Item 1. Business
Overview
We are a leading provider of midstream natural gas and NGL services in the United States. We provide these services through our integrated platform of midstream assets. Our gathering and processing assets are located in the Permian Basin in west Texas and southeast New Mexico, the Louisiana Gulf Coast primarily accessing the offshore region of Louisiana, and, through the Partnership, the Fort Worth Basin in north Texas, the Permian Basin in west Texas and the onshore region of the Louisiana Gulf Coast. Our NGL logistics and marketing assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana, with terminals and transportation assets across the United States.
We were formed in 2004 by our management team, which consists of former members of senior management of several midstream and other diversified energy companies, and Warburg Pincus LLC (“Warburg Pincus”). We are a large-scale, integrated midstream energy company with the ability to offer a wide range of midstream services to a diverse group of natural gas and NGL producers and customers. At December 31, 2007, we had total assets of $3.8 billion. We own interests in or operate approximately 11,000 miles of natural gas pipelines and approximately 700 miles of NGL pipelines, with natural gas gathering systems covering
Index to Financial Statements
approximately 14,500 square miles and 22 natural gas processing plants with access to natural gas supplies in the Permian Basin, north Texas, onshore southern Louisiana and the Gulf of Mexico. Additionally, we have an integrated NGL logistics and marketing business, with 16 storage, marine and transport terminals with above ground NGL storage capacity of approximately 900 MBbl, net NGL fractionation capacity of approximately 300 MBbl/d and 43 owned and operated storage wells with a net storage capacity of approximately 67 MMBbl.
Natural Gas Gathering and Processing
Natural gas gathering and processing consists of gathering, compressing, dehydrating, treating, conditioning, processing, marketing and transporting natural gas and NGLs. The gathering of natural gas consists of aggregating natural gas produced from various wells through small diameter gathering lines for transportation to processing plants. Natural gas has a widely varying composition, depending on the field, the formation and the reservoir from which it is produced. The processing of natural gas consists of the extraction of imbedded NGLs and the removal of water vapor, solids and other contaminants to form (i) a stream of marketable natural gas, commonly referred to as residue gas, and (ii) a stream of raw NGL mix, commonly referred to as “Mixed NGLs” or “Y-Grade.” Once processed, the residue gas is transported to markets through pipelines that are either owned by the gatherers/processors or third parties. End-users of residue gas include large commercial and industrial customers, as well as natural gas and electric utilities serving individual consumers. We sell our residue gas either directly to such end-users or to marketers into intrastate or interstate pipelines, which are typically located in close proximity or ready access to our facilities.
NGL Logistics and Marketing
NGL logistics and marketing consists of the fractionation, storage, terminalling, transportation, distribution and marketing of NGLs. Through fractionation, raw NGL mix is separated into its component parts (ethane, propane, butanes and natural gasoline). These component parts are delivered to end-users through pipelines, barges, trucks and rail cars. End-users of component NGLs include petrochemical and refining companies and propane markets for heating, cooking or crop drying applications. Retail distributors often sell to end-use propane customers.
Business Strategies
Our primary objective is to create and increase value for our stakeholders across all of our business segments. Our business strategies focus on creating and increasing value for our stakeholders through efficient operations, prudent risk management and growth through acquisitions and organic projects. We implement this strategy by pursuing the following initiatives:
Enhance Cash Flows. We intend to continue to pursue new contracts, cost efficiencies and operating improvements of our assets. Such improvements in the past have included new production and acreage commitments, reducing gas fuel, flare and loss volumes and enhancing NGL recoveries. We will also continue to enhance existing plant assets to improve and maximize capacity and throughput.
Managing our contract mix to optimize profitability. The majority of our gas gathering and processing operating margin is generated pursuant to percent-of-proceeds contracts or similar arrangements which, if unhedged, benefit us in increasing commodity price environments and expose us to a reduction in profitability in decreasing commodity price environments. We believe that appropriately managed, our current contract mix allows us to optimize our profitability over time. Although we expect to maintain primarily percent-of-proceeds arrangements, we continually evaluate the market for attractive fee-based and other arrangements which will further reduce the variability of our cash flows as well as enhance our profitability and competitiveness.
