ITEM 1. Business.
Duke Energy Field Services, LLC is a company formed in 1999 that holds to the extent that it existed at the time, 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”) prior to its merger with Conoco Inc. (“ConocoPhillips”). References to ConocoPhillips, for periods prior to the merger of Conoco Inc. and Phillips, are references to 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 ConocoPhillips 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 that existed at the time of the Combination. 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 2500, Denver, Colorado 80202. Our telephone number is 303-595-3331 and our internet website is www.defs.com.
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:
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natural gas gathering, compression, treating, processing, transportation, trading and marketing and storage (“Natural Gas Segment”); and
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NGL fractionation, transportation, marketing and trading (“NGLs 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 2003:
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. At December 31, 2003, our gathering systems consisted of approximately 58,000 miles of gathering and transmission pipe, with approximately 34,000 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 56 owned and operated plants and at 10 third party operated facilities in which we hold an equity interest.
The NGLs separated from the raw natural gas by our processing operations are either sold and transported as NGL raw mix or further separated through a process known as fractionation into their individual components (ethane, propane, butanes and natural gasoline) and then sold as individual components. We fractionate NGL raw mix at our 10 owned and operated fractionators and at four 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 ConocoPhillips and ChevronPhillips under an existing contract which expires January 1, 2015. 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, Marketing and Trading” in this section.)
The residue gas that results from our processing is sold at market-based prices to marketers and end-users, including large industrial customers and natural gas and electric utilities serving individual consumers. We market residue gas directly or through our wholly-owned gas marketing company. We also store residue gas at our 6.0 billion cubic foot natural gas storage facility.
We own 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, petrochemicals, natural gas 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 gathering and transportation sectors of the midstream natural gas industry.
A discussion of the current business and operations of each of our segments follows the description of our business strategy. 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 18, “Business Segments,” of the Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplemental Data.
Our Business Strategy
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. In the current economic environment, we are pursuing the following strategies:
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Leverage the size and focus of our existing operations. Our size, scope and concentration of our assets in our regions of operation provide for opportunities to acquire additional supplies of raw natural gas. Our market presence and asset base generally provide us opportunities to use our economies of scale to be a low cost provider in connecting new raw natural gas supplies and providing value chain gathering and processing services. 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.
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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.
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Further streamline our cost structure. We believe that we have a complementary base of assets from which to further extract operating efficiencies and cost reductions, while continuing to provide superior customer service. In addition, we continue to optimize our existing assets by looking at potential plant consolidation and ensuring reliability in our plant operations.
Natural Gas Gathering, Processing, Transportation, Marketing and Storage
Overview
At December 31, 2003, our raw natural gas gathering and processing operations consisted of:
In 2003, we gathered, processed and/or transported approximately 7.7 trillion Btus per day of raw natural gas. As a result of new connections resulting from both increased drilling and released raw natural gas, we connected approximately 1,300 additional receipt points in 2003.
Our raw natural gas gathering and processing operations are located in 10 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. According to Hart Downstream Energy Services “Gas Processors Report” dated November 17, 2003, we are the largest NGL producer in North America.
Raw Natural Gas Supply Arrangements. We take ownership, control or custody of raw natural gas primarily at the wellhead. The producer may dedicate to us the raw natural gas produced from designated oil and natural gas leases for a specific term. The term for purchase commitments of dedicated gas can range from 30 days to life of lease. We obtain access to raw natural gas and provide our midstream natural gas service principally under three types of processing contracts: percentage-of-proceeds contracts, fee-based contracts and keep-whole and wellhead-purchase 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. 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 ConocoPhillips, Anadarko, BP, Devon, and Dominion, which together account for approximately 15% 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. 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 third party 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 asset base and scope of our operations provide us with opportunities to add released raw natural gas to our systems. In addition, we have unused processing capacity in the Offshore Gulf of Mexico and Rocky Mountain regions, which contain quantities of proved natural gas reserves. We also have a presence in other potential high-growth areas such as the Western Canadian Sedimentary Basin.
Gathering systems are operated at design pressures that will maximize 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 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 6.1 trillion Btus per day of raw natural gas and produced an average of 365,000 barrels per day of NGLs during 2003.
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 one of our owners, ConocoPhillips, to small, regional retail propane distributors. At four of our Mid-Continent facilities the element helium is isolated from the raw gas stream and sold to industrial gas companies.
We also remove off-quality crude oil, nitrogen, hydrogen sulfide, 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 at 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, we are involved in the purchase and sale of residue gas, directly or through our wholly owned gas marketing company and our affiliates. Our gas marketing efforts involve supplying the residue gas demands of end-user customers that are physically attached to our pipeline systems, supplying the gas processing requirements associated with our keep-whole processing agreements and selling gas into downstream pipelines. We are focused on extracting the highest possible value for the residue gas that results from our processing and transportation operations.
Our gas asset based trading and marketing activities are supported by our ownership of the Spindletop storage facility and various intrastate pipelines which give us access to market centers/hubs such as Waha, Texas; Katy, Texas and the Houston Ship Channel. 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.
Our Spindletop storage facility plays an important role in our ability to act as a full-service natural gas trader and 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.
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, 2003.
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Note that while capacity is measured volumetrically (in cubic feet), inlet volumes are measured using heating value (in British thermal units).
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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 principal competitors in this segment of our business consist of major integrated oil companies, independent oil and gas producers, independent oil and gas gatherers, and interstate and intrastate pipeline companies.
Regional Strategies. Continued raw natural gas supply is key to our success. Maintaining our raw natural gas supply enables us to maintain throughput volumes and asset utilization throughout our entire midstream natural gas value chain. We evaluate the nature of the opportunity that a particular region presents, including 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:
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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.
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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.
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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 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, 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 we are the operator of, 15 natural gas processing plants in this region. In addition, we own a minority interest in one natural gas processing plant that is operated by a third party. Our natural gas processing plants are strategically located to access Permian Basin production. Our plants have processing capacity net to our interest of 1.3 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. Two 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 2003, these plants operated at an overall 84% capacity utilization rate.
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 and improve reliability.
Our key suppliers in this region include ExxonMobil, Occidental, Anadarko, ConocoPhillips, Dominion, ChevronTexaco, and Yates. Our principal competitors in this region include Dynegy, Sid Richardson, ConocoPhillips, Western Gas, BP, El Paso, Marathon and ChevronTexaco.
Mid-Continent. Our facilities in this region are located in Oklahoma, Kansas, the Texas Panhandle and four counties in Southeast Colorado. In this region, we own and are the operator of 12 natural gas processing plants. We also own a minority interest in one other natural gas processing plant that is operated by a third party. We gather and process raw natural gas primarily from the Ardmore and Anadarko Basins, including the prolific Hugoton and Panhandle fields. Our plants have processing capacity net to our interest of 2.0 billion cubic feet of raw natural gas per day. During 2003, our plants operated at an overall 81% capacity utilization rate.
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 dedicated acreage 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 in this region.
Our key suppliers in this region include ConocoPhillips, ExxonMobil, Gungoll, Newfield, OXY USA, Dominion, EOG, Marathon, Chesapeake, Apache and Anadarko. Our principal competitors in this region include Oneok, Cantera, Mustang, Western Gas, Enogex., Regency, Pioneer, Enbridge, and BP.
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 five natural gas processing plants in this region. Our plants have processing capacity net to our interest of 1.1 billion cubic feet of raw natural gas per day. During 2003, these plants operated at an overall 72% capacity utilization rate.
Our East Texas operations are centered around our East Texas Complex, located near Carthage, Texas. This plant complex is the third largest raw natural gas processing facility in the continental United States, based on liquids recovery, and in 2003 produced approximately 33,000 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 Gulf South, Anadarko and American Central. The complex is adjacent to our Carthage Hub, which delivers residue gas to interconnects with 11 interstate and intrastate pipelines. The Carthage Hub, with an aggregate delivery capacity of 1.5 billion cubic feet per day, acts as a key exchange point for the purchase and sale of residue gas.
In the Austin Chalk area, where we provide essential low pressure gathering and compression services, infill drilling and recompletion activity continue 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), consolidation of the gas processing facilities was completed in July 2002. Gas prices are supporting new drilling activity, which has reduced decline rates. Volume declines in the near term, however, are expected to continue. Additional improvements in technology or sustained higher gas prices could significantly increase activity and reserve recovery in either of these two areas.
In North Louisiana, we gathered and processed or gathered and transported approximately 390 billion Btus per day in 2003. We operate one of the largest intrastate pipelines in Louisiana, the PELICO System, which delivers gas to industrial customers and electric generators within the state and also makes deliveries to five interstate pipelines at or near the Perryville Hub.
Our key suppliers in this region include Anadarko, Devon and ConocoPhillips. Our principal competitors in this region include Gulf South, Regency and Energy Transfer.
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 a third party. Our plants have processing capacity net to our interest of 1.1 billion cubic feet of raw natural gas per day. During 2003, the plants in this region ran at an overall 68% capacity utilization rate.
Our Spindletop natural gas storage facility is located near Beaumont, Texas and has current working natural gas capacity of 6.0 billion cubic feet, plus expansion potential of up to an additional 11.5 billion cubic feet. We have numerous firm and interruptible services available including daily services, 30-day services and service contracts for up to 10 years. This high deliverability storage facility interconnects with 9 interstate and intrastate pipelines and is positioned to meet the continuing changing gas demand market including the hourly demand needs of the natural gas-fired electric generation marketplace, currently the fastest growing demand segment of the natural gas industry.
To achieve growth in our Onshore Gulf of Mexico region, we intend to fully integrate our 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, Dominion, Bass Enterprises and El Paso. Our principal competitors in this region include Gulfterra, Kinder Morgan, Crosstex and Houston Pipe Line.
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 nine natural gas processing plants in this region. Our plants have processing capacity of 475 million cubic feet of raw natural gas per day. During 2003, our plants in this region operated at an overall 70% capacity utilization rate.
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 of the region where new technologies and recovery methods are being employed.
Our key suppliers in the region include Patina, BP, Kerr-McGee and Anadarko. Our principal competitors in this region include Kerr-McGee, Williams and Western Gas.
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 five other natural gas processing plants, all of which are operated by third parties. The plants have processing capacity net to our interest of 1.3 billion cubic feet of raw natural gas per day. During 2003, our plants in this region operated at an overall 44% 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.
In addition, we own a 71.8% interest in Dauphin Island Gathering Partners (“Dauphin Island”), a partnership which owns and operates offshore gathering and transmission systems. Dauphin Island has attractive market outlets, including deliveries to Texas Eastern Transmission (“TETCO”), Gulfstream Natural Gas System, 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 TETCO’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 shallow-water and deep-water oil production platforms and dual market outlets into Shell’s Delta terminal as well as ChevronTexaco’s Cypress terminal.
On May 31, 2002, we acquired 33.3% of the outstanding membership interests in Discovery Producer Services, LLC (“Discovery”). The Discovery assets, which were primarily constructed in 1997, extend from deepwater offshore Louisiana to onshore delivery points approximately 30 miles south of New Orleans. Discovery owns and operates a 600 million cubic feet per day (MMcf/d) interstate pipeline, including a 30-inch mainline that extends to the edge of the outer continental shelf, a condensate handling facility, a 600 MMcf/d cryogenic gas processing plant, a 42,000 barrels per day fractionator, 400 MMcf/d of deepwater gathering laterals and a fixed-leg platform at Grand Isle 115 to host deepwater developments.
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 plan for this region is to connect new facilities to our existing base so that we can realize new offshore development opportunities. Our existing assets in the eastern Gulf of Mexico are positioned to access new and ongoing production developments.
Our key suppliers in the Offshore Gulf of Mexico region include El Paso, ExxonMobil, Dominion and ENI. Our principal competitors in this region include BP, Shell, Williams and Gulfterra.
Western Canada. We own interests in seven natural gas processing plants in Western Canada and operate six of these plants. These facilities are located in northeastern British Columbia, the Peace River Arch area of northwestern Alberta and the central plains and foothills area of Alberta. In total, the facilities in this region have processing capacity net to our interest of 570 million cubic feet of raw sour natural gas per day. During 2003, our processing plants in this area operated at an overall 66% capacity utilization rate. Most of 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 directly subject to fluctuations in commodity prices. Our operations in Canada are subject to risks inherent in transactions involving foreign currencies.
Our key suppliers in this region include Burlington, Canadian Natural Resources, EnCana and Devon. Our principal competitors in the area include Keyspan, Taylor, Enerpro and Altagas.
Natural Gas Liquids Transportation, Fractionation, Marketing and Trading
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. In 2003, we marketed and traded approximately 575,000 barrels per day of NGLs, of which approximately 64% was production for our own account.
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.
In 2001, we acquired five propane rail terminals and constructed one in the northeastern United States. Marketing propane from these rail terminals, along with volume from TEPPCO’s Providence, Rhode Island import facility, accounts for approximately 27,000 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 10 owned and operated fractionators and four fractionators operated by others, including two at the Mont Belvieu market center, and 13 pipeline systems. Our current total fractionation capacity is approximately 166,000 barrels per day.
Strategy
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.
Customer Services. We plan to continue to expand our services to customers, including producers and end users, principally in the areas of price risk management and 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 the value of our product by continuing to expand local sales. We have fractionation capabilities at 10 of our owned and operated raw natural gas processing plants, and at two raw natural gas processing plants in which we own minority interests and which are operated by others. Our ability to fractionate NGLs at regional processing plants provides us with direct access to local NGL markets.
Market Hub Fractionation. We will continue to focus on optimizing our product slate from our two Mont Belvieu, Texas market center 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 use company owned NGL pipelines to transport approximately 43,000 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, East Texas, 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 customer base.
Wholesale Propane Marketing. We continue to expand our propane wholesale marketing activity into areas where asset infrastructure exists. We currently utilize rail, pipeline and waterborne import facility assets to transport propane to market. Propane wholesale marketing involves the purchase of propane from both our Natural Gas Segment and third party producers for delivery and sale to wholesale and end use customers. Additionally, we provide our wholesale customers price risk products such as fixed price and option contracts to mitigate the seasonal price fluctuations of propane.
Key Suppliers and Competition
The marketing of NGLs is a highly competitive business that involves integrated oil and natural gas companies, midstream 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 processing plants and Oneok, Koch, ConocoPhillips and RME. Our largest sales customers are ChevronPhillips, ConocoPhillips, Dow Hydrocarbons and Formosa Plastics which accounted for approximately 24%, 18%, 5%, and 4%, respectively, of our total NGL transportation, fractionation and marketing revenues in 2003. Our principal competitors in the marketing of NGLs are Enterprise Products, Koch, Dynegy and Louis Dreyfus. In 2003, we marketed and traded an average of approximately 575,000 barrels per day.
TEPPCO
On March 31, 2000, we obtained by transfer from Duke Energy, ownership of the general partner of TEPPCO, a publicly traded master limited partnership. TEPPCO operates in three principal areas:
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refined products, liquefied petroleum gases and petrochemicals transportation (Downstream Segment);
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crude oil gathering, transportation and marketing (Upstream Segment); and
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natural gas gathering, NGLs transportation and NGLs fractionation (Midstream Segment).
