10-K405 1 d95180e10-k405.txt FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 2001 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 --------------------- FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 0-31095 DUKE ENERGY FIELD SERVICES, LLC (Exact name of registrant as specified in its charter) DELAWARE 76-0632293 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 370 17TH STREET, SUITE 900 80202 DENVER, COLORADO (Zip Code) (Address of principal executive offices)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE 303-595-3331 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED ------------------- ----------------------------------------- None Not Applicable
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: LIMITED LIABILITY COMPANY MEMBER INTERESTS (Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months or for such shorter period that the registrant was required to file such reports and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] As of March 22, 2002, 69.7% of the registrant's outstanding member interests is beneficially owned by Duke Energy Corporation and 30.3% is beneficially owned by Phillips Petroleum Company. The aggregate market value of the voting member interests held by non-affiliates of the Registrant as of March 22, 2002 was $0. DOCUMENTS INCORPORATED BY REFERENCE: NONE -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- DUKE ENERGY FIELD SERVICES, LLC FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2001 TABLE OF CONTENTS
ITEM PAGE ---- ---- PART I 1. Business.................................................... 3 Our Business................................................ 3 Our Business Strategy....................................... 4 Natural Gas Gathering, Processing, Transportation, Marketing and Storage................................................. 5 Natural Gas Liquids Transportation, Fractionation and Marketing................................................... 12 TEPPCO...................................................... 13 Natural Gas Suppliers....................................... 14 Competition................................................. 15 Regulation.................................................. 15 Environmental Matters....................................... 18 Employees................................................... 19 2. Properties.................................................. 19 3. Legal Proceedings........................................... 19 4. Submission of Matters to a Vote of Security Holders......... 19 PART II 5. Market for Registrant's Common Equity and Related Stockholder Matters......................................... 19 6. Selected Financial Data..................................... 21 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................... 23 7A. Quantitative and Qualitative Disclosures About Market Risk........................................................ 34 8. Financial Statements and Supplementary Data................. 39 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................... 69 PART III 10. Directors and Executive Officers of the Registrant.......... 69 11. Executive Compensation...................................... 71 12. Security Ownership of Certain Beneficial Owners and Management.................................................. 74 13. Certain Relationships and Related Transactions.............. 75 PART IV 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K......................................................... 77 Signatures........................................................ 78
1 CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as "may," "could," "project," "believe," "anticipate," "expect," "estimate," "potential," "plan," "forecast" and other similar words. All of such statements other than statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements. These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks include, but are not limited to, the following: - our ability to access the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations; - our use of derivative financial instruments to hedge commodity and interest rate risks; - the level of creditworthiness of counterparties to transactions; - changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment or the increased regulation of the gathering and processing industry; - the timing and extent of changes in commodity prices, interest rates and demand for our services; - weather and other natural phenomena; - industry changes, including the impact of consolidations, and changes in competition; - our ability to obtain required approvals for construction or modernization of gathering and processing facilities, and the timing of production from such facilities, which are dependent on the issuance by federal, state and municipal governments, or agencies thereof, of building, environmental and other permits, the availability of specialized contractors and work force and prices of and demand for products; and - the effect of accounting policies issued periodically by accounting standard-setting bodies. In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. 2 PART I ITEM 1. BUSINESS Duke Energy Field Services, LLC is a company formed in 1999 that holds the combined North American midstream natural gas gathering, processing, marketing and natural gas liquids ("NGL") business of Duke Energy Corporation ("Duke Energy") and Phillips Petroleum Company ("Phillips"). The transaction in which those businesses were combined is referred to in this Form 10-K 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 NGLs 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 Form 10-K 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." In this Form 10-K, the terms "the Company," "we," "us" and "our" refer to Duke Energy Field Services, LLC and our subsidiaries, giving effect to the Combination and related transactions. From a financial reporting perspective, we are the successor to Duke Energy's North American midstream natural gas business. The subsidiaries of Duke Energy that conducted this business were contributed to us immediately prior to the Combination. For periods prior to the Combination, Duke Energy Field Services and these subsidiaries of Duke Energy are collectively referred to herein as the "Predecessor Company." 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. Our telephone number is 303-595-3331. 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 ("Natural Gas Segment"); and - NGL fractionation, transportation, marketing and trading ("NGL Segment"). 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 2001: - we handled an average of approximately 8.6 trillion British thermal units ("Btus") per day of raw natural gas; - we produced an average of approximately 397,000 barrels per day of NGLs; and - we marketed and traded an average of approximately 565,000 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 40,000 active receipt points. 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 64 owned and operated plants and at 12 third party operated facilities in which we hold an equity interest. 3 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 fractionators 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 and Chevron Phillips Chemical Company LLC under an existing contract which expires December 31, 2014. In addition, we use trading and storage to manage our price risk and provide additional services to our customers. (See "Natural Gas Liquids Transportation, Fractionation and Marketing" in this section.) 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 9.0 billion cubic foot natural gas storage facility. 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. Concurrent with the Combination, on March 31, 2000, we obtained by transfer from Duke Energy the general partner of TEPPCO Partners, L.P. ("TEPPCO"), a publicly traded master limited partnership which owns and operates a network of pipelines and storage and terminal facilities for refined products, liquefied petroleum gases, liquefied natural gas, petrochemicals, natural gas gathering 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. A discussion of the current business and operations of each of our segments follows. For further discussion of these segments, see "Management's Discussion and Analysis of Financial Condition and Results of Operations." For financial information concerning our business segments, see Note 17, "Business Segments," of the Notes to Consolidated Financial Statements. 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. 4 - 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 30 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. NATURAL GAS GATHERING, PROCESSING, TRANSPORTATION, MARKETING AND STORAGE OVERVIEW At December 31, 2001, our raw natural gas gathering and processing operations consisted of: - approximately 57,000 miles of gathering pipe, with connections to approximately 40,000 active receipt points; and - 64 owned and operated processing plants and ownership interests in 12 additional third party operated plants, with a combined processing capacity of approximately 8.0 billion cubic feet per day. In 2001, we gathered, processed and/or transported approximately 8.6 trillion Btus per day of raw natural gas. During 2001, our natural gas gathering, processing, transportation, marketing and storage activities produced $1.2 billion of gross margin. 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. According to the "Gas Processors Report" dated July 2, 2001, we are the largest NGL producer. Raw Natural Gas Supply Arrangements. Typically, we take ownership, control or custody of raw natural gas at the wellhead. Each producer generally dedicates to us the raw natural gas produced from designated oil 5 and natural gas leases for a specific term. The term will typically extend for three to seven years. 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, 2001, we had over 20 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 Phillips, Anadarko Petroleum, EOG Resources, Exxon Mobil, and Louis Dreyfus Natural Gas, 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 provide 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, 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 2,800 additional receipt points in 2001. 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 received an average of approximately 6.6 trillion Btus per day of raw gas and produced an average of 397,000 barrels per day of NGLs during 2001. 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. 6 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. Our Spindletop storage facility plays an important role in our ability to act as a full-service natural gas marketer. We lease over half 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, provide "backup" service to our customers and support our trading activities. 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. 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. 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 December 31, 2001.
2001 OPERATING DATA GAS PLANTS ------------------------- GATHERING COMPANY OPERATED NET PLANT PLANT INLET NGLS SYSTEM OPERATED BY CAPACITY(1) VOLUME(1) PRODUCTION REGION (MILES) PLANTS OTHERS (MMcf/d)(3) (BBtu/d)(3) (Bbls/d)(3) ------ --------- -------- -------- ----------- ----------- ----------- Permian Basin............ 13,400 17 2 1,380 1,391 124,928 Mid-Continent............ 29,759 14 2 2,119 1,910 123,992 East Texas-Austin Chalk- North Louisiana........ 5,541 8 - 1,352 1,161 68,725 Onshore Gulf of Mexico... 3,775 7 1 1,118 1,044 46,798 Rocky Mountains.......... 3,400 10 1 640 503 26,421 Offshore Gulf of Mexico................. 452 2 5 1,100 270(2) 4,968 Western Canada........... 921 6 1 543 311 1,472 ------ -- -- ----- ----- ------- Total.................... 57,248 64 12 8,252 6,590 397,304
--------------- (1) Note that while capacity is measured volumetrically (in cubic feet), inlet volumes are measured using heating value (in British thermal units). (2) Excludes inlet volumes of about 470 BBtu/d net for plants operated by others. (3) MMcf/d: million cubic feet per day; BBtu/d: billion British thermal units per day; Bbls/d: barrels per day. 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 7 principal competitors in this segment of our business consist of major integrated oil companies, independent oil and gas gatherers, 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 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 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 17 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 Permian Basin production. 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, processing, and marketing of natural gas and NGLs. We offer low, intermediate and high pressure gathering services, and processing and treating services for both sweet and sour gas production. 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 some of our plants include facilities for the production of sulfur. During 2001, these plants operated at an overall 82% capacity utilization rate. On average, the raw natural gas from West Texas and New Mexico contains approximately 5.0 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 increases 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 Exxon Mobil, Occidental, Anadarko Petroleum, Phillips, Dominion, Chevron-Texaco, and Yates Petroleum. Our principal competitors in this region include Dynegy, 8 Sid Richardson, Conoco, Western Gas, British Petroleum, El Paso Field Services, Marathon and Chevron-Texaco. Mid-Continent. Our facilities in this region are located in Oklahoma, Kansas, the Texas Panhandle and the Ladder Creek area of Southeast Colorado. In this region, we own and are the operator of 14 natural gas processing plants. 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 2.1 billion cubic feet of raw natural gas per day. During 2001, our plants operated at an overall 77% capacity utilization rate. On average, the raw natural gas from this region contains 4.2 gallons of NGLs per thousand cubic feet. We also produce approximately 30% 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 is uniquely positioned to pursue our consolidation strategy. Our key suppliers in this region include Phillips, OXY USA, Dominion, EOG Resources and Anadarko Petroleum. Our principal competitors in this region include 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 eight natural gas processing plants in this region. Our plants have processing capacity net to our interest of 1.4 billion cubic feet of raw natural gas per day. During 2001, these plants operated at an overall 74% capacity utilization rate. 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. The plant is connected to and processes raw natural gas from our own gathering systems as well as from several third party gathering systems, including those owned by Koch, Anadarko Petroleum and American Central. Most of the raw natural gas processed at the complex is contracted under percent-of-proceeds agreements with an average remaining term of approximately five years. This plant is adjacent to our Carthage Hub, which delivers residue gas to interconnects with 12 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. In the Austin Core area, where we provide essential low pressure gathering and compression services, infill drilling and recompletion activity continues to offset the lower decline rates of this mature production area. Given the maturity of this area, consolidation of our own facilities and/or consolidation with other gathering and processing companies could occur. In the Eastern Chalk area (Brookeland and Masters Creek) where we are in the process of consolidating facilities, reduced activity and declining volumes are expected to continue. Additional improvements in technology could significantly increase activity and reserve recovery in either of these areas. In North Louisiana, we gather and process or gather and transport over 420,000 million Btu/d. We operate one of the largest intrastate pipelines in Louisiana, our PELICO System, which delivers gas to industrial customers and electric generators within the state and also makes deliveries to six interstate pipelines at or near the Perryville Hub. 9 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 Anadarko Petroleum, Devon and Phillips. Our principal competitors in this region include Koch, El Paso Field Services and Aquila 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 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 2001, the plants in this region ran at an overall 83% capacity utilization rate. Our Spindletop natural gas storage facility is located near Beaumont, Texas and has current working natural gas capacity of 9.0 billion cubic feet, plus expansion potential of up to an additional 10 billion cubic feet. We currently have approximately 5.0 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 10 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 Apache, United Oil and Minerals and TransTexas. Our principal competitors in this region include El Paso Gas Transmission, Co., 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 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 640 million cubic feet of raw natural gas per day. During 2001, our plants in this region operated at an overall 72% capacity utilization rate. These assets provide for the gathering and processing of raw natural gas and the transportation and fractionation of NGLs. 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, British Petroleum, Kerr McGee and Anadarko Petroleum. 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 an average 48% interest in and are the operator of two natural gas processing plants in this region. In addition, we own a 51% interest in one natural gas processing plant and minority interests in four other natural gas processing plants, all of which are operated by other entities. The plants have processing capacity net to our interest of 1.1 billion cubic feet of raw natural gas per day. During 2001, our plants in this region operated at an overall 63% capacity utilization rate. All of these plants straddle offshore pipeline systems delivering a lower NGL-content gas stream than that of our onshore gathering systems. 10 In addition, we own a 71.8% interest in the Dauphin Island Gathering Partners ("Dauphin Island"), a partnership which owns and operates an offshore gathering and transmission system. Dauphin Island has attractive market outlets, including deliveries to Texas Eastern Transmission, LP, Transco, Gulf South, 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, LP's pipeline provides us with a means to 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 33.3% 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 El Paso Production Company, Exxon Mobil and Dominion. Our principal competitors in this region include El Paso, Coral Energy, Enterprise, and Williams. Western Canada. On May 1, 2001, we closed the acquisition of Canadian Midstream Services Ltd. ("CMSL"). From CMSL, we acquired working interests in the Brazeau area of west central Alberta, the Nevis area of southern Alberta and the Peggo-Pesh area of northeast British Columbia. In total, we acquired 325 MMcf/d of sour gas processing capacity, 580 miles of gathering lines and 53,000 horsepower of compression from CMSL. As a result of the CMSL transaction, we currently own interests in seven natural gas processing plants in Western Canada and operate six of these plants. These facilities are located in northeast British Columbia, the Peace River Arch area of northwestern Alberta and the central foothills area of Alberta. In total, the facilities in this region have processing capacity net to our interest of 543 million cubic feet of raw sour natural gas per day. Over 900 miles of gathering systems and 100,000 horsepower of compression support these facilities. During 2001, our processing plants in this area operated at an overall 52% 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. Our foreign operations in Canada are subject to risks inherent in transactions involving foreign currencies. 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. We believe that significant growth opportunities exist in this region. We anticipate that producers in this area may follow the lead of United States 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 Burlington Resources Canada Ltd., Canadian Natural Resources Ltd., Alberta Energy Company and Devon Energy Canada. Our principal competitors in the area include Gibson Gas Processing Ltd., BP Amoco, Petro Canada and Keyspan Energy. 11 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 2001, our NGL transportation, fractionation and marketing activities produced $55.4 million of gross margin and $49.0 million of earnings before interest, taxes, depreciation and amortization ("EBITDA") (see "Item 6. Selected Financial Data" footnote three for definition of EBITDA). In 2001, we marketed and traded approximately 565,000 barrels per day of NGLs, of which approximately 73% was production for our own account, ranking us as one of the largest NGL 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 addition, we own an interest in the Black Lake Pipeline in Louisiana and East Texas. We also own several regional fractionation plants and NGL pipelines. In 2001, we acquired five propane rail terminals and constructed one in the northeastern United States, establishing us as a prominent wholesale purchaser and seller of propane in the Northeast. Marketing propane from these rail terminals, along with volume from TEPPCO's Providence, Rhode Island import facility, accounts for approximately 25,000 barrels per day of wholesale business. 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 nine pipeline systems. Our current fractionation capacity is approximately 164,000 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 is discussed briefly 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 NGL 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 12 49,500 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 NGL 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 NGL needs. Our largest suppliers are our own plants and Anadarko Petroleum. Our largest sales customers are Chevron Phillips Chemical Company, Phillips Chemical Company, Equistar Chemicals, Dow Hydrocarbons and Huntsman, which accounted for approximately 15.0%, 13.0%, 5.0%, 4.0% and 3.0%, respectively, of our total NGL transportation, fractionation and marketing revenues in 2001. Our three principal competitors in the marketing of NGLs are El Paso, Dynegy and Williams. In 2001, we marketed and traded an average of approximately 565,000 barrels per day, or approximately 21% 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 master limited partnership. TEPPCO operates in three principal areas: - refined products, liquefied petroleum gases and petrochemicals transportation (Downstream Segment); - crude oil and NGLs transportation and marketing (Upstream Segment); and - natural gas gathering (Midstream Segment). 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; - intrastate transportation of petrochemicals; - sale of product inventory; - fractionation of NGLs; and - ancillary services. TEPPCO owns and operates an approximate 4,500 mile products pipeline system, which includes storage facilities and delivery terminals, extending from southeast Texas through central and midwest states to the northeast United States. TEPPCO's asset base includes the only pipeline system that transports liquefied petroleum gases to the northeast United States from the Texas Gulf Coast. TEPPCO recently initiated a new service to the petrochemical industry through the construction, ownership and operation of three pipelines in Texas between Mont Belvieu and Port Arthur. TEPPCO also owns and operates approximately 2,900 miles of crude oil gathering and trunk line pipelines and approximately 650 miles of NGL pipelines, primarily in Texas 13 and Oklahoma. TEPPCO also owns a 50% interest in, and operates, a 500 mile large diameter crude oil pipeline extending from the Texas Gulf Coast to Cushing, Oklahoma. TEPPCO also owns interests in two joint venture crude oil pipelines operating in New Mexico, Oklahoma and Texas. TEPPCO also owns a 300 mile gathering system which gathers and transports natural gas from the Green River Basin in southwestern Wyoming. 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 to TEPPCO appropriate assets currently held by us. 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 and 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 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 2001 per unit distribution level, the general partner received approximately 21% of the cash distributed by TEPPCO to its partners, which consisted of 19% from the incentive cash distribution and 2% from the general partner interest. During 2001, total cash distributions to the general partner of TEPPCO were $22.0 million. On January 9, 2002, TEPPCO announced that it had signed a definitive agreement to acquire the Chaparral and Quanah NGL pipelines from Diamond-Koch II, L.P. and Diamond-Koch III, L.P. for approximately $132.0 million. The transaction closed on March 1, 2002. The Chaparral system is an 800 mile NGL pipeline that extends from West Texas and New Mexico to Mont Belvieu, Texas. The approximately 170 mile Quanah pipeline is a NGL gathering system located in West Texas. The assets will be operated and commercially managed by us on behalf of TEPPCO. On September 30, 2001, TEPPCO completed the purchase of the Jonah Gas Gathering Company ("Jonah") from Alberta Energy Company for approximately $360.0 million. The acquisition serves as an entry for TEPPCO into the natural gas gathering industry. The 300 mile Jonah system gathers and transports natural gas from the Green River Basin in southwestern Wyoming, one of the most prolific and active basins in the United States. The Jonah system is commercially managed and operated by us on behalf of TEPPCO. 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 2001. Each producer generally dedicates to us the raw natural 14 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 consider our relations with our many 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 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 the Federal Energy Regulatory Commission ("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 NGL 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 has been regulated under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978, and the regulations promulgated thereunder by the 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 15 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 the 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 a partnership interest in Dauphin Island Gathering Partners, which owns and operates a natural gas gathering system and interstate transmission system located in offshore waters south of Louisiana and Alabama. The offshore gathering system does not provide jurisdictional service under the Natural Gas Act; the interstate offshore transmission system is regulated by the FERC. Commencing in April 1992 the 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 users of the pipeline services. The 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 the FERC continues to review and modify its regulations. For example, the FERC issued Order No. 637 in February 2000 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 it 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 the 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, transporters, processors and marketers with which we compete. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been heavily regulated; 16 therefore, there is no assurance that the less stringent and pro-competition regulatory approach recently pursued by the FERC and Congress will continue. Gathering. The Natural Gas Act exempts natural gas gathering facilities from FERC jurisdiction. Interstate natural gas transmission facilities, on the other hand, remain subject to FERC jurisdiction. The 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 the FERC uses to grant non-jurisdictional gathering facility status. However, there is no assurance that the 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 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. In April 2000, the FERC 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 the 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 that owned and operated by 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. The Company and others challenged the rule, and on January 11, 2002, the U.S. District Court for the District of Columbia issued a summary judgement in favor of the Company and the other plaintiffs, and a permanent injunction against the FERC prohibiting enforcement of Order No. 639. The FERC has filed notice of appeal to the D.C. Circuit Court of Appeals. A ruling in favor of the FERC 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 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 functions of our natural gas processing plants are the extraction of NGLs and the conditioning of natural gas for marketing. The 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 FERC jurisdiction. 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 17 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 assets in the province of British Columbia are regulated by the B.C. Oil and Gas Commission. Our West Doe natural gas gathering pipeline and the Pesh Creek natural gas sales line, which both cross the Alberta/British Columbia border, fall under the jurisdiction of the National Energy Board of Canada. It is a Group 2 company which is regulated on a complaint only basis by the National Energy Board. 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 United States and Canadian laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. Environmental regulations and laws affecting us include: - The Clean Air Act and the 1990 amendments to the Act, as well as counterpart state laws and regulations affecting emissions to the air, that impose responsibilities on the owners and/or operators of air emissions sources including obtaining permits and annual compliance and reporting obligations; - The Federal Water Pollution Control Act and other amendments, which require permits for facilities that discharge treated wastewater or other materials into waters of the United States; - Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act and its amendments, which regulate the management, treatment, and disposal of solid and hazardous wastes, and state programs addressing parallel state issues; - The Comprehensive Environmental Response, Compensation, and Liability Act and its amendments, which may impose liability, regardless of fault, for historic or future disposal or releases of hazardous substances into the environment, including cleanup obligations associated with such releases or discharges; - State regulations for the reporting, assessment and remediation of releases of material to the environment, including historic releases of hydrocarbon liquids; and - Canadian Environmental Laws. 18 Costs of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions or restrictions on operation. For further discussion of our environmental matters, including possible liability and capital costs, see "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Environmental Considerations" and Note 14, "Commitments and Contingent Liabilities -- Environmental," of the Notes to Consolidated Financial Statements. EMPLOYEES As of December 31, 2001, we had approximately 3,600 employees, which includes approximately 900 employees of our wholly-owned subsidiary Texas Eastern Products Pipeline Company, LLC, the general partner of TEPPCO Partners, L.P. We are a party to four collective bargaining agreements which cover an aggregate of approximately 140 of our employees. We believe our relations with our employees are good. ITEM 2. PROPERTIES For information regarding the Company's properties, see "Item 1. Business -- Natural Gas Gathering, Processing, Transportation, Marketing and Storage," and "Natural Gas Liquids Transportation, Fractionation and Marketing," and "TEPPCO" in this section, each of which is incorporated herein by reference. ITEM 3. LEGAL PROCEEDINGS See Note 14, "Commitments and Contingent Liabilities," of the Notes to Consolidated Financial Statements for discussion of the Company's legal proceedings which is incorporated herein by reference. Management believes that the resolution of the matters discussed will not have a material adverse effect on the consolidated results of operations or the financial position of the Company. In addition to the foregoing, from time to time, we are named as parties in legal proceedings arising in the ordinary course of our business. We believe we have meritorious defenses to all of these lawsuits and legal proceedings and will vigorously defend against them. Based on our evaluation of pending matters and after consideration of reserves established, we believe that the resolution of these proceedings will not have a material adverse effect on our business, financial position or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of the Company's members during the last quarter of 2001. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Duke Energy beneficially owns 69.7% of our outstanding member interests and Phillips beneficially owns the remaining 30.3%. There is no market for our member interests. Unless otherwise approved by our board of directors, we are prohibited from making any distributions except in an amount sufficient to pay certain tax obligations of our members that arise from their ownership of member interests. 19 In August 2000, we issued $300.0 million of preferred members 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, semiannually. 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 semiannual 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 or consummation of an initial public offering of the Company's equity securities. 20 ITEM 6. SELECTED FINANCIAL DATA The following table sets forth selected historical consolidated financial and other data for the Company and the Predecessor Company. The selected historical Annual Income Statement Data, Cash Flow Data and Balance Sheet Data as of December 31, 2001 and 2000 and for the periods then ended have been derived from the audited consolidated financial statements of the Company included elsewhere in this Form 10-K. The selected historical combined financial data as of December 31, 1999, 1998 and 1997 and for the periods then ended have been derived from the Predecessor Company's audited historical financial statements. The data should be read in conjunction with the financial statements and related notes and other financial information appearing elsewhere in this Form 10-K.