Capitalizing on organic expansion opportunities. We continually evaluate economically attractive organic expansion opportunities in existing or new areas of operation that will allow us to expand our business.
Index to Financial Statements Pursuing strategic and accretive acquisitions. We plan to pursue strategic and accretive acquisition opportunities within the midstream energy industry. We will seek acquisitions in our existing areas of operation that provide the opportunity for operational efficiencies, the potential for higher capacity utilization and expansion of existing assets, as well as acquisitions in other related midstream businesses and/or expansion into new geographic areas of operation. Among the factors we will consider in deciding whether to acquire assets include, but are not limited to, the economic characteristics of the acquisition, the region in which the assets are located (both regions contiguous to our areas of operation and other regions with attractive characteristics) and the availability and sources of capital to finance the acquisition. We intend to finance our expansion through a combination of debt and equity, including commercial debt facilities and public and private offerings of debt and equity.
Provide Growth and Deleveraging Through Drop-down Strategy. In October 2006, we formed a master limited partnership, Targa Resources Partners LP. We contributed the assets of the North Texas System to the Partnership and the Partnership sold common units representing limited partnership interests to the public in February 2007. In October 2007, we sold the San Angelo System (“the SAOU System”) and the Louisiana System (“the LOU System”) to the Partnership and the Partnership sold additional common units to the public. We own 24.5% of the outstanding limited partner interests of the Partnership, a 2% general partner interest and incentive distribution rights. We intend to utilize the Partnership as a growth vehicle to enhance our cash flows. Our expected drop-downs to the Partnership should reduce our leverage over the next several years.
Competitive Strengths
Large Scale, Strategically Located and Diversified Operations
Our portfolio of integrated midstream assets is strategically positioned across multiple geographic regions and producing basins where we provide products and services spanning the midstream value chain to a broad base of customers. We believe the size and scope of our portfolio of assets place us in proximity to a large number of new and existing gas producing wells in our areas of operations, allowing us to generate economies of scale within our operating regions and allowing us to attract customers by providing access to our existing facilities and to multiple end-use markets and market hubs. We believe that we are well positioned to execute our primary business strategies.
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Significant scale of operations. We own interests in or operate approximately 11,000 miles of natural gas pipelines and approximately 700 miles of NGL pipelines, with natural gas gathering systems covering approximately 14,500 square miles and 22 natural gas processing plants with access to natural gas supplies in the Permian Basin, north Texas, onshore southern Louisiana and the Gulf of Mexico. Additionally, we have an integrated NGL logistics and marketing business, with 16 storage, marine and transport terminals with an NGL above ground storage capacity of approximately 900 MBbl, net NGL fractionation capacity of approximately 300 MBbl/d and 43 owned and operated storage wells with a net storage capacity of 67 MMBbl. Due to the high cost of obtaining permits for and constructing midstream assets and the difficulty of developing the expertise necessary to operate them, the barriers to enter the midstream natural gas sector on a scale competitive with ours are high.
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Multiple producing basins. Our major gathering and processing systems source natural gas volumes from four producing areas: the Permian Basin, the onshore south Louisiana basin, the Gulf of Mexico basin, and the Fort Worth Basin, which includes Barnett Shale production. In aggregate, these basins are a significant contributor to current domestic natural gas production, favorably positioning us to access large, diverse and important sources of domestic natural gas supply.
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Large and diverse customer base. We focus on providing high-quality services at competitive costs, which we believe has allowed us to attract and retain a large, diverse customer base. Our customer base includes a large portfolio of natural gas producers in our regions of operations as well as purchasers and consumers of NGLs. While we have commercial relationships with large, diversified energy companies, we also provide services to a number of other customers, which reduces our dependence on
Index to Financial Statements
any one customer. As of December 31, 2007, other than Chevron Corporation (“Chevron”) (including the Chevron Phillips Chemical Company LLC joint venture, “CPC”), no single customer accounted for more than 10% of our consolidated revenue. We expect to continue to strengthen and grow our customer relationships due to our broad service offerings, well-positioned assets, competitive cost of service, market access, and commitment to providing high-quality customer service.