TEPPCO’s Downstream Segment is one of the largest pipeline common carriers of refined petroleum products and liquefied petroleum gases in the United States. This system is comprised of an approximate 4,600 mile products pipeline system, extending from southeast Texas through central and midwest states to the northeast United States and is the only pipeline system that transports liquefied petroleum gases to the northeast United States from the Texas Gulf Coast. Its operations include the interstate transportation, storage and terminaling of petroleum products; short-haul shuttle transportation of liquefied petroleum gas at its Mont Belvieu, Texas complex; and other ancillary services. TEPPCO’s Downstream Segment also owns and operates three petrochemical pipelines in Texas between Mont Belvieu and Port Arthur. As of February 10, 2003, TEPPCO’s Downstream Segment also owns a 50% interest in Centennial Pipeline LLC (“Centennial”), which owns and operates an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. Marathon Ashland Petroleum LLC owns the other 50% interest. At December 31, 2003, TEPPCO’s Downstream Segment also owns a 50% interest in Mont Belvieu Storage Partners, L.P. (“MB Storage”), which serves the fractionation, refining and petroleum industries, providing substantial capacity and flexibility for the transportation, terminaling and storage of NGLs, liquefied petroleum gases and refined products. Louis Dreyfus owns the other 50% interest.
TEPPCO’s Upstream Segment owns and operates approximately 3,650 miles of crude oil trunk line and gathering pipelines, primarily in Oklahoma, New Mexico, Texas and the Rocky Mountain region. It also owns a 50% interest in Seaway Crude Pipeline Company “(Seaway”), which owns an approximately 500 mile, large diameter crude oil pipeline that transports primarily imported
crude oil from the Texas Gulf Coast to the mid-continent and midwest refining sectors. ConocoPhillips owns the other 50% interest in Seaway. In addition, TEPPCO’s Upstream Segment owns crude oil storage tanks at Cushing, Oklahoma and Midland, Texas, and interests in two crude oil pipelines operating in New Mexico, Oklahoma and Texas.
TEPPCO’s Midstream Segment owns and operates approximately 500 miles of NGLs pipelines located along the Texas Gulf Coast and two fractionators in Colorado. In September 2001, TEPPCO’s Midstream Segment acquired Jonah Gas Gathering Company, which gathers natural gas in the Green River Basin in southwestern Wyoming. The Jonah natural gas gathering system consists of approximately 480 miles of pipelines. Natural gas gathered on the Jonah system is delivered to several interstate pipeline systems that provide access to a number of West Coast, Rocky Mountain and midwest markets. On March 1, 2002, TEPPCO’s Midstream Segment expanded its NGLs operations with the acquisition of the Chaparral and Quanah pipelines, which consist of a combined 1,000 miles of gathering and trunk pipelines extending from southeastern New Mexico and West Texas to Mont Belvieu, Texas. On June 30, 2002, TEPPCO’s Midstream Segment acquired the Val Verde coal seam gas gathering system from a subsidiary of Burlington Resources Inc. The Val Verde gathering system consists of 360 miles of pipeline, 14 compressor stations and a large amine treating facility for the removal of carbon dioxide. The system has a pipeline capacity of approximately one billion cubic feet of gas per day. The Val Verde gathering system gathers coal seam gas from the Fruitland Coal Formation of the San Juan Basin in New Mexico and Colorado. The system is one of the largest coal seam gas gathering and treating facilities in the United States. Certain of the assets of TEPPCO’s Midstream Segment are operated and commercially managed by us under agreements with TEPPCO.
The general partner of TEPPCO manages and directs TEPPCO under the TEPPCO partnership agreement and the partnership agreements of its operating partnerships. Under these 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 and debt payments, 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:
At TEPPCO’s 2003 per unit distribution level, the general partner received approximately 27% of the cash distributed by TEPPCO to its partners, which consisted of 25% from the incentive cash distribution and 2% from the general partner interest. During 2003, total cash distributions to the general partner of TEPPCO were $55 million. At TEPPCO’s current per unit distribution level, we expect to receive total cash distributions of approximately $65 million in 2004.
Natural Gas Suppliers
We purchase substantially all of our raw natural gas from producers under varying term contracts. We take ownership of raw natural gas primarily 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 ConocoPhillips, our largest single supplier. No single producer accounted for more than 10% of our natural gas throughput in 2003. Each producer often dedicates to us the raw natural gas produced from designated oil and natural gas leases for a specific term. The term for dedicated gas can range from 30 days to life of lease. We consider our relationships 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:
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major integrated oil companies;
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major interstate and intrastate pipelines or their affiliates;
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independent oil and gas producers;
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other large raw natural gas gatherers that gather, process and market natural gas and/or NGLs; and
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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 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:
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the reputation, efficiency and reliability of the gatherer/processor, including the operating pressure of the gathering system;
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the availability of gathering and transportation;
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the pricing arrangement offered by the gatherer/processor; and
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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, refineries 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
Natural Gas Transportation. We own ten natural gas intrastate pipelines that are subject to state and federal regulation. Seven of these pipelines provide service on behalf of interstate pipelines. Such service is governed by Section 311 of the Natural Gas Policy Act of 1978 and causes such pipelines to be subject to FERC regulation. FERC approves the maximum transportation rate that can be charged and approves other terms and conditions of service when these 7 intrastate pipelines receive gas from or deliver gas to interstate pipelines.
We are the managing partner of a FERC-regulated-pipeline, Dauphin Island Gathering Partners (“DIGP”), and have a non-operating interest in another FERC-regulated pipeline, Discovery Gas Transmission, LLC (“Discovery”). The rates, terms and conditions of service and pipeline modification on these pipelines are subject to regulation by the FERC under the Natural Gas Act of 1938 (“NGA”). The NGA requires, among other things, that pipeline rates be just and reasonable and non-discriminatory.
On November 25, 2003, the FERC issued new Standards of Conduct for interstate natural gas pipelines and their energy affiliates (“Standards of Conduct”). Under the Standards of Conduct, interstate pipeline entities cannot share pipeline operating information,
including daily operating information, future expansion plans and shipper information, with their Energy Affiliates (as defined in the Standards of Conduct). The new Standards of Conduct will apply to us as a result of our ownership interest in DIGP and Discovery because we are considered an “Energy Affiliate” under Order 2004. Energy Affiliate has been broadly defined in the proposed rule to include any affiliate that “buy[s], sell[s] trades or administer[s] natural gas ... in U.S. energy or transmission markets.” Interstate pipelines are required to be in compliance with the rule by June 1, 2004. We do not anticipate any compliance issues with the implementation of the Standards of Conduct.
Natural Gas Gathering and Processing. The NGA exempts natural gas gathering facilities from FERC jurisdiction. However, certain 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.
Transportation and Sales of Natural Gas Liquids. We own non-operating interests in two pipelines that transport natural gas liquids (“NGLs”) in interstate commerce. The rates, terms and conditions of service on these pipelines are subject to FERC regulation under the Interstate Commerce Act. The Interstate Commerce Act requires, among other things, that NGL pipeline rates be just and reasonable and non-discriminatory. At this time, FERC allows NGL pipeline rates to be established on a number of bases, including historic cost, historic cost plus an index and market factors. While NGL sales prices are not currently regulated, the ability to sell NGLs and the pricing of such NGLs is often dependent on and affected by access to NGL pipelines and the rates, terms and conditions of such pipelines.
U.S. Department of Transportation. Some of our natural gas pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”) with respect to 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. The Pipeline Safety Improvement Act of 2002, which was enacted on December 17, 2002, establishes mandatory inspections for all U.S oil and natural gas transmission pipelines and some gathering lines in high-consequence areas within 10 years. The DOT has developed regulations implementing the Pipeline Safety Improvement Act that will require pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. At this time we are unable to estimate the expected cost of complying with these regulations.
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. In addition to the statutes referenced above, 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.
Canadian Regulation. Our Canadian assets in the province of Alberta are regulated by the Alberta Energy and Utilities Board. In British Columbia our assets are regulated by the BC Oil and Gas Commission. Our West Doe and Pesh Creek natural gas gathering pipeline, which crosses the Alberta/British Columbia border, falls under the jurisdiction of the National Energy Board of Canada and are classified as 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:
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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;
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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;
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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;
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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.
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 2, “Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements.
Employees
As of December 31, 2003, we had approximately 3,575 employees, which includes approximately 1,050 employees of our wholly-owned subsidiary Texas Eastern Products Pipeline Company, LLC, the general partner of TEPPCO. We are a party to one collective bargaining agreement in the U.S. which covers approximately 65 of our employees and one collective bargaining agreement in Canada which covers approximately 20 employees. We believe our relations with our employees are good.
ITEM 2.
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.
ITEM 3. Legal Proceedings.
See Note 15, “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, based on currently known information, these proceedings will not have a material adverse effect on our business, financial position or results of operations.
ITEM 4.
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 2003.
PART II.
ITEM 5.
ITEM 5. Market for Registrant’s Common Equity and Related Stockholder Matters.
Duke Energy beneficially owns 69.7% of our outstanding member interests and ConocoPhillips beneficially owns the remaining 30.3%. There is no market for our member interests. Our LLC Agreement restricts making any distributions except by approval of both members or in an amount sufficient to pay specified tax obligations of our members that arise from their ownership of member interests. In 2003, our board of directors approved a plan to consider the payment of a quarterly dividend to our members. Our board of directors may consider net income, cash flow or any other criteria deemed appropriate for determining the amount of the quarterly dividend to be paid.
In August 2000, we issued $300 million of preferred member’s interests to affiliates of Duke Energy and ConocoPhillips in proportion to their ownership interests. 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. On September 9, 2002, we redeemed $100 million, on September 19, 2003, we redeemed $125 million, and on December 31, 2003, we redeemed the remaining $75 million of our preferred members’ interest by paying cash to each of our members (Duke Energy and ConocoPhillips) in proportion to their ownership interests. At December 31, 2003, we have no preferred member’s interests outstanding to Duke Energy and ConocoPhillips.
Reference is made to Item 12 of this report regarding equity compensation plan information, which is incorporated herein by reference.
ITEM 6.
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, 2003, 2002, 2001 and 2000 and for the periods then ended have been derived from the consolidated financial statements of the Company. The selected historical combined financial data as of December 31, 1999 and for the period then ended has 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.
(a)
Includes the results of operations of ConocoPhillips’ gas gathering, processing, marketing and NGL business for the nine months ended December 31, 2000. To the extent that it existed at the time, ConocoPhillips’ gas gathering, processing, marketing and NGL business was acquired by the Predecessor Company on March 31, 2000.
(c)
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.
(d)
Based on NYMEX prices for the periods indicated.
N/A Not applicable due to change in corporate structure as of March 31, 2000.
ITEM 7.
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion details the material factors that affected our historical financial condition and results of operations in 2003, 2002 and 2001. 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.
Overview
We operate in the two principal business segments of the midstream natural gas industry:
•
Natural gas gathering, processing, transportation and storage, from which we generate revenues primarily by providing services such as compression, gathering, treating, processing, transportation of residue gas, storage and trading and marketing (the “Natural Gas Segment”). In 2003, approximately 82% 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 (the “NGLs Segment”). In 2003, approximately 18% of the Company’s operating revenues prior to intersegment revenue elimination and approximately 4% of the Company’s gross margin were derived from this segment.
•
Intersegment activity is primarily related to the sale of NGLs from the Natural Gas Segment to the NGLs Segment at market based transfer prices.
Our limited liability company agreement limits the scope of our business to the midstream natural gas industry in the United States and Canada, the marketing of NGLs in Mexico and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our board of directors. This limitation in scope is not currently expected to materially impact the results of our operations.
Effects of Commodity Prices
The Company is exposed to commodity prices as a result of being paid for certain services in the form of commodities rather than cash. For gathering services, the Company receives fees or commodities from the producers to bring the raw 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 types of contracts which are described below. 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. 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 $0.01 per gallon in the price of NGLs and $0.10 per million Btus in the average price of natural gas would result in changes in annual pre-tax net income of approximately $(18) million and $1 million, respectively. In addition, a decrease of $1 per barrel in the average price of crude oil would result in a change to annual pre-tax net income of approximately $(5) million.
During the year ended December 31, 2003, approximately 80% of our gross margin was generated by commodity sensitive arrangements and approximately 20% of our gross margin (excluding hedging and including earnings of unconsolidated affiliates) was generated by fee-based arrangements. The commodity exposure is managed by the Company as discussed below.
The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which in turn has been generally correlated to the price of crude oil. Although the prevailing price of natural gas has less short term significance to our operating results than the price of NGLs, in the long term, the growth of our business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production. In the past, the prices of NGLs, crude oil and natural gas have been extremely volatile.
We generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. However, the relationship or correlation between crude oil value and NGL prices declined significantly during 2001 and 2002. In late 2002 and throughout 2003, this relationship reverted back toward historical trends.
We believe that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. The price increases in crude oil, NGLs and natural gas experienced during 2000 and first half of 2001 spurred increased natural gas drilling activity. However, a decline in commodity prices in late 2001, continuing into 2002, negatively affected drilling activity. Drilling activity increased in 2003 due to higher commodity prices. The average number of active oil and gas rigs drilling in the United States increased to 1,126 at December 31, 2003 from 862 at December 31, 2002. Recent significant increases in natural gas prices could result in continued increased drilling activity in 2004. However, energy market uncertainty could negatively impact the United States drilling activity in the short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.
To better address the risks associated with volatile commodity prices, we employ a comprehensive commodity price risk management program. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, use various commodity instruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of our assets and operations from such price risks. See “Item 7A.
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, to a limited extent, foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Duke Energy Field Services’ Risk Management Committee is responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. The Risk Management Committee is composed of senior executives who receive regular briefings on the Company’s positions and exposures as well as periodic updates from and consultations with the Duke Energy Chief Risk Officer (CRO) and other expert resources at Duke Energy regarding market risk positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.
See Critical Accounting Policies beginning on page 27 - Risk Management Activities for further discussion of Risk and Accounting Policies.
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, futures and options. (See Notes 2 and 13 to the Consolidated Financial Statements.)
Commodity Derivatives - Mark-to-Market - The risk in the commodity mark-to-market 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 Value at Risk (“DVaR”) as described below. DVaR is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor the risk in the commodity mark-to-market portfolio (which includes all trading and non-trading derivatives 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.