2001 2000(1) 1999(2) 1998 1997 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS) ANNUAL INCOME STATEMENT DATA: Operating revenues: Sales of natural gas and petroleum products........................ $9,315,921 $8,893,515 $3,310,260 $1,469,133 $1,700,029 Transportation, storage and processing...................... 281,744 199,851 148,050 115,187 101,803 ---------- ---------- ---------- ---------- ---------- Total operating revenues...... 9,597,665 9,093,366 3,458,310 1,584,320 1,801,832 Costs and expenses: Natural gas and petroleum products........................ 8,313,865 7,875,418 2,965,297 1,338,129 1,468,089 Operating and maintenance.......... 373,477 331,572 181,392 113,556 104,308 Depreciation and amortization...... 278,930 234,862 130,788 75,573 67,701 General and administrative......... 129,968 171,154 73,685 44,946 36,023 Net (gain) loss on sale of assets.......................... (1,277) (10,660) 2,377 (33,759) (236) ---------- ---------- ---------- ---------- ---------- Total costs and expenses...... 9,094,963 8,602,346 3,353,539 1,538,445 1,675,885 ---------- ---------- ---------- ---------- ---------- Operating income..................... 502,702 491,020 104,771 45,875 125,947 Equity in earnings of unconsolidated affiliates......................... 30,069 27,424 22,502 11,845 9,784 Interest expense..................... 165,670 149,220 52,915 52,403 51,113 ---------- ---------- ---------- ---------- ---------- Income before income taxes and cumulative effect of accounting change............................. 367,101 369,224 74,358 5,317 84,618 Income tax expense (benefit)......... 2,783 (310,937) 31,029 3,289 33,380 ---------- ---------- ---------- ---------- ---------- Net income before cumulative effect of accounting change............... 364,318 680,161 43,329 2,028 51,238 ---------- ---------- ---------- ---------- ---------- Cumulative effect of accounting change............................. 411 -- -- -- -- ---------- ---------- ---------- ---------- ---------- Net income........................... $ 363,907 $ 680,161 $ 43,329 $ 2,028 $ 51,238 ========== ========== ========== ========== ==========
2001 2000(1) 1999(2) 1998 1997 ---------- ---------- ----------- ---------- ---------- (IN THOUSANDS, EXCEPT RATIOS AND PER UNIT DATA) CASH FLOW DATA: Cash flow from operations......... $ 448,429 $ 713,065 $ 173,136 $ 40,409 $ 173,357 Cash flow from investing activities..................... (533,847) (234,733) (1,571,446) (203,625) (138,021) Cash flow from financing activities..................... 88,771 (477,571) 1,398,934 162,514 (35,061)
21
2001 2000(1) 1999(2) 1998 1997 ---------- ---------- ----------- ---------- ---------- (IN THOUSANDS, EXCEPT RATIOS AND PER UNIT DATA) OTHER DATA: Acquisitions and other capital expenditures...................... $ 592,630 $ 370,948 $ 1,570,083 $ 185,479 $ 121,978 EBITDA(3)........................... $ 811,701 $ 753,306 $ 258,061 $ 133,293 $ 203,432 Ratio of EBITDA to interest expense(4)........................ 4.90 5.05 4.88 2.54 3.98 Ratio of earnings to fixed charges(5)........................ 3.24 3.46 2.33 1.07 2.52 Gas transported and/or processed (TBtu/d).......................... 8.6 7.6 5.1 3.6 3.4 NGLs production(MBbl/d)............. 397 359 192 110 108 MARKET DATA: Average NGLs price per gallon(6).... $ .45 $ .53 $ .34 $ .26 $ .35 Average natural gas price per MMBtu(7).......................... $ 4.27 $ 3.89 $ 2.27 $ 2.11 $ 2.59 BALANCE SHEET DATA (END OF PERIOD): Total assets........................ $6,630,209 $6,527,997 $ 3,482,296 $1,770,838 $1,649,213 Long term debt...................... $2,235,034 $1,688,157 $ 101,600 $ 101,600 $ 101,600 Preferred members' interest......... $ 300,000 $ 300,000 $ -- $ -- $ -- Members' equity..................... $2,653,042 $2,420,835 (8) (8) (8)
--------------- (1) Includes the results of operations of Phillips' gas gathering, processing, marketing and NGL business for the nine months ended December 31, 2000. Phillips' gas gathering, processing, marketing and NGL business was acquired by the Predecessor Company on March 31, 2000. (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. EBITDA is not a measurement presented in accordance with generally accepted accounting principles. You should not consider this measure in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as 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. This measure may not be comparable to similarly titled measures reported by other companies. (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) The ratios of earnings to fixed charges are computed utilizing the Securities and Exchange Commission ("SEC") guidelines. (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) Not applicable due to change in corporate structure as of March 31, 2000. 22 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Duke Energy Field Services, LLC holds the combined North American midstream natural gas gathering, processing, marketing and NGL business of Duke Energy and Phillips Petroleum. The transaction in which those businesses were combined is referred to as 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 the Mid-Continent gathering and processing assets of Conoco and Mitchell Energy. 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 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 following discussion details the material factors that affected our historical financial condition and results of operations in 2001, 2000 and 1999. This discussion should be read in conjunction with "Item 1. Business," and the consolidated financial statements with the related notes, included elsewhere in this Form 10-K. From a financial reporting perspective, we are the successor to Duke Energy's North American midstream natural gas business. The subsidiaries of Duke Energy that conducted this business were contributed to us immediately prior to the Combination. For periods prior to the Combination, Duke Energy Field Services and these subsidiaries of Duke Energy are collectively referred to herein as the "Predecessor Company." 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 2001, approximately 56% of the Company's operating revenues prior to intersegment revenue elimination and approximately 96% of the 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 2001, approximately 44% prior to intersegment revenue elimination of the Company's operating revenues and approximately 4% of the 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. 23 EFFECTS OF COMMODITY PRICES The Company is exposed to commodity prices as a result of being paid for certain services in the form of commodities rather than cash. For gathering services, the Company receives fees from the producers to bring the natural gas from the well head to the processing plant. For processing services, the Company either receives fees or commodities as payment for these services, depending on the type of contract. Under a percentage-of-proceeds contract type, the Company is paid for its services by keeping a percentage of the NGLs produced and the residue gas resulting from processing the natural gas. Under a keep-whole contract, the Company keeps a portion of the NGLs produced, but returns the equivalent Btu content of the gas back to the producer. Based on the Company's current contract mix, the Company has a long NGL position and is sensitive to changes in NGL prices. The Company also has a short gas position, however the short gas position is less significant than the long NGL position. 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 was more heavily weighted towards arrangements that are commodity price sensitive, approximately 75% of our gross margin is generated by commodity sensitive arrangements and approximately 25% of our gross margin is generated by fee-based arrangements during 2001. The commodity exposure is actively managed by the Company as discussed below. The midstream natural gas industry has been cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which in turn has been generally correlated to the price of crude oil. Although the prevailing price of natural gas has less short term significance to our operating results than the price of NGLs, in the long term the growth of our business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production. In the past, the prices of NGLs and natural gas have been extremely volatile. 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 United States producers, which in turn had a significant negative effect on natural gas volumes gathered and processed in 1999. Due to reduced supply and strong demand, natural gas and NGL prices increased throughout 2000 along with renewed strength in drilling activity. The slowing economy combined with an increase in supply availability resulting from increased drilling levels drove declines in both crude oil and natural gas prices during the final two quarters of 2001. NGL prices dramatic decline is attributed to the decline in crude oil prices in addition to a decline in the correlation between NGL price and crude oil. As a result, the weighted average NGL price during 2001 (based on index prices from the Mont Belvieu and Conway market hubs that are weighted by our component product and location mix) was approximately $.45 per gallon compared to $.53 per gallon in 2000 and $.34 per gallon in 1999. During the last two quarters of 2001, the relationship or correlation between crude oil value and NGL prices remained depressed. We generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. In contrast, we believe that future natural gas prices will be influenced by supply deliverability, the severity of winter weather and the level of United States economic growth. We believe that weather will be the 24 strongest determinant of near term natural gas prices. The price increases in crude oil, NGLs and natural gas experienced during 2000 and the first two quarters of 2001 spurred increased natural gas drilling activity. For example, the average number of active drilling rigs in North America increased by approximately 19% from approximately 1,263 in 2000 to 1,497 in 2001. This drilling activity increase is expected to have a positive effect on natural gas volumes gathered and processed in the near term. The decline in commodity prices over the final two quarters of 2001 negatively effected drilling activity as the average number of active rigs declined to 1,282 during the fourth quarter of 2001. We expect that continued pressure from reduced commodity prices on drilling will negatively impact North American drilling activity. We expect lower drilling levels over a sustained period will have a negative effect on natural gas volumes gathered and processed. To better address the risks associated with volatile commodity prices, the Company employs a comprehensive commodity price risk management program. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge the value of our assets and operations from such price risks. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk." Our 2000 and 2001 results of operations include a hedging loss of $127.7 million and gain of $6.0 million, respectively. The hedging loss observed in 2000 relates to hedges placed during periods of increasing prices. The slight gain recognized in 2001 is the result of a combination of hedging losses experienced during the first and second quarters, offset by later gains achieved as a result of a sharp decline in commodity prices during the third and fourth quarters. 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. During 2001 approximately 65% of our gross margin from the Natural Gas Segment 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. During 2001 approximately 20% of our gross margin from the Natural Gas Segment was generated from fee-based contracts including our general partnership interest in TEPPCO. - 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 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. During 2001 approximately 5% of our gross margin from the Natural Gas Segment was generated from keep-whole contracts. In addition to the above contracts, during 2001 approximately 10% of the gross margin from the Natural Gas Segment was generated from condensate sales. 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 25 prices) significantly mitigates our exposure to changes in natural gas prices. Our exposure to decreases in NGL prices is partially offset by our hedging program. Our hedging program reduces the potential negative impact that commodity price changes could have on our earnings and improves our ability to adequately plan for cash needed for debt service, dividends, and capital expenditures. The primary goals of our hedging program include maintaining minimum cash flows to fund debt service, dividends, production replacement and maintenance capital projects; avoiding disruption of our growth capital and value creation process; and retaining a high percentage of potential upside relating to price increases of NGLs. 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 economic 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 a variety of contracts to attract certain supply to our systems. 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 Company's portfolio of supply contracts, without giving effect to hedging activities that would reduce the impact of commodity price decreases, a decrease of $.01 per gallon in the price of NGLs and $.10 per million Btus in the average price of natural gas would result in changes in annual pre-tax net income of approximately $(25.0) million and $5.0 million, respectively. After considering the affects of commodity hedge positions in place at December 31, 2001, it is estimated that if NGL prices average $.01 per gallon less in the next twelve months pre-tax net income would decrease approximately $15.0 million. During the first two months of 2002, NGL prices averaged $.28 per gallon and natural gas prices averaged $2.28 per million Btus versus the year ending December 31, 2001 average prices of $.45 per gallon and $4.27 per million Btus respectively. OTHER FACTORS THAT HAVE SIGNIFICANTLY AFFECTED OUR RESULTS Our results of operations are also correlated with increases and decreases in the volume of raw natural gas that we handle 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 activities have also affected our results of operations, in 2000 and 2001. Our 2000 and 2001 results of operations include a hedging loss of $127.7 million and gain of $6.0 million, respectively. See "Item 7A. Quantitative and Qualitative Disclosure About Market Risk." 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. HISTORICAL RESULTS OF OPERATIONS The following is a discussion of our historical results of operations. The discussion for periods ending on or prior to the Combination on March 31, 2000 relates solely to the Predecessor Company and does not give effect to the Combination, the transfer to our company of additional midstream natural gas assets acquired by 26 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.