We have an ongoing relationship with CPC for feedstock supply and services provided at Mont Belvieu, Texas and Galena Park, Texas. Agreements associated with this relationship are expected to be renegotiated over time to better meet the objectives of both companies, but are expected to continue on a similar basis due to the integrated nature of facilities and the difficulty and cost associated with replicating our assets.
For a detailed discussion of our gathering and processing agreements with Chevron, see “-Significant Customers.”
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Broad service and product offering. We offer a wide range of midstream natural gas gathering and processing services and NGL logistics and marketing services. We believe the breadth and scope of our assets allow us to attract customers due to our ability to deliver products and services across the value chain and due to our well-positioned assets and markets. We believe this breadth and asset positioning, combined with our singular midstream focus, gives us a competitive advantage over other midstream companies and divisions of larger companies. In addition, we believe this diversity of assets and services diversifies cash flows by reducing our dependency on any particular line of business.
Attractive Cash Flow Characteristics
We believe our strategy, combined with our high-quality asset portfolio and strong industry fundamentals, allows us to generate attractive cash flows with the ability to reduce our leverage of the business. Geographic, business and customer diversity enhances our cash flow profile. We have a favorable contract mix that is primarily fee-based or percent-of-proceeds which, along with our long-term commodity-hedging program, serves to mitigate the impact of commodity price movements on cash flow.
We have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2007 through 2012 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are covered by our hedges are approximately 60% to 80% through 2009 and decreases over time. The primary purpose of our commodity risk management activities is to hedge our exposure to price risk and to mitigate the impact of fluctuations in commodity prices on cash flow. We have intentionally tailored our hedges to approximate our actual NGL product composition and to approximate our actual NGL and natural gas delivery points. We intend to continue to manage our exposure to commodity prices in the future by entering into similar hedge transactions as market conditions permit.
Our maintenance capital expenditures have averaged approximately $40.1 million over the last three years. We believe that our assets are well maintained and anticipate that a similar level of capital expenditures will be sufficient for us to continue to operate these assets in a prudent and cost-effective manner.
Asset Base Well-Positioned for Organic Growth
We believe our asset platform and strategic locations allow us to maintain and grow our cash flows as our supply areas continue to benefit from active exploration and development. Generally, higher oil and gas prices, such as those currently being experienced in global energy markets, result in increased domestic drilling and workover activity to increase production. The location of our assets provides us with access to stable natural gas supplies and proximity to end-use markets and liquid market hubs while positioning us to capitalize on high drilling and production activity in those areas and on emerging opportunities for Gulf Coast assets associated with LNG imports and LPG imports. Our existing infrastructure has the capacity to handle incremental volumes
Index to Financial Statements
without significant capital investments. We believe that as domestic demand for natural gas and NGLs continues to grow, our infrastructure will continue to increase in value as such infrastructure takes on increasing importance in meeting that demand.
Experienced and Incentivized Management Team
Our senior management team members have over 200 years of combined experience operating, acquiring, integrating and improving the value of midstream natural gas assets and businesses across major supply areas including Texas, Louisiana and the Gulf Coast, and have held management positions at companies with midstream assets and commercial operations similar in scale and scope to ours. Several of the senior management team members have worked together effectively in prior roles and have complementary skills and sufficient depth to continue to manage the combined businesses and seek opportunities for operational and commercial improvements. Our management team is also incentivized to maintain and grow value since the executive management team, other senior managers and our directors own approximately 20% of the equity of Targa Investments, our parent company, on a fully diluted basis.