DVaR computations are based on a historical simulation, which uses price movements over an 11 day period to simulate forward price curves in the energy markets to estimate the potential favorable or unfavorable impact of one day’s price movement on the existing portfolio. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for crude oil, NGLs, natural gas and other energy-related products. DVaR computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. The Company’s DVaR amounts for commodity mark-to-market derivatives instruments and related activities are shown in the following table:
Daily Value at Risk (millions)
DVaR is an estimate based on historical price volatility. Actual volatility can exceed predicted results. DVaR also assumes a normal distribution of price changes, thus if the actual distribution is not normal, the DVaR may understate or overstate actual results. DVaR 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 DVaR to measure risk where market data information is limited. In the current DVaR 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. Effective January 1, 2003, in connection with the implementation of EITF 02-03, the Company designates each commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or sale contract, while certain non-trading derivatives, which are related to our asset based marketing, are non-trading mark-to-market derivatives. For each of the Company’s derivatives, the accounting method and presentation of gains and losses or revenue and expense in the Consolidated Statements of Income are as follows:
Classification of Contract
Accounting Method
Presentation of Gains & Losses or Revenue & Expense
Trading Derivatives
Mark-to-marketa
Net basis in Trading and marketing net margin
Non-Trading Derivatives:
Cash Flow Hedge
Hedge methodb
Gross basis in the same income statement
category as the related hedged item
Fair Value Hedge
Hedge methodb
Gross basis in the same income statement
category as the related hedged item
Normal Purchase or
Normal Sale
Accrual methodc
Gross basis upon settlement in the
Non-Trading Mark-to-
Mark-to-marketa
corresponding income statement category
Market
based on commodity type
Net basis in Trading and marketing net margin
a Mark-to-market- An accounting method whereby the change in the fair value of the asset or liability is recognized in the Consolidated Statements of Income in Trading and marketing net margin during the current period.
b Hedge method- An accounting method whereby the effective portion of the change in the fair value of the asset or liability is recorded in the Consolidated Balance Sheets and there is no recognition in the Consolidated Statements of Income for the effective portion until the service is provided or the associated delivery period occurs.
c Accrual method- An accounting method whereby there is no recognition in the Consolidated Statements of Income for normal purchases and sales derivatives for changes in fair value of a contract until the service is provided or the associated delivery period occurs.
The following table illustrates the movements in the fair value of our mark-to-market instruments during 2003:
Changes in Fair Value of Mark-to-Market Contracts (millions)
The fair value of these contracts is expected to be realized in future periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events that could impact the amount and/or realization of these values.
When available, quoted market prices are used to record a contract’s fair value. However, market values for energy trading contracts may not be readily determinable because the duration of the contracts exceeds the liquid activity in a particular market. If no active trading market exists for a commodity or for a contract’s duration, holders of these contracts must calculate fair value using internally developed valuation techniques or models. Key components used in these valuation techniques include price curves, volatility, correlation, interest rates, and tenor. Of these components, volatility and correlation are the most subjective. Internally developed valuation techniques include the use of interpolation, extrapolation, and fundamental analysis in the calculation of a contract’s fair value. All risk components for new and existing transactions are valued using the same valuation technique and market data and discounted using a LIBOR based interest rate. Valuation adjustments for performance, market risk and administration costs are used to adjust the fair value of the contract to the gain or loss ultimately recognized in the Consolidated Statements of Operations.
The following table shows the fair value of our mark-to-market portfolio as of December 31, 2003:
The “Prices supported by quoted market prices and other external sources” category includes our New York Mercantile Exchange (“NYMEX”) swap positions in natural gas and crude oil. The NYMEX has currently quoted prices for the next 32 months. In addition, this category includes our forward positions and options in natural gas and natural gas basis swaps at points for which over-the-counter (“OTC”) broker quotes are available. On average, OTC quotes for natural gas forwards and swaps extend 22 and 32 months into the future, respectively. OTC quotes for natural gas options extend 12 months into the future, on average. We value these positions against internally developed forward market price curves that are validated and recalibrated against OTC broker quotes. This category also includes “strip” transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate.
The “Prices based on models and other valuation methods” category includes (i) the value of options not quoted by an exchange or OTC broker and (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. In certain instances structured transactions can be decomposed and modeled by us as simple forwards and options based on prices actively quoted. Although the valuation of the simple structures might not be different from the valuation of contracts in other categories, the effective model price for any given period is a combination of prices from two or more different instruments and therefore has been included in this category due to the complex nature of these transactions.
Hedging Strategies - We are exposed to market fluctuations in the prices of energy commodities related to natural gas gathering, processing and marketing activities. We closely monitor the risks associated with these commodity price changes on our future operations and, where appropriate, may 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 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 and capital expenditures. The primary goals of the hedging program include maintaining minimum cash flows to fund debt service, production replacement and maintenance capital projects, and retaining a high percentage of potential upside relating to price increases of NGLs.
Our primary use of commodity derivatives is to hedge the output and production of assets we physically own. Current contract terms are up to one year; however, our risk management guidelines allow for contract terms up to three years. Since these contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets, liabilities or firm commitments, to the extent that the hedge relationships are effective, their market value change impacts are not recognized in current earnings. The unrealized gains or losses on these contracts are deferred in Accumulated Other Comprehensive Income (Loss) (“AOCI”) for cash flow hedges or included in Other Current or Noncurrent Assets or Liabilities on the Consolidated Balance Sheets for fair value hedges of firm commitments. Amounts in AOCI are realized in earnings concurrently with the transaction being hedged. However, in instances where the hedging contract no longer qualifies for hedge accounting, amounts included in AOCI through the date of de-designation remain in AOCI until the underlying transaction actually occurs. The derivative contract (if continued as an open position) will be marked to market currently through earnings. Several factors influence the effectiveness of a hedge contract, including counterparty credit risk and using contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured each month.
The following table shows when gains and losses deferred on the Consolidated Balance Sheets for derivative instruments qualifying as effective hedges of firm commitments or anticipated future transactions will be recognized into earnings. However, as mentioned previously, the effective portion of the gains and losses for these contracts are not recognized in earnings until settlement at their future 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. The following table show the fair value of our hedging contracts, including both commodity hedges and interest rate hedges, as of December 31, 2003:
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 $0.01 per gallon in the price of NGLs and $0.10 per million Btus in the average price of natural gas would result in changes in annual pre-tax net income of approximately $(18) million and $1 million, respectively. In addition, a decrease of $1 per barrel in the average price of crude oil would result in a change to annual pre-tax net income of approximately $(5) million.
Credit Risk
Our principle customers in the Natural Gas Segment are large, natural gas marketing services and industrial end-users. In the NGLs segment, our principle customers range from large multi-national petrochemical and refining companies to small regional propane distributors. Substantially all of our natural gas and NGLs sales are made at index, market-based prices. Approximately 40% of our NGLs production is committed to ConocoPhillips and ChevronPhillips, under an existing 15-year contract which expires in 2015. This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. The corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure. Collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. Substantially all other agreements contain adequate assurance provisions, which would allow us, at our discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to us.
Despite the current credit environment in the energy sector, management believes that the credit risk management process described above is operating effectively. As of December 31, 2003, we had cash or letters of credit of $65 million to secure future performance by counterparties, and had deposited with counterparties $39 million of such collateral to secure our obligations to provide future services or to perform under financial contracts. Collateral amounts held or posted may be fixed or may vary depending on the value of the underlying contracts and could cover normal purchases and sales, trading and hedging contracts. In many cases, we and our counterparties’ publicly disclosed credit ratings impact the amounts of collateral requirements.
Interest Rate Risk
We enter into debt arrangements that are exposed to market risks related to changes in interest rates. We periodically utilize interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to total debt for our debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical averages. As of December 31, 2003, the fair value of our interest rate swaps was an asset of $15 million. (See Notes 2 and 13 to the Consolidated Financial Statements.)
As of December 31, 2003, we had no outstanding commercial paper. As a result of our debt and interest rate swaps, we are exposed to market risks related to changes in interest rates. In the future, we intend to manage our interest rate exposure using a mix of fixed and floating interest rate debt. An increase of 0.5% in interest rates would result in an increase in annual interest expense of approximately $2 million.
Foreign Currency Risk
Our primary foreign currency exchange rate exposure at December 31, 2003 was the Canadian dollar. Foreign currency risk associated with this exposure was not material.
Accounting Pronouncements
In May 2003, the FASB issued SFAS 150 which requires that certain financial instruments that could previously be accounted for as equity, be classified as liabilities in the Consolidated Balance Sheets and initially recorded at fair value. In addition to its requirements for the classification and measurement of financial instruments in its scope, SFAS 150 also requires disclosures about the nature and terms of the financial instruments and about alternative ways of settling the instruments. The provisions of SFAS 150 are effective for all financial instruments entered into or modified after May 31, 2003, and are otherwise effective at the beginning of the first interim period beginning after June 15, 2003. Upon adoption on July 1, 2003, we reclassified our preferred members’ interest, which are mandatorily redeemable securities, of $200 million from mezzanine equity to long term debt and prospectively classified accrued or paid distributions on the preferred members’ interest, which had previously been classified as dividends, as interest expense. Interest expense recorded in 2003 on the preferred members’ interest was $6 million. During 2003, we redeemed the remaining $200 million of the securities in cash.
In April 2003, the FASB issued SFAS No. 149 (“SFAS 149”), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133. SFAS 149 clarifies the discussion around initial net investment, clarifies when a derivative contains a financing component, and amends the definition of an underlying to conform to language used in FASB Interpretation No. 45 (“FIN 45”), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In addition, SFAS 149 also incorporates certain of the Derivative Implementation Group Implementation Issues. The provisions of SFAS 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The guidance is to be applied to hedging relationships on a prospective basis. The adoption of the new interpretation had no material effect on our consolidated results of operations, cash flows or financial position.
In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities” which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46 defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. In December 2003, the FASB issued FIN 46R, which supercedes and amends certain provisions of FIN 46. While FIN 46R retains many of the concepts and provisions of FIN 46, it also provides additional guidance related to the application of FIN 46,
provides for certain additional scope exceptions, and incorporates several FASB Staff Positions issued related to the application of FIN 46.
The provisions of FIN 46 are immediately applicable to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003 and the provisions of FIN 46R are required to be applied to such entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for us). For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 or FIN 46R is required to be applied to special-purpose entities by the end of the first reporting period ending after December 15, 2003 (December 31, 2003 for calendar-year entities) and is required to be applied to all other non-special purpose entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for calendar-year entities). FIN 46 and FIN 46R may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 and FIN 46R also require certain disclosures of an entity’s relationship with variable interest entities.
We have not identified any material variable interest entities created, or interests in variable entities obtained, after January 31, 2003 which require consolidation or disclosure under FIN 46 and continue to assess the existence of any interests in variable interest entities created on or prior to January 31, 2003. We currently anticipate one non-special purpose entity, previously accounted for under the equity method of accounting, will be consolidated by us in the first quarter of 2004 under the provisions of FIN 46R. This entity, which is a substantive entity, has total assets of approximately $92 million as of December 31, 2003 and total revenue of approximately $43 million for the year ended December 31, 2003. Our maximum exposure to loss as a result of our involvement with this entity is approximately $82 million as of December 31, 2003. We continue to assess FIN 46R but do not anticipate that it will have a material impact on our consolidated results of operations, cash flows or financial position.
In November 2002, the FASB issued FIN 45 which elaborates on the disclosures to be made by a guarantor about its obligations under certain guarantees issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. We adopted the initial recognition and measurement provisions of FIN 45 effective January 1, 2003. The adoption of the new interpretation had no material effect on our consolidated results of operations, cash flows or financial position.
In June 2002, the EITF reached a partial consensus on EITF 02-03. EITF 02-03 concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Operations. We had previously chosen to report certain energy trading contracts on a gross basis, as sales in operating revenues and the associated costs recorded as purchases in costs and expenses, in accordance with prevailing industry practice. The amounts in the comparative 2001 Consolidated Statements of Operations have been reclassified to conform to the 2003 and 2002 presentation of all amounts on a net basis. Revenues were adjusted downward by $931 million from the previously reported amount, with offsetting adjustments made to operating expenses resulting in no impact on net income.
In October 2002, the EITF, as part of their further deliberations on EITF 02-03, rescinded the consensus reached in Issue No. 98-10 (“EITF 98-10”), “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133, and trading inventories that previously had been recorded at fair values, must now be recorded at the lower of cost or market and are reported on an accrual basis resulting in the recognition of earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 should be accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair values have been adjusted to the lower of historical cost or market, resulting in a $5 million charge recorded in 2003 in Cumulative effect of accounting change in the Consolidated Statements of Operations. In connection with the consensus reached on Issue No. 02-03, the FASB staff observed that, effective July 1, 2002, an entity should not recognize unrealized gains or losses at the inception of a derivative instrument unless the fair value of that instrument is evidenced by quoted market prices or current market transactions.
In October 2002, the EITF also reached a consensus on EITF 02-03 that, effective for periods beginning after December 15, 2002, all gains and losses on all derivative instruments held for trading purposes should be shown on a net basis in Consolidated Statements of Operations. Gains and losses on non-derivative energy trading contracts should similarly be presented on a gross or net basis in connection with the guidance in Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Upon application of this presentation, comparative financial statements for prior periods are required to be reclassified to conform to the consensus other than for energy trading contracts that were shown on a net basis under EITF 98-10. Accordingly, for 2003, derivative instruments that are held for trading and marketing purposes and are accounted for under mark-to-market accounting are included in Trading and
marketing net margin in the Consolidated Statements of Operations. As noted above, for 2002 and 2001, Trading and marketing net margin also includes the net margin on non-derivative energy trading contracts (primarily gas storage inventories and the related physical purchases and sales). The gross revenue presentation requirements had no impact on gross margin or net income.
In July 2003, the EITF reached consensus in EITF Issue No. 03-11 (“EITF 03-11”), “Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes,” that determining whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis is a matter of judgment that depends on the relevant facts and circumstances. In analyzing the facts and circumstances, EITF Issue No. 99-19 and Opinion No. 29, “Accounting for Nonmonetary Transactions,” should be considered. EITF 03-11 is effective for transactions or arrangements entered into after September 30, 2003. The adoption of EITF 03-11 had no material effect on our consolidated results of operations, cash flows or financial position as we continue to net non-trading mark-to-market activity.
On June 25, 2003, the FASB cleared the guidance contained in DIG Issue C20, “Scope Exceptions: Interpretation of the Meaning of ‘Not Clearly and Closely Related’ in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.” DIG Issue C20, which applies only to the guidance in paragraph 10(b) of FASB 133 and not in reference to embedded derivatives, describes three circumstances in which the underlying in a price adjustment incorporated into a contract that otherwise satisfies the requirements for the normal purchases and normal sales exception would be considered to be “not clearly and closely related to the asset being sold or purchased.” The guidance in DIG Issue C20 was effective for us on October 1, 2003. The adoption of this Issue had no material impact on our consolidated results of operations, cash flows or financial position.
We adopted SFAS No. 142 (“SFAS 142”), “Goodwill and Other Intangible Assets,” on January 1, 2002 which requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts are subject to a fair-value-based annual impairment assessment. We did not recognize any impairments due to the implementation of SFAS 142. The standard also requires certain identifiable intangible assets to be recognized separately and amortized as appropriate. No adjustments to intangibles were identified by us at transition.
The following table shows what net income (loss) would have been if amortization related to goodwill that is no longer being amortized had been excluded from prior periods:
We adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002. The new rules supersedes but retains many of the fundamental recognition and measurement provisions of SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” The new rules significantly change the criteria for classifying an asset as held-for-sale. Adoption of the new standard had no material effect on our consolidated results of operations or financial position.