2001 2000 1999 ---------- ---------- ---------- (IN THOUSANDS) Operating revenues: Sales of natural gas and petroleum products.... $9,315,921 $8,893,515 $3,310,260 Transportation, storage and processing......... 281,744 199,851 148,050 ---------- ---------- ---------- Total operating revenues............... 9,597,665 9,093,366 3,458,310 Purchases of natural gas and petroleum products.................................... 8,313,865 7,875,418 2,965,297 ---------- ---------- ---------- Gross margin..................................... 1,283,800 1,217,948 493,013 Equity earnings of unconsolidated affiliates..... 30,069 27,424 22,502 ---------- ---------- ---------- Total gross margin and equity earnings of unconsolidated affiliates(1)................... $1,313,869 $1,245,372 $ 515,515 ========== ========== ==========
--------------- (1) Gross margin and equity in earnings ("Gross Margin") consists of income from continuing operations before operating and general and administrative expense, interest expense, income tax expense, and depreciation and amortization expense plus equity earnings of unconsolidated affiliates. Gross margin as defined is not a measurement presented in accordance with generally accepted accounting principles. You should not consider this measure in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as an isolated measure of our profitability or liquidity. Gross margin is included as a supplemental disclosure because it may provide useful information regarding the impact of key drivers such as commodity prices and supply contract mix on the Company's earnings. 2001 COMPARED WITH 2000 Gross Margin. Gross Margin increased $68.5 million, or 6% from $1,245.4 million in 2000 to $1,313.9 million in 2001. Of this increase, approximately $183.0 million was related to the addition of the Phillips' midstream natural gas business to our operations in the Combination on March 31, 2000. Additional increases of approximately $28.0 million were attributable to the combination of our acquisition of Canadian Midstream, Texas intrastate pipelines, northeast propane terminal and marketing assets, and the acquisition of the general partnership interest in TEPPCO. These increases were offset by approximately $130.0 million (net of hedging) due to an $.08 per gallon decrease in average NGL prices, and approximately $12.0 million due to a $.38 per million Btu increase in natural gas prices. The effects of lower NGL prices significantly offset higher gross margin. Weighted average NGL prices, based on our component product mix, were approximately $.08 per gallon lower, and natural gas prices were approximately $.38 per million Btus higher during 2001. These price changes yielded average prices of $.45 per gallon of NGLs and $4.27 per million Btus of natural gas, respectively, as compared with $.53 per gallon and $3.89 per million Btus during 2000. Gross margin associated with the natural gas gathering, processing, transportation, and storage segment increased $62.5 million, or 5%, from $1,194.8 million to $1,257.3 million, mainly as a result of the Combination. Commodity sensitive processing arrangements offset this increase by approximately $130.0 million (net of hedging) due to the $.08 per gallon decrease in average NGL prices. This reduction was the result of the interaction of commodity prices and our gas supply arrangements. During the first quarter, historically high natural gas prices and low fractionation spread caused us to manage our natural gas price exposure by reducing levels of NGL recovery and processing volumes where contractual arrangements allowed. Gross Margin attributable to keep-whole arrangements declined approximately $90.0 million from approximately $140.0 million in 2000 to $50.0 million in 2001. This decrease is mainly due to the market dynamics present in the first quarter of 2001. The remainder of decline of gross margin related to NGL price declines is due to percent-of-proceeds arrangements and condensate sales. These commodity driven declines 27 were slightly offset by an increased fee-based activity associated with acquisitions and processing arrangements. NGL production during 2001 increased 38,700 barrels per day, or 11%, from 358,500 barrels per day to 397,200 barrels per day, and natural gas transported and/or processed increased 1.0 trillion Btus per day, or 13%, from 7.6 trillion Btus per day to 8.6 trillion Btus per day. The primary cause of the increase in NGL production was the addition of the Phillips' midstream natural gas business in the Combination offset by reduced recoveries at certain facilities resulting from tightened fractionation spreads driven by high natural gas prices experienced during the first two quarters and low NGL prices experienced during the fourth quarter. Costs and Expenses. Operating and maintenance expenses increased $41.8 million, or 13%, from $331.6 million in 2000 to $373.4 million in 2001. Of this increase, approximately $35.6 million is related to the addition of the Phillips' midstream natural gas business in the Combination. The remainder is primarily the result of acquisitions offset by plant consolidation and cost reduction efforts. General and administrative expenses decreased $41.2 million, or 24%, from $171.2 million in 2000 to $130.0 million in 2001. This decrease is primarily the result of decreased allocated overhead from our parents, decreased incentive compensation accruals and focussed cost reduction efforts offset by the Combination. Depreciation and amortization increased $44.0 million, or 19%, from $234.9 million in 2000 to $278.9 million in 2001. Of this increase, $21.8 million was due to the addition of the Phillips' midstream natural gas business in the Combination. The remainder was due to acquisitions, ongoing capital expenditures for well connections and facility maintenance/enhancements. Interest. Interest expense increased $16.5 million, or 11%, from $149.2 million in 2000 to $165.7 million in 2001. This increase was primarily the result of higher outstanding debt levels, partially offset by lower interest rates. Income Taxes. The Company is structured as a limited liability company, which is a pass-through entity for income tax purposes. As a result of the March 31, 2000 Predecessor Company conversion to a limited liability company, substantially all of the Predecessor Company's existing net deferred tax liability ($327.0 million) was eliminated and a corresponding income tax benefit was recorded. The 2001 income tax expense of $2.8 million is mainly the result of other miscellaneous taxes. Net Income. Net income decreased $316.3 million from $680.2 million in 2000 to $363.9 million in 2001. This decrease was largely the result of the tax benefit recognition discussed above, offset by the addition of the Phillip's midstream natural gas business in the Combination and cost reduction efforts. A $6.0 million pre-tax gain from hedging activities experienced during 2001 partially offset the decrease. Lower NGL prices and higher gas prices also contributed to this decrease. 2000 COMPARED WITH 1999 Gross Margin. Gross Margin increased $729.9 million, or 142% from $515.5 million in 1999 to $1,245.4 million in 2000. Of this increase, approximately $523.0 million was related to the addition of the Phillips' midstream natural gas business to our operations in the Combination on March 31, 2000, and approximately $85.0 million was related to the March 31, 1999 acquisition of Union Pacific Fuels. The effects of higher NGL prices also contributed significantly to higher gross margin. Weighted average NGL prices, based on our component product mix, were approximately $.19 per gallon higher and natural gas prices were approximately $1.62 per million Btus higher during 2000. These price increases yielded average prices of $.53 per gallon of NGLs and $3.89 per million Btus of natural gas, respectively, as compared with $.34 per gallon and $2.27 per million Btus during 1999. Gross Margin associated with the natural gas gathering, processing, transportation, and storage segment increased $714.0 million, or 149%, from $480.8 million to $1,194.8 million, mainly as a result of the Combination and the Union Pacific Fuels acquisition. Commodity sensitive processing arrangements also contributed to this increase by approximately $91.0 million (net of hedging) due to the $.19 per gallon increase in average NGL prices. Other factors contributing to the increase were the combination of our acquisition of the Conoco/Mitchell facilities, Wilcox plant expansion, completion of our Mobile Bay plant, the 28 acquisition of Koch's South Texas assets, and the acquisition of the general partnership interest in TEPPCO. These increases were offset by approximately $50.0 million due to the $1.62 per million Btus increase in natural gas prices. Gross Margin attributable to the NGLs fractionation, transportation, marketing and trading segment increased $15.7 million or 45% from $34.8 million to $50.5 million. This increase is due primarily to NGL trading and marketing activity and the acquisition of Union Pacific Fuels. NGL production during 2000 increased 166,100 barrels per day, or 86%, from 192,400 barrels per day to 358,500 barrels per day, and natural gas transported and/or processed increased 2.5 trillion Btus per day, or 49%, from 5.1 trillion Btus per day to 7.6 trillion Btus per day. Of the 166,100 barrels per day increase in NGL production, the addition of the Phillips' midstream natural gas business in the Combination contributed approximately 125,800 barrels per day, and the Union Pacific Fuels acquisition contributed approximately 25,150 barrels per day. The acquisition of assets from Conoco/Mitchell, 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 2.5 trillion Btus per day increase in natural gas transported and/or processed, the addition of the Phillips' midstream natural gas business in the Combination contributed approximately 1.6 trillion Btus per day, and the Union Pacific Fuels acquisition contributed approximately 0.5 trillion Btus per day. The combination of other acquisitions, plant expansions and completions accounted for the balance of the increase. Costs and Expenses. Operating and maintenance expenses increased $150.2 million, or 83%, from $181.4 million in 1999 to $331.6 million in 2000. Of this increase, approximately $109.3 million is related to the addition of the Phillips' midstream natural gas business in the Combination and approximately $13.0 million was related to the Union Pacific Fuels acquisition. General and administrative expenses increased $97.5 million, or 132%, from $73.7 million in 1999 to $171.2 million in 2000. Of this increase, $12.5 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 incentive compensation accruals for 2000. Depreciation and amortization increased $104.1 million, or 80%, from $130.8 million in 1999 to $234.9 million in 2000. Of this increase, $72.5 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. Interest. Interest expense increased $96.3 million, or 182%, from $52.9 million in 1999 to $149.2 million in 2000. This increase was primarily the result of the issuance of commercial paper and the subsequent debt offering in the third quarter used to repay a portion of the outstanding 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 ($327.0 million) was eliminated and a corresponding income tax benefit was recorded. Net Income. Net income increased $636.9 million from $43.3 million in 1999 to $680.2 million in 2000. 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 but were partially offset by higher natural gas prices. A $127.7 million pre-tax loss from hedging activities experienced during 2000 partially offset the increase. ENVIRONMENTAL CONSIDERATIONS We have various ongoing remedial matters related to historical operations similar to others in the industry, based primarily on state authorities generally described under "Item 1. Business -- Environmental 29 Matters." 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. On June 13, 2001, the Company received two administrative Compliance Orders from the New Mexico Environment Department ("NMED") seeking civil penalties for primarily historic air permit matters. One order alleges specific permit non-compliance at 11 facilities that occurred periodically between 1996 and 1999. Allegations under this order relate primarily to emissions from certain compressor engines in excess of what were then new operating permit limits. The other order alleges numerous unexcused excursions from an hourly permit limit arising from upset events at the Company's Dagger Draw facility's sulfur recovery unit between 1997 and 2001. NMED applied its civil penalty policy to the alleged violations and calculated the penalties to be $10.4 million in the aggregate. NMED has initiated settlement discussions and offered to resolve these matters for an amount lower than the calculated penalties. The Company is continuing its discussions with NMED and anticipates that it will resolve all issues relating to the alleged violations. On September 12, 2001, the Company received a Proposed Agreed Order from the Texas Natural Resource Conservation Commission ("Commission") to settle allegations reflected in a June 2001 notice from the Commission relating to the Company's Port Arthur natural gas processing plant. The Proposed Agreed Order sought penalties of $278,000 for various items of alleged-noncompliance relating to the facility's air permit and state air regulations, including valve monitoring and repair requirements under 40 CFR 60, subpart KKK. The Company has reached a settlement with the staff of the Commission for a monetary penalty in the amount of $39,832 and a Supplemental Environmental Project in the amount of $39,832, subject to the approval of the Commission. The Company received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality ("LDEQ") in the spring of 2001 enabling the Company to discharge certain wastewater streams from its Minden Gas Processing Plant until a new discharge permit is issued by the LDEQ. The Compliance Order authorized certain discharges, and otherwise addressed various historic and recent deviations from Clean Water Act regulatory requirements, including the lapse of the facility's discharge permit. The Compliance Order also contemplates final resolution of these matters including the LDEQ issuing a penalty assessment. The Company and LDEQ are now in discussions to resolve all issues relating to this matter. The Company is in discussion with the Oklahoma Department of Environmental Quality ("ODEQ") regarding apparent non-compliance issues relating to the Company's Title V Clean Air Act Operating permits at its Oklahoma facilities, primarily consisting of compliance issues disclosed to the ODEQ pursuant to permit requirements or otherwise voluntarily disclosed to the ODEQ in 2001. These non-compliance issues relate to various specific and detailed terms of the Title V permits, including, separate filing requirements, engine testing procedural requirements, certification requirements, and quarterly emissions testing obligations. As a result of these discussions, the Company anticipates a comprehensive settlement agreement will be entered into to resolve these various items. We make expenditures in connection with environmental matters as part of our normal operations and as capital expenses. For each of 2002 and 2003, we estimate that our expensed and capital-related environmental costs will be approximately $18.7 million. LIQUIDITY AND CAPITAL RESOURCES OPERATING CASH FLOWS Net cash provided by operations decreased $264.6 million in 2001 from 2000 and increased $539.9 million in 2000 from 1999. The 2001 decrease is primarily due to a reduction in net income of $316.3 million. The reduction in net income is largely due to the income tax benefit recorded in 2000. The 2001 decrease is also due to a reduction in accounts payable, partially offset by a reduction in accounts receivable. These reductions are due primarily to a lower price environment in 2001 as compared to 2000. 30 The increase in cash provided by operations in 2000 as compared to 1999 is primarily due to an increase in net income of $636.8 million. The increase in net income is primarily due to the income tax benefit recorded in 2000, the GPM acquisition in March 2000 and higher commodity prices. The increase is also due to an increase in accounts payable, partially offset by an increase in accounts receivable. Price volatility in crude oil, NGLs and natural gas prices have a direct impact on our use and generation of cash from operations. INVESTING CASH FLOWS Our capital expenditures consist of expenditures for acquisitions and construction of additional gathering systems, processing plants, fractionators and other facilities and infrastructure in addition to well connections and upgrades to our existing facilities. For the year ended December 31, 2001, we spent approximately $592.6 million on capital expenditures. On July 10, 2001, the Company acquired additional interests in Mobile Bay Processing Partners, Gulf Coast NGL Pipeline, L.L.C. and Dauphin Island Gathering Partners from MCNIC Energy Enterprise Inc. ("MCNIC") for approximately $66.2 million. On May 1, 2001, we acquired the outstanding shares of CMSL for a total purchase price of approximately $162.0 million. The purchase price included the assumption of debt of approximately $49.3 million. On April 30, 2001, we acquired in a purchase transaction, Gas Supply Resources, Inc. ("GSRI"), a propane wholesaler located in the Northeast, for approximately $45.0 million. The remaining capital expenditures were primarily for plant expansions, well connections and plant upgrades. Our level of capital expenditures for acquisitions and construction depends on many factors, including industry conditions, the availability of attractive acquisition opportunities and construction projects, the level of commodity prices and competition. We expect to finance our capital expenditures with our cash on hand, cash flow from operations and borrowings available under our commercial paper program, our credit facilities or other available sources of financing. Our capital expenditure budget for well connections and plant upgrades of our existing facilities in 2002 is approximately $200.0 million. FINANCING CASH FLOWS Bank Financing and Commercial Paper In March 2001, we entered into a $675.0 million credit facility ("the Facility"), of which $150.0 million can be used for letters of credit. The Facility is used to support our commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 29, 2002, however, any outstanding loans under the Facility at maturity may, at our option, be converted to a one-year term loan. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 53%. The Facility bears interest at a rate equal to, at our option, either (1) LIBOR plus 0.75% per year or (2) the higher of (a) the Bank of America prime rate and (b) the Federal Funds rate plus 0.50% per year. At December 31, 2001, there were no borrowings against the Facility. The Facility will be replaced by a new $650.0 million credit facility (the "New Facility"). We expect to close on the New Facility on March 29, 2002. The New Facility will have substantially the same terms as the Facility being replaced. At December 31, 2001 we had a $45.0 million outstanding Irrevocable Standby Letter of Credit expiring March 29, 2002. This letter of credit was amended to $30.0 million in January 2002. We plan to extend the expiration of this letter of credit to March 2003. At December 31, 2001 we had $213.0 million in outstanding commercial paper, with maturities ranging from two days to 19 days and annual interest rates ranging from 7.05% to 7.6%. At no time did the amount of our outstanding commercial paper exceed the available amount under the Facility. In the future, our debt levels will vary depending on our liquidity needs, capital expenditures and cash flow. 31 Based on current and anticipated levels of operations, we believe that our cash on hand and cash flow from operations, combined with borrowings available under the commercial paper program and the New Facility, will be sufficient to enable us to meet our current and anticipated cash operating requirements and working capital needs for the next year. Actual capital requirements, however, may change, particularly as a result of any acquisitions that we may make. Our ability to meet current and anticipated operating requirements will depend on our future performance. Preferred Financing In August 2000, we issued $300.0 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, semiannually. 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 semiannual 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 or consummation of an initial public offering of equity securities. For the years ending December 31, 2001 and 2000, we have paid preferential distributions of $28.5 million and $11.7 million, respectively. Debt Securities During 2000 and 2001, we registered and issued the following series of unsecured senior debt securities:
PRINCIPAL INTEREST ISSUE DATE ($000S) RATE DUE DATE ---------------------------------------------- --------- -------- ----------------- August 16, 2000............................... $600,000 7 1/2% August 16, 2005 August 16, 2000............................... $800,000 7 7/8% August 16, 2010 August 16, 2000............................... $300,000 8 1/8% August 16, 2030 February 2, 2001.............................. $250,000 6 7/8% February 1, 2011 November 9, 2001.............................. $300,000 5 3/4% November 15, 2006
The notes mature and become due and payable on the respective due dates, and are not subject to any sinking fund provisions. Interest is payable semiannually. Each series of notes is redeemable, in whole or in part, at our option. The proceeds from the issuance of debt securities were used to repay a portion of our outstanding commercial paper. In October 2001, the Company entered an interest rate swap to convert the fixed interest rate of $250.0 million of debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on 6-month LIBOR rates, which is re-priced semiannually through 2005. The terms of the swap match the associated debt which permits the assumption of no ineffectiveness, as defined by Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities." As such, for the life of the swap no ineffectiveness will be recognized. As of December 31, 2001, the fair value of the interest rate swap of ($4.6) million was included in the Consolidated Balance Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions with an offset to the underlying debt included in Long Term Debt. Distributions In connection with the Combination, we are required to make quarterly distributions to Duke Energy and Phillips based on allocated taxable income. Our Limited Liability Company Agreement provides for taxable income to be allocated in accordance with the Internal Revenue Code Section 704(c). This Code section takes into account the variation between the adjusted tax basis and the book value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member, with the 32 other member receiving a proportionate amount to maintain the ownership capital accounts at 69.7% for Duke Energy and 30.3% for Phillips. As of December 31, 2001, the distributions based on allocated taxable income payable to the members were $45.7 million and were paid in January 2002. CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS As part of our normal business, we are a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of us having to honor our contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We would record a reserve if events occurred that required that one be established. At December 31, 2001 we had a $45 million outstanding Irrevocable Standby Letter of Credit expiring March 29, 2002. This letter of credit was amended to $30 million in January 2002. We plan to extend the expiration of this letter of credit to March 2003. In addition, at December 31, 2001 we are the guarantor of approximately $28.9 million of debt associated with an unconsolidated subsidiary. Assets of the unconsolidated subsidiary are pledged as collateral for the debt. ACCOUNTING PRONOUNCEMENTS On January 1, 2001, the Company adopted SFAS No. 133. In accordance with the transition provisions of SFAS No. 133, the Company recorded a cumulative-effect adjustment of $0.4 million as a reduction in earnings and a cumulative-effect adjustment increasing Other Comprehensive Income ("OCI") and member's equity by $6.6 million. In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires all business combinations initiated (as defined by the standard) after June 30, 2001 to be accounted for using the purchase method. Companies may no longer use the pooling method for future combinations. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001 and was adopted by the Company as of January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts will be subject to a fair-value-based annual impairment assessment. The standard also requires acquired intangible assets to be recognized separately and amortized as appropriate. No such intangibles have been identified at the Company. We expect the adoption of SFAS No. 142 to have an impact on future financial statements, due to the discontinuation of goodwill amortization expense. For 2001, goodwill amortization expense was $22.0 million. We have evaluated the fair value evidence and have concluded that there is no impairment of goodwill as of January 1, 2002. In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. It is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. We are currently assessing the new standard and have not yet determined the impact on our consolidated results of operations, cash flows or financial position. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The new rules supersede SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The new rules retain many of the fundamental recognition and measurement provisions of SFAS No. 121, but significantly change the criteria for classifying an asset as held-for-sale. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. We have evaluated the new standard and believe that it will have no material effect on our consolidated results of operations or financial position. 33 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK RISK AND ACCOUNTING POLICIES We are exposed to market risks associated with commodity prices, credit exposure, interest rates and foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Our Risk Management Committee ("RMC") oversees risk exposure including fluctuations in commodity prices. The RMC ensures that proper policies and procedures are in place to adequately manage our commodity price risks and is responsible for the overall management of commodity price and other risk exposures. Mark-to-Market Accounting ("MTM accounting") -- Under the MTM accounting method, an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in earnings during the current period. This accounting method has been used by other industries for many years, and in 1998 the FASB's Emerging Issues Task Force ("EITF") issued guidance 98-10 that required MTM accounting for energy trading contracts. MTM accounting reports contracts at their "fair value," (the value a willing third party would pay for the particular contract at the time a valuation is made). When available, quoted market prices are used to record a contract's fair value. However, market values for energy trading contracts are often not easy to determine because the duration of the contracts may exceed the liquid activity in a particular market. If no active trading market exists for a commodity or for a contract's duration, holders of these contracts must calculate fair value using pricing models or matrix pricing based on contracts with similar terms and risks. This is validated by a group independent of the Company's trading area. Holders of thinly-traded securities or investments (mutual funds, for example) use similar techniques to price such holdings. Correlation and volatility are two significant factors used in the computation of fair values. We validate our internally developed fair values by comparing locations/tenors that are highly correlated, using forecasted market intelligence and mathematical extrapolation techniques. While we use industry best practices to develop our pricing models, changes in our pricing methodologies or the assumptions therein could result in significantly different fair values and realization in future periods. Hedge Accounting -- Hedge accounting typically refers to the mechanism that the Company uses to minimize losses caused by price fluctuations. Hedge accounting treatment is used when we contract to buy or sell a commodity such as natural gas at a fixed price for future delivery corresponding with the anticipated physical sale or purchase of natural gas (cash flow hedge). In addition, hedge accounting treatment is used when the Company holds firm commitments or asset positions, and enters into transactions that "hedge" our risk that the price of natural gas may change between the contract's inception and the physical delivery date of the commodity (fair value hedge). The majority of our hedging transactions are used to protect the value of future cash flows related to physical assets. To the extent the hedge is effective, we recognize in earnings the value of the contract when the commodity is purchased or sold, or the hedged transaction occurs or settles. COMMODITY PRICE RISK We are exposed to the impact of market fluctuations primarily in the price of NGLs that we own as a result of our processing activities. We employ established policies and procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including forward contracts, swaps and options for non-trading activity (primarily hedge strategies). (See Notes 2 and 12 to the Consolidated Financial Statements.) Commodity Derivatives -- Trading -- The risk in the commodity trading portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk ("DER"). DER is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor the risk in the commodity trading portfolio (which includes all trading contracts not designated as hedge positions) on a monthly and annual basis. These measures include limits on the nominal size of positions and periodic loss limits. DER computations are based on a historical simulation, which uses price movements over a specified period (generally ranging from seven to 14 days) to simulate forward price curves in the energy markets to 34 estimate the potential favorable or unfavorable impact of one day's price movement on the existing portfolio. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for crude, NGLs, gas and other energy-related products. DER computations utilize several key assumptions, including 95% confidence level for the resultant price movement and the holding period specified for the calculation. The Company's DER amounts for commodity derivatives instruments held for trading purposes are shown in the following table. DAILY EARNINGS AT RISK
ESTIMATED AVERAGE ESTIMATED AVERAGE HIGH ONE-DAY LOW ONE-DAY ONE-DAY IMPACT ONE-DAY IMPACT IMPACT ON EBIT IMPACT ON EBIT ON EBIT FOR 2001 ON EBIT FOR 2000 FOR 2001 FOR 2001 ----------------- ----------------- -------------- -------------- (IN MILLIONS) Calculated DER................... $1.7 $1.2 $5.7 $0.4
DER is an estimate based on historical price volatility. Actual volatility can exceed predicted results. DER also assumes a normal distribution of price changes, thus if the actual distribution is not normal, the DER may understate or overstate actual results. DER is used to estimate the risk of the entire portfolio, and for locations that do not have daily trading activity, it may not accurately estimate risk due to limited price information. Stress tests may be employed in addition to DER to measure risk where market data information is limited. In the current DER methodology, options are modeled in a manner equivalent to forward contracts which may understate the risk. Our exposure to commodity price risk is influenced by a number of factors, including contract size, length of contract, market liquidity, location and unique or specific contract terms. The following table illustrates the movements in the fair value of our trading instruments during 2001. CHANGES IN FAIR VALUE OF TRADING CONTRACTS
(IN MILLIONS) Fair value of contracts outstanding at the beginning of the year...................................................... $ (5.0) SFAS No. 133 reclassification adjustment.................... (14.1) Contracts realized or otherwise settled during the year..... (1.6) Net mark-to-market changes in fair values................... 58.1 ------ Fair value of contracts outstanding at the end of the year...................................................... $ 37.4 ======
For the year ended December 31, 2001, the unrealized net margin recognized in operating income was $42.4 million as compared to ($5.4) million for 2000 and $0.4 million for 1999. The fair value of these contracts is expected to be realized in future periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events that could impact the amount and/or realization of these values. At December 31, 2001, we held cash or letters of credit of $3.3 million to secure such future performance, and had no amounts deposited with counterparties. When available, we use observable market prices for valuing our trading instruments. When quoted market prices are not available, we use established guidelines for the valuation of these contracts. We may use a variety of reasonable methods to assist in determining the valuation of a financial instrument, including analogy to reliable quotations of similar financial instruments, pricing models, matrix pricing and other formula-based pricing methods. These methodologies incorporate factors for which published market data may be available. All valuation methods employed by us are approved by an internal corporate risk management organization independent of the trading function and are applied on a consistent basis. 35 The following table shows the fair value of our trading portfolio as of December 31, 2001.