Our Business
Natural Gas Gathering and Processing Division
We gather and process natural gas from the Permian Basin in west Texas and southeast New Mexico, the offshore region of the Louisiana Gulf Coast and, through the Partnership, the Fort Worth Basin in north Texas, the Permian Basin in west Texas and the onshore region of the Louisiana Gulf Coast. Most of the NGLs we process are supplied through our gathering systems which, in aggregate, consist of approximately 11,000 miles of natural gas pipelines. The remainder is supplied through third party owned pipelines. Our processing plants include 16 facilities that we own (either wholly or jointly) and operate as well as 6 facilities in which we have an ownership interest but are operated by others. In 2007, we processed an average of approximately 2.0 Bcf per day of natural gas and produced an average of approximately 107 MBbl/d of NGLs, in each case, net to our ownership interests.
We continually seek new supplies of natural gas, both to offset the natural declines in production from connected wells and to increase throughput volumes. We obtain additional natural gas supply in our operating areas by contracting for production from new wells or by capturing existing production currently gathered by others. Competition for new natural gas supplies is based primarily on location of assets, commercial terms, service levels and access to markets. The commercial terms of natural gas gathering and processing arrangements are driven, in part, by capital costs, which are impacted by the proximity of systems to the supply source and operating costs, which are impacted by operational efficiencies and economies of scale.
We believe our extensive asset base and scope of operations in the regions in which we operate provide us with significant opportunities to add both new and existing natural gas production to our systems. We believe our size and scope give us a strong competitive position by placing us in proximity to a large number of existing and new natural gas producing wells in our areas of operations, allowing us to generate economies of scale and to provide our customers with access to our existing facilities and to multiple end-use markets and market hubs. Additionally, we believe our ability to serve our customers’ needs across the natural gas and NGL value chain further augments our ability to attract new customers and end-users.
Index to Financial Statements The following table sets forth key ownership and operational information regarding our operating gathering systems and natural gas processing plants:
(1) Cryo-Cryogenic Processing; RA-Refrigerated Absorption Processing.
(2) These plants are part of our Versado joint venture with Chevron (“Versado”), and 2007 volumes represent our 63.0% ownership interest.
(3) Our ownership is adjustable and subject to annual redetermination.
Index to Financial Statements
(4) Venice Energy Services Company (“VESCO”) volumes represent our 22.9% ownership interest.
(5) The Iowa plant is currently shut down.
(6) The Chico and Gillis plants have fractionation capacities of approximately 12 MBbl/d and 13 MBbl/d, respectively.
(7) The Conger plant is not currently operating, but is on standby and can be quickly reactivated on short notice to meet additional needs for processing capacity.
Permian Basin Assets
We believe we are well positioned as a gatherer and processor in the Permian Basin. We have broad geographic scope, covering portions of 20 counties and approximately 8,160 square miles in southeast New Mexico and west Texas. Proximity to production and development provides us with a competitive advantage in capturing new supplies of natural gas because of our resulting competitive costs to connect new wells and to process additional natural gas in our existing processing plants. Additionally, because we operate all of our plants in this region, we are often able to redirect natural gas among several of our processing plants, allowing us to optimize processing efficiency and further improve the profitability of our operations.
Our Permian Basin operations consist of: (i) west Texas, (ii) the Versado System and (iii) the SAOU System.
West Texas Assets. Our west Texas facilities consist of the Sand Hills plant and the West Seminole and Puckett gathering systems. The systems consist of approximately 1,300 miles of natural gas gathering pipelines. These gathering systems are low-pressure gathering systems with significant compression assets. The Sand Hills refrigerated cryogenic processing plant has residue gas connections to pipelines owned by affiliates of Enterprise Products Partners L.P. (“Enterprise”), ONEOK, Inc. (“ONEOK”) and El Paso Corporation (“El Paso”).
Versado System. Our Versado System consists of the Saunders, Eunice and Monument gas processing plants and related gathering systems. Our ownership in the Versado System is through Versado Gas Processors, a joint venture that is 63% owned by us and 37% owned by Chevron. These refrigerated cryogenic processing plants have 280 MMcf per day of aggregate processing capacity (176 MMcf per day, net to our ownership interest). The Versado plants have residue gas connections to pipelines owned by affiliates of El Paso Corporation, MidAmerican Energy Company and Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”).