In June 2001, the FASB issued SFAS No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations,” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. We adopted the provisions of SFAS 143 as of January 1, 2003. In accordance with the transition provisions of SFAS 143, we recorded an $18 million charge in 2003 in Cumulative effect of accounting change in the Consolidated Statements of Operations.
In May 2003, the EITF reached consensus in EITF Issue No. 01-08 (“EITF 01-08”), “Determining Whether an Arrangement Contains a Lease,” to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its
inception. The guidance in the consensus is designed to mandate reporting revenue as rental or leasing income that otherwise would be reported as part of product sales or service revenue. EITF 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, “Accounting for Leases.” The consensus is to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations in fiscal periods beginning on July 1, 2003. The adoption of EITF 01-08 had no material effect on our consolidated results of operations, cash flows or financial position.
Subsequent Events
In August 2003, we entered into a purchase and sale agreement to sell gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million. The transaction was to be closed on September 30, 2003; however, the purchaser was unable to meet the conditions of closing. In October 2003, we entered into a new purchase and sale agreement for the sale of these assets to a party related to the original third party purchaser for a sales price of approximately $62 million. The transaction was to be closed in December 2003; however, the purchaser was again unable to meet the conditions of closing. In February 2004, we entered into a new purchase and sale agreement for the sale of these assets to a party related to the original third party purchaser for a sales price of approximately $62 million. The transaction closed in the first quarter of 2004 with no significant book gain or loss.
On March 10, 2004, we entered into an agreement to acquire gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips for approximately $75 million. Pending approvals from governmental authorities, the transaction is scheduled to close in the second quarter of 2004. The assets to be acquired include three natural gas processing plants with capacity of 112 MMcf/d, over 1,000 miles of gathering lines and associated compression, and a 75 mile intrastate natural gas pipeline.
ITEM 8.
ITEM 8. Financial Statements and Supplementary Data.
DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, 2003, 2002 and 2001
(millions)
See Notes to Consolidated Financial Statements.
DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Years Ended December 31, 2003, 2002 and 2001
(millions)
See Notes to Consolidated Financial Statements.
DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2003, 2002 and 2001
(millions)
See Notes to Consolidated Financial Statements.
DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED BALANCE SHEETS
As of December 31, 2003 and 2002
(millions)
See Notes to Consolidated Financial Statements.
DUKE ENERGY FIELD SERVICES, LLC
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
Years Ended December 31, 2003, 2002 and 2001
(millions)
See Notes to Consolidated Financial Statements.
DUKE ENERGY FIELD SERVICES, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2003, 2002 and 2001
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, trading and marketing and trading. Field Services LLC’s limited liability company agreement (“LLC Agreement”) limits the scope of the Company’s 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. Field Services LLC is 69.7% owned by Duke Energy Corporation (“Duke Energy”) and 30.3% owned by ConocoPhillips.
2. Summary of Significant Accounting Policies
Consolidation - The Consolidated Financial Statements include the accounts of the Company and all majority-owned subsidiaries, after eliminating intercompany transactions and balances. Investments in 20% to 50% owned affiliates, and investments in less than 20% owned affiliates where the Company had the ability to exercise significant influence, are accounted for using the equity method. Investments greater than 50% are consolidated unless the Company does not have the ability to exercise control, in which case, they are accounted for using the equity method (see Note10).
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.
Cash and Cash Equivalents - Cash and cash equivalents includes all cash balances and highly liquid investments with an original maturity of three months or less.
Inventories - Inventories consist primarily of 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 6). Prior to 2003, natural gas storage arbitrage volumes were marked to market. However, effective January 1, 2003, with the Financial Accounting Standard Board’s (“FASB”) Emerging Issues Task Force’s (“EITF”) rescission of Issue No. 98-10 (“EITF 98-10”), “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” all gas storage inventories are recorded at the lower of cost or market, (see “Cumulative Effect of Changes in Accounting Principles” and “New Accounting Standards” below).
Accounting for Hedges and Commodity Trading and Marketing Activities - All derivatives not qualifying for the normal purchases and sales exception under Statement of Financial Accounting Standards (“SFAS”) No. 133 (“SFAS 133”), “Accounting for Derivative Instruments and Hedging Activities,” as amended, are recorded in the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. Prior to the implementation of EITF Issue No. 02-03 (“EITF 02-03”), “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities,” on January 1, 2003, certain non-derivative energy trading contracts were also recorded on the Consolidated Balance Sheets at their fair value. See the Cumulative Effect of Changes in Accounting Principles section below for further discussion of the implementation of the provisions of EITF 02-03.
Effective January 1, 2003, in connection with the implementation of the remaining provisions of EITF 02-03, the Company designates each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or sale contract, while certain non-trading derivatives, which are related to
asset based activity, are non-trading mark-to-market derivatives. For each of the Company’s derivatives, the accounting method and presentation of gains and losses or revenue and expense in the Consolidated Statements of Income are as follows:
Classification of
Presentation of Gains & Losses or Revenue &
Contract
Accounting Method
Expense
Trading Derivatives
Mark-to-marketa
Net basis in Trading and marketing net margin
Non-Trading Derivatives:
Cash Flow Hedge
Hedge methodb
Gross basis in the same income statement
category as the related hedged item
Fair Value Hedge
Hedge methodb
Gross basis in the same income statement
category as the related hedged item
Normal Purchase or
Normal Sale
Accrual methodc
Gross basis upon settlement in the
corresponding income statement category
based on commodity type
Non-Trading Mark-to-
Market
Mark-to-marketa
Net basis in Trading and marketing net margin
a Mark-to-market- An accounting method whereby the change in the fair value of the asset or liability is recognized in the Consolidated Statements of Income in Trading and marketing net margin during the current period.
b Hedge method- An accounting method whereby the effective portion of the change in the fair value of the asset or liability is recorded in the Consolidated Balance Sheets and there is no recognition in the Consolidated Statements of Income for the effective portion until the service is provided or the associated delivery period occurs.
c Accrual method- An accounting method whereby there is no recognition in the Consolidated Statements of Income for normal purchases and sales derivatives for changes in fair value of a contract until the service is provided or the associated delivery period occurs.
For hedge contracts, the Company formally assesses, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in fair values or cash flows of hedged items. The Company excludes the time value of options when assessing hedge effectiveness.
When available, quoted market prices or prices obtained through external sources are used to verify a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and expected correlations with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
Commodity Trading and Marketing - A favorable or unfavorable price movement of any derivative contract held for trading and marketing purposes is reported as Trading and Marketing Net Margin in the Consolidated Statements of Operations. An offsetting amount is recorded in the Consolidated Balance Sheets as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. When a contract is settled, the realized gain or loss is reclassified to a receivable or payable account. Settlement has no revenue presentation effect on the Consolidated Statements of Operations.
See the “New Accounting Standards” section below for a discussion of the implications of EITF 02-03 on the accounting for trading activities subsequent to October 25, 2002.
Commodity Cash Flow Hedges - The fair value of a derivative designated and qualified as a cash flow hedge is recorded in the Consolidated Balance Sheets as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. The effective portion of the change in fair value of a derivative designated and qualified as a cash flow hedge is included in the Consolidated Balance Sheets as Accumulated Other Comprehensive Income (Loss) (“AOCI”) until earnings are affected by the hedged item. Settlement amounts of cash flow hedges are removed from AOCI and recorded in the Consolidated Statements of Operations in the same accounts as the item being hedged. The Company discontinues hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative continues to be carried on the Consolidated Balance Sheets at its fair value; however, subsequent changes in its fair value are recognized in current
period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until earnings are affected by the hedged item, unless it is no longer probable that the hedged transaction will occur, in which case, the gains and losses that were in AOCI will be immediately recognized in current period earnings. At December 31, 2003 and 2002, there were losses of $29 million and $58 million, respectively, in AOCI related to cash flow hedges. At December 31, 2001, there was a gain of $55 million in AOCI related to cash flow hedges.
Commodity Fair Value Hedges - Changes in the fair value of a derivative that is designated and qualifies as a fair value hedge are included in the Consolidated Statements of Operations as Sales of Natural Gas and Petroleum Products and Purchases of Natural Gas and Petroleum Products, as appropriate. Changes in the fair value of the physical portion of a fair value hedge (i.e., the hedged item) are recorded in the Consolidated Statements of Operations in the same accounts as the changes in the fair value of the derivative, with offsetting amounts recorded in the Consolidated Balance Sheets as Other Current Assets, Other Noncurrent Assets, Other Current Liabilities or Other Long Term Liabilities, as appropriate.
Interest Rate Fair Value Hedges - The Company periodically enters into interest rate swaps to convert a portion 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 swaps match those of the associated debt which permits the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps, no ineffectiveness will be recognized.
Intangible Assets - Intangible assets consist of goodwill and NGLs sales and purchases contracts. 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 Company implemented SFAS No. 142 (“SFAS 142”), “Goodwill and Other Intangible Assets” as of January 1, 2002. For information on the impact of SFAS 142 on goodwill and goodwill amortization see the “New Accounting Standards” section below. (See Notes 3 and 9 for information on significant goodwill additions.) Commodity sales and purchases contracts are amortized on a straight-line basis over the term of the contract, ranging from one to 15 years.
Property, Plant and Equipment - Property, plant and equipment are recorded at original cost. Depreciation is computed using the straight-line method over the estimated useful lives of the individual assets (see Note 7). The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Interest totaling $1 million for 2003, $5 million for 2002 and $1 million for 2001 has been capitalized on construction projects.
Impairment of Long-Lived Assets, Assets Held for Sale and Discontinued Operations - 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.
The Company primarily uses the criteria in SFAS No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” to determine when an asset is classified as held for sale. Upon classification as held for sale, the long-lived asset is measured at the lower of its carrying amount or fair value less cost to sell, depreciation is ceased and the asset is separately presented on the Consolidated Balance Sheets.
If an asset held for sale or sold has clearly distinguishable operations and cash flows, generally at the plant level, and the Company will not have significant continuing involvement in the operations after the disposal, then the related results of operations for the current and prior periods, including any related impairments, and gains or losses on sales are reflected as Gain (loss) from discontinued operations in the Consolidated Statements of Operations. If an asset held for sale does not have clearly distinguishable operations and cash flows, impairments and gains or losses on sales are recorded as Net loss (gain) on sale of assets in the Consolidated Statements of Operations. Impairments for all other long-lived assets, other than goodwill, are recorded as Asset impairments in the Consolidated Statements of Operations.
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 are provided. For gathering services, the Company receives fees from the producers to transport 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 energy
content of the gas back to the producer. The Company also receives fees for further fractionation of the NGLs produced, and for transportation and for storage of NGLs and residue gas.
The Company recognizes revenue for its NGL and residue gas derivative trading activities net in the Consolidated Statements of Operations as trading and marketing net margin. These activities include mark-to-market gains and losses on energy trading contracts and the financial or physical settlement of energy trading contracts.
Revenue for goods and services provided but not invoiced is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. Actual invoices for the current month are issued in the following month and differences from estimated amounts are recorded. There are no material differences from the actual amounts invoiced subsequent to year end relating to estimated revenues and purchases recorded at December 31, 2003, 2002 and 2001.
Significant Customers - Duke Energy, an affiliated company, was a significant customer in each of the past three years. Sales to Duke Energy, primarily residue gas, totaled approximately $799 million during 2003, $1,122 million during 2002 and $1,637 million during 2001. Effective February 28, 2003, the Company’s Master Natural Gas Sales and Purchase Agreement with Duke Energy Trading and Marketing, L.L.C. (“DETM”), a subsidiary of Duke Energy, terminated. DETM provided a thirty-day notice of termination on January 30, 2003. The Company will continue to conduct business with DETM on a transactional basis in the future at a reduced volume level.
ConocoPhillips, an affiliated company, was also a significant customer in each of the past three years. Sales to ConocoPhillips, including its affiliate, ChevronPhillips Chemical Company LLC (“CP Chem.”) totaled approximately $1,500 million during 2003, $934 million during 2002 and $1,188 million during 2001.
Unamortized Debt Premium, Discount and Expense - Premiums, discounts and expenses incurred with the issuance of long term debt are amortized over the terms of the debt using the effective interest method.
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 $21 million and $26 million at December 31, 2003 and 2002, respectively.
Gas Imbalance Accounting - Quantities of natural gas over-delivered or under-delivered related to imbalance agreements with producers or pipelines 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 monthly exchange rates during the year, which approximates the exchange rates at the time of each transaction during the year. Foreign currency translation adjustments are included in the Consolidated Statements of Comprehensive Income (Loss). At December 31, 2003, there was a translation gain of $53 million in AOCI. At December 31, 2002 and 2001, there were translation losses of $7 million in each period in AOCI.
Income Taxes -The Company is structured as a limited liability company which is a pass-through entity for U.S. income tax purposes. The Company owns corporations who file their own respective federal, foreign and state corporate income tax returns. The income tax expense related to these corporations is included in the income tax expense of the Company, along with other miscellaneous state, local and franchise taxes of the limited liability company and other subsidiaries. In addition, the Company has Canadian subsidiaries which are subject to Canadian taxes.
The Company follows the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities (see Note 11).
Under the terms of the LLC Agreement, the Company is required to make quarterly distributions to Duke Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement, as amended, provides for taxable income to be allocated in
accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market 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 ConocoPhillips. As of December 31, 2003 and 2002, no distributions were due the members.
Stock Based Compensation - Under Duke Energy’s 1998 Long Term Incentive Plan, stock options for Duke Energy’s common stock may be granted to the Company’s key employees. The Company accounts for stock based compensation using the intrinsic value recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and FASB Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” 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. Since the exercise price for all options granted under the plan was equal to the market value of the underlying common stock on the date of grant, no compensation cost is recognized in the accompanying Consolidated Statements of Operations. Restricted stock grants, phantom stock awards and stock-based performance awards are recorded over the required vesting period as compensation cost, based on the market value on the date of grant. 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. The following disclosures reflect the provisions of SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123.”
The following table shows what earnings available for members’ interest would have been if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to all stock-based compensation awards.
Pro Forma Stock-Based Compensation (millions)
Cumulative Effect of Changes in Accounting Principles - The Company adopted the provisions of EITF 02-03 that required new non-derivative energy trading contracts entered into after October 25, 2002 to be accounted for under the accrual accounting basis. Non-derivative energy trading contracts recorded in the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair values were adjusted to historical cost via a cumulative effect adjustment of $5 million as a reduction to 2003 earnings.
The Company adopted the provisions of SFAS No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations,” as of January 1, 2003 which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. In accordance with the transition provisions of SFAS 143, the Company recorded a cumulative-effect adjustment of $18 million as a reduction in 2003 earnings.
The Company adopted SFAS 133 on January 1, 2001. In accordance with the transition provisions of SFAS 133, the Company recorded an immaterial cumulative-effect adjustment as a reduction in 2001 earnings and a cumulative-effect adjustment increasing OCI and member’s equity by $6 million. For the years ended December 31, 2002 and 2001, the Company reclassified into earnings $1 million and $12 million of losses, respectively, from OCI for derivatives included in the transition adjustment related to hedge transactions that settled. All hedge transactions in the transition adjustment had been settled as of December 31, 2002. The amounts reclassified out of OCI were different from the amounts included in the transition adjustment due to market price changes since January 1, 2001.