FAIR VALUE OF CONTRACTS AS OF DECEMBER 31, 2001 ------------------------------------------------------------------------ MATURITY IN MATURITY IN MATURITY IN MATURITY IN 2005 AND SOURCES OF FAIR VALUE 2002 2003 2004 THEREAFTER TOTAL FAIR VALUE --------------------- ----------- ----------- ----------- ----------- ---------------- (IN MILLIONS) Prices supported by quoted market prices and other external sources................ $27.1 $1.0 $ 0.7 $ -- $28.8 ----- ---- ----- ---- ----- Prices based on models and other valuation methods................ 10.8 1.2 (3.6) 0.2 8.6 ----- ---- ----- ---- ----- Total.......... $37.9 $2.2 $(2.9) $0.2 $37.4 ===== ==== ===== ==== =====
The "prices supported by quoted market prices and other external sources" category includes Duke Energy Field Services' New York Mercantile Exchange ("NYMEX") swap positions in natural gas and crude oil. The NYMEX has currently quoted prices for the next 32 months. In addition, this category includes our forward positions and options in natural gas and natural gas basis swaps at points for which over-the-counter ("OTC") broker quotes are available. On average, OTC quotes for natural gas forwards and swaps extend 22 and 32 months into the future, respectively. OTC quotes for natural gas options extend 12 months into the future, on average. We value these positions against internally developed forward market price curves that are constantly validated and recalibrated against OTC broker quotes. This category also includes "strip" transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate. The "prices based on models and other valuation methods" category includes (i) the value of options not quoted by an exchange or OTC broker, (ii) the value of transactions for which an internally developed price curve was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point, and (iii) the value of structured transactions. It is important to understand that in certain instances structured transactions can be decomposed and modeled by us as simple forwards and options based on prices actively quoted. Although the valuation of the simple structures might not be different from the valuation of contracts in other categories, the effective model price for any given period is a combination of prices from two or more different instruments and therefore have been included in this category due to the complex nature of these transactions. Hedging Strategies -- We are exposed to market fluctuations in the prices of energy commodities related to natural gas gathering, processing and marketing activities. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge the value of our assets and operations from such price risks. Our primary use of commodity derivatives is to hedge the output and production of assets we physically own. Contract terms are up to four years, however, since these contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets owned by us, to the extent that the hedge relationships are effective, their market value change impacts are not recognized in current earnings. The unrealized gains or losses on these contracts are deferred in OCI or included in Other Current or Noncurrent Assets or Liabilities on the Consolidated Balance Sheets, in accordance with SFAS No. 133. Amounts deferred in OCI are realized in earnings concurrently with the transaction being hedged. (See Notes 2 and 12 to the Consolidated Financial Statements.) However, in instances where the hedging contract no longer qualifies for hedge accounting, amounts included in OCI through the date of de-designation remain in OCI until the underlying transaction actually occurs. The derivative contract (if continued as an open position) will be marked to market currently through earnings. Several factors influence the effectiveness of a hedge contract, including counterparty credit. The following table shows when gains and losses deferred on the Consolidated Balance Sheets for derivative instruments qualifying as effective hedges of firm commitments or anticipated future transactions will be recognized into earnings. Contracts with terms extending several years are generally valued using 36 models and assumptions developed internally or by industry standards. However, as mentioned previously, the effective portion of the gains and losses for these contracts are not recognized in earnings until settlement at their then market price. Therefore, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement for the effective portion of these hedges. The fair value of our qualifying hedge positions at a point in time is not necessarily indicative of the results realized when such contracts settle.
CONTRACT VALUE AS OF DECEMBER 31, 2001 ------------------------------------------------------------------ MATURITY IN MATURITY IN MATURITY IN MATURITY IN 2005 AND TOTAL FAIR SOURCES OF FAIR VALUE 2002 2003 2004 THEREAFTER VALUE --------------------- ----------- ----------- ----------- ----------- ---------- (IN MILLIONS) Quoted market prices........... $27.6 $3.5 $ -- $ -- $31.1 ----- ---- ----- ----- ----- Prices based on models or other valuation techniques......... 26.0 -- -- -- 26.0 ----- ---- ----- ----- ----- Total................ $53.6 $3.5 $ -- $ -- $57.1 ===== ==== ===== ===== =====
Based upon our portfolio of supply contracts, without giving effect to hedging activities that would reduce the impact of commodity price decreases, a decrease of $.01 per gallon in the price of NGLs and $.10 per million Btus in the average price of natural gas would result in changes in annual pre-tax net income of approximately ($25.0) million and $5.0 million, respectively. After considering the affects of commodity hedge positions in place at December 31, 2001, it is estimated that if NGL prices average $.01 per gallon less in the next twelve months, pre-tax net income would decrease approximately $15.0 million. Comparatively, the same sensitivity analysis as of December 31, 2000 estimated that pre-tax net income would decrease approximately $20.0 million in 2001. The hedge contracts are intended to mitigate the impact that price changes have on our physical positions. During the first two months of 2002, NGL prices averaged $.28 per gallon and natural gas prices averaged $2.28 per million Btus versus the year ending December 31, 2001 average prices of $.45 per gallon and $4.27 per million Btus respectively. CREDIT RISK We sell natural gas liquids 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 NGL production that is committed to Phillips and Chevron Phillips Chemical LLC, under an existing 15-year contract, of which 13 years remain. This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. On all transactions where we are exposed to credit risk, we analyse the counterparties' financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. The corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure. The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. However, these transactions are generally subject to margin agreements with the majority of our counterparties. Following the bankruptcy of Enron Corporation, we have terminated substantially all contracts with Enron Corporation and its affiliated companies (collectively, "Enron"). As a result, we recorded in 2001, as a charge, a non-collateralized accounting exposure of $2.7 million. The transactions between Enron and the Company consisted of physical purchase/sale contracts for natural gas and NGLs, forward contracts, swaps and options used to trade natural gas and NGLs, and transportation and storage transactions. 37 The $2.7 million charge was a direct reduction to earnings before income taxes and was a result of charging the full amount of unsettled mark-to-market earnings previously recognized, and all derivative assets and accounts receivable that became impaired due to Enron's condition. Our determination of the bankruptcy claims against Enron is still under review, and the claims made in the bankruptcy case are likely to exceed $2.7 million. Any bankruptcy claims that exceed this amount would primarily relate to termination and settlement rights under contracts and transactions with Enron that would have been recognized in future periods and not in the historical periods covered by the financial statements to which the $2.7 million charge relates. Substantially all contracts with Enron were completed or terminated prior to December 31, 2001. INTEREST RATE RISK We enter into debt arrangements that are exposed to market risks related to changes in interest rates. We periodically utilize interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with new debt issuances. Our primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for the Company's debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical averages. As of December 31, 2001, the fair value of our interest rate swap was a liability of $4.6 million. (See Notes 2 and 12 to the Consolidated Financial Statements.) As of December 31, 2001, we had approximately $213.0 million outstanding under a commercial paper program. As a result, we are exposed to market risks related to changes in interest rates. In the future, we intend to manage our interest rate exposure using a mix of fixed and floating interest rate debt. An increase of .5% in interest rates would result in an increase in annual interest expense of approximately $2.3 million. FOREIGN CURRENCY RISK Our primary foreign currency exchange rate exposure at December 31, 2001 was the Canadian dollar. Foreign currency risk associated with this exposure was not material. 38 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF INCOME YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
2001 2000 1999 ---------- ---------- ---------- (IN THOUSANDS) OPERATING REVENUES: Sales of natural gas and petroleum products............ $6,851,265 $6,787,599 $2,613,560 Sales of natural gas and petroleum products -- affiliates.............................. 2,464,656 2,105,916 696,700 Transportation, storage and processing................. 281,744 188,501 138,151 Transportation, storage and processing -- affiliates... -- 11,350 9,899 ---------- ---------- ---------- Total operating revenues....................... 9,597,665 9,093,366 3,458,310 ---------- ---------- ---------- COSTS AND EXPENSES: Purchases of natural gas and petroleum products........ 7,495,229 7,114,070 2,836,697 Purchases of natural gas and petroleum products -- affiliates.............................. 818,636 761,348 128,600 Operating and maintenance.............................. 373,477 331,572 181,392 Depreciation and amortization.......................... 278,930 234,862 130,788 General and administrative............................. 118,249 140,557 54,585 General and administrative -- affiliates............... 11,719 30,597 19,100 Net (gain) loss on sale of assets...................... (1,277) (10,660) 2,377 ---------- ---------- ---------- Total costs and expenses....................... 9,094,963 8,602,346 3,353,539 ---------- ---------- ---------- OPERATING INCOME......................................... 502,702 491,020 104,771 EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES.......... 30,069 27,424 22,502 INTEREST EXPENSE: Interest expense (income).............................. 165,670 134,016 (985) Interest expense -- affiliates......................... -- 15,204 53,900 ---------- ---------- ---------- Total interest expense......................... 165,670 149,220 52,915 ---------- ---------- ---------- INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................ 367,101 369,224 74,358 INCOME TAX EXPENSE (BENEFIT)............................. 2,783 (310,937) 31,029 ---------- ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE...................................... 364,318 680,161 43,329 CUMULATIVE EFFECT OF ACCOUNTING CHANGE................... 411 -- -- ---------- ---------- ---------- NET INCOME............................................... 363,907 680,161 43,329 DIVIDENDS ON PREFERRED MEMBERS' INTEREST................. 28,500 11,717 -- ---------- ---------- ---------- EARNINGS AVAILABLE FOR MEMBERS' INTEREST................. $ 335,407 $ 668,444 $ 43,329 ========== ========== ==========
See Notes to Consolidated Financial Statements. 39 DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
2001 2000 1999 -------- -------- ------- (IN THOUSANDS) NET INCOME.................................................. $363,907 $680,161 $43,329 OTHER COMPREHENSIVE INCOME (LOSS): Cumulative effect of change in accounting principle....... 6,626 -- -- Foreign currency translation adjustment................... (4,460) (2,717) 288 Net unrealized gains on cash flow hedges.................. 51,621 -- -- Reclassification into earnings............................ (3,313) -- -- -------- -------- ------- Total other comprehensive income (loss)........... 50,474 (2,717) 288 -------- -------- ------- TOTAL COMPREHENSIVE INCOME.................................. $414,381 $677,444 $43,617 ======== ======== =======
See Notes to Consolidated Financial Statements. 40 DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
2001 2000 1999 --------- ----------- ----------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 363,907 $ 680,161 $ 43,329 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization........................... 278,930 234,862 130,788 Deferred income taxes (benefit)......................... 2,783 (308,001) 86,301 Change in fair value of derivative instruments.......... 2,066 -- -- Equity in earnings of unconsolidated affiliates......... (30,069) (27,424) (22,502) Net (gain) loss on sale of assets....................... (1,277) (10,660) 2,377 Change in operating assets and liabilities (net of effects of acquisitions) which provided (used) cash: Accounts receivable..................................... 533,109 (492,475) (168,806) Accounts receivable -- affiliates....................... 22,756 (189,300) (6,202) Inventories............................................. 9,856 (73,348) (5,303) Unrealized gains on mark-to-market transactions......... (88,842) (35,724) (10,461) Other current assets.................................... 1,013 41,324 20,356 Other noncurrent assets................................. (590) (9,414) -- Accounts payable........................................ (633,599) 808,980 101,309 Accounts payable -- affiliates.......................... (35,844) (906) 51,608 Accrued interest payable................................ 7,807 49,641 -- Unrealized losses on mark-to-market transactions........ 46,811 41,100 10,079 Other current liabilities............................... (7,647) 51,036 (4,390) Other long term liabilities............................. (22,741) (46,787) (55,347) --------- ----------- ----------- Net cash provided by operating activities.......... 448,429 713,065 173,136 --------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for acquisitions............................. (220,097) (163,565) (1,404,354) Other capital expenditures................................ (372,533) (207,383) (165,729) Investment expenditures................................... (4,795) (5,323) (62,752) Investment distributions.................................. 41,278 43,557 31,999 Proceeds from sales of assets............................. 22,300 97,981 29,390 --------- ----------- ----------- Net cash used in investing activities.............. (533,847) (234,733) (1,571,446) --------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Net (decrease) increase in advances -- members............ (11,347) (55,509) 1,350,054 Distributions to members.................................. (235,564) (2,744,319) -- Proceeds from issuing preferred members' interest......... -- 300,000 -- Short term debt -- net.................................... (133,455) 346,410 -- Proceeds from issuing debt -- net......................... 546,918 1,687,564 48,880 Payment of debt........................................... (49,281) -- -- Payment of dividends...................................... (28,500) (11,717) -- --------- ----------- ----------- Net cash provided by (used in) financing activities....................................... 88,771 (477,571) 1,398,934 --------- ----------- ----------- NET INCREASE IN CASH........................................ 3,353 761 624 CASH, BEGINNING OF YEAR..................................... 1,553 792 168 --------- ----------- ----------- CASH, END OF YEAR........................................... $ 4,906 $ 1,553 $ 792 ========= =========== =========== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION -- Cash paid for interest (net of amounts capitalized)............ $ 155,946 $ 95,805 $ 52,915
See Notes to Consolidated Financial Statements. 41 DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2001 AND 2000
2001 2000 ---------- ---------- (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash...................................................... $ 4,906 $ 1,553 Accounts receivable: Customers, net.......................................... 520,118 1,080,083 Affiliates.............................................. 230,521 253,277 Other................................................... 136,810 67,316 Inventories............................................... 82,935 86,520 Unrealized gains on trading and hedging transactions...... 180,809 46,185 Other..................................................... 9,060 14,275 ---------- ---------- Total current assets............................... 1,165,159 1,549,209 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT, NET.......................... 4,711,960 4,152,480 INVESTMENT IN AFFILIATES.................................... 132,252 261,551 INTANGIBLE ASSETS: Natural gas liquids sales and purchases contracts, net.... 94,019 97,956 Goodwill, net............................................. 421,176 376,195 ---------- ---------- Total intangible assets............................ 515,195 474,151 ---------- ---------- UNREALIZED GAINS ON TRADING AND HEDGING TRANSACTIONS.............................................. 19,095 -- OTHER NONCURRENT ASSETS..................................... 86,548 90,606 ---------- ---------- TOTAL ASSETS....................................... $6,630,209 $6,527,997 ========== ========== LIABILITIES AND MEMBERS' EQUITY CURRENT LIABILITIES: Accounts payable: Trade................................................... $ 620,094 $1,273,029 Affiliates.............................................. 25,620 61,464 Other................................................... 76,914 41,322 Short term debt........................................... 212,955 346,410 Accrued taxes other than income........................... 24,646 21,717 Distributions payable to members.......................... 45,672 127,561 Accrued interest payable.................................. 57,417 49,641 Unrealized losses on trading and hedging transactions..... 84,811 51,179 Other..................................................... 102,694 114,408 ---------- ---------- Total current liabilities.......................... 1,250,823 2,086,731 ---------- ---------- DEFERRED INCOME TAXES....................................... 14,362 -- LONG TERM DEBT.............................................. 2,235,034 1,688,157 UNREALIZED LOSSES ON TRADING AND HEDGING TRANSACTIONS...................................... 25,188 -- OTHER LONG TERM LIABILITIES................................. 15,845 32,274 MINORITY INTERESTS.......................................... 135,915 -- PREFERRED MEMBERS' INTEREST................................. 300,000 300,000 COMMITMENTS AND CONTINGENT LIABILITIES MEMBERS' EQUITY: Members' interest......................................... 1,709,290 1,709,290 Retained earnings......................................... 895,707 713,974 Accumulated other comprehensive income (loss)............. 48,045 (2,429) ---------- ---------- Total members' equity.............................. 2,653,042 2,420,835 ---------- ---------- TOTAL LIABILITIES AND MEMBERS' EQUITY....................... $6,630,209 $6,527,997 ========== ==========
See Notes to Consolidated Financial Statements. 42 DUKE ENERGY FIELD SERVICES, LLC CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
ACCUMULATED ADDITIONAL OTHER COMMON PAID-IN MEMBERS' RETAINED COMPREHENSIVE STOCK CAPITAL INTEREST EARNINGS INCOME (LOSS) TOTAL ------ ---------- ----------- --------- ------------- ----------- (IN THOUSANDS) BALANCE, JANUARY 1, 1999...... $ 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 Combination at March 31, 2000 -- see Note 2: Contribution of TEPPCO general partnership interest.................. -- 2,148 -- -- -- 2,148 Contribution of DEFS Inc. and DEFSCL to DEFS, LLC... (1) (215,239) 215,240 -- -- -- Contribution of notes and advances payable.......... -- -- 2,318,569 -- -- 2,318,569 Contribution of GPM assets and liabilities........... -- -- 1,919,800 -- -- 1,919,800 Distributions............... -- -- (2,744,319) (127,561) -- (2,871,880) Dividends on preferred members' interest........... -- -- -- (11,717) -- (11,717) Net Income.................... -- -- -- 680,161 -- 680,161 Other......................... -- -- -- -- (2,717) (2,717) ----- --------- ----------- --------- ------- ----------- BALANCE, DECEMBER 31, 2000.... -- -- 1,709,290 713,974 (2,429) 2,420,835 Distributions................. -- -- -- (153,674) -- (153,674) Dividends on preferred members' interest........... -- -- -- (28,500) -- (28,500) Net Income.................... -- -- -- 363,907 -- 363,907 Other......................... -- -- -- -- 50,474 50,474 ----- --------- ----------- --------- ------- ----------- BALANCE, DECEMBER 31, 2001.... $ -- $ -- $ 1,709,290 $ 895,707 $48,045 $ 2,653,042 ===== ========= =========== ========= ======= ===========
See Notes to Consolidated Financial Statements. 43 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 1. GENERAL Basis of Presentation -- 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. Field Services LLC's limited liability company agreement limits the scope of the Company's 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 Company is the successor to Duke Energy Corporation's ("Duke Energy") North American midstream natural gas business. The subsidiaries of Duke Energy that conducted this business were contributed to the Company immediately prior to the Combination (see Note 3). For periods prior to the Combination, Duke Energy Field Services and these subsidiaries of Duke Energy are collectively referred to herein as the "Predecessor Company." 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Consolidation -- The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, after eliminating significant intercompany transactions and balances. Investments in 20% to 50% owned affiliates are accounted for using the equity method. Investments greater than 50% are consolidated unless the Company does not operate these investments and as a result does not have the ability to exercise control (see Note 9). Use of Estimates -- Conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management's best available knowledge of current and expected future events, actual results could be different from those estimates. Inventories -- Inventories consist primarily of materials and supplies and natural gas and NGLs held in storage for transmission and processing and sales commitments. Inventories are recorded at the lower of cost or market value using the average cost method (see Note 7). Natural gas storage arbitrage volumes are marked to market. Accounting for Hedges and Commodity Trading Activities -- All derivatives are recorded in the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Trading and Hedging Transactions. On the date that swaps or option contracts are entered into, the Company designates the derivative as either held for trading (trading instruments); as a hedge of a recognized asset, liability or firm commitment (fair value hedges); as a hedge of a forecasted transaction or future cash flows (cash flow hedges); or leaves the derivative undesignated and marks it to market. For hedge contracts, the Company formally assesses, both at the hedge contracts inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in fair values or cash flows of hedged items. The Company currently excludes the time value of the options when assessing hedge effectiveness. When available, quoted market prices or prices obtained through external sources are used to verify a contract's fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices. 44 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Values are adjusted to reflect the potential impact of liquidating the positions held in an orderly manner over a reasonable time period under current conditions. Changes in market price and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term. Commodity Trading -- A favorable or unfavorable price movement of any derivative contract held for trading purposes is reported as Purchases of Natural Gas and Petroleum Products in the Consolidated Statements of Income. An offsetting amount is recorded in the Consolidated Balance Sheets as Unrealized Gains or Unrealized Losses on Trading and Hedging Transactions. When a contract to sell is physically settled, the fair value entries are reversed and the gross amount invoiced to the customer is included as Sales of Natural Gas and Petroleum Products in the Consolidated Statements of Income. Similarly, when a contract to purchase is physically settled, the purchase price is included as Purchases of Natural Gas and Petroleum Products in the Consolidated Statements of Income. If a contract is not physically settled, the unrealized gain or unrealized loss in the Consolidated Balance Sheets is reclassified to a receivable or payable account. For income statement purposes, financial settlement has no net operating income presentation effect on the Consolidated Statements of Income. Commodity Cash Flow Hedges -- Changes in fair value of a derivative designated and qualified as a cash flow hedge are included in the Consolidated Statements of Comprehensive Income as Other Comprehensive Income ("OCI") until earnings are affected by the hedged item. Settlement amounts and ineffective portions of cash flow hedges are removed from OCI and recorded in the Consolidated Statements of Income in the same accounts as the item being hedged. The Company discontinues hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative continues to be carried on the Consolidated Balance Sheets at its fair value, with subsequent changes in its fair value recognized in current-period earnings. Gains and losses related to discontinued hedges that were previously accumulated in OCI will remain in OCI until earnings are affected by the hedged item, unless it is no longer probable that the hedged transaction will occur. Gains and losses that were accumulated in OCI will be immediately recognized in current-period earnings. Commodity Fair Value Hedges -- Changes in the fair value of a derivative that is designated and qualifies as a fair value hedge are included in the Consolidated Statements of Income as Sales of Natural Gas and Petroleum Products and Purchases of Natural Gas and Petroleum Products, as appropriate. Changes in the fair value of the physical portion of a fair value hedge (i.e., the hedged item) are recorded in the Consolidated Statements of Income in the same accounts as the changes in the fair value of the derivative, with offsetting amounts in the Consolidated Balance Sheets as Other Current Assets, Other Noncurrent Assets, Other Current Liabilities, or Other Long Term Liabilities, as appropriate. Interest Rate Fair Value Hedges -- The Company enters into interest rate swaps to convert some of its fixed-rate long term debt to floating-rate long term debt. Hedged items in fair value hedges are marked-to-market with the respective derivative instruments. Accordingly, the Company's hedged fixed-rate debt is carried at fair value. The terms of the outstanding swap and the associated debt are matched at December 31, 2001 which permits the assumption of no ineffectiveness, as defined by Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities." As such, for the life of the swap no ineffectiveness will be recognized. Goodwill -- Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. Prior to January 1, 2002, the Company amortized goodwill on a straight-line basis over the useful lives of the acquired assets, ranging from 15 to 20 years. The amount of goodwill reported on the Consolidated Balance Sheets as of December 31, 2001 was $421.2 million, net of accumulated amortization of $60.9 million. The amount of goodwill as of December 31, 2000 was $376.2 million, net of accumulated amortization of $38.9 million The Company has implemented SFAS No. 142, "Goodwill and Other Intangible Assets" as of 45 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) January 1, 2002. For information on the impact of SFAS No. 142 on goodwill and goodwill amortization see the New Accounting Standards section of this footnote. (See Notes 3 and 4 for information on significant goodwill additions.) Property, Plant and Equipment -- Property, plant and equipment are stated at original cost. Depreciation is computed using the straight-line method over the estimated useful lives of the individual assets (see Note 8). The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Interest totaling $0.8 million for 2001, $0.3 million for 2000 and $0.9 million for 1999 has been capitalized on construction projects. Impairment of Long-Lived Assets -- The Company reviews the recoverability of long-lived assets and intangible assets when circumstances indicate that the carrying amount of the asset may not be recoverable. This evaluation is based on undiscounted cash flow projections. For the years presented, there has been no impairment. Revenue Recognition -- The Company recognizes revenues on sales of natural gas and petroleum products in the period of delivery and transportation revenues in the period service is provided. For gathering services, the Company receives fees from the producers to bring the natural gas from the wellhead to the processing plant. For processing services, the Company either receives fees or commodities as payment for these services, depending on the type of contract. Under the Percentage-of-Proceeds contract type, the Company is paid for its services by keeping a percentage of the NGLs produced and the residue gas resulting from processing the natural gas. Under a Keep-Whole contract, the Company keeps a portion of the NGLs produced, but returns the equivalent British thermal unit ("Btu") content of the gas back to the producer. The Company also receives fees for further fractionation of the NGLs produced, for transportation and storage of NGLs and residue gas. In addition, the Company recognizes revenue for its NGL and residue gas marketing activities. Significant Customers -- Duke Energy Trading and Marketing, L.L.C. ("DETM"), an affiliated company, is a significant customer. Sales to DETM, primarily residue gas, totaled $1,628.8 million during 2001, $1,444.0 million during 2000 and $684.0 million during 1999. Unamortized Debt Premium, Discount and Expense -- Premiums, discounts and expenses incurred with the issuance of outstanding long term debt are amortized over the terms of the debt issues. Natural Gas Liquids Sales and Purchases Contracts -- Natural gas liquids sales and purchases contracts are amortized on a straight-line basis over the contract lives, ranging from two to 15 years. Environmental Expenditures -- 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 generate current or future revenue, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Recorded environmental liabilities were $40.0 million at the end of 2001 and $38.7 million at the end of 2000. (See Note 14). Gas Imbalance Accounting -- Quantities of natural gas over-delivered or under-delivered related to imbalance agreements are recorded monthly as other receivables or other payables using then current index prices or the weighted average prices of natural gas at the plant or system. These balances are settled with cash or deliveries of natural gas. Foreign Currency Translation -- The Company translates assets and liabilities of its Canadian operations, where the Canadian dollar is the functional currency, at the year-end exchange rates. Revenues and expenses are translated using average exchange rates during the year. Foreign currency translation adjustments are included in the Consolidated Statements of Comprehensive Income. 46 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Income Taxes -- The Company follows the asset and liability method of accounting for income taxes. Deferred taxes are provided for temporary differences in the tax and financial reporting basis of assets and liabilities (see Note 10). At March 31, 2000, the Company converted to a limited liability company which is a pass-through entity for income tax purposes. As a result, substantially all of the existing net deferred tax liability of $327.0 million was eliminated and a corresponding income tax benefit recorded. Going forward, income taxes will consist primarily of miscellaneous state, local and franchise taxes. In addition, the Company has Canadian subsidiaries that are levied certain foreign taxes. In connection with the Combination (see Note 3), the Company is required to make quarterly distributions to Duke Energy and Phillips Petroleum Company ("Phillips") based on allocated taxable income. The limited liability company agreement, as amended, provides for taxable income to be allocated in accordance with the Internal Revenue Code section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the book value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 69.7% for Duke Energy and 30.3% for Phillips. As of December 31, 2001 and 2000, the total estimated distributions due to the members were approximately $45.7 and $127.6 million, respectively. Stock Based Compensation -- Under Duke Energy's 1998 Long Term Incentive Plan, stock options for Duke Energy's common stock may be granted to the Company's key employees. The Company accounts for stock-based compensation using the intrinsic method of accounting. Under this method, any compensation cost is measured as the quoted market price of stock at the date of the grant less the amount an employee must pay to acquire the stock. Restricted stock grants and Company performance awards are recorded as compensation cost over the requisite vesting period based on the market value on the date of the grant. (See Note 15 for pro forma disclosures using the fair value accounting method.) All outstanding common stock amounts and compensation awards have been adjusted to reflect Duke Energy's two-for-one common stock split effected January 26, 2001. (See Note 15 for additional information on the stock split.) Cumulative Effect of Change in Accounting Principle -- The Company adopted SFAS No. 133 on January 1, 2001. In accordance with the transition provisions of SFAS No. 133, the Company recorded a cumulative-effect adjustment of $0.4 million as a reduction in earnings and a cumulative-effect adjustment increasing OCI and member's equity by $6.6 million. For the year ended December 31, 2001, the Company reclassified as earnings $12.1 million of losses from OCI for derivatives included in the transition adjustment related to hedge transactions that settled. The amount reclassified out of OCI will be different from the amount included in the transition adjustment due to market price changes since January 1, 2001. New Accounting Standards -- In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires all business combinations initiated (as defined by the standard) after June 30, 2001 to be accounted for using the purchase method. Companies may no longer use the pooling method for future combinations. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001 and will be adopted by the Company as of January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts will be subject to a fair-value-based annual impairment assessment. The standard also requires certain identifiable intangible assets to be recognized separately and amortized as appropriate. No such intangibles have been identified at the Company. The Company expects the adoption of SFAS No. 142 to have an impact on future financial statements, due to the discontinuation of goodwill amortization expense. For 2001, goodwill amortization expense was $22.0 mil- 47 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) lion. The Company has evaluated the fair value evidence and has concluded that there is no impairment of goodwill as of January 1, 2002. In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. It is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. The Company is currently assessing the new standard and has not yet determined the impact on its consolidated results of operations, cash flows or financial position. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The new rules supersede SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The new rules retain many of the fundamental recognition and measurement provisions of SFAS No. 121, but significantly change the criteria for classifying an asset as held-for-sale. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The Company has evaluated the new standard, and management believes that it will have no material effect on its consolidated results of operations or financial position. Reclassifications -- Some amounts reported in prior periods have been reclassified in the Consolidated Financial Statements to conform to current classifications. 3. COMBINATION On March 31, 2000, the natural gas gathering, processing and NGL 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 subsidiaries of Duke Energy were eliminated and contributed to equity. Also on March 31, 2000, Phillips contributed its midstream natural gas gathering, processing and NGL 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 with Phillips has been accounted for as a purchase business combination in accordance with Accounting Principles Board Opinion No. 16 "Accounting for Business Combinations." The Phillips assets, net of liabilities, have been valued at $1,919.8 million, excluding $20.1 million of acquisition costs. The following is a summary of the allocated purchase price (in millions): Property, plant and equipment............................... $1,634.7 Goodwill.................................................... 291.1 Current assets.............................................. 228.3 Other noncurrent assets..................................... 57.7 Current liabilities......................................... (228.3) Other noncurrent liabilities................................ (43.6) -------- Total purchase price.............................. $1,939.9 ========
Unaudited Pro Forma Disclosures -- Revenues for the years ended December 31, 2000 and 1999, on a pro forma basis would have increased $542.4 million and $1,095.7 million, respectively, and net income for the years ended December 31, 2000 and 1999, on a pro forma basis would have increased by $65.7 million and $21.2 million, respectively, if the acquisition of the Phillips midstream business had occurred at the beginning of 1999. 48 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) TEPPCO General Partner -- On March 31, 2000, and in connection with the Combination, Duke Energy contributed the general partner of TEPPCO Partners, L.P. ("TEPPCO") to Field Services LLC. In connection with the contribution of the general partner of TEPPCO, the Company recorded an investment in TEPPCO of $2.1 million and increased equity by $2.1 million. TEPPCO is a publicly traded master limited partnership that owns and operates a network of pipelines and storage and terminal facilities for refined products, liquefied petroleum gases, liquefied natural gas, petrochemicals, natural gas gathering and crude oil. The general partner is responsible for TEPPCO's management and operations. Because Field Services LLC owns the general partner of TEPPCO, it has the right to receive incentive cash distributions from TEPPCO in addition to a 2% share of distributions based on the general partner interest. At TEPPCO's 2001 per unit distribution level, the general partner received approximately 21% of the cash distributed by TEPPCO to its partners. Due to the general partner's share of unit distributions and degree of control exercised through its management of the partnership and other partnership governance issues, the Company's investment in TEPPCO is accounted for under the equity method. 4. ACQUISITIONS AND DISPOSITIONS Acquisition of Additional Equity Interests -- On July 10, 2001, the Company acquired additional interests in Mobile Bay Processing Partners, Gulf Coast NGL Pipeline, L.L.C. and Dauphin Island Gathering Partners from MCNIC Energy Enterprise Inc. ("MCNIC") for approximately $66.2 million. This acquisition of additional interests has been accounted for as a purchase business combination in accordance with Accounting Principles Board Opinion No. 16. As a result of these acquisitions, the Company has controlling interests in each of the affiliates, and the assets and liabilities and results of operations of the three affiliates have been consolidated in the Company's financial statements since the date of the purchases with an offsetting amount recorded as minority interest. The pro forma impact of the acquisition on the Company's results of operations was not material. Canadian Midstream Services, Ltd. -- On May 1, 2001, the Company acquired the outstanding shares of Canadian Midstream Services, Ltd. ("CMSL") for a purchase price of approximately $162.0 million. The purchase price included assumed debt of approximately $49.3 million. The acquisition was accounted for under the purchase method of accounting, and the assets and liabilities and results of operations of CMSL have been consolidated in the Company's financial statements since the date of purchase. On a pro forma basis, revenues and net income for the year ended December 31, 2001 would have increased $7.8 million and $1.4 million, respectively, if the acquisition of CMSL had occurred on January 1, 2001. The following is a summary of the allocated purchase price (in millions): Property, plant and equipment............................... $139.0 Goodwill.................................................... 53.7 Current assets.............................................. 14.0 Current liabilities......................................... (57.3) Other noncurrent liabilities................................ (35.9) ------ Total purchase price.............................. $113.5 ======
Gas Supply Resources, Inc. -- On April 30, 2001, the Company acquired in a purchase transaction, Gas Supply Resources, Inc. ("GSRI"), a propane wholesaler located in the Northeast, for approximately $45.0 million. The pro forma impact of the acquisition on the Company's results of operations was not material. Goodwill of $28.1 million has been recorded as a result of allocating the purchase price to the individual assets and liabilities acquired. 49 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Disposition of NGL Pipeline Assets -- On December 31, 2000, the Company sold pipeline assets to TEPPCO for $91.0 million. The NGL pipeline assets sold included the Panola Pipeline and the San Jacinto Pipeline. TEPPCO also assumed the lease of a 34 mile condensate pipeline. A $12.0 million gain and a $3.2 million deferred gain was recorded in connection with the sale. 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 $99.8 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. The pro forma impact of the acquisition on the Company's results of operations was not material. 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 Company ("UPR"), for a total purchase price of $1,359.0 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. On a pro forma basis, revenues and net income for the year ended December 31, 1999 would have increased $298.0 million and $3.4 million, respectively, if the acquisition of UP Fuels had occurred on January 1, 1999. In connection with the acquisition, $77.6 million of goodwill was recorded. 5. AGREEMENTS AND TRANSACTIONS WITH DUKE ENERGY Services Agreement with Duke Energy -- In connection with the Combination, the Company entered into a services agreement with Duke Energy and some of its subsidiaries, dated March 14, 2000. Under this agreement, Duke Energy and those subsidiaries will provide the Company with various staff and support services, including information technology products and services, payroll, employee benefits, insurance, cash management, ad valorem taxes, treasury, media relations, printing, records management, legal functions and investor services. These services are priced on the basis of a monthly charge which management believes approximates market prices. Additionally, the Company may use other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments. This agreement, as amended, expires on December 31, 2002. Expenses resulting from this agreement were $10.0 million and $7.4 million in 2001 and 2000, respectively. License Agreement -- In connection with the Combination, Duke Energy has licensed to the Company a non-exclusive right to use the phrase "Duke Energy" and its logo and certain other trademarks in identifying the Company's businesses. This right may be terminated by Duke Energy at its sole option any time after Duke Energy's direct or indirect ownership interest in the Company is less than or equal to 35%; or Duke Energy no longer controls, directly or indirectly, the management and policies of the Company. Transactions between Duke Energy and the Company -- The Company sells a portion of its residue gas and NGLs to, purchases raw natural gas and other petroleum products from, and provides gathering and transportation services 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 to purchase and sell these commodities and provide these services to Duke Energy in the ordinary course of business. The Company's total revenues from these activities were approximately $1,648.5 million, $1,459.2 million and $684.0 million for the years ended December 31, 2001, 2000 and 1999, respectively. 6. AGREEMENTS AND TRANSACTIONS WITH PHILLIPS 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 (the "Phillips NGL 50 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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, and subsequently Chevron Phillips Chemical 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 Basin 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 March 31, 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, the Phillips Combined Subsidiaries purchased raw natural gas from Phillips at contractual prices that have approximated market prices. The Company is continuing these transactions in the ordinary course of business. The Company's total revenues from these activities were approximately $816.2 million and $942.3 million for the years ended December 31, 2001 and 2000, respectively. 7. INVENTORIES A summary of inventories by category follows:
DECEMBER 31, ----------------- 2001 2000 ------- ------- (IN THOUSANDS) Gas held for resale......................................... $32,553 $11,720 NGLs........................................................ 44,310 67,441 Materials and supplies...................................... 6,072 7,359 ------- ------- Total inventories................................. $82,935 $86,520 ======= =======
8. PROPERTY, PLANT AND EQUIPMENT A summary of property, plant and equipment by classification follows:
DECEMBER 31, DEPRECIATION ------------------------ RATES 2001 2000 ------------ ----------- ---------- (IN THOUSANDS) Gathering....................................... 4% - 6% $ 2,308,905 $2,409,136 Processing...................................... 4% 1,786,431 1,802,824 Transmission.................................... 4% 1,241,408 424,120 Underground storage............................. 2% - 5% 91,205 77,174 General plant................................... 20% - 33% 126,125 83,175 Construction work in progress................... 253,831 154,330 ----------- ---------- 5,807,905 4,950,759 Accumulated depreciation...................... (1,095,945) (798,279) ----------- ---------- Property, plant and equipment, net............ $ 4,711,960 $4,152,480 =========== ==========
51 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 9. INVESTMENTS IN AFFILIATES The Company has investments in the following businesses accounted for using the equity method:
DECEMBER 31, 2001 ------------------- OWNERSHIP 2001 2000 --------- -------- -------- (IN THOUSANDS) TEPPCO Partners, L.P................................. 2.00% $ 13,401 $ 3,323 Mont Belvieu I....................................... 20.00% 37,706 38,936 Sycamore Gas System General Partnership.............. 48.45% 18,803 22,172 Main Pass Oil Gathering.............................. 33.33% 16,817 17,131 Tri-States NGL Pipeline, LLC......................... 10.00% 13,971 -- Black Lake Pipeline.................................. 50.00% 8,996 8,751 Fox Plant LLC........................................ 50.00% 8,247 8,045 Dauphin Island Gathering Partners(1)................. 71.84% -- 102,440 Mobile Bay Processing Partners(1).................... 57.61% -- 34,571 Other affiliates..................................... Various 14,311 26,182 -------- -------- Total investments in affiliates............ $132,252 $261,551 ======== ========
Mont Belvieu I -- Mont Belvieu I operates a 200 MBbl/d fractionation facility in the Mont Belvieu, Texas Market Center. 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. Tri-States NGL Pipeline, LLC -- Tri-States NGL Pipeline, LLC owns 169 miles of pipeline, extending from a point near Mobile Bay, Alabama to a point near Kenner, Louisiana. 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. Fox Plant LLC -- Fox Plant LLC is a limited liability company formed for the purpose of constructing, owning and operating a gathering facility and gas processing plant in Carter County, Oklahoma. ---------- (1) On July 10, 2001, the Company acquired additional interests in Mobile Bay Processing Partners and Dauphin Island Gathering Partners. As a result of these acquisitions, the assets and liabilities and results of operations of the three affiliates have been consolidated in the Company's Consolidated Financial Statements since the date of the purchase (see Note 4). 52 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Equity in earnings amounted to the following for the years ended December 31:
2001 2000 1999 ------- ------- ------- (IN THOUSANDS) TEPPCO Partners, L.P.................................... $24,517 $10,589 $ -- Mont Belvieu I.......................................... (766) (501) 440 Sycamore Gas System General Partnership................. (302) 44 142 Main Pass Oil Gathering................................. 3,768 2,973 3,638 Tri-States NGL Pipeline, LLC............................ 554 -- -- Black Lake Pipeline..................................... 1,322 1,833 1,141 Fox Plant LLC........................................... 202 508 -- Dauphin Island Gathering Partners....................... 1,287 3,835 5,974 Mobile Bay Processing Partners.......................... (971) 2,413 2,307 Ferguson-Burleson....................................... -- 651 5,600 Westana Gathering Company............................... -- 346 1,339 Other affiliates........................................ 458 4,733 1,921 ------- ------- ------- Total equity earnings......................... $30,069 $27,424 $22,502 ======= ======= =======
Distributions in excess of earnings were $11.3 million, $4.2 million and $9.5 million in 2001, 2000 and 1999, respectively. The following summarizes combined financial information of unconsolidated affiliates for the years ended December 31:
2001 2000 1999 --------- --------- -------- (IN THOUSANDS) Income statement: Operating revenues............................... $ 211,792 $ 242,900 $452,118 Operating expenses............................... (167,289) 216,334 374,079 Net income....................................... 40,352 27,278 55,606 Balance sheet: Current assets................................... $ 73,466 $ 97,478 Noncurrent assets................................ 599,727 749,772 Current liabilities.............................. (35,014) (79,567) Noncurrent liabilities........................... (260,583) (133,058) --------- --------- Net assets............................... $ 377,596 $ 634,625 ========= =========
10. INCOME TAXES At March 31, 2000, the Company converted to a limited liability company which is a pass-through entity for income tax purposes. As a result, substantially all of the existing net deferred tax liability of $327.0 million was eliminated and a corresponding income tax benefit was recorded. 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. 53 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Income tax as presented in the Statements of Income is summarized as follows:
YEARS ENDED DECEMBER 31, ----------------------------- 2001 2000 1999 ------ --------- -------- (IN THOUSANDS) Current: Federal............................................. $ -- $ (5,066) $(46,429) State............................................... 480 2,130 (8,843) Foreign............................................. 1,324 -- -- ------ --------- -------- Total current............................... 1,804 (2,936) (55,272) ------ --------- -------- Deferred: Federal............................................. -- (268,911) 73,201 State............................................... 979 (39,090) 13,100 ------ --------- -------- Total deferred.............................. 979 (308,001) 86,301 ------ --------- -------- Total income tax expense.............................. $2,783 $(310,937) $ 31,029 ====== ========= ========
Total income tax expense for the year ended December 31, 1999 differed from the amount computed by applying the federal income tax rate to earnings before income tax. The reasons for this difference are as follows (in thousands): Federal income tax rate..................................... 35.0% ======= Income tax, computed at the statutory rate.................. $26,025 Adjustments resulting from: State income tax, net of federal income tax effect........ 2,863 Non-deductible amortization and other..................... 2,141 ------- Total income tax.................................. $31,029 =======
11. FINANCING Credit Facility with Financial Institutions -- In March 2000, Field Services LLC entered into a $2,800.0 million credit facility with several financial institutions. On April 3, 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 matured on March 30, 2001, and was replaced by a new $675.0 million revolving credit facility (the "Facility"), of which $150.0 million can be used for letters of credit. The Facility is used to support the Company's commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 29, 2002, however, any outstanding loans under the Facility at maturity may, at the Company's option, be converted to a one-year term loan. The Facility requires the Company to maintain at all times a debt to total capitalization ratio of less than or equal to 53%. The Facility bears interest at a rate equal to, at the Company's option, either (1) LIBOR plus 0.75% per year or (2) the higher of (a) the Bank of America prime rate and (b) the Federal Funds rate plus 0.50% per year. At December 31, 2001, there were no borrowings against the Facility. At December 31, 2001 the Company had a $45.0 million outstanding Irrevocable Standby Letter of Credit expiring March 29, 2002. In addition, the Company had $213.0 million and $346.4 million in outstanding commercial paper at December 31, 2001 and 2000, respectively with maturities ranging from two days to 19 days and annual interest rates ranging from 7.05% to 7.6%. The weighted average interest rate on the outstanding commercial paper was 2.53% and 7.39% 54 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) for the years ended December 31, 2001 and 2000, respectively. The amount of the Company's outstanding commercial paper never exceeded the available amount under the Facility. Preferred Financing -- In August 2000, the Company issued $300.0 million of preferred member interests to affiliates of Duke Energy and Phillips. The proceeds from this financing were used to repay a portion of the Company's outstanding commercial paper. The preferred member interests are entitled to cumulative preferential distributions of 9.5% per annum payable, unless deferred, semi-annually. The Company has the right to defer payments of preferential distributions on the preferred member interests, other than certain tax distributions, at any time, for up to 10 consecutive semiannual 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 or consummation of an initial public offering of equity securities. For the years ended December 31, 2001 and 2000, the Company has paid preferential distributions of $28.5 million and $11.7 million, respectively. Debt Securities -- Long term debt at December 31, 2001 and 2000 was as follows:
PRINCIPAL/DISCOUNT ----------------------- INTEREST 2001 2000 ISSUE DATE RATE DUE DATE ---------- ---------- ----------------- -------- ----------------- (IN THOUSANDS) Debt Securities........... $ 600,000 $ 600,000 August 16, 2000 7 1/2% August 16, 2005 800,000 800,000 August 16, 2000 7 7/8% August 16, 2010 300,000 300,000 August 16, 2000 8 1/8% August 16, 2030 250,000 -- February 2, 2001 6 7/8% February 1, 2011 300,000 -- November 9, 2001 5 3/4% November 15, 2006 Interest rate swap........ (4,659) -- Capitalized leases........ 3,288 -- Unamortized discount...... (13,595) (11,843) ---------- ---------- Net long term debt........ $2,235,034 $1,688,157 ========== ==========
The notes mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. Debt securities maturing over the next five years include $600.0 million in 2005 and $300.0 million in 2006. Interest is payable semiannually. The notes are redeemable at the option of the Company. The Company used the proceeds from the issuance of the debt securities to repay short term debt. In October 2001, the Company entered an interest rate swap to convert the fixed interest rate of $250.0 million of debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on 6-month LIBOR rates, which is re-priced semiannually through 2005. The Company is guarantor of approximately $28.9 million of debt associated with an unconsolidated subsidiary. Assets of the unconsolidated subsidiary are pledged as collateral for the debt. 12. DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND CREDIT RISK Commodity price risk -- The Company's principal operations of gathering, processing, and storage of natural gas, and the accompanying operations of processing, fractionation, transportation, and marketing of natural gas liquids create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of natural gas liquids. As an owner and operator of natural gas processing 55 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) and other midstream assets, the Company has an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas acquisition contracts entered in to purchase and process natural gas feedstock. Risk is also dependent on the types and mechanisms for sales of natural gas and natural gas liquid products produced, processed, transported, or stored. Energy trading (market) risk -- Certain of the Company's subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sales of commodity-based instruments. Corporate economic risks -- The Company enters into debt arrangements that are exposed to market risks related to changes in interest rates. The Company periodically utilizes interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with new debt issuances. The Company's primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for the Company's debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates. Counterparty risks -- The Company has credit risk from its extension of credit for sales of energy products and services, and credit risk with its counterparties in terms of settlement risk and performance risk. On all transactions where the Company is exposed to credit risk, the Company analyzes the counterparties' financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. Commodity cash flow hedges -- The Company uses cash flow hedges, as specifically defined by SFAS No. 133, to reduce the potential negative impact that commodity price changes could have on the Company's earnings, and its ability to adequately plan for cash needed for debt service, dividends and capital expenditures. The Company's primary corporate hedging goals include (1) maintaining minimum cash flows to fund debt service, dividends, production replacement and maintenance capital projects; (2) avoiding disruption of the Company's growth capital and value creation process; and (3) retaining a high percentage of potential upside relating to price increases of natural gas liquids. The Company utilizes natural gas, crude oil and NGL swaps and options to hedge the impact of market fluctuations in the price of natural gas liquids and other energy-related products. For the year ended December 31, 2001, the Company recognized a net gain of $4.7 million, of which a $1.4 million gain represented the total ineffectiveness of all cash flow hedges and a $3.3 million gain represented the total derivative settlements. The time value of the options, a recognized $1.4 million gain for the year ended December 31, 2001, was excluded in the assessment of hedge effectiveness. The time value of the options is included in Sales of Natural Gas and Petroleum Products in the Consolidated Statements of Income. No derivative gains or losses were reclassified from OCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are probable of not occurring. Gains and losses on derivative contracts that are reclassified from accumulated OCI to current period earnings are included in the line item in which the hedged item is recorded. As of December 31, 2001, $51.5 million of the deferred net gains on derivative instruments accumulated in OCI are expected to be reclassified as earnings during the next 12 months as the hedge transactions occur; however, due to the volatility of the commodities markets, the corresponding value in OCI is subject to change prior to its reclassification into earnings. The maximum term over which the Company is hedging its exposure to the variability of future cash flows is 24 months. 56 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Commodity fair value hedges -- The Company utilizes fair value hedges to hedge exposure to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to price risk. The Company hedges producer price locks (fixed price gas purchases) and market locks (fixed price gas sales) to reduce the Company's exposure to fixed price risk via swapping out the fixed price risk for a floating price position (NYMEX or index based). For the year ended December 31, 2001, the gains or losses representing the ineffective portion of the Company's fair value hedges were not material. All components of each derivative's gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. The Company did not have any firm commitments that no longer qualified as fair value hedge items and therefore, did not recognize an associated gain or loss. Commodity Derivatives -- Non-Trading -- 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 three months ended March 31, 2000 and the year ended December 31, 1999, the Company recorded hedging losses of $46.7 million and $34.0 million, respectively, under Duke Energy's centralized program. As of March 31, 2000, the commodity positions then held by the Company under the 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. During the nine months ended December 31, 2000, the Company recorded a hedging loss of $81.0 million under the Company's self-directed risk management program. In 1999, the Company managed its exposure to risk from existing assets, liabilities and commitments by hedging the impact of market fluctuations. At December 31, 2000, the Company held or issued several commodity derivatives that reduce exposure to market fluctuations in the price and transportation costs of natural gas and NGLs. At December 31, 2000, these commodity derivatives extended for periods of up to 10 years. The gains, losses and costs related to non-trading commodity derivatives are not recognized until the underlying physical transaction closes. At December 31, 2000, the Company had unrealized net losses of $15.3 million related to non-trading commodity derivatives. Commodity Derivatives -- Trading -- The trading of energy related products and services exposes the Company to the fluctuations in the market values of traded instruments. The Company manages its traded instrument portfolio with strict policies which limit exposure to market risk and require daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate a daily earnings at risk measurement. Fair Values of Commodity Derivatives -- Trading:
2001 2000 ---------------------- --------------------- ASSETS LIABILITIES ASSETS LIABILITIES -------- ----------- ------- ----------- (IN THOUSANDS) Fair value at December 31.................... $135,456 $97,990 $46,185 $51,179
Interest rate fair value hedge -- In October 2001, the Company entered an interest rate swap to convert the fixed interest rate of $250.0 million of debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on six-month LIBOR rates, which is re-priced semiannually through 2005. The swap meets conditions which permit the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swap no ineffectiveness will be recognized. As of December 31, 2001, the fair value of the interest rate swap of ($4.6) million was included in the Consolidated Balance Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions with an offset to the underlying debt included in Long Term Debt. 57 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 13. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS The following fair value amounts have been determined by the Company using available market information and appropriate valuation methodologies. However, considerable judgment is 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 Company could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.
DECEMBER 31, 2001 DECEMBER 31, 2000 ---------------------------- ---------------------------- CARRYING ESTIMATED FAIR CARRYING ESTIMATED FAIR AMOUNT VALUE AMOUNT VALUE ----------- -------------- ----------- -------------- (IN THOUSANDS) Accounts receivable............. $ 887,449 $ 887,449 $ 1,400,676 $ 1,400,676 Notes receivable................ -- -- 29,465 29,465 Accounts payable................ (722,628) (722,628) (1,375,815) (1,375,815) Natural gas, NGL and oil hedge and trading contracts......... 89,905 89,905 (4,994) (20,292) Short term debt................. (212,955) (212,955) (346,410) (346,410) Long term debt.................. (2,235,034) (2,342,795) (1,688,157) (1,795,371)
The fair value of cash and cash equivalents, accounts receivable, accounts payable, and short term debt are not materially different from their carrying amounts because of the short term nature of these instruments or the stated rates approximating market rates. Notes receivable is carried in the accompanying balance sheet at cost. 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. The estimated fair value of options is determined by the Black-Scholes options valuation model. The estimated fair value of long term debt is determined by prices obtained from market quotes. 14. COMMITMENTS AND CONTINGENT LIABILITIES Litigation -- The midstream natural gas industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. A number of these cases are now being brought as class actions. The Company and its subsidiaries are currently named as defendants in some of these cases. Management believes the Company and its subsidiaries have meritorious defenses to these cases, and therefore will continue to defend them vigorously. However, these class actions can be costly and time consuming to defend. Management believes that the final disposition of these proceedings will not have a material adverse effect on the consolidated results of operations or financial position of the Company. In December 1998, Williams Field Services ("Williams") sued Union Pacific Resources Company ("UPRC") and certain affiliates of the Company in Carbon County, Wyoming District Court to enforce its rights under a preferential purchase right. Williams is the majority owner and operator of the Echo Springs Gas Plant and Wamsutter Gathering System in which the Company acquired an interest from UPRC (the "Acquired Assets"). Williams' suit claims that they believe a change of control of the corporate entity that held the UPRC interest in the Acquired Assets occurred at the time of the merger between the Company and 58 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) UPRC and triggered Williams' preferential purchase right. On November 22, 1999, the District Court granted UPRC and the Company's motion for summary judgment. Williams appealed this decision on March 23, 2000 to the Wyoming Supreme Court and on June 20, 2001, the Wyoming Supreme Court reversed the District Court's summary judgment ruling and ordered that a summary judgement be entered for Williams. A request for rehearing was denied. On February 28, 2002, the Company and Williams resolved all issues associated with this matter by closing an exchange transaction in which the Company exchanged the Acquired Assets for certain assets of Williams in the Texas Panhandle and Western Oklahoma. This transaction has been accounted for as a nonmonetary exchange in accordance with Accounting Principles Board Opinion No. 29 "Accounting for Nonmonetary Transactions." There is no gain or loss on the exchange as the fair value of the assets received exceeds the book value of the Company's Acquired Assets. Environmental -- On June 13, 2001, the Company received two administrative Compliance Orders from the New Mexico Environment Department ("NMED") seeking civil penalties for primarily historic air permit matters. One order alleges specific permit non-compliance at 11 facilities that occurred periodically between 1996 and 1999. Allegations under this order relate primarily to emissions from certain compressor engines in excess of what were then new operating permit limits. The other order alleges numerous unexcused excursions from an hourly permit limit arising from upset events at the Company's Dagger Draw facility's sulfur recovery unit between 1997 and 2001. NMED applied its civil penalty policy to the alleged violations and calculated the penalties to be $10.4 million in the aggregate. NMED has initiated settlement discussions and offered to resolve these matters for an amount lower than the calculated penalties. The Company is continuing its discussions with NMED and anticipates that it will resolve all issues relating to the alleged violations. On September 12, 2001, the Company received a Proposed Agreed Order from the Texas Natural Resource Conservation Commission ("Commission") to settle allegations reflected in a June 2001 notice from the Commission relating to the Company's Port Arthur natural gas processing plant. The Proposed Agreed Order sought penalties of $278,000 for various items of alleged-noncompliance relating to the facility's air permit and state air regulations, including valve monitoring and repair requirements under 40 CFR 60, subpart KKK. The Company has reached a settlement with the staff of the Commission for a monetary penalty in the amount of $39,832 and a Supplemental Environmental Project in the amount of $39,832, subject to the approval of the Commission. The Company received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality ("LDEQ") in the spring of 2001 enabling the Company to discharge certain wastewater streams from its Minden Gas Processing Plant until a new discharge permit is issued by the LDEQ. The Compliance Order authorized certain discharges, and otherwise addressed various historic and recent deviations from Clean Water Act regulatory requirements, including the lapse of the facility's discharge permit. The Compliance Order also contemplates final resolution of these matters including the LDEQ issuing a penalty assessment. The Company and LDEQ are now in discussions to resolve all issues relating to this matter. The Company is in discussion with the Oklahoma Department of Environmental Quality ("ODEQ") regarding apparent non-compliance issues relating to the Company's Title V Clean Air Act Operating permits at its Oklahoma facilities, primarily consisting of compliance issues disclosed to the ODEQ pursuant to permit requirements or otherwise voluntarily disclosed to the ODEQ in 2001. These non-compliance issues relate to various specific and detailed terms of the Title V permits, including, separate filing requirements, engine testing procedural requirements, certification requirements, and quarterly emissions testing obligations. As a result of these discussions, the Company anticipates a comprehensive settlement agreement will be entered into to resolve these various items. Management believes that the final disposition of these proceedings will not have a material adverse effect on the consolidated results of operations or financial position of the Company. 59 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Other Commitments and Contingencies -- The Company utilizes assets under operating leases in several areas of operation. Combined rental expense amounted to $23.5 million, $20.2 million and $11.8 million in 2001, 2000 and 1999, respectively. Minimum rental payments under the Company's various operating leases for the years 2002 through 2006 are $8.3 million, $7.0 million, $5.4 million, $5.3 million and $3.5 million, respectively. Thereafter, payments aggregate $6.4 million through 2011. 15. STOCK-BASED COMPENSATION Under Duke Energy's 1998 Long Term Incentive Plan, stock options for Duke Energy's common stock may be granted to the Company's key employees. Under the plan, the exercise price of each option granted cannot be less than 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 term of 10 years. On December 20, 2000, Duke Energy announced a two-for-one common stock split effective January 26, 2001, to shareholders of record on January 3, 2001. The following option information has been restated to reflect the stock split, and appropriate adjustments have been made in the exercise price and number of shares subject to stock options. The following tables show information regarding options to purchase Duke Energy's common stock granted to employees of the Company. STOCK OPTION ACTIVITY
WEIGHTED AVERAGE EXERCISE OPTIONS PRICE ------- -------- (IN THOUSANDS) Outstanding at December 31, 1998............................ 868 $22 Granted................................................... 1,756 27 Exercised................................................. (66) 13 Forfeited................................................. (36) 28 ----- --- Outstanding at December 31, 1999............................ 2,522 26 Granted................................................... 837 41 Exercised................................................. (568) 22 Forfeited................................................. (223) 27 ----- --- Outstanding at December 31, 2000............................ 2,568 31 Granted................................................... 815 38 Exercised................................................. (251) 27 Forfeited................................................. (144) 32 ----- --- Outstanding at December 31, 2001............................ 2,988 $33 ===== ===
60 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) STOCK OPTIONS AT DECEMBER 31, 2001
OUTSTANDING ---------------------------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE REMAINING EXERCISE EXERCISABLE EXERCISE RANGE OF EXERCISE PRICES NUMBER LIFE (YEARS) PRICE NUMBER PRICE ------------------------ -------------- ------------ -------- -------------- -------- (IN THOUSANDS) (IN THOUSANDS) $ 8 to $10................. 12 3.1 $10 12 $10 $11 to $16................. 24 3.3 12 24 12 $17 to $22................. 16 5.1 22 16 22 $23 to $28................. 1,258 7.4 26 533 26 $29 to $34................. 180 7.7 30 59 30 $35 to $40................. 814 10.0 38 -- -- > $40..................... 684 9.0 43 169 43 ----- --- Total................. 2,988 8.4 33 813 29 ===== ===
On December 21, 2000, there were approximately 403,000 exercisable options with a $25 weighted average exercise price. On December 31, 1999, there were 382,000 options exercisable with a weighted average exercise price of $17 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, $10 and $5 per option during 2001, 2000 and 1999, respectively. The fair value of each option granted was estimated on the date of grant using the Black-Scholes options valuation model. WEIGHTED-AVERAGE ASSUMPTIONS FOR OPTION-PRICING
2001 2000 1999 ------- ------- ------- Stock dividend yield...................................... 3.4% 3.7% 4.1% Expected stock price volatility........................... 29.7% 25.1% 18.8% Risk-free interest rates.................................. 5.0% 5.3% 5.9% Expected option lives..................................... 7 years 7 years 7 years
Stock-based compensation expense calculated using the Black-Scholes options valuation model for 2001, 2000 and 1999 would have been $3.7 million, $2.9 million and $2.5 million, respectively and net income would have been $361.7 million, $678.2 million and $41.8 million, respectively. Duke Energy granted performance awards of Duke Energy common stock to key employees of the Predecessor Company under the 1998 Long Term Incentive Plan. Performance awards under the 1998 plan vest over periods ranging from one to seven years. Duke Energy did not award any performance awards in 2001 or 2000. Duke Energy awarded 86,400 shares (fair value of approximately $2.3 million at grant dates) in 1999. Compensation expense for the performance grants is charged to the Company's earnings over the vesting period, and amounted to approximately $217,000, $1.2 million, and $305,000, in 2001, 2000, and 1999, respectively. Duke Energy granted phantom shares of Duke Energy common stock to employees of the Predecessor Company under the 1998 Plan. Phantom stock awards under the 1998 Plan vest over periods ranging from one to four years. Duke awarded 34,190 shares (fair value of approximately $1.3 million at grant dates) in 2001 and 13,100 shares (fair value of approximately $0.6 million at grant date) in 2000. Compensation expense for 61 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the stock grants is charged to the Company's earnings over the vesting period, and amounted to approximately $300,000 in 2001. Compensation expense in 2000 was immaterial. In addition, Duke Energy granted restricted shares of Duke Energy common stock to key employees of the Predecessor Company under the 1996 Stock Incentive Plan. Restricted stock grants under the 1996 plan vest over periods ranging from one to five years. No restricted shares were awarded in 2001. Duke Energy awarded 28,526 restricted shares (fair value of approximately $822,000 at grant dates) in 2000 and 11,100 shares (fair value of approximately $618,000 at grant dates) in 1999. Compensation expense for the stock grants is charged to the Company's earnings over the vesting period, and amounted to approximately $418,000, $402,000, and $275,000, in 2001, 2000, and 1999, respectively. 16. PENSION AND OTHER BENEFITS Effective March 31, 2000, participation by the Company's employees in Duke Energy's non-contributory defined benefit retirement 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. During 2001 and 2000, the Company expensed plan contributions of $14.1 million and $8.9 million, respectively. Duke Energy has, and the Predecessor Company participated in, a non-contributory trustee pension plan which covered eligible employees with minimum service requirements using a cash balance formula. For eligible employees of the Predecessor Company, the plan provides pension benefits 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 Company are as follows: Components of Net Periodic Pension Costs
YEARS ENDED DECEMBER 31, --------------- 2000 1999 ----- ------- (IN THOUSANDS) Service cost benefit earned during year..................... $ 480 $ 1,280 Interest cost on projected benefit obligation............... 460 1,375 Expected return on plan assets.............................. (674) (2,307) Amortization of net transition asset........................ (21) (85) Amortization of prior service cost.......................... 8 34 Recognized actuarial loss................................... -- 6 ----- ------- Net periodic pension cost................................... 253 303 Impact of terminating plan participation.................... 483 -- ----- ------- Total pension cost.......................................... $ 736 $ 303 ===== =======
62 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Reconciliation of Funded Status to Pre-Funded Pension Costs
DECEMBER 31, 2000 -------------- (IN THOUSANDS) CHANGE IN BENEFIT OBLIGATION Benefit obligation at beginning of year..................... $ 21,846 Service cost................................................ 480 Interest cost............................................... 460 Intercompany transfers(a)................................... 128 Benefits paid............................................... (180) Impact of terminating plan participation.................... (22,734) -------- Benefit obligation at end of year........................... $ -- ========
DECEMBER 31, 2000 -------------- (IN THOUSANDS) CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of year.............. $ 33,827 Intercompany transfers(a)................................... 128 Actual return on plan assets................................ 37 Employer contributions...................................... 736 Benefits paid............................................... (180) Impact of terminating plan participants..................... (34,548) -------- Fair value of plan assets at end of year.................... $ -- ======== Pre-funded pension costs.................................... $ -- ========
--------------- (a) Intercompany transfers relate to benefit obligations and plan assets associated with employees transferring between the Predecessor Company and other Duke Energy affiliates. Assumptions Used for Pension Benefit Accounting
YEARS ENDED DECEMBER 31, ------------- 2000 1999 ----- ----- Discount rate............................................... 7.50% 7.50% Rate of increase in compensation levels..................... 4.53% 4.50% Expected long term rate of return on plan assets............ 9.25% 9.25%
The Predecessor Company sponsored an employee savings plan which covered substantially all employees. During 1999, the Company expensed plan contributions of $3.6 million. The employee savings plan was terminated on March 31, 2000 in connection with the Combination. The Predecessor Company's post-retirement benefits, in conjunction with Duke Energy, consist of certain health care and life insurance benefits for certain retired employees. Post-retirement benefits costs were not material in 2000 and 1999. The Company does not have any significant, continuing obligations with respect to post-retirement benefits. 63 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 17. BUSINESS SEGMENTS The Company operates in two principal business segments: (1) natural gas gathering, processing, transportation, marketing and storage, and (2) NGL fractionation, transportation, marketing and trading. These segments are monitored separately by management for performance against its internal forecast and are consistent with the Company's internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Margin, earnings before interest, taxes, depreciation and amortization ("EBITDA") and earnings before interest and taxes ("EBIT") are the performance measures utilized by management to monitor the business of each segment. The accounting policies for the segments are the same as those described in Note 1. Foreign operations are not material and are therefore not separately identified. The following table sets forth the Company's segment information.