SAOU System (described under the Partnership below).
Louisiana Gulf Coast Assets
Our Louisiana Gulf Coast gathering systems and processing plants are supplied by natural gas produced from the south Louisiana basin onshore and from fields in the Gulf of Mexico. With the strategic location of our assets in Louisiana, we have access to the Henry Hub, the largest natural gas hub in the United States, and a substantial NGL distribution system with access to markets throughout Louisiana and the southeast United States.
Our Louisiana Gulf Coast assets consist of (i) the coastal straddle plants and (ii) the LOU System.
Coastal Straddle Plants. Coastal straddle plants are generally situated on mainline natural gas pipelines and process volumes of natural gas collected from multiple offshore producing areas through a series of offshore gathering systems and pipelines. Our coastal straddle plants consist of three wholly owned and eight partially owned straddle plants, some of which are operated by us. We also own and operate two offshore gathering systems, the 89-mile Pelican pipeline system, which has capacity of 125 MMcf per day, and supplies a portion of the natural gas to the Barracuda processing facility, and the 120-mile Seahawk pipeline system, which has capacity of 105 MMcf per day and supplies a portion of the natural gas to the Lowry processing facility. The gathering systems are unregulated pipelines that gather natural gas from the shallow water central Gulf of
Index to Financial Statements
Mexico shelf. The Seahawk gathering system that aggregates natural gas to supply the Lowry plant also gathers some natural gas from onshore south Louisiana locations. Additionally, we have an interest in the Venice gathering system, an offshore gathering system, regulated as an interstate pipeline by the Federal Energy Regulatory Commission (“FERC”), which supplies a portion of the natural gas to VESCO.
Our coastal straddle plants process natural gas produced from shallow water central and western Gulf of Mexico natural gas wells and from deep shelf and deepwater Gulf of Mexico production via connections to third party pipelines or through pipelines owned by us. Our coastal straddle plants have access to markets across the United States through the interstate natural gas pipelines to which they are interconnected.
LOU System (described under the Partnership below).
The Partnership
The Partnership’s business consists of three sets of gathering and processing assets: (i) the North Texas System, (ii) the SAOU System and (iii) the LOU System.
The North Texas System. The North Texas System consists of two gathering systems connected via a high-pressure 32-mile, 10-inch diameter pipeline (“the Interconnect Pipeline”). This interconnection between the gathering systems allows the Partnership to send natural gas in excess of the Shackelford plant’s processing capacity to the Chico plant. The gathering systems comprise approximately 4,000 miles of pipelines that, gather wellhead natural gas from approximately 2,700 meters for transport to the Chico and Shackelford natural gas processing facilities.
The Chico gathering system consists of approximately 1,950 miles of primarily low pressure gathering pipelines, which gathers natural gas from Denton, Montague, Wise, Clay, Jack, Palo Pinto and Parker counties on the eastern part of the North Texas System. The natural gas that is gathered on the Chico gathering system is either delivered directly to the Chico plant, where it is compressed for processing, or is compressed in the field at approximately 26 compressor stations and then transported via one of several high-pressure gathering pipelines to the Chico plant.
The Shackelford gathering system consists of approximately 2,050 miles of natural gas gathering pipelines, which gathers natural gas from Jack, Palo Pinto, Archer, Young, Stephens, Eastland, Throckmorton, Shackelford and Haskell counties on the western part of the North Texas System. The western and southern portions of the Shackelford gathering system gather natural gas that is transported on intermediate-pressure gathering pipelines to the Shackelford plant. The approximately 15 MMcf/d of natural gas gathered from the northern and eastern portions of the Shackelford gathering system is typically transported on the Interconnect Pipeline to the Chico plant for processing. This natural gas is compressed at approximately 11 compressor stations to achieve sufficient pressure to enter the high pressure Interconnect Pipeline.
For 2007 and 2006, the North Texas System gathered approximately 168 MMcf/d of natural gas each year.