New Accounting Standards - In May 2003, the FASB issued SFAS No. 150 (“SFAS 150”), “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS 150 requires that certain financial instruments that could previously be accounted for as equity, be classified as liabilities in the Consolidated Balance Sheets and initially recorded at fair value.
In addition to its requirements for the classification and measurement of financial instruments in its scope, SFAS 150 also requires disclosures about the nature and terms of the financial instruments and about alternative ways of settling the instruments. The provisions of SFAS 150 are effective for all financial instruments entered into or modified after May 31, 2003, and are otherwise effective at the beginning of the first interim period beginning after June 15, 2003. Upon adoption on July 1, 2003, the Company reclassified its preferred members’ interest, which are mandatorily redeemable securities, of $200 million from mezzanine equity to long term debt and prospectively classified accrued or paid distributions on the preferred members’ interest, which had previously been classified as dividends, as interest expense. Interest expense recorded in 2003 on the preferred members’ interest was $6 million. During 2003, the Company redeemed the remaining $200 million of the securities in cash.
In April 2003, the FASB issued SFAS No. 149 (“SFAS 149”), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133. SFAS 149 clarifies the discussion around initial net investment, clarifies when a derivative contains a financing component, and amends the definition of an underlying to conform to language used in FASB Interpretation No. 45 (“FIN 45”), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In addition, SFAS 149 also incorporates certain of the Derivative Implementation Group Implementation Issues. The provisions of SFAS 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The guidance is to be applied to hedging relationships on a prospective basis. The adoption of the new interpretation had no material effect on the Company’s consolidated results of operations, cash flows or financial position.
In January 2003, the FASB issued Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities” which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46 defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. In December 2003, the FASB issued FIN 46R, which supercedes and amends certain provisions of FIN 46. While FIN 46R retains many of the concepts and provisions of FIN 46, it also provides additional guidance related to the application of FIN 46, provides for certain additional scope exceptions, and incorporates several FASB Staff Positions issued related to the application of FIN 46.
The provisions of FIN 46 are immediately applicable to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003 and the provisions of FIN 46R are required to be applied to such entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for the Company). For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 or FIN 46R is required to be applied to special-purpose entities by the end of the first reporting period ending after December 15, 2003 (December 31, 2003 for calendar-year entities) and is required to be applied to all other non-special purpose entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for calendar-year entities). FIN 46 and FIN 46R may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 and FIN 46R also require certain disclosures of an entity’s relationship with variable interest entities.
The Company has not identified any material variable interest entities created, or interests in variable entities obtained, after January 31, 2003 which require consolidation or disclosure under FIN 46 and continues to assess the existence of any interests in variable interest entities created on or prior to January 31, 2003. The Company currently anticipates one non-special purpose entity, previously accounted for under the equity method of accounting, will be consolidated by the Company in the first quarter of 2004 under the provisions of FIN 46R. This entity, which is a substantive entity, has total assets of approximately $92 million as of December 31, 2003 and total revenue of approximately $43 million for the year ended December 31, 2003. The Company’s maximum exposure to loss as a result of its involvement with this entity is approximately $82 million as of December 31, 2003. The Company continues to assess FIN 46R but does not anticipate that it will have a material impact on the Company’s consolidated results of operations, cash flows or financial position.
In November 2002, the FASB issued FIN 45 which elaborates on the disclosures to be made by a guarantor about its obligations under certain guarantees issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The Company adopted the initial recognition and measurement provisions of FIN 45 effective January 1, 2003. The adoption of the new interpretation had no material effect on the Company’s consolidated results of operations, cash flows or financial position.
In June 2002, the EITF reached a partial consensus on EITF 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” EITF 02-03 concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be shown on a net basis in the Consolidated Statements of Operations. The Company had previously chosen to report certain energy trading contracts on a gross basis, as sales in operating revenues and the associated costs recorded as purchases in costs and expenses, in accordance with prevailing industry practice. The amounts for 2001 in the comparative Consolidated Statements of Operations have been reclassified to conform to the 2003 and 2002 presentation of all amounts on a net basis. Revenues for 2001 were adjusted downward by $931 million from the previously reported amount, with offsetting adjustments made to operating expenses resulting in no impact on net income.
In October 2002, the EITF, as part of their further deliberations on EITF 02-03, rescinded the consensus reached in EITF 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS 133, and trading inventories that previously had been recorded at fair values, must now be recorded at the lower of cost or market and are reported on an accrual basis resulting in the recognition of earnings or losses at the time of contract settlement or termination. New non-derivative energy trading contracts entered into after October 25, 2002 should be accounted for under the accrual accounting basis. Non-derivative energy trading contracts on the Consolidated Balance Sheet as of January 1, 2003 that existed at October 25, 2002 and inventories that were recorded at fair values have been adjusted to the lower of historical cost or market resulting in a $5 million charge recorded in 2003 in Cumulative effect of accounting change in the Consolidated Statements of Operations. In connection with the consensus reached on EITF 02-03, the FASB staff observed that, effective July 1, 2002, an entity should not recognize unrealized gains or losses at the inception of a derivative instrument unless the fair value of that instrument is evidenced by quoted market prices or current market transactions.
In October 2002, the EITF also reached a consensus on EITF 02-03 that, effective for periods beginning after December 15, 2002, all gains and losses on all derivative instruments held for trading purposes should be shown on a net basis in the Consolidated Statements of Operations. Gains and losses on non-derivative energy trading contracts should similarly be presented on a gross or net basis in connection with the guidance in Issue No. 99-19 (“EITF 99-19”), “Reporting Revenue Gross as a Principal versus Net as an Agent.” Upon application of this presentation, comparative financial statements for prior periods are required to be reclassified to conform to the consensus other than for energy trading contracts that were shown on a net basis under EITF 98-10. Accordingly, for 2003, derivative instruments that are held for trading and marketing purposes and are accounted for under mark-to-market accounting are included in Trading and Marketing Net Margin in the Consolidated Statements of Operations. As noted above, for 2002 and 2001, Trading and Marketing Net Margin also includes the net margin on non-derivative energy trading contracts (primarily gas storage inventories and the related physical purchases and sales). The gross revenue presentation requirements had no impact on operating income or net income.
In July 2003, the EITF reached consensus in EITF Issue No. 03-11 (“EITF 03-11”), “Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes,” that determining whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis is a matter of judgment that depends on the relevant facts and circumstances. In analyzing the facts and circumstances, EITF 99-19 and Opinion No. 29, “Accounting for Nonmonetary Transactions,” should be considered. EITF 03-11 is effective for transactions or arrangements entered into after September 30, 2003. The adoption of EITF 03-11 had no material effect on the Company’s consolidated results of operations, cash flows or financial position, as the Company continues to net non-trading mark-to-market activity.
On June 25, 2003, the FASB cleared the guidance contained in DIG Issue C20, “Scope Exceptions: Interpretation of the Meaning of ‘Not Clearly and Closely Related’ in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.” DIG Issue C20, which applies only to the guidance in paragraph 10(b) of FASB 133 and not in reference to embedded derivatives, describes three circumstances in which the underlying in a price adjustment incorporated into a contract that otherwise satisfies the requirements for the normal purchases and normal sales exception would be considered to be “not clearly and closely related to the asset being sold or purchased.” The guidance in DIG Issue C20 was effective for the Company on October 1, 2003. The adoption of this Issue had no material impact on the Company’s consolidated results of operations, cash flows or financial position.
The Company adopted SFAS 142 which requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts are subject to a fair-value-based annual impairment assessment. The Company did not recognize any impairments due to the implementation of SFAS 142. The standard also requires certain identifiable intangible assets to be recognized separately and amortized as appropriate. No adjustments to intangibles were identified at transition.
The following table shows what net income (loss) would have been if amortization related to goodwill that is no longer being amortized had been excluded from prior periods:
The Company adopted SFAS 144 on January 1, 2002 which supersedes but retains many of the fundamental recognition and measurement provisions of SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” The new rules significantly change the criteria for classifying an asset as held-for-sale. Adoption of the new standard had no material effect on the Company’s consolidated results of operations or financial position.
In June 2001, the FASB issued SFAS 143 which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. The Company adopted the provisions of SFAS 143 as of January 1, 2003. In accordance with the transition provisions of SFAS 143, the Company recorded an $18 million charge in 2003 in Cumulative effect of accounting change in the Consolidated Statements of Operations.
In May 2003, the EITF reached consensus in EITF Issue No. 01-08 (“EITF 01-08”), “Determining Whether an Arrangement Contains a Lease,” to clarify the requirements of identifying whether an arrangement should be accounted for as a lease at its inception. The guidance in the consensus is designed to mandate reporting revenue as rental or leasing income that otherwise would be reported as part of product sales or service revenue. EITF 01-08 requires both parties to an arrangement to determine whether a service contract or similar arrangement is or includes a lease within the scope of SFAS No. 13, “Accounting for Leases.” The consensus is to be applied prospectively to arrangements agreed to, modified, or acquired in business combinations in fiscal periods beginning on July 1, 2003. The adoption of EITF 01-08 had no material effect on the Company’s consolidated results of operations, cash flows or financial position.
Reclassifications - Certain prior period amounts have been reclassified in the Consolidated Financial Statements to conform to the current period presentation. Included in the reclassified amounts are increases in both Sales of natural gas and petroleum products and in Purchases of natural gas and petroleum products in the amount of approximately $805 million and $639 million for the years ended December 31, 2002 and 2001, respectively. This reclassification resulted from intersegment trading activities being eliminated twice from the Consolidated Statements of Operations in the years ended December 31, 2002 and 2001. In addition, Accounts receivable - Customers, net and Accounts payable - Trade were increased by $102 million at December 31, 2002 to properly present on a gross basis balances that were previously presented net in the Consolidated Balance Sheet. Management has concluded that these reclassifications are not material to the fair presentation of the Company’s financial statements.
3. Acquisitions and Dispositions
Disposition of Various Gathering, Transmission and Processing Assets - On June 30, 2003, the Company sold various gathering, transmission and processing assets to two separate buyers for a combined sales price of approximately $90 million. These assets were included in the Company’s Natural Gas Segment as disclosed in Note 18. These assets comprised a component of the Company for purposes of reporting discontinued operations. All prior period operations have been revised to reflect these assets as discontinued operations.
The following table sets forth selected financial information associated with these assets accounted for as discontinued operations.
Included in the 2002 loss from discontinued operations of $33 million are asset impairments of $32 million.
Disposition of Vehicles - In July 2003, the Company entered into an agreement to sell approximately 900 vehicles for approximately $14 million. This is a sale-leaseback transaction whereby the Company sold the vehicles but will lease them back over a one-year lease term. The lease expires in July 2004, with subsequent annual extensions exercisable at the Company’s option. The future minimum lease payments under the lease are approximately $3 million. The Company does not have an option to purchase the leased vehicles at the end of the minimum lease term. As the proceeds from the sale of the vehicles were equal to the net book value of the vehicles, no gain or loss was recognized.
Acquisition of Discovery Producer Services - On May 31, 2002, the Company acquired 33.3% of the outstanding membership interests in Discovery Producer Services, LLC (“DPS”). The base purchase price of $71 million was adjusted for working capital and certain capital expenditures. This adjusted purchase price was then reduced by approximately $85 million of DPS debt guaranteed by the Company, resulting in the Company receiving cash of approximately $15 million on the closing date of the transaction. This investment is accounted for under the equity method of accounting. The pro forma impact of the acquisition on the Company’s results of operations was not material.
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 million. This acquisition of additional interests has been accounted for under the purchase method of accounting. As a result, the Company has controlling interests in each of these entities, 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.
Acquisition of 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 million. The purchase price included assumed debt of approximately $49 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 an unaudited pro forma basis, revenues and net income for the year ended December 31, 2001 would have increased $8 million and $1 million, respectively, if the acquisition of CMSL had occurred on January 1, 2001. The following is a summary of the allocated purchase price (millions):
Acquisition of 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 million. The pro forma impact of the acquisition on the Company’s results of operations was not material. Goodwill of $28 million has been recorded as a result of allocating the purchase price to the individual assets and liabilities acquired.
4. Agreements and Transactions with Duke Energy
Services Agreements with Duke Energy - Under a services agreement dated March 14, 2000, Duke Energy and certain of its subsidiaries provide the Company with various staff and support services, including information technology products and services, payroll, employee benefits, insurance, cash management, treasury, media relations, printing, records management, legal functions and investor services. These services are priced on the basis of a monthly charge. 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, expired on December 31, 2003; however, the parties anticipate renewing the agreement.
Included in Other Current Assets at December 31, 2003 are prepaid insurance premiums of $5 million and included in Other Current Liabilities at December 31, 2002 are accrued insurance premiums of $2 million that were paid or payable to an insurance provider that is a subsidiary of Duke Energy. Included in Accounts receivable - Affiliates are insurance recovery receivables of $4 million at December 31, 2003 from an insurance provider that is a subsidiary of Duke Energy.
The Company also entered into an IT Consolidation and Operations Services Agreement, dated July 30, 2003, with a subsidiary of Duke Energy. Under this Agreement, Duke Energy agreed to assist the Company in transferring and consolidating its information technology operations into Duke Energy’s information technology operations and provide future ongoing information technology services to the Company. These services are priced on the basis of a monthly charge. This agreement expires on December 31, 2005, but automatically renews each year thereafter unless terminated by either party as provided for in the agreement.
Total expenditures resulting from these agreements were $27 million, $16 million and $7 million in 2003, 2002 and 2001, respectively. The total expenditures include expenditures for capital spending of $1 million and $2 million in 2003 and 2002, respectively.
License Agreement - 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. The Company anticipates continuing to purchase and sell these commodities and provide these services to Duke Energy in the ordinary course of business (see Note 2, “Significant Customers”). The Company’s total revenues from these activities were approximately $799 million, $1,122 million and $1,637 million for 2003, 2002 and 2001, respectively. The Company’s total purchases from these activities were approximately $137 million, $108 million and $262 million for 2003, 2002 and 2001, respectively.
5. Agreements and Transactions with ConocoPhillips
Long Term NGLs Purchases Contract with ConocoPhillips - Under the NGL Output Purchase and Sale Agreement (the “ConocoPhillips NGL Agreement”) between ConocoPhillips and the Company, a wholly-owned subsidiary of ConocoPhillips, has the right to purchase at index-based prices substantially all NGLs produced by various processing plants of the Company located in the Mid-Continent and Permian Basin regions, and the Austin Chalk area which include approximately 40% of the Company’s total NGLs production. The ConocoPhillips NGL Agreement also grants ConocoPhillips, and subsequently CP Chem, 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 January 1, 2015.
Transactions with ConocoPhillips - The Company sells a portion of its residue gas and other by-products to ConocoPhillips and CP Chem. In addition, the Company purchases raw natural gas from ConocoPhillips. The Company’s total revenues from these activities were approximately $1,500 million, $934 million and $1,188 million for 2003, 2002 and 2001, respectively (see Note 2, “Significant Customers”.) The Company’s total purchases from these activities were approximately $447 million, $280 million, and $327 million for 2003, 2002 and 2001, respectively.