YEARS ENDED DECEMBER 31, ---------------------------------------- 2001 2000 1999 ----------- ----------- ---------- (IN THOUSANDS) Operating revenues: Natural gas................................ $ 6,503,921 $ 7,036,003 $2,483,197 NGLs....................................... 5,030,897 3,652,120 1,365,577 Intersegment(a)............................ (1,937,153) (1,594,757) (390,464) ----------- ----------- ---------- Total operating revenues........... $ 9,597,665 $ 9,093,366 $3,458,310 ----------- ----------- ---------- Margin: Natural gas................................ $ 1,228,424 $ 1,169,286 $ 459,843 NGLs....................................... 55,376 48,662 33,170 ----------- ----------- ---------- Total margin....................... $ 1,283,800 $ 1,217,948 $ 493,013 =========== =========== ========== Other operating costs: Natural gas................................ $ 364,664 $ 329,054 $ 182,062 NGLs....................................... 7,536 (8,142)(c) 1,707 Corporate.................................. 129,968 171,154 73,685 ----------- ----------- ---------- Total other operating costs........ $ 502,168 $ 492,066 $ 257,454 =========== =========== ========== Equity in earnings of unconsolidated affiliates: Natural gas................................ $ 28,899 $ 25,554 $ 20,917 NGLs....................................... 1,170 1,870 1,585 ----------- ----------- ---------- Total equity in earnings of unconsolidated affiliates........ $ 30,069 $ 27,424 $ 22,502 =========== =========== ==========
64 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEARS ENDED DECEMBER 31, ---------------------------------------- 2001 2000 1999 ----------- ----------- ---------- (IN THOUSANDS) EBITDA(b): Natural gas................................ $ 892,659 $ 865,786 $ 298,698 NGLs....................................... 49,010 58,674 33,048 Corporate.................................. (129,968) (171,154) (73,685) ----------- ----------- ---------- Total EBITDA....................... $ 811,701 $ 753,306 $ 258,061 =========== =========== ========== Depreciation and amortization: Natural gas................................ $ 264,445 $ 218,593 $ 119,425 NGLs....................................... 10,077 12,636 9,073 Corporate.................................. 4,408 3,633 2,290 ----------- ----------- ---------- Total depreciation and amortization..................... $ 278,930 $ 234,862 $ 130,788 =========== =========== ========== EBIT(b): Natural gas................................ $ 628,214 $ 647,193 $ 179,273 NGLs....................................... 38,933 46,038 23,975 Corporate.................................. (134,376) (174,787) (75,975) ----------- ----------- ---------- Total EBIT......................... $ 532,771 $ 518,444 $ 127,273 =========== =========== ========== Corporate interest expense................... $ 165,670 $ 149,220 $ 52,915 =========== =========== ========== Income before income taxes: Natural gas................................ $ 628,214 $ 647,193 $ 179,273 NGLs....................................... 38,933 46,038 23,975 Corporate.................................. (300,046) (324,007) (128,890) ----------- ----------- ---------- Total income before income taxes... $ 367,101 $ 369,224 $ 74,358 =========== =========== ========== Capital Expenditures: Natural gas................................ $ 560,775 $ 356,542 $1,387,805 NGLs....................................... 10,911 1,284 177,070 Corporate.................................. 20,944 13,122 5,208 ----------- ----------- ---------- Total Capital Expenditures......... $ 592,630 $ 370,948 $1,570,083 =========== =========== ==========
AS OF DECEMBER 31, ----------------------- 2001 2000 ---------- ---------- (IN THOUSANDS) Total assets: Natural gas............................................... $5,326,889 $4,896,542 NGLs...................................................... 258,177 219,282 Corporate(d).............................................. 1,045,143 1,412,173 ---------- ---------- Total assets...................................... $6,630,209 $6,527,997 ========== ==========
65 DUKE ENERGY FIELD SERVICES, LLC NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) --------------- (a) Intersegment sales represent sales of NGLs from the Natural Gas Segment to the NGLs Segment at either index prices or weighted average prices of NGLs. Both measures of intersegment sales are effectively based on current economic market conditions. (b) EBITDA consists of income from continuing operations before interest expense, income tax expense, and depreciation and amortization expense. EBIT is EBITDA less depreciation and amortization. These measures are not a measurement presented in accordance with generally accepted accounting principles and should not be considered in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as a measure of the Company's profitability or liquidity. The measures are included as a supplemental disclosure because it may provide useful information regarding the Company's ability to service debt and to fund capital expenditures. However, not all EBITDA or EBIT may be available to service debt. This measure may not be comparable to similarly titled measures reported by other companies. (c) Other operating cost for NGLs in 2000 include a gain on sale of NGL Pipeline Assets of $12 million. (d) Includes items such as unallocated working capital, intercompany accounts and intangible and other assets. 18. QUARTERLY FINANCIAL DATA (UNAUDITED)
FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER TOTAL ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS) 2001 Operating revenue...... $3,380,072 $2,536,325 $1,681,127 $2,000,141 $9,597,665 Operating income....... 179,688 145,393 114,672 62,949 502,702 Net income............. 142,378 115,642 78,836 27,051 363,907 2000 Operating revenue...... $1,451,211 $2,172,360 $2,551,995 $2,917,800 $9,093,366 Operating income....... 55,627 136,881 152,501 146,011 491,020 Net income............. 361,900 92,229 114,304 111,728 680,161
66 SCHEDULE II DUKE ENERGY FIELD SERVICES, LLC VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
ADDITIONS ------------------------ PRINCIPAL CASH BALANCE AT CHARGED TO PAYMENTS AND BALANCE AT BEGINNING CHARGED TO OTHER RESERVE END OF OF PERIOD EXPENSES ACCOUNTS(B) REVERSALS PERIOD ---------- ---------- ----------- -------------- ---------- DECEMBER 31, 2001: Allowance for doubtful accounts..... $ 3.6 $3.3 $ -- $ (1.0) $ 5.9 Environmental....................... 38.7 -- 8.9 (7.6) 40.0 Litigation.......................... 28.7 -- 1.2 (22.4) 7.5 Other(a)............................ 18.6 -- 16.2 (22.7) 12.1 ----- ---- ----- ------ ----- $89.6 $3.3 $26.3 $(53.7) $65.5 DECEMBER 31, 2000: Allowance for doubtful accounts..... $ 6.7 $1.2 $ -- $ (4.3) $ 3.6 Environmental....................... 15.7 .7 26.5 (4.2) 38.7 Litigation.......................... 10.9 -- 20.0 (2.2) 28.7 Other(a)............................ 19.5 -- 2.6 (3.5) 18.6 ----- ---- ----- ------ ----- $52.8 $1.9 $49.1 $(14.2) $89.6 DECEMBER 31, 1999: Allowance for doubtful accounts..... $ 1.1 $ -- $ 5.6 $ -- $ 6.7 Environmental....................... 5.8 -- 63.0 (53.1) 15.7 Litigation.......................... -- -- 11.0 (0.1) 10.9 Other(a)............................ 11.3 -- 17.0 (8.8) 19.5 ----- ---- ----- ------ ----- $18.2 $ -- $96.6 $(62.0) $52.8
--------------- (a) Principally consists of other contingency reserves which are included in the "Other Current Liabilities" or "Other Long Term Liabilities". (b) Principally consists of environmental, litigation and other contingency reserves assumed in business acquisitions and combinations. 67 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Members of Duke Energy Field Services, LLC We have audited the accompanying consolidated balance sheets of Duke Energy Field Services, LLC and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, members' equity, and cash flows for each of the three years in the period ended December 31, 2001. Our audits also included the financial statement schedule listed in the Index at Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 consolidated financial statements present fairly, in all material respects, the financial position of Duke Energy Field Services, LLC and subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. As discussed in Note 2 to the Consolidated Financial Statements, in 2001 the Company changed its method of accounting for derivative instruments and hedging activities to conform to Statement of Financial Accounting Standards No. 133. DELOITTE & TOUCHE LLP Denver, Colorado March 1, 2002 68 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The following table provides information regarding our directors and executive officers:
NAME AGE POSITION ---- --- -------- Jim W. Mogg.................... 53 Director and Chairman of the Board, President and Chief Executive Officer Mark A. Borer.................. 47 Senior Vice President, Southern Division Michael J. Bradley............. 47 Senior Vice President, Northern Division Robert F. Martinovich.......... 44 Senior Vice President, Western Division Rose M. Robeson................ 41 Vice President and Chief Financial Officer Brent L. Backes................ 42 Vice President, General Counsel and Secretary William W. Slaughter........... 54 Executive Vice President Fred J. Fowler................. 56 Director John E. Lowe................... 43 Director Michael J. Panatier............ 53 Director Richard B. Priory.............. 55 Director
Jim W. Mogg is Chairman of the Board, President and Chief Executive Officer of our company. Mr. Mogg also serves as Senior Vice President -- Field Services for Duke Energy. Mr. Mogg was President and Chief Executive Officer of the Predecessor Company from 1994 until the Combination. Mr. Mogg is also a director, Vice Chairman and Chairman of the Audit Committee of the general partner of TEPPCO. Mr. Mogg has been in the energy industry since 1973. Mark A. Borer is Senior Vice President, Southern Division of our company. Mr. Borer held the same position with the Predecessor Company from 1999 until the Combination. From 1992 until 1999, Mr. Borer served as Vice President of Natural Gas Marketing for Union Pacific Fuels, Inc. Mr. Borer is also a director of the general partner of TEPPCO. Mr. Borer has been in the energy industry since 1978. Michael J. Bradley is Senior Vice President, Northern Division of our company. Mr. Bradley held the same position with the Predecessor Company from 1994 until the Combination. Mr. Bradley has been in the energy industry since 1979. Robert F. Martinovich is Senior Vice President, Western Division of our company. Mr. Martinovich was Senior Vice President of GPM Gas Corporation, a subsidiary of Phillips, from 1999 until the Combination. From 1996 until 1999, Mr. Martinovich was Vice President, Oklahoma Region for GPM Gas Corporation, and from 1994 until 1996, he was Business Development Manager for GPM Gas Corporation. Mr. Martinovich has been in the energy industry since 1980. Rose M. Robeson was named Vice President and Chief Financial Officer of our company effective January 29, 2002. Ms. Robeson joined the Company on May 1, 2000 as Vice President and Treasurer. She was previously Vice President and Treasurer of Kinder Morgan, Inc. (formerly KN Energy, Inc.) from April 1998 to April 2000 and Assistant Treasurer of Kinder Morgan, Inc. from August 1996 to April 1998. Ms. Robeson has been in the energy industry since 1987. Brent L. Backes is Vice President, General Counsel and Secretary of our company effective January 29, 2002. Mr. Backes joined the Predecessor Company in April 1998 as Senior Attorney. He was previously Senior Associate Attorney at LeBoeuf, Lamb, Greene & MacRae, LLP. Mr. Backes has been in the energy industry since 1998. 69 William W. Slaughter is Executive Vice President of our company. Mr. Slaughter held the position of Advisor to the Chief Executive Officer of the Predecessor Company from 1998 until his appointment as Executive Vice President in 2000. From 1997 until 1998, Mr. Slaughter was Vice President of Energy Services for Duke Energy. From 1994 until 1997, Mr. Slaughter served as Vice President of Corporate Strategic Planning for PanEnergy and President of PanEnergy International Development Corporation. Mr. Slaughter is also a director of the general partner of TEPPCO. Mr. Slaughter has been in the energy industry since 1970. Fred J. Fowler, a Director of our company, is Group President -- Energy Transmission of Duke Energy and has held that position since 1997. Mr. Fowler served as Group Vice President of Pan Energy from 1996 until 1997. From 1994 until 1996, Mr. Fowler served as President of Texas Eastern Transmission Corporation. Mr. Fowler is also a director of the general partner of TEPPCO. Mr. Fowler has been in the energy industry since 1968. John E. Lowe, a Director of our company, is the Senior Vice President of Corporate Strategy and Development of Phillips, and has held that position since 2001. Mr. Lowe previously served as Senior Vice President of Planning and Strategic Transactions of Phillips from 2000 to 2001 and as Vice President of Planning and Strategic Transactions of Phillips from 1999 to 2000. From 1997 to 1999, Mr. Lowe served as Supply Chain Manager for Refining, Marketing and Transportation of Phillips. From 1993 to 1997 he served as either Director or Manager of Finance for Phillips. Mr. Lowe has been in the energy industry since 1981. Michael J. Panatier, a Director of our company, is the Executive Vice President of Refining, Marketing and Transportation of Phillips, and has held that position since 2001. Mr. Panatier previously served as Vice Chairman of our Company from the Combination until 2001. Mr. Panatier served as Senior Vice President of Gas Processing and Marketing for Phillips from 1998 until the Combination. From 1994 until the Combination, he also served as President and Chief Executive Officer of GPM Gas Corporation, a subsidiary of Phillips. Mr. Panatier has been in the energy industry since 1975. Richard B. Priory, a Director of our company, is the Chairman, President and Chief Executive Officer of Duke Energy and has held that position since 1998. Mr. Priory served as Chairman and CEO of Duke Energy from 1997 to 1998. From 1994 until 1997, Mr. Priory served as President and Chief Operating Officer of Duke Energy. Mr. Priory is also a director of Dana Corporation and US Airways Group, Inc. Mr. Priory has been in the energy industry since 1976. Pursuant to our limited liability company agreement, we have five directors two of which are appointed by Phillips and three of which are appointed by Duke Energy. There are no family relationships between any of the executive officers nor any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected. 70 ITEM 11. EXECUTIVE COMPENSATION The following table sets forth compensation information for the years ended December 31, 2000 and December 31, 2001 for the Chief Executive Officer and each of our next four most highly compensated executive officers. These five individuals are referred to as the "Named Executive Officers."
