financial statements of Duke Energy Field Services, LLC and Affiliates as of December 31, 1998 and 1999 and each of the three years in the period ended December 31, 1999 and the 1997 combined statements of operations and cash flows for UPFuels Division incorporated in this prospectus by reference and appearing in the Form 10 of the Company filed on July 20, 2000 have been audited by Deloitte & Touche LLP, independent auditors, as stated in their reports which are also incorporated herein by reference, and have been so incorporated in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing. The consolidated financial statements of Phillips Gas Company as of December 31, 1999 and 1998 and for each of the three years in the period ended December 31, 1999 included in the Form 10 of the Company filed on July 20, 2000, which are incorporated herein by reference, have been audited by Ernst & Young LLP, independent auditors, as set forth in their report which is incorporated herein by reference and has been so incorporated in reliance upon such report given on the authority of such firm as experts in accounting and auditing. The combined statements of income and cash flows of the UPFuels Division of Union Pacific Resources Group, Inc. for the year ended December 31, 1998 and the three months ended March 31, 1999 included in the Form 10 of the Company filed on July 20, 2000, which are incorporated herein by reference, have been audited by Arthur Andersen LLP, independent public accountants, as stated in their report on such financial statements in reliance upon the report of such firm given upon their authority as experts in auditing and accounting. VALIDITY OF THE SECURITIES Our legal counsel, Vinson & Elkins L.L.P., Houston, Texas, will pass upon the validity of the Debt Securities on our behalf. Counsel named in any applicable prospectus supplement will pass upon the validity of the Debt Securities on behalf of any underwriters, dealers or agents. 18 140 ================================================================================ UNTIL , 2000, ALL DEALERS THAT EFFECT TRANSACTIONS IN THESE SECURITIES, WHETHER OR NOT PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO DELIVER A PROSPECTUS AND PROSPECTUS SUPPLEMENT. THIS IS IN ADDITION TO THE DEALERS' OBLIGATION TO DELIVER A PROSPECTUS AND PROSPECTUS SUPPLEMENT WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR SUBSCRIPTIONS. $ [DUKE ENERGY FIELD SERVICES LOGO] DUKE ENERGY FIELD SERVICES, LLC $ % NOTES DUE $ % NOTES DUE ------------------------------------------------------------ PROSPECTUS SUPPLEMENT ------------------------------------------------------------ MERRILL LYNCH & CO. J.P. MORGAN & CO. BANC OF AMERICA SECURITIES LLC CHASE SECURITIES INC. LEHMAN BROTHERS MORGAN STANLEY DEAN WITTER , 2000 ================================================================================