6. Inventories
A summary of inventories by category follows:
7. Property, Plant and Equipment
A summary of property, plant and equipment by classification follows:
Asset Impairments - As part of the Company’s periodic asset performance evaluations, it was determined in December 2003 and 2002 that certain gas plants and gathering systems have recently generated cash flow losses and are expected to continue to generate minimal or negative cash flows in future years. Accordingly, at December 31, 2003 and 2002, the Company performed tests for recoverability on these assets in accordance with the requirements of SFAS 144 using probability weighted undiscounted future cash flow models. Based upon the results of these analyses, the Company determined that the carrying value of these assets was impaired and, accordingly, wrote them down to their fair value. Fair value was determined based on management’s best estimates of sales value and/or discounted future cash flow models. The charge associated with these impairments was $4 million and $8 million for 2003 and 2002, respectively, relating to the natural gas gathering, processing, transportation, marketing and storage segment. There were no asset impairments recorded in 2001.
The Company’s revenues and expenses are significantly dependent on commodity prices such as NGLs and natural gas. Past and current trends in the price changes of these commodities may not be indicative of future trends. In addition, revenues and expenses are impacted by throughput volumes. If negative market conditions persist over time or throughput volumes decline, estimated cash flows over the lives of assets may not exceed the carrying value of those individual assets, and asset impairments may occur in the future under existing accounting rules. Furthermore, a change in management’s intent about the use of individual assets (held for use vs. held for sale) could also impact an impairment analysis.
8. Asset Retirement Obligations
In June 2001, the FASB issued SFAS 143 which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs and applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. The Company’s asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements and contractual leases for land use.
SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the
associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.
The Company identified various assets as having an indeterminate life in accordance with SFAS 143, which do not trigger a requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. These assets may have obligations associated with them, but a liability for these asset retirement obligations will only be recorded if and when a future retirement obligation with a determinable life is identified.
SFAS 143 was effective for fiscal years beginning after June 15, 2002, and was adopted by the Company on January 1, 2003. At January 1, 2003, the implementation of SFAS 143 resulted in a net increase in total assets of $25 million, consisting of an increase in net property, plant and equipment. Long term liabilities increased by $43 million, which represents the establishment of an asset retirement obligation liability. A cumulative-effect of a change in accounting principle adjustment of $18 million was recorded on January 1, 2003, as a reduction in earnings. On an unaudited pro forma basis, net income (loss) would not have been materially different if SFAS 143 had been applied during each of the periods presented.
The following table shows the asset retirement obligation liability as though SFAS 143 had been in effect for the prior three years.
The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The following table rolls forward the asset retirement obligation from the balance at January 1, 2003 through December 31, 2003.
9. Goodwill and Other Intangibles
The changes in the carrying amount of goodwill for the years ended December 31, 2003 and December 31, 2002 are as follows:
There were no impairments of goodwill for the years ended December 31, 2003, 2002 and 2001.
The gross carrying amount and accumulated amortization for commodity sales and purchases contracts are as follows:
During the years ended December 31, 2003, 2002 and 2001, the Company recorded amortization expense associated with commodity sales and purchases contracts of $11 million, $10 million and $9 million, respectively. The average remaining amortization period for these contracts is 4.5 years. Estimated amortization for these contracts for the next five years is as follows:
10. Investments in Affiliates
The Company has investments in the following businesses (included in the Natural Gas Segment) accounted for using the equity method:
Discovery Producer Services, LLC - Discovery Producer Services, LLC (“Discovery”) owns and operates a 600 MMcf/d interstate pipeline, a condensate handling facility, a cryogenic gas processing plant, and other gathering assets in deepwater offshore Louisiana. The Company received approximately $15 million to purchase this interest in 2002. The negative purchase price was related to the underlying debt of Discovery of $85 million which was repaid during 2003 through a capital contribution made by the
members. The deficit between the carrying amount of the investment and the underlying equity of Discovery of $48 million at December 31, 2003 is associated with and is being depreciated over the life of the underlying long-lived assets of Discovery.
Mont Belvieu I - Mont Belvieu I operates a 200 MBbl/d fractionation facility in the Mont Belvieu, Texas Market Center. The excess of the carrying amount of the investment over the underlying equity of Mont Belvieu I of $6 million at December 31, 2003 is associated with and is being depreciated over the life of the underlying long-lived assets of Mont Belvieu I.
Sycamore Gas System General Partnership - Sycamore Gas System General Partnership (“Sycamore”) is a partnership formed for the purpose of constructing, owning and operating a gas gathering and compression system in Carter County, Oklahoma. The excess of the carrying amount of the investment over the underlying equity of Sycamore of $12 million at December 31, 2003 is associated with and is being depreciated over the life of the underlying long-lived assets of Sycamore.
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 NGL pipeline, extending from a point near Mobile Bay, Alabama to a point near Kenner, Louisiana.
Black Lake Pipeline - Black Lake Pipeline (“Black Lake”) 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. The deficit between the carrying amount of the investment and the underlying equity of Black Lake of $4 million at December 31, 2003 is associated with and is being depreciated over the life of the underlying long-lived assets of Black Lake.
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.
MidTexas Pipeline Company - MidTexas Pipeline Company (“MidTexas”) is a company formed for the purpose of constructing, owning and operating a gas utility. The deficit between the carrying amount of the investment and the underlying equity of MidTexas of $31 million at December 31, 2003 is associated with and is being depreciated over the life of the underlying long-lived assets of MidTexas.
TEPPCO Partners, L.P. - The Company owns a 2% general partner interest in TEPPCO Partners, L.P. (“TEPPCO”), a publicly traded master limited partnership. TEPPCO owns and operates assets for the transportation and storage of refined products, liquefied petroleum gases and petrochemicals; the gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals; and the gathering of natural gas, fractionation of NGLs and transportation of NGLs.
The general partner of TEPPCO manages and directs TEPPCO under the TEPPCO partnership agreement and the partnership agreements of its operating partnerships. Under these 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 and debt payments, 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 $0.275 per limited partner unit, the general partner of TEPPCO will receive incentive distributions equal to:
At TEPPCO’s 2003 per unit distribution level, the general partner received approximately 27% of the cash distributed by TEPPCO to its partners, which consisted of 25% from the incentive cash distribution and 2% from the general partner interest. During 2003, total cash distributions to the general partner of TEPPCO were $55 million.
As of December 31, 2003, the Company has a negative investment balance of $7 million in TEPPCO. This negative balance represents deferred income, but does not represent any liability or commitment by the Company to contribute cash to TEPPCO. The Company’s investment in TEPPCO consists of its capital contributions, increased by its cumulative share of net income and decreased by cash distributions received from TEPPCO. Cash distributions that TEPPCO pays during a period may exceed their net income for that same period. Cumulative cash distributions in excess of net income allocations and capital contributions resulted in a negative investment amount at December 31, 2003. Future cash distributions which exceed net income will result in an increase in the negative investment amount. According to the partnership agreement, in the event of TEPPCO’s dissolution, its assets and liabilities would be divided among the limited partners and general partner in the same proportion as available cash. After all allocations are made between the partners, if a deficit balance still remains for the general partner, the general partner would not be required to make whole any deficits in its equity account.
Under the terms of the partnership agreement, the general partner is required to maintain a 2% interest in the sum of the general partner and the limited partners’ capital accounts. Compliance with the requirement is calculated in accordance with the rules of Treasury Regulations Section 1.704-1(b), and the tax accounting definition of a capital account thereunder. As of December 31, 2003, the general partner’s capital account balance was in excess of this 2% minimum investment requirement, as calculated under the tax accounting rules.
Equity in earnings amounted to the following for the years ended December 31:
Distributions in excess of earnings were $23 million, $16 million and $11 million in 2003, 2002 and 2001, respectively.
The following summarizes combined financial information of unconsolidated affiliates for the years ended December 31:
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 unconsolidated affiliates (primarily TEPPCO). The Company anticipates continuing to purchase and sell these commodities and provide these services to unconsolidated affiliates in the ordinary course of business. The Company’s total revenues from these activities were approximately $166 million, $138 million and $172 million for 2003, 2002 and 2001, respectively. The Company’s total purchases from these activities were approximately $98 million, $82 million and $103 million for 2003, 2002 and 2001, respectively.
11. Income Taxes
The Company is a limited liability company which is a pass-through entity for U.S. income tax purposes. The Company owns corporations who file their own respective federal and state corporate income tax returns. The income tax expense related to these corporations is included in the income tax expense of the Company, along with other miscellaneous state, local and franchise taxes of the limited liability company and other subsidiaries. In addition, the Company has Canadian subsidiaries that are levied certain foreign taxes.
Income tax as presented in the Statements of Operations is summarized as follows:
The Company’s temporary differences primarily relate to depreciation on property, plant and equipment. Cash paid for income taxes was not material for the years ended December 31, 2003, 2002 and 2001.
12. Financing
Credit Facility with Financial Institutions - On March 28, 2003, the Company entered into a credit facility (the “Facility”). The Facility replaces a credit facility that matured on March 28, 2003. The Facility is used to support the Company’s commercial paper program and for working capital and other general corporate purposes. The Facility matures on March 26, 2004; however; any outstanding loans under the Facility at maturity may, at the Company’s option, be converted to a one-year term loan. The Facility is a $350 million revolving credit facility, of which $100 million can be used for letters of credit. The Facility requires the Company to maintain at all times a debt to total capitalization ratio of less than or equal to 53%; and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the Facility, for the four most recent quarters to interest expense for the same period) of at least 2.5 to 1 (adjusted EBITDA is defined by the Facility to be earnings before interest, taxes and depreciation and amortization and other adjustments); and contains various restrictions applicable to dividends and other payments to the Company’s members. The Facility bears interest at a rate equal to, at the Company’s option and based on our current debt rating, either (1) LIBOR plus 1.25% per year or (2) the higher of (a) the JP Morgan Chase Bank prime rate plus 0.25% per year and (b) the Federal Funds rate plus 0.75% per year. At December 31, 2003, there were no borrowings or letters of credit drawn against the Facility and the Company had no outstanding commercial paper. At December 31, 2002, the Company had $215 million in outstanding commercial paper, with maturities ranging from three to 30 days and annual interest rates ranging from 1.83% to 1.90%. The weighted average interest rate on the outstanding commercial paper was 1.89% as of December 31, 2002. The amount of the Company’s outstanding commercial paper never exceeded the available amount under the Facility. By March 26, 2004, the Company expects to refinance the Facility and replace it with an up to $250 million credit facility which will mature on March 25, 2005 and have similar terms as the Facility, with the exception that there will no longer be a restriction applicable to dividends and other payments to the Company’s members and the Company will be able to request letters of credit up to the full committed amount of the new credit facility.
On March 28, 2003, the Company also entered into a $100 million funded short-term loan with a bank (the “Short-Term Loan”). The Short-Term Loan was used for working capital and other general corporate purposes. The Short-Term Loan contained an original maturity of September 30, 2003, but was repaid by August 2003 with funds generated from asset sales and operations.
On November 3, 2003, the Company executed a $32 million irrevocable standby letter of credit expiring on May 15, 2004 to be used to secure transaction exposure with a counterparty.
In April 2002, the Company filed a shelf registration statement increasing its ability to issue securities to $500 million. The shelf registration statement provides for the issuance of senior notes, subordinated notes and trust preferred securities.
Preferred Financing - In August 2000, the Company issued $300 million of preferred member interests to affiliates of Duke Energy and ConocoPhillips in proportion to their ownership interests. The proceeds from this financing were used to repay a portion of the Company’s outstanding commercial paper. The outstanding preferred member interests are entitled to cumulative preferential distributions of 9.5% per annum payable, unless deferred, semiannually. For the years ending December 31, 2003, 2002 and 2001, the Company paid preferential distributions of $9 million (representing the first half of 2003), $25 million and $29 million, respectively. On September 9, 2002, the Company redeemed $100 million, on September 19, 2003, the Company redeemed $125 million, and on December 31, 2003, the Company redeemed the remaining $75 million of its preferred members’ interest by paying cash to each member (Duke Energy and ConocoPhillips) in proportion to their ownership interests.
Upon adoption of SFAS 150 on July 1, 2003, the Company reclassified its preferred members’ interest, which are mandatorily redeemable securities, of $200 million from mezzanine equity to long term debt. During 2003, subsequent to the reclassification, the Company redeemed the remaining $200 million. Beginning on July 1, 2003, accrued or paid distributions previously classified as dividends on the preferred members’ interest are prospectively classified as interest expense in the Consolidated Statements of Operations. Interest expense for 2003 on the preferred members’ interest was $6 million (representing the second half of 2003 preferential distributions).
Debt Securities - Long term debt at December 31, 2003 and 2002 was as follows (millions):
The debt securities mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. Interest is payable semiannually. The debt securities are unsecured and are redeemable at the option of the Company. Approximate future maturities of long term debt in the year indicated are as follows at December 31, 2003:
In October 2001, the Company entered into an interest rate swap to convert the fixed interest rate of $250 million of debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on a six-month LIBOR, which is re-priced semiannually through 2005. In August 2003, the Company entered into two additional interest rate swaps to convert the fixed interest rate of $100 million of debt securities issued on August 16, 2000 to floating rate debt. These interest rate fair value hedges also bear a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030.
13. Derivative Instruments, Hedging Activities and Credit Risk
Commodity price risk - The Company’s principal operations of gathering, processing, transportation and storage of natural gas, and the accompanying operations of fractionation, transportation, trading and marketing of NGLs create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. As an owner and operator of natural gas processing and other midstream assets, the Company has an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts entered into to purchase and process raw natural gas. Risk is also dependent on the types and mechanisms for sales of natural gas and NGLs and related products produced, processed, transported or stored.
Energy trading (market) risk - Certain of the Company’s subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments.
Corporate economic risks - The Company enters into debt arrangements that are exposed to market risks related to changes in interest rates. The Company periodically uses interest rate lock agreements and interest rate swaps to hedge interest rate risk associated with new debt issuances. The Company’s primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to total debt for the Company’s debt rating; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates.
Counterparty risks - The Company sells various commodities (i.e., natural gas, NGLs and crude oil) to a variety of customers. The natural gas customers include local utilities, industrial consumers, independent power producers and merchant energy trading organizations. The NGLs customers range from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of the Company’s NGLs sales are made at market-based prices, including approximately 40% of NGLs production that is committed to ConocoPhillips and CP Chem, under a contract with a primary term that expires on January 1, 2015. This concentration of credit risk may affect the Company’s overall credit risk in that these customers may be similarly affected by changes in economic, regulatory or other factors. On all transactions where the Company is exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. The corporate credit policy prescribes the use of master collateral agreements to mitigate credit exposure. The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with the corporate credit
policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions.
Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.
Commodity cash flow hedges - The Company uses cash flow hedges, as specifically defined by SFAS 133, to reduce the potential negative impact that commodity price changes could have on the Company’s earnings, and its ability to adequately plan for cash needed for debt service, dividends, capital expenditures and tax distributions. The Company’s primary corporate hedging goals include maintaining minimum cash flows to fund debt service, dividends, production replacement, maintenance capital projects and tax distributions; and retaining a high percentage of potential upside relating to price increases of NGLs.