The SAOU System. The SAOU System consists of approximately 1,350 miles of pipeline in the Permian Basin of west Texas and the Mertzon, Sterling and Conger processing plants. The broad geographic scope of the SAOU System, covering portions of 10 counties and approximately 4,000 square miles in west Texas, and proximity to production and development, provide us with a competitive advantage to connect new wells and to process additional natural gas in our existing processing plants.
Index to Financial Statements The SAOU System is connected to approximately 3,000 producing wells and/or central delivery points. During 2007, the system gathered approximately 94 MMcf/d of natural gas. The system has approximately 850 miles of low-pressure gathering systems. The system also contains approximately 500 miles of high-pressure gathering pipelines to deliver the natural gas to its processing plants. The gathering system has 27 compressor stations to inject low-pressure gas into these high-pressure pipelines.
The SAOU System includes two currently operating processing plants. The Mertzon plant and the Sterling plant, both of which are refrigerated cryogenic plants, have aggregate processing capacity of approximately 110 MMcf/d. The SAOU System also has the Conger cryogenic plant with a capacity of approximately 25MMcf/d. The Conger plant is not currently operating, but can be quickly reactivated on short notice to meet additional needs for processing capacity.
The Mertzon processing plant currently delivers residue gas to Kinder Morgan’s Rancho Pipeline and to Northern Natural Gas Company. NGLs produced by the plant are delivered to a pipeline owned by Enterprise that transports the NGLs to Cedar Bayou Fractionators (“CBF”, in which we own an interest) located at the Mont Belvieu hub. The Sterling processing plant has residue gas connections to pipelines owned by affiliates of Atmos Energy Corporation, El Paso, ONEOK and Enterprise / ET Fuel Pipeline, L.P., and NGLs are delivered to the West Texas LPG pipeline, owned by Chevron, which also delivers to CBF at the Mont Belvieu hub.
The LOU System. The LOU System consists of approximately 600 miles of gathering system pipelines, covering approximately 3,800 square miles in southwest Louisiana between Lafayette and Lake Charles, the Gillis and Acadia processing plants and an intrastate pipeline system.
The LOU System is connected to approximately 200 producing wells and/or central delivery points in the area between Lafayette and Lake Charles, Louisiana. The gathering system is a high-pressure gathering system that delivers natural gas for processing to either the Acadia or Gillis plants via three main trunk lines. During 2007, the gathering system gathered approximately 191 MMcf/d of natural gas.
The Gillis and Acadia plants are cryogenic plants, with an aggregate processing capacity of approximately 260 MMcf/d. Natural gas can be readily moved between the Gillis and Acadia plants in order to optimize operational efficiencies, meet customer needs and improve profitability.
Raw NGL mix from the Acadia plant is transported to, and combined with raw NGL mix from the Gillis plant via the system’s pipelines, with fractionation occurring at the integrated fractionation facility at the Gillis plant. Excess raw NGL mix can also be transported to Targa’s Lake Charles fractionation facility. The operating capacity of the Gillis fractionator is approximately 13 MBbl/d. Component NGL products are delivered from the Gillis fractionator via the system’s pipelines to local or other markets via pipeline, truck and/or barge.
NGL Logistics and Marketing Division
Our NGL Logistics and Marketing division uses our platform of integrated assets to fractionate, store, terminal, transport, distribute and market NGLs typically under fee-based and margin-based arrangements. For NGLs to be used by refineries, petrochemical manufacturers, propane distributors and other industrial end-users, they must be fractionated into their component products and delivered to various points throughout the United States. Our NGL logistics and marketing assets are generally connected to and supplied, in part, by our Natural Gas Gathering and Processing assets and are primarily located at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana with terminals and transportation assets across the United States. In
Index to Financial Statements
addition, we own or commercially manage assets in a number of other states, including Alabama, Nevada, California, Florida, Mississippi, Tennessee, Kentucky and New Jersey. The geographic diversity of our assets provides us direct access to many NGL customers as well as markets via Targa barges, rail cars and open-access regulated NGL pipelines owned by third parties.