LONG TERM COMPENSATION ---------------------------------- ANNUAL COMPENSATION SECURITIES -------------------------------- RESTRICTED UNDERLYING OTHER ANNUAL STOCK STOCK LTIP ALL OTHER SALARY BONUS COMPENSATION AWARDS OPTIONS PAYOUTS COMPENSATION NAME AND PRINCIPAL POSITION YEAR ($) ($)(4) ($)(5) ($)(6) (#)(12) ($) ($)(13) --------------------------- ---- ------- ------- ------------ ---------- ---------- ------- ------------ Jim W. Mogg(1)............... 2001 419,231 201,482 -- 337,990(7) 74,800 -- 91,825 Chairman of the Board, 2000 376,474 475,219 -- 193,513 133,000 76,102 37,399 President and Chief Executive Officer Mark A. Borer(1)............. 2001 219,230 65,500 -- 116,431(8) 25,800 -- 39,457 Senior Vice President, 2000 196,154 166,300 -- 145,730 33,600 -- 24,497 Southern Division Michael J. Bradley(1)........ 2001.. 219,230 61,800 -- 116,431(9) 25,800 -- 27,587 Senior Vice President, 2000 196,154 169,400 -- 145,730 34,400 52,553 19,277 Northern Division Robert F. Martinovich(2)..... 2001.. 219,230 55,800 -- 116,431(10) 25,800 -- 38,632 Senior Vice President, 2000 190,797 160,400 -- 145,730 33,600 -- 54,507 Western Division Martha B. Wyrsch(1)(3)....... 2001.. 192,500 53,323 -- 94,163(11) 21,000 -- 22,256 Senior Vice President, 2000 171,500 165,043 -- 50,127 19,320 -- 12,525 General Counsel and Secretary
--------------- (1) Prior to the Combination on March 31, 2000 all compensation paid to Messrs. Mogg, Borer and Bradley and Ms. Wyrsch was paid by Duke Energy and was attributable to services provided to the Predecessor Company. (2) Prior to the Combination on March 31, 2000 all compensation paid to Mr. Martinovich was paid by Phillips. (3) During the years covered by this table, Ms. Wyrsch also provided services to Duke Energy as Senior Vice President and General Counsel Energy Transmission. During these time periods, the Company was responsible for 70% of Ms. Wyrsch's compensation and Duke Energy was responsible for the remaining 30% of such compensation, except for bonuses which were paid based in part by the performance of each company. The compensation for Ms. Wyrsch reflected in this table consists of the 70% of her compensation that was paid by the Company for services she provided to the Company, except for the bonus, which was paid based on the Company's performance. In 2001, Ms. Wyrsch's combined total salary, bonus, restricted stock award, stock option award and all other compensation for her services to both the Company and Duke Energy were the following respectively: $275,000, $135,852, $134,518, 30,000, and $31,793. In 2000, Ms. Wyrsch's combined total salary, bonus, restricted stock award, stock option award and all other compensation for her services to both the Company and Duke Energy were the following respectively: $245,000, $235,775, $71,610, 27,600 and $17,893. (4) Messrs. Mogg, Borer, Bradley and Ms. Wyrsch elected to forego a portion of their 2001 cash bonus for Duke Energy stock options under the Duke Energy Short Term Incentive Exchange Program as follows: Mr. Mogg, $40,296 for 7,500 option shares; Mr. Borer, $32,750 for 6,100 option shares; Mr. Bradley $12,360 for 2,300 option shares; and Ms. Wyrsch, $13,585 for 2,500 option shares. The awards were granted under the Duke Energy 1998 Long Term Incentive Plan on January 17, 2002 at the fair market value on that date of $38.33, as provided under that Plan. The number of option shares awarded is calculated by dividing the foregone bonus amount by 50% of the present value of a share of Duke Energy Common Stock on the date of grant. The options were 100% vested at grant. These stock options will be reported in next year's Annual Report on Form 10-K. 71 (5) Perquisites and other personal benefits received by each Named Executive Officer did not exceed the lesser of $50,000 or 10% of any such officer's salary and bonus disclosed in the table. (6) Messrs. Mogg, Borer, Bradley and Martinovich and Ms. Wyrsch elected to receive a portion of the value of their long term incentive component of their 2002 compensation in the form of phantom stock. The awards were granted under the Duke Energy 1998 Long Term Incentive Plan on December 19, 2001. Phantom stock is represented by units denominated in shares of Duke Energy common stock. Each phantom stock unit represents the right to receive, upon vesting, one share of Duke Energy common stock. One quarter of each award vests on each of the first four anniversaries of the grant date provided the recipient continues to be employed by the Company or his or her employment terminates on account of retirement. The awards fully vest in the event of the recipient's death or disability or a change in control as specified in the Plan. If the recipient's employment terminates other than on account of retirement, death or disability, any unvested shares remaining on the termination date are forfeited. The phantom stock awards also grant an equal number of dividend equivalents, which represent the right to receive cash payments equivalent to the cash dividends paid on the number of shares of Duke Energy common stock represented by the phantom stock units awarded, until the related phantom stock units vest or are forfeited. The aggregate number of phantom stock units held by Messrs. Mogg, Borer, Bradley and Martinovich and Ms. Wyrsch at December 31, 2001 and their values on that date are as follows:
NUMBER OF VALUE AT PHANTOM STOCK DECEMBER 31, UNITS 2001 ------------- ------------ J. Mogg.................................... 12,360 $485,254 M. Borer................................... 3,930 154,292 M. Bradley................................. 3,930 154,292 R. Martinovich............................. 3,930 154,292 M. Wyrsch.................................. 4,830 189,626
(7) In addition to the 12,360 phantom stock units in note 6, at December 31, 2001, Mr. Mogg held an aggregate of 36,000 restricted shares of Duke Energy common stock having a value of $1,413,360. Dividends are paid on such shares. The vesting of these shares is determined by, among other things, the performance of Duke Energy. (8) In addition to the 3,930 phantom stock units in note 6, at December 31, 2001, Mr. Borer held an aggregate of 5,390 restricted shares of Duke Energy common stock having a value of $211,611. Dividends are paid on such shares. Of these restricted shares, 2,000 will vest on April 1, 2002 and 3,390 will vest on May 26, 2003. (9) In addition to the 3,930 phantom stock units in note 6, at December 31, 2001, Mr. Bradley held an aggregate of 3,390 restricted shares of Duke Energy common stock having a value of $133,091. Dividends are paid on such shares. These shares will vest on May 26, 2002. (10) In addition to the 3,930 phantom stock units in note 6, at December 31, 2001, Mr. Martinovich held an aggregate of 1,695 restricted shares of Duke Energy common stock having a value of $66,546. Dividends are paid on such shares. One half of these shares will vest on May 26, 2002. (11) In addition to the 4,830 phantom stock units in note 6, at December 31, 2001, Ms. Wyrsch held an aggregate of 6,516 restricted shares of Duke Energy common stock having a value of $255,818. Dividends are paid on such shares. Of these restricted shares, 2,916 will vest on May 26, 2003 and 1,200 will vest on the next three anniversaries of October 1. The vesting of these shares is determined by, among other things, the performance of Duke Energy. (12) Represents options granted by Duke Energy to purchase shares of Duke Energy common stock. (13) Represents the following for 2001: - Matching contributions under the Company's 401(k) and Retirement Plan as follows: J. Mogg, $17,200; M. Borer, $17,200; M. Bradley, $17,200; R. Martinovich, $17,200; M. Wyrsch, $7,140. 72 - Make-whole contributions under the Company's Executive Deferred Compensation Plan as follows: J. Mogg, $72,445; M. Borer, $21,553; M. Bradley, $9,683; R. Martinovich, $20,963; M. Wyrsch, $14,312. - Life Insurance premiums paid by the Company as follows: J. Mogg, $2,180; M. Borer, $704; M. Bradley, $704; R. Martinovich, $469; M. Wyrsch, $803. BOARD COMPENSATION Our Directors do not receive a retainer or fees for service on our Board of Directors or any committees. All of our directors are reimbursed for reasonable out-of-pocket expenses incurred in attending meetings of our Board of Directors or committees and for other reasonable expenses related to the performance of their duties as directors. CONSULTING AGREEMENT We have entered into a contract for consulting services with Mr. Slaughter that terminates in June 2002. During the term of this contract, Mr. Slaughter receives a quarterly retainer of $46,860, in exchange for which Mr. Slaughter has agreed to perform services for us for up to 30 days per quarter. If Mr. Slaughter works more than 30 days per quarter, he is entitled to additional compensation at the rate of $1,562 for each additional day. For the year ended December 31, 2001, the Company paid Mr. Slaughter $356,136 under this arrangement. In addition, under the terms of the contract, Mr. Slaughter receives a long term incentive award that tracks the performance of Duke Energy common stock. The award, valued at $360,000 at the time of grant, is paid in cash, 50% on each of the first and second anniversary of grant. Any unpaid portion of such award will automatically be converted into stock options and restricted stock in the event of an initial public offering of equity securities occurring before the payment date. OPTION GRANTS IN LAST FISCAL YEAR None of the Named Executive Officers has received options to purchase members interests in our company. None of the Named Executive Officers held options to purchase member interests in our company at December 31, 2001. This table shows options granted of Duke Energy common stock to the Named Executive Officers during 2001, along with the present value of the options on the date they were granted, calculated as described in footnote 2 to the table. OPTION/SAR GRANTS IN LAST FISCAL YEAR
INDIVIDUAL GRANTS -------------------------------------------------------------------- NUMBER OF SHARES % OF TOTAL UNDERLYING OPTIONS/SARS OPTIONS/SARS GRANTED TO EXERCISE OR BASE GRANT DATE PRESENT NAME GRANTED(1)(#) EMPLOYEES(2) PRICE ($/SH) EXPIRATION DATE VALUE(3)($) ---- ---------------- ------------ ---------------- --------------- ------------------ J. W. Mogg........... 74,800 --(4) 37.68 12/19/2011 786,896 M. A. Borer.......... 25,800 --(4) 37.68 12/19/2011 271,416 M. J. Bradley........ 25,800 --(4) 37.68 12/19/2011 271,416 R. F. Martinovich.... 25,800 --(4) 37.68 12/19/2011 271,416 M. B. Wyrsch......... 30,000 --(4) 37.68 12/19/2011 315,600
--------------- (1) Neither the Company nor Duke Energy has granted any SARs to the Named Executive Officers or any other persons. (2) Reflects percentage that the grant represents of the total options granted to employees of Duke Energy and its subsidiaries during 2001. 73 (3) Based on the Black-Scholes option valuation model. The following table lists key input variables used in valuing the options:
INPUT VARIABLE: --------------- Risk-free Interest Rate..................................... 5.23% Dividend Yield.............................................. 3.37% Stock Price Volatility...................................... 29.71% Option Term................................................. 10 years
With respect to all option grants listed in the table, the volatility variable reflected historical monthly stock price trading date from November 30, 1998 through November 30, 2001. An adjustment was made with respect to each valuation for a risk of forfeiture during the vesting period. The actual value, if any, that a grantee may realized will depend on the excess of the stock price over the exercise price on the date the option is exercised, so that there is no assurance the value realized will be at or near the value estimated based upon the Black-Scholes option valuation model. (4) less than one percent. OPTION EXERCISES AND YEAR-END VALUES This tables shows aggregate exercises of options for Duke Energy common stock during 2001 by the Named Executive Officers, and the aggregate year-end value of the unexercised options held by them. The value assigned to each unexercised "in-the-money" stock option is based on the positive spread between the exercise price of the stock option and the fair market value of Duke Energy common stock on December 31, 2001, which was $39.65. The fair market value is the average of the high and low prices of a share of Duke Energy common stock on that date as reported on the New York Stock Exchange Composite Transactions Tape. The ultimate value of a stock option will depend on the market value of the underlying shares on a future date. AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION/SAR VALUES
NUMBER OF SECURITIES UNDERLYING VALUE OF UNEXERCISED UNEXERCISED IN-THE-MONEY OPTIONS/SARS AT OPTIONS/SARS AT FY-END*(#) FY-END($) --------------- -------------------- SHARES ACQUIRED EXERCISABLE/ EXERCISABLE/ NAME ON EXERCISE(#) VALUE REALIZED($) UNEXERCISABLE UNEXERCISABLE ---- --------------- ----------------- --------------- -------------------- J. W. Mogg........... 1,180 36,827 113,854/218,634 1,200,952/1,160,106 M. A. Borer.......... 5,000 77,791 16,450/56,550 165,142/274,999 M. J. Bradley........ 13,981 249,840 11,899/60,050 147,052/301,592 R. F. Martinovich.... 10,650/51,750 60,900/172,626 M. B. Wyrsch......... 33,700/77,500 372,083/431,183
--------------- * Neither the Company nor Duke Energy has granted any SARs to the Named Executive Officers or any other persons. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth information regarding the beneficial ownership of the member interests in our company by: - each holder of more than 5% of our member interests; - the Named Executive Officers; 74 - each director; and - all directors and executive officers as a group.
NAME OF BENEFICIAL OWNERS BENEFICIAL OWNERSHIP ------------------------- -------------------- Duke Energy Corporation..................................... 69.7% 526 South Church Street Charlotte, North Carolina 28201-1006 Phillips Petroleum Company.................................. 30.3 Phillips Building Bartlesville, Oklahoma 74004 Jim W. Mogg................................................. -- Mark A. Borer............................................... -- Michael J. Bradley.......................................... -- Robert F. Martinovich....................................... -- Martha B. Wyrsch............................................ -- Fred J. Fowler.............................................. -- John E. Lowe................................................ -- Michael J. Panatier......................................... -- Richard B. Priory(1)........................................ 69.7 All directors and executive officers as a group (11 persons)(1)............................................... 69.7%
--------------- (1) Mr. Priory serves as Chairman, President and Chief Executive Officer of Duke Energy. As such, Mr. Priory may be deemed to have voting and dispositive power over our member interests beneficially owned by Duke Energy. Mr. Priory disclaims beneficial ownership of the securities owned by Duke Energy. In August 2000, we issued $300.0 million of preferred member interests to affiliates of Duke Energy and Phillips. Duke Energy Field Services Investment Corp. was issued a preferred member interest representing 69.7% of the outstanding preferred member interests in our company and Phillips Gas Investment Company was issued a preferred member interest representing a 30.3% of the outstanding preferred member interests in our company. See Note 11 to the Notes to Consolidated Financial Statements. The preferred member interests have no voting rights in the election of our directors. Duke Energy and Mr. Priory may be deemed to have dispositive power over the preferred member interest held by Duke Energy Field Services Investment Corp., and Phillips may be deemed to have dispositive power over the preferred member interest held by Phillips Gas Investment Company. Mr. Priory disclaims beneficial ownership of the preferred member interests held by Duke Energy Field Services Investment Corp. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS On March 31, 2000, we combined the midstream natural gas 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 the Mid-Continent gathering and processing assets of Conoco and Mitchell Energy. In addition, concurrently with the Combination, we obtained by transfer from Duke Energy the general partner of TEPPCO. In exchange for the asset contributions, Phillips received 30.3% of the outstanding non-preferred member interests in our company, with Duke Energy holding the remaining 69.7% of the outstanding non-preferred 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. 75 There are significant transactions and relationships between us, Duke Energy and Phillips. For purposes of governing these ongoing relationships and transactions, we will continue in effect the agreements described below. We intend that the terms of any future transactions and agreements between us and Duke Energy or Phillips will be at least as favorable to us as could be obtained from third parties. Depending on the nature and size of the particular transaction, in any such reviews, our Board of Directors may rely on our management's knowledge, use outside experts or consultants, secure appropriate appraisals, refer to industry statistics or prices, or take other actions as are appropriate under the circumstances. TRANSACTIONS WITH DUKE ENERGY SERVICES AGREEMENT We have entered into a services agreement with Duke Energy and some of its subsidiaries, dated as of March 14, 2000. Under this agreement, Duke Energy and those subsidiaries will provide us with various staff and support services, including information technology products and services, payroll, employee benefits, insurance, cash management, ad valorem taxes, treasury, media relations, printing, records management, legal functions and shareholder services. These services are priced on the basis of a monthly charge approximating market prices. Additionally, we may use other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments. This agreement, as amended, expires on December 31, 2002. We believe that the overall charges under this agreement will not exceed charges we would have incurred had we obtained similar services from outside sources. LICENSE AGREEMENT In connection with the Combination, Duke Energy has licensed to us a non-exclusive right to use the phrase "Duke Energy" and its logo and certain other trademarks in identifying our businesses. This right may be terminated by Duke Energy at its sole option any time after: - Duke Energy's direct or indirect ownership interest in our company is less than or equal to 35%; or - Duke Energy no longer controls, directly or indirectly, the management and policies of our company. Following the receipt of Duke Energy's notice of termination, we have agreed to amend our organizational documents and those of our subsidiaries to remove the "Duke" name and to phase out within 180 days of the date of the notice the use of existing signage, printed literature, sales and other materials bearing a name, phrase or logo incorporating "Duke." OTHER TRANSACTIONS Prior to the Combination, Duke Energy and its subsidiaries engaged in a number of transactions with the Predecessor Company. This included sales of residue gas and NGLs, the purchase of raw natural gas and other petroleum products and providing natural gas gathering and transportation services to Duke Energy and its subsidiaries. We anticipate that we will continue to engage is such activities with Duke Energy and its subsidiaries in the ordinary course of business. In 2001, our total revenues from such activities with Duke Energy and its subsidiaries were approximately $1,648.5 million. TRANSACTIONS WITH PHILLIPS Prior to the Combination, Phillips engaged in a number of transactions with GPM Gas Corporation, the subsidiary of Phillips that owned its midstream natural gas assets that were transferred to us as part of the Combination. This included the sale of residue gas, NGLs and sulfur, and the purchase of raw natural gas. In addition, it included a long term agreement with Phillips, and subsequently Chevron Phillips Chemical Company LLC ("CPChem"), for the sale of NGLs at index-based prices. We anticipate that we will continue to engage in such activities with Phillips and its subsidiaries and CPChem in the ordinary course of business. For the year ended December 31, 2001, our total revenues from such activities with Phillips and its subsidiaries, and CPChem were approximately $816.2 million. 76 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedule included in Part II of this annual report are as follows: Consolidated Financial Statements Consolidated Statements of Income for the Years Ended December 31, 2001, 2000 and 1999 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2001, 2000 and 1999 Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999 Consolidated Balance Sheets as of December 31, 2001 and 2000 Consolidated Statements of Members' Equity for the Years Ended December 31, 2001, 2000 and 1999 Notes to Consolidated Financial Statements Quarterly Financial Data (unaudited) (included in Note 18 of the Notes to Consolidated Financial Statements) Consolidated Financial Statement Schedule II -- Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2001, 2000 and 1999 All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto. (b) Reports on Form 8-K A current report on Form 8-K was filed on November 9, 2001 under Item 5, Other Events and under Item 7, Financial Statements and Disclosures. (c) Exhibits -- See Exhibit Index immediately following the signature page. 77 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. DUKE ENERGY FIELD SERVICES, LLC By: /s/ JIM W. MOGG ------------------------------------ Jim W. Mogg Chairman of the Board, President and Chief Executive Officer March 27, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
SIGNATURE TITLE DATE --------- ----- ---- /s/ JIM W. MOGG Chairman of the Board, President March 27, 2002 ------------------------------------------------ and Chief Executive Officer Jim W. Mogg (Principal Executive Officer) /s/ ROSE M. ROBESON Chief Financial Officer (Principal March 27, 2002 ------------------------------------------------ Financial and Accounting Officer) Rose M. Robeson /s/ FRED J. FOWLER Director March 27, 2002 ------------------------------------------------ Fred J. Fowler /s/ JOHN E. LOWE Director March 27, 2002 ------------------------------------------------ John E. Lowe /s/ MICHAEL J. PANATIER Director March 27, 2002 ------------------------------------------------ Michael J. Panatier /s/ RICHARD B. PRIORY Director March 27, 2002 ------------------------------------------------ Richard B. Priory
78 EXHIBIT INDEX Exhibits filed herewith are designated by an asterisk(*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting management contracts or compensatory plans or arrangements are designated by a double asterisk (**).
EXHIBIT NUMBER DESCRIPTION ------- ----------- 3.1 -- Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC by and between Phillips Gas Company and Duke Energy Field Services Corporation, dated as of March 31, 2000 (incorporated by reference to Exhibit 3.1 to Form 10 (Registration No. 000-31095) of registrant filed on July 20, 2000). 3.2 -- First Amendment to Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC dated as of August 4, 2000 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K of registrant filed on August 16, 2000). 4.1 -- Form of Indenture (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-3/A (Registration No. 333-41854) of registrant filed on August 2, 2000). 4.2 -- First Supplemental Indenture between Duke Energy Field Services, LLC and The Chase Manhattan Bank, as trustee, dated as of August 16, 2000 (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K of registrant filed on August 16, 2000). 4.3 -- Second Supplemental Indenture between Duke Energy Field Services, LLC and The Chase Manhattan Bank, as trustee, dated as of February 2, 2001 (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K of registrant filed on February 1, 2001). *4.4 -- Third Supplemental Indenture between Duke Energy Field Services, LLC and The Chase Manhattan Bank, as trustee, dated as of November 9, 2001. 10.1 -- Second Amendment to Parent Company Agreement among Phillips Petroleum Company, Duke Energy Corporation, Duke Energy Field Services, LLC and Duke Energy Field Services Corporation dated as of August 4, 2000 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K of registrant filed on August 16, 2000). 10.2** -- Employment Agreement dated as of April 1, 2000 between Duke Energy Field Services Assets, LLC and Michael J. Panatier (incorporated by reference to Exhibit 10.1 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on May 4, 2000). 10.3** -- First Amendment to Employment Agreement dated as of June 28, 2000 between Duke Energy Field Services Assets, LLC and Michael J. Panatier (incorporated by reference to Exhibit 10.1(b) to Form 10/A (Registration No. 000-31095) of registrant filed on August 2, 2000). 10.4 -- Services Agreement dated as of March 14, 2000 by and between Duke Energy Corporation, Duke Energy Business Services, LLC, Pan Service Company, Duke Energy Gas Transmission Corporation and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 10.3 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on March 27, 2000). 10.5 -- First Amendment to Services Agreement dated as of December 15, 2000 between Duke Energy Corporation, Duke Energy Business Services, LLC, Pan Service Company, Duke Energy Gas Transmission Corporation and Duke Energy Field Services, LLC. (incorporated by reference to Exhibit 10.5 to Annual Report on Form 10-K of registrant filed on March 30, 2001). 10.6 -- Transition Services Agreement dated as of March 17, 2000 among Phillips Petroleum Company and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 10.4 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on March 27, 2000). 10.7 -- Trademark License Agreement dated as of March 31, 2000 among Duke Energy Corporation and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 10.5 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on May 4, 2000). 10.8 -- Contribution Agreement dated as of December 16, 1999 among Duke Energy Corporation, Phillips Petroleum Company and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 2.1 to Duke Energy Corporation's Form 8-K filed on December 30, 1999).
EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.9 -- First Amendment to Contribution and Governance Agreement dated as of March 23, 2000 among Phillips Petroleum Company, Duke Energy Corporation and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 10.7(b) to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on March 27, 2000). 10.10 -- NGL Output Purchase and Sale Agreement effective as of January 1, 2000 between GPM Gas Corporation and Phillips 66 Company, a division of Phillips Petroleum Company, as amended by Amendment No. 1 dated December 16, 1999 (incorporated by reference to Exhibit 10.8 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on March 15, 2000). 10.11 -- Sulfur Sales Agreement effective as of January 1, 1999 between Phillips 66 Company, a division of Phillips Petroleum Company, and GPM Gas Corporation (incorporated by reference to Exhibit 10.9 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on March 27, 2000). 10.12 -- Parent Company Agreement dated as of March 31, 2000 among Phillips Petroleum Company, Duke Energy Corporation, Duke Energy Field Services, LLC and Duke Energy Field Services Corporation (incorporated by reference to Exhibit 10.10 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on May 4, 2000). 10.13 -- First Amendment to the Parent Company Agreement dated as of May 25, 2000 among Phillips Petroleum Company, Duke Energy Corporation, Duke Energy Field Services, LLC and Duke Energy Field Services Corporation (incorporated by reference to Exhibit 10.8(b) to Form 10 (Registration No. 333-41854) of registrant filed on July 20, 2000). 10.14** -- Contract for Services dated as of April 1, 2000 between Duke Energy Field Services Assets, LLC and William W. Slaughter (incorporated by reference to Exhibit 10.11 to Registration Statement on Form S-1/A (Registration No. 333-32502) of Duke Energy Field Services Corporation, filed on May 4, 2000). 10.15** -- First Amendment to Contract for Services dated as of June 29, 2000 between Duke Energy Field Services Assets, LLC and William W. Slaughter (incorporated by reference to Exhibit 10.9(b) to Form 10/A (Registration No. 333- 41854) of registrant filed on August 2, 2000). 10.16 -- 364-Day Credit Facility among Duke Energy Field Services, LLC,Duke Energy Field Services Corporation, Bank of America, N.A., as Agent and the Lenders named therein, Dated March 31, 2001(incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q of registrant filed on August 13, 2001). *12.1 -- Calculation of Ratio of Earnings to Fixed Charges. *21.1 -- Subsidiaries of the Company. *23.1 -- Consent of Deloitte & Touche LLP.