The Company uses natural gas, crude oil and NGLs swaps and options to hedge the impact of market fluctuations in the price of NGLs, natural gas and other energy-related products. For the year ended December 31, 2003, the Company recognized a net loss of $115 million, of which, a $6 million gain represented the total ineffectiveness of all cash flow hedges and a $121 million loss represented the total derivative settlements. For the year ended December 31, 2002, the Company recognized a net loss of $27 million, of which, a $10 million loss represented the total ineffectiveness of all cash flow hedges and a $16 million loss represented the total derivative settlements. The time value of options was excluded in the assessment of hedge effectiveness and totaled a $1 million loss in 2002 which is included in Sales of natural gas and petroleum products in the Consolidated Statements of Operations. No derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.
Gains and losses on derivative contracts that are reclassified from AOCI to current period earnings are included in the line item in which the hedged item is recorded. As of December 31, 2003, the entire $29 million of deferred net losses on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedge transactions occur; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings. The maximum term over which the Company is hedging its exposure to the variability of future cash flows is one year.
Commodity fair value hedges - The Company uses fair value hedges to hedge exposure to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to price risk. The Company may hedge producer price locks (fixed price gas purchases) and market locks (fixed price gas sales) to reduce the Company’s exposure to fixed price risk via swapping out the fixed price risk for a floating price position (New York Mercantile Exchange or index based).
For the years ended December 31, 2003, 2002 and 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.
Interest rate fair value hedges - In October 2001, the Company entered into an interest rate swap to convert the fixed interest rate of $250 million of debt securities that were issued in August 2000 to floating rate debt. The interest rate fair value hedge is at a floating rate based on a six-month LIBOR, which is re-priced semiannually through 2005. In August 2003, the Company entered into two additional interest rate swaps to convert the fixed interest rate of $100 million of debt securities issued on August 16, 2000 to floating rate debt. These interest rate fair value hedges are also at a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet conditions which permit the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps no ineffectiveness will be recognized. As of December 31, 2003 and 2002, the fair value of the interest rate swaps were a $15 million asset and a $14 million asset, respectively. These amounts are included in the Consolidated Balance Sheets as Unrealized Gains or Losses on Trading and Hedging Transactions with an offset to the underlying debt included in Long Term Debt.
Commodity Derivatives - Mark-to-Market - The trading and marketing of energy related products and services exposes the Company to the fluctuations in the market values of traded instruments. The Company manages its trading and marketing 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 daily earnings at risk measurement.
14. 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.
The fair value of 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.
The estimated fair value of the natural gas, NGLs and crude oil hedge contracts is determined by multiplying the difference between the quoted termination prices for natural gas, NGLs and crude 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.
15. Commitments and Contingent Liabilities
Litigation - The midstream 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, based on currently known information, these proceedings will not have a material adverse effect on the consolidated results of operations or financial position of the Company.
General Insurance - The Company carries insurance coverage that management believes is consistent with companies engaged in similar commercial operations with similar type properties. The Company’s insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, excluding electric transmission and distribution lines, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.
The Company also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of the Company’s general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.
Severance Program - On October 30, 2003, the Company communicated a company-wide voluntary and involuntary severance program to its employees to reduce approximately 6% of the Company’s workforce. The plan was completed on December 8, 2003 and includes the reduction of 160 employees over the period of December 2003 to June 2004. The Company has expensed $6 million
related to this severance program in the fourth quarter of 2003 in the General and administrative expense. An additional $1 million of expense will be recognized in the first and second quarters of 2004, which is the remaining future service period. The severance liability that was recorded in the fourth quarter of 2003 is $6 million at December 31, 2003, as the majority of the severance payouts will occur in the first and second quarters of 2004. The severance liability is recorded in Other current liabilities.
Other Commitments and Contingencies - The Company utilizes assets under operating leases in several areas of operation. Combined rental expense, including leases with no continuing commitment, amounted to $20 million, $20 million and $24 million in 2003, 2002 and 2001, respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term. Minimum rental payments under the Company’s various operating leases in the year indicated are as follows at December 31, 2003:
16. 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 immediate to five years with a maximum option term of 10 years.
The following tables show information regarding options to purchase Duke Energy’s common stock granted to employees of the Company.
Stock Option Activity
Stock Options at December 31, 2003
On December 31, 2002, there were 1.6 million exercisable options with a $31 weighted-average exercise price. On December 31, 2001, there were 0.8 million exercisable options with a $29 weighted-average exercise price.
The weighted-average fair value per option granted was $4 for 2003, $10 for 2002 and 2001. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model.
Weighted-Average Assumptions for Option-Pricing
Duke Energy granted stock-based performance awards of Duke Energy common stock to key employees of the Company under the 1998 Long Term Incentive Plan. Stock-based performance awards under the 1998 plan vest over periods ranging from three to seven years. Vesting can occur in year three, at the earliest if performance is met. Compensation expense for stock-based performance awards is charged to the Company’s earnings over the vesting period and amounted to less than $1 million in 2003, 2002, and 2001.
Duke Energy granted phantom shares of Duke Energy common stock to employees of the 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 million at grant dates) in 2001. Compensation expense for phantom awards is charged to the Company’s earnings over the vesting period and amounted to less than $1 million in 2003, approximately $1 million in 2002 and less than $1 million in 2001.
Duke Energy granted restricted shares of Duke Energy common stock to employees of the Company under the 1998 Plan. Restricted stock awards under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 3,000 shares (fair value was not significant) in 2003. Duke Energy did not award any restricted awards in 2002 or 2001. Compensation expense for restricted awards is charged to the Company’s earnings over the vesting period and amounted to less than $1 million in 2003.
In addition, Duke Energy granted restricted shares of Duke Energy common stock to key employees of the 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 2003, 2002 or 2001. Compensation expense for restricted awards is charged to the Company’s earnings over the vesting period, and amounted to less than $1 million in 2003, 2002, and 2001.
17. Pension and Other Benefits
All Company employees who are 18 years old and work at least 20 hours per week are eligible for participation in the Company’s 401(k) and retirement plan in which the Company contributes 4% of each eligible employee’s qualified earnings. Additionally, the Company matches employees’ contributions in the plan up to 6% of qualified earnings. During 2003, 2002 and 2001, the Company expensed plan contributions of $14 million each year.
The Company offers certain eligible executives the opportunity to participate in the Duke Energy Field Services’, LP Non-Qualified Executive Deferred Compensation Plan. This plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that the Company can contribute to the 401(k) plan on the participant’s behalf. All amounts contributed to or earned by the plan’s investments are held in a trust account for the benefit of the participants. The trust and the liability to the participants are part of the general assets and liabilities, respectively, of the Company. Additionally, certain executives of the Company participate in restricted stock and other compensatory plans. Total expense for the Company for all executive compensatory plans was $1 million, $2 million and $2 million in 2003, 2002 and 2001, respectively.
18. Business Segments
The Company operates in two principal business segments:
(1) natural gas gathering, processing, transportation and storage, from which the Company generates revenues primarily by providing services such as compression, gathering, treating, processing, transportation of residue gas, storage and trading and marketing (the “Natural Gas Segment”), and
(2) NGLs fractionation, transportation, marketing and trading, from which the Company generates revenues from transportation fees, market center fractionation and the marketing and trading of NGLs (the “NGLs Segment”).
Intersegment activity is primarily related to the sale of NGLs from the Natural Gas Segment to the NGLs Segment at market based transfer prices.
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 is a performance measure utilized by management to monitor the business of each segment. The accounting policies for the segments are the same as those described in Note 2. Foreign operations are not material and are therefore not separately identified.
The following table sets forth the Company’s segment information.
(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)
Gross margin consists of total operating revenues less purchases of natural gas and petroleum products. Gross margin is viewed as a non-Generally Accepted Accounting Principles (“GAAP”) measure under the rules of the Securities and Exchange Commission (“SEC”), but is included as a
supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.
(c)
Includes items such as unallocated working capital, intercompany accounts and intangible and other assets.
19. Guarantor’s Obligations Under Guarantees
At December 31, 2003, the Company was the guarantor of $3 million of debt associated with unconsolidated subsidiaries. The guaranteed debt was repaid in full in January of 2004. Assets of the unconsolidated subsidiaries were pledged as collateral for the debt. At December 31, 2003, the Company had no liability recorded for the guarantees of the debt associated with the unconsolidated subsidiaries.
The Company periodically enters into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities related to the assets being acquired or divested. Typically, claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The effective periods on these indemnification provisions generally have terms of one to five years, although some are longer. The Company’s maximum potential exposure under these indemnification agreements can range depending on the nature of the claim and the particular transaction. The Company is unable to estimate the total maximum potential amount of future payments under indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities. At December 31, 2003, the Company had a liability of $1 million recorded for these outstanding indemnification provisions.
Management believes that it is not probable that the Company would be required to perform or incur any significant losses associated with the guarantees and indemnities discussed above and has, therefore, not recorded any liabilities for contingent losses at December 31, 2003.
20. Accounting Adjustments
During 2003, the Company recorded an $11 million charge to properly account for its vacation accrual in accordance with SFAS No. 43, “Accounting for Compensated Absences”. The Company recorded this adjustment, which related primarily to prior periods, entirely in 2003. Management has determined that this charge, related to an error correction, is immaterial on both a quantitative and qualitative basis to the trends in the financial statements for the periods presented, the prior periods affected and to a fair presentation of the Company’s financial statements.
The Company completed a comprehensive account reconciliation project to review and analyze its balance sheet accounts in 2002. This account reconciliation project identified the following five categories where account adjustments were necessary: operating expense accruals; gas inventory adjustments; gas imbalances; joint venture and investment account reconciliation; and other balance sheet accounts. As a result of this account reconciliation project, the Company recorded numerous adjustments in 2002. Adjustments totaling approximately $53 million may be related to corrections of accounting errors in prior periods. However, management has determined that the charges related to error corrections are immaterial both individually and in the aggregate on both a quantitative and qualitative basis to the trends in the financial statements for the periods presented, the prior periods affected and to a fair presentation of the Company’s financial statements. In addition, numerous items identified in the account reconciliation project resulted from system conversions and otherwise unsupportable balance sheet amounts. Due to the nature of certain of these account reconciliation adjustments, it would be impractical to determine what periods such adjustments relate to. Accordingly, the corrections have been made for the year ended December 31, 2002.
21. Subsequent Events
In August 2003, the Company entered into a purchase and sale agreement to sell gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million. The transaction was to be closed on September 30, 2003; however, the purchaser was unable to meet the conditions of closing. In October 2003, the Company entered into a new purchase and sale agreement for the sale of these assets to a party related to the original third party purchaser for a sales price of approximately $62 million. The transaction was to be closed in December 2003; however, the purchaser was again unable to meet the conditions of closing. In February 2004, the Company entered into a new purchase and sale agreement for the sale of these assets to a
party related to the original third party purchaser for a sales price of approximately $62 million. The transaction closed in the first quarter of 2004 with no significant book gain or loss.
On March 10, 2004, the Company entered into an agreement to acquire gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips for approximately $75 million. Pending approvals from governmental authorities, the transaction is scheduled to close in the second quarter of 2004.
22. Quarterly Financial Data (Unaudited)
Certain quarterly amounts have been reclassified to conform to the current presentation as disclosed in Note 2.
DUKE ENERGY FIELD SERVICES, LLC
Schedule II - Consolidated Valuation and Qualifying Accounts and Reserves (millions)
(a)
Principally consists of other contingency reserves which are included in “Other Current Liabilities” or “Other Long Term Liabilities.”
(b)
Principally consists of environmental, litigation and other contingency reserves reclassified to other non-reserves accounts or assumed in business acquisitions.
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, 2003 and 2002, and the related consolidated statements of operations, comprehensive income (loss), members’ equity, and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the 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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated 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 2003, the Company changed its method of accounting for asset retirement obligations to conform to Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations and changed its method of accounting for energy trading contracts that do not meet the definition of a derivative under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and trading inventories that previously had been recorded at fair value to conform to Emerging Issues Task Force Issue 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. In 2002, the Company changed it method of accounting for goodwill to conform to SFAS No. 142, Goodwill and Other Intangible Assets. In 2001, the Company changed its method of accounting for derivative instruments and hedging activities to conform to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.
DELOITTE & TOUCHE LLP
Denver, Colorado
March 15, 2004
ITEM 9.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
ITEM 9A.
ITEM 9A. Controls and Procedures
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) (Disclosure Controls Evaluation) and concluded that, as of the end of the period covered by this report, the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this annual report has been made known to them in a timely fashion. Our disclosure controls and procedures are designed to provide reasonable assurance that the required information was effectively recorded, processed, summarized and reported within the time period necessary to prepare this annual report. Our disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that all information required to be disclosed in our reports under the Exchange Act are accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
In performing its audit of our Consolidated Financial Statements for the year ended December 31, 2003, our independent auditors, Deloitte & Touche LLP ("Deloitte"), noted certain matters involving our internal controls that it considered to be a reportable condition under the standards established by the American Institute of Certified Public Accountants. A reportable condition involves matters relating to significant deficiencies in the design or operation of internal controls that, in Deloitte’s judgment, could adversely affect our ability to record, process, summarize and report financial data consistent with the assertions of management on the financial statements. The reportable condition noted by Deloitte related to the elimination of intercompany transactions in our consolidation process and the resulting effect on the Consolidated Financial Statements. The reportable condition was not considered by Deloitte to be a material weakness under the applicable auditing standards and had no material effect on our financial statements. Management has discussed the reportable condition with our Audit Committee and is implementing additional internal procedures and controls to address the identified deficiency and enhance the reliability of our internal control procedures.
PART III.
ITEM 10.
ITEM 10. Directors and Executive Officers of the Registrant.
Audit Committee of the Board of Directors
The Company is a majority-owned subsidiary of Duke Energy and we have no equity securities listed on a national securities exchange. Therefore, we are not required to have an Audit Committee. However, we voluntarily established an Audit Committee which is made up of one Director from each of the Company’s members. Both members of the audit committee, Richard J. Osborne and John E. Lowe, qualify as financial experts as defined in Item 401(h) of Regulation S-K. The Audit Committee provides independent oversight with respect to our financial reporting practices, internal controls, internal audit function, accounting policies and the independent auditors.
Code of Business Ethics
We have adopted a Code of Business Ethics which is applicable to all the employees of the Company including both the principal executive officer and principal financial officer. A copy of the Code of Business Ethics is available on our web site at www.defs.com under the "About DEFS" link.