Our NGL Logistics and Marketing division consists of three segments: (i) Logistics Assets, (ii) NGL Distribution and Marketing and (iii) Wholesale Marketing. Our Logistics Assets segment includes the assets involved in the fractionation, storage and transportation of NGLs. Our NGL Distribution and Marketing segment markets our own NGL production and also purchases NGL products from third parties for resale. Our Wholesale Marketing segment includes our refinery services business and wholesale propane marketing operations.
Logistics Assets Segment
Fractionation. NGL fractionation facilities separate raw NGL mix into discrete NGL products: ethane, propane, butanes and natural gasoline. Raw NGL mix recovered from our Natural Gas Gathering and Processing division represents the largest source of volumes processed by our NGL fractionators.
The majority of our NGL fractionation facilities process raw NGL mix under fee-based arrangements. These fees are subject to adjustment for changes in certain fractionation expenses, including energy costs. The operating results of our NGL fractionation business are dependent upon the volume of raw NGL mix fractionated and the level of fractionation fees charged.
We believe that sufficient volumes of raw NGL mix will be available for fractionation in commercially viable quantities for the foreseeable future due to increases in NGL production from the Fort Worth Basin, Fayetteville Shale, Rockies and certain other basins accessed by pipelines to Mont Belvieu, as well as from continued production of NGLs in areas such as the Permian Basin, Mid-Continent, south Louisiana and Shelf and Deepwater Gulf of Mexico. Changes in dew point specifications implemented by individual pipelines and enacted by the FERC across the industry should result in a potential increase in volumes of raw NGL mix available for fractionation because the natural gas will require processing or conditioning to meet pipeline quality specifications. These requirements could help to establish a base volume of raw NGL mix during periods when it might be otherwise uneconomical to process certain sources of natural gas. Furthermore, significant volumes of raw NGL mix are contractually committed to our NGL fractionation facilities.
Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain raw NGL mix and distribute NGL products is also an important competitive factor. This ability is a function of the existence of the pipeline and storage infrastructure necessary to conduct such operations. The scope and capability of our logistics assets, including our transportation and distribution systems, give us access to both substantial sources of raw NGL mix and a large number of end-use markets.
The following table details our fractionation facilities:
Index to Financial Statements
(1) Excludes operating data for our Chico and Gillis fractionation facilities.
(2) Includes ownership through our 88% interest in Downstream Energy Ventures Co, LLC.
(3) Included in our Natural Gas Gathering and Processing division.
Our fractionation assets include ownership interests in three stand-alone fractionation facilities that are strategically located on the Gulf Coast. We operate two of the facilities, one at Mont Belvieu, Texas, and the other at Lake Charles, Louisiana. We also have an equity investment in a third fractionator, Gulf Coast Fractionators (“GCF”), also located at Mont Belvieu. We are subject to a consent decree with the Federal Trade Commission, issued December 12, 1996, that, among other things, prevents us from participating in commercial decisions regarding rates paid by third parties for fractionation services at GCF. This restriction on our activity at GCF will terminate on December 12, 2016, twenty years after the date the consent order was issued. This consent decree predates our ownership of the assets.
Storage and Terminalling. In general, our storage assets provide warehousing of raw NGL mix, NGL products and petrochemical products in underground wells, which allows for the injection and withdrawal of such products at various times in order to meet demand cycles. Similarly, our terminalling operations provide the inbound/outbound logistics and warehousing of raw NGL mix, NGL products and petrochemical products in above-ground storage tanks. Our underground storage and terminalling facilities range in scale from serving a singular market, such as propane, to serving multiple products and markets, such as our Mont Belvieu and Galena Park facilities where we have extensive pipeline connections for mixed NGL supply and delivery of component NGLs. In addition, some of these facilities are connected to marine, rail and truck loading and unloading facilities that provide services and products to our customers. We provide long-and short-term storage and terminalling services and throughput capability to affiliates and third party customers for a fee.
We own and operate a total of 43 storage wells at our facilities with a net storage capacity of approximately 67 MMBbl, the usage of which may be limited by brine handling capacity, which is utilized to displace NGLs from storage. We also have 14 wholly owned terminal facilities in Texas, Kentucky, Mississippi, Tennessee, Louisiana, Florida and New Jersey.
We operate our storage and terminalling facilities based on the needs and requirements of our customers in the NGL, petrochemical, heating and other related industries. We usually experience an increase in demand for storage and terminalling of mixed NGLs during the summer months when gas plants typically reach peak NGL production, refineries have excess NGL products and liquid petroleum gas (“LPG”) imports are often highest. Likewise, demand for storage and terminalling at our propane facilities typically peak during the highest demand periods of fall, winter and early spring.
Our fractionation, storage and terminalling business are supported by approximately 650 miles of company-owned pipelines to transport mixed NGL and specification products.
The following tables detail our NGL storage and terminalling assets:
Index to Financial Statements
(1) One of the inactive wells is expected to be in commercial service during 2008.
(2) Out of service.
(3) Four of the twelve owned wells are leased to Citgo under a long-term lease; one of the twelve wells is currently permitting for hydrocarbon service.
(4) We own and operate 20 wells and operate 6 wells owned by ChevronPhillipsChemical Company LLC.
(1) Volumes reflect total import and export across the dock/terminal.
(2) Volumes reflect total transport and injection volumes.
(3) Volumes reflect total transport and terminal throughput volumes.
(4) Volumes are net to Targa’s ownership interest.
Transportation and Distribution. Our NGL transportation and distribution infrastructure includes a wide range of assets supporting both third party customers and the delivery requirements of our marketing and asset management business. We provide fee-based transportation services to refineries and petrochemical companies throughout the Gulf Coast area. Our assets are also deployed to serve our wholesale distribution terminals, fractionation facilities, underground storage facilities, and pipeline injection terminals. These distribution assets provide a variety of ways to transport and deliver products to our customers.
Our transportation assets, as of December 31, 2007, include:
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approximately 800 railcars that we lease and manage;
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approximately 80 leased transport tractors and 100 company-owned tank trailers; and
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21 company-owned pressurized NGL barges with more than 320,000 barrels of capacity.
Wholesale Marketing Segment
Refinery Services. In our refinery services business, we typically provide NGL balancing services, in which we have contractual arrangements with refiners to purchase and/or market propane and to provide butane supply. We also contract for and use the storage, transportation and distribution assets included in our Logistics Assets segment to assist refinery customers in managing their NGL product demand and production schedules. This includes both feedstocks consumed in refinery processes and the excess NGLs produced by those same refining
Index to Financial Statements
processes. Under typical net-back contracts, we generally retain a portion of the resale price of NGL sales or receive a fixed minimum fee per gallon on products sold. Under net-back contracts, fees are earned for locating and supplying NGL feedstocks to the refineries based on a percentage of the cost to obtain such supply or a minimum fee per gallon. In 2007, we sold an average of approximately 25 MBbl/d of NGLs through this refinery services business.
Key factors impacting the results of our refinery services business include production volumes, propane and butane prices, as well as our ability to perform receipt, delivery and transportation services in order to meet refinery demand.
Wholesale Propane Marketing. Our wholesale propane marketing operations include primarily the sale of propane and related logistics services to major multi-state retailers, independent retailers and other end-users. Our propane supply primarily originates from both our refinery/gas supply contracts and our other owned or managed logistics and marketing assets. We generally sell propane at a fixed or posted price at the time of delivery and, in some circumstances, we earn margin on a net-back basis. In 2007, we sold an average of approximately 39 MBbl/d.
Our wholesale propane marketing business is significantly impacted by weather-driven demand, particularly in the winter, the price of propane in the markets we serve and our ability to deliver propane to customers to satisfy peak winter demand.
NGL Distribution and Marketing Segment
In our NGL Distribution and Marketing segment, we market our own NGL production and also purchase component NGL products from other NGL producers and marketers for resale. In 2007, our distribution and marketing services business sold an average of approximately 250 MBbl/d of NGLs to third