Directors and Executive Officers
The following table provides information regarding our directors and executive officers:
Name
Age
Position
W. H. Easter III
Director and Chairman of the Board, President and Chief
Executive Officer
Mark A. Borer
Executive Vice President, Marketing and Corporate Development
Michael J. Bradley
Executive Vice President, Gathering and Processing
Robert F. Martinovich
Senior Vice President, Northern Division
Rose M. Robeson
Vice President and Chief Financial Officer
Brent L. Backes
Vice President, General Counsel and Secretary
Philip L. Frederickson
Director
Fred J. Fowler
Director
John E. Lowe
Director
Richard J. Osborne
Director
W. H. Easter III is Chairman of the Board, President and Chief Executive Officer of our company. Prior to joining our company on January 5, 2004, Mr. Easter served as Vice President of State Government Affairs for ConocoPhillips from 2002 through 2003. From 1998 to 2002, Mr. Easter served as General Manager of Gulf Coast businesses unit for Conoco Inc. and from 1992 to 1998 he served as Managing Director and CEO of Conoco Jet Nordic in Stockholm, Sweden. Mr. Easter has been in the energy industry since 1971.
Fred J. Fowler, a Director of our company, is President and Chief Operating Officer of Duke Energy and has held that position since November 2002. Mr. Fowler previously served as Group President - Energy Transmission of Duke Energy from 1997 to 2002. From 1996 to 1997, Mr. Fowler served as Group Vice President of Pan Energy. From 1994 until 1996, Mr. Fowler served as President of Texas Eastern Transmission Corporation. Mr. Fowler has been in the energy industry since 1968.
Richard J. Osborne, a Director of our company, is the Group Vice President, Public and Regulatory Policy of Duke Energy. Mr. Osborne served as the Executive Vice President and Chief Risk Officer of Duke Energy from 2000 to 2003. From 1997 to 2000, Mr. Osborne served as Executive Vice President and Chief Financial Officer of Duke Energy. From 1994 to 1997, Mr. Osborne served as Senior Vice President and Chief Financial Officer of Duke Power. Mr. Osborne is a member of our Audit Committee. Mr. Osborne has been in the energy industry since 1975.
Philip L. Frederickson, a Director of our company, is the Executive Vice President, Commercial for ConocoPhillips. Mr. Frederickson previously served as Senior Vice President of Corporate Strategy and Business Development of Conoco Inc. from 2001 to 2002. From 1998 to 2001, Mr. Frederickson served as Vice President, Business Development of Conoco Inc. From 1997 to 1998, he served as General Manager, Strategy and Portfolio Management, Upstream of Conoco Inc.
John E. Lowe, a Director of our company, is the Executive Vice President, Planning, Strategy and Corporate Affairs for ConocoPhillips. Mr. Lowe previously served as the Senior Vice President of Corporate Strategy and Development of Phillips Petroleum Company from 2001 to 2002 and as Senior Vice President of Planning and Strategic Transactions of Phillips Petroleum Company from 2000 to 2001. From 1999 to 2000, Mr. Lowe served as Vice President of Planning and Strategic Transactions of Phillips Petroleum Company. During 1999 before being appointed Vice President, Planning & Strategic Transactions, Mr. Lowe served as Manager, Strategic Growth Projects. From 1997 to 1999, Mr. Lowe served as Supply Chain Manager for Refining, Marketing and Transportation of Phillips Petroleum Company. From 1993 to 1997 he served as either Director or Manager of Finance for Phillips Petroleum Company. Mr. Lowe is a member of our Audit Committee. Mr. Lowe has been in the energy industry since 1981.
Rose M. Robeson was named Vice President and Chief Financial Officer of our company in January 2002. Ms. Robeson joined the Company in May 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.
Robert F. Martinovich was named Senior Vice President, Northern Division of our Company in July 2002. Mr. Martinovich joined the Company in April 2000 as Senior Vice President, Western Division. He was Senior Vice President of GPM Gas Corporation, a subsidiary of Phillips Petroleum Company, 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.
Michael J. Bradley was named Executive Vice President, Gathering and Processing of our company in April 2002. He was previously Senior Vice President, Northern Division since 1999. Mr. Bradley is also a director of the general partner of TEPPCO. Mr. Bradley has been in the energy industry since 1979.
Mark A. Borer was named Executive Vice President, Marketing and Corporate Development of our company in April 2002. Mr. Borer joined the Predecessor Company in April 1999 as Senior Vice President, Southern Division. 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.
Brent L. Backes was named Vice President, General Counsel and Secretary of our company in January 2002. Mr. Backes joined the Predecessor Company in April 1998 as Senior Attorney. He was previously an attorney at LeBoeuf, Lamb, Greene & MacRae, LLP with a focus on mergers and acquisitions. Mr. Backes has been in the energy industry since 1998 and prior to that represented energy companies in various capacities while in private practice.
Pursuant to our limited liability company agreement, we have five directors, two of which are appointed by ConocoPhillips 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.
ITEM 11.
ITEM 11. Executive Compensation.
The following table sets forth compensation information for the years ended December 31, 2001, December 31, 2002 and December 31, 2003 for the Chief Executive Officer and each of our next four most highly compensated executive officers of our company. These five individuals are referred to as the “Named Executive Officers.”
(1)
Mr. Mogg resigned as Chairman of the Board, President and Chief Executive Officer effective December 31, 2003.
(2)
Mr. Slaughter provided services to our company pursuant to a Consulting Agreement, which provided for the terms of his compensation as Executive Vice President. The Consulting Agreement ended on December 31, 2003 and Mr. Slaughter resigned as Executive Vice President of the Company effective that date. For a description of his agreement, see the disclosure below under the heading “Consulting Agreement.” For the year ended December 31, 2001, Mr. Slaughter received compensation that included allocations for base salary, bonus and supplemental payments to offset his ineligibility for company benefits. In addition, he received phantom restricted stock and phantom stock options from the Company. The agreement was amended on June 28, 2002. The amended agreement provided for allocations for base salary, bonus, supplemental payments to offset his ineligibility for company benefits and phantom stock options, but no other benefits. The agreement was further amended on April 16, 2003 to provide for the granting of phantom stock options and phantom performance shares for 2003, but otherwise remained the same.
(3)
The bonus paid to Mr. Slaughter for fiscal year 2001, and the first half of 2002, was an allocation of his billing rate under his Consulting Agreement. The Consulting Agreement was amended in June 2002, and under the amended agreement Mr. Slaughter’s bonus is based on Company and personal performance similar to other executive officers of the Company.
(4)
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.
(5)
Awards made in 2003 to Messrs. Mogg, Borer, Bradley and Martinovich are performance shares granted under the Duke Energy 1998 Long-Term Incentive Plan. The awards were made on February 25, 2003. Performance shares are represented by units denominated in shares of Duke Energy Common Stock. Each performance share represented the right to receive, upon vesting, one share of Duke Energy Common Stock. Between fifty percent (50%) to one hundred percent (100%) of the shares awarded were eligible for vesting based upon achievement of Duke Energy 2003 earnings per share (EPS) within a specified range. Based on 2003 EPS, all performance shares in each award were forfeited. Mr. Slaughter was also granted performance shares for 2003 under his Consulting Agreement that were identical to the performance shares of the other executive officers except they provided for receipt of phantom common stock. However, based on 2003 EPS, all of Mr. Slaughter’s performance shares were forfeited.
(6)
Messrs. Mogg, Borer, Bradley and Martinovich elected to receive a portion of the value of the 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. The awards for Messrs. Mogg, Borer, Bradley and Martinovich were made 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 at December 31, 2003 and their values on that date are as follows:
(7)
Represents options granted by Duke Energy to purchase shares of Duke Energy common stock, except for Mr. Slaughter, who received phantom stock options that track the performance of Duke Energy common stock.
(8)
Represents the following for 2003:
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 entered into a contract for consulting services with Mr. Slaughter that terminated on December 31, 2003. The agreement was amended on June 28, 2002 and again on April 16, 2003. The amended agreement provides for a billing rate of $1,272 per day for 2002 and a billing rate of $1,335 per day for 2003 until the agreement terminates. In addition, the amended agreement provides that Mr. Slaughter is eligible for a bonus award with a target of 55% of his base annual compensation. In addition, under the terms of the amended agreement, Mr. Slaughter was awarded a long term incentive award for 2002 that tracks the performance of Duke Energy common stock. The award, valued at $387,500 at the time of grant, vested on December 31, 2003 and is exercisable for three years following vesting. The agreement also provided that Mr. Slaughter be awarded a long term incentive award for 2003 split evenly between phantom stock options and phantom performance shares. This award, valued at $406,875 at the time of grant, vested on December 31, 2003 and the phantom stock options are exercisable for three years following vesting. The phantom performance shares were forfeited because Duke Energy did not meet certain performance targets for 2003. Mr. Slaughter is not eligible for any other benefits under the Company’s compensation plans.
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, 2003.
This table shows options granted of Duke Energy common stock to the Named Executive Officers during 2003, along with the present value of the options on the date they were granted, calculated as described in the footnote to the table.
Option/SAR Grants in Last Fiscal Year
(1)
Neither the Company nor Duke Energy has granted any SARs to the Named Executive Officers or any other persons except for Mr. Slaughter who received phantom stock options.
(2)
Reflects percentage that the grant represents of the total options granted to employees of Duke Energy and its subsidiaries during 2003.
(3)
Based on the Black-Scholes option valuation model except for Mr. Slaughter, which was based on his Consulting Agreement (See above under the heading “Consulting Agreement”). The following table lists key input variables used in valuing the options:
With respect to all option grants listed in the table, the volatility variable reflected historical monthly stock price trading data with respect to Duke Energy Common Stock from November 30, 1999 through November 30, 2002. An adjustment was made with respect to each valuation for a risk of forfeiture during any applicable vesting period. The actual value, if any, that a grantee may realize 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 model.
(4)
Mr. Slaughter was not an employee at the time of grant but provided services to the Company under a Consulting Agreement (See above under the heading “Consulting Agreement”).
OPTION EXERCISES AND YEAR-END VALUES
This table shows aggregate exercises of options for Duke Energy common stock during 2003 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, 2003, which was $20.45. The fair market value is the closing price 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
*
Neither the Company nor Duke Energy has granted any SARs to the Named Executive Officers or any other persons except for Mr. Slaughter who received phantom stock options.
ITEM 12.
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;
•
each director; and
•
all directors and executive officers as a group.
In August 2000, we issued $300 million of preferred member interests to affiliates of Duke Energy and ConocoPhillips. 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. On September 9, 2002, we redeemed $100 million, on September 19, 2003, we redeemed $125 million, and on December 31, 2003, we redeemed the remaining $75 million of our preferred members’ interest by paying cash to each of our members (Duke Energy and ConocoPhillips) in proportion to their ownership interests.
The Company does not have any equity compensation plans. However, employees of the Company receive stock options, restricted stock and performance shares of Duke Energy under the Duke Energy 1998 Long Term Incentive Plan.
ITEM 13.
ITEM 13. Certain Relationships and Related Transactions.
On March 31, 2000, we combined the then existing midstream natural gas businesses of Duke Energy and ConocoPhillips. In connection with the Combination, Duke Energy and ConocoPhillips transferred all of their respective interests in their subsidiaries that conducted their midstream natural gas business at that time to us. In connection with the Combination, Duke Energy and ConocoPhillips also transferred to us additional midstream natural gas assets acquired by Duke Energy or ConocoPhillips 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, ConocoPhillips 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 ConocoPhillips.
There are significant transactions and relationships between us, Duke Energy and ConocoPhillips. 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 ConocoPhillips 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 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 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, and legal functions. 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, 2003, however, we intend to renew this agreement. 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.
In addition, we entered into an IT Consolidation and Operations Services Agreement, dated as of July 30, 2003, with a subsidiary of Duke Energy. Under this Agreement, Duke Energy agreed to assist us in transferring and consolidating our information technology operations into Duke Energy’s information technology operations and provide future ongoing information technology services to us. These services are priced on the basis of a monthly charge. This agreement expires on December 31, 2005, but automatically renews each year thereafter unless terminated by either party as provided for in the agreement.
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 continue to engage in such activities with Duke Energy and its subsidiaries in the ordinary course of business. In 2003, 2002 and 2001, our total revenues from such activities, including amounts netted in trading and marketing net margin, with Duke Energy and its subsidiaries were approximately $799 million, $1,122 million, and $1,637 million, respectively.
Transactions with ConocoPhillips
Prior to the Combination, ConocoPhillips engaged in a number of transactions with GPM Gas Corporation, the subsidiary of ConocoPhillips 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 ConocoPhillips, and subsequently its affiliate CP Chem, for the sale of NGLs at index-based prices. This agreement expires January 1, 2015. We anticipate that we will continue to engage in such activities with ConocoPhillips and its subsidiaries and CP Chem in the ordinary course of business. For the years ended December 31, 2003, 2002 and 2001, our total revenues from such activities, including
amounts netted in trading and marketing net margin, with ConocoPhillips and its subsidiaries, and CP Chem were approximately $1,500 million, $934 million and $1,188 million, respectively.
ITEM 14.
ITEM 14. Principal Accounting Fees and Services
The following table presents fees for professional services rendered by Deloitte & Touche LLP (“Deloitte”), our principal accountant, for the audit of our financial statements for the years ended December 31, 2003 and 2002, and the fees billed for other services rendered by Deloitte during those periods:
(a)
Audit Fees are fees billed by Deloitte for professional services for the audit of the Company’s consolidated financial statements included in the Company’s Annual Report on Form 10-K and review of financial statements included in the Company’s Quarterly Reports on Form 10-Q, services that are normally provided by Deloitte in connection with statutory and regulatory filings or engagements or any other service performed by Deloitte to comply with generally accepted auditing standards and include comfort and consent letters in connection with Securities and Exchange Commission filings and financing transactions.
(b)
Audit-Related Fees are fees billed by Deloitte for assurance and related services that are reasonably related to the performance of an audit or review of the Company’s financial statements, including assistance with acquisitions and divestitures, internal control reviews, and employee benefit plan audits.
(e)
All Other Fees are fees billed by Deloitte for any services not included in the first three categories.
The Company is a majority-owned subsidiary of Duke Energy and we have no equity securities listed on a national securities exchange. Therefore, we are not required to have an Audit Committee. However, we voluntarily established an Audit Committee which is made up of one Director from each of the Company’s members. Both members of the audit committee, Richard J. Osborne and John E. Lowe, qualify as financial experts as defined in Item 401(h) of Regulation S-K. The charter of the Audit Committee provides that the Audit Committee is responsible for reviewing fees paid to the Company’s external auditors. At the beginning of each fiscal year all audit services to be provided by the independent auditors during that fiscal year are approved by the Audit Committee.
PART IV.
ITEM 15.
ITEM 15. 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
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
None.
(c) Exhibits - See Exhibit Index immediately following the signature page.
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.
March 15, 2004
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
/s/ W. H. Easter III
W. H. Easter III
Chairman of the Board, President and Chief
Executive Officer (Principal Executive
Officer)
/s/ROSE M ROBESON
Rose M. Robeson
Chief Financial Officer (Principal Financial
and Accounting Officer)
/s/ PHILIP L. FREDRICKSON
Philip L. Frederickson
Director
/s/ FRED J. FOWLER
Fred J. Fowler
Director
/s/ JOHN E. LOWE
John E. Lowe
Director
/s/ RICHARD J. OSBORNE
Richard J. Osborne
Director
Date: March 15, 2004
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 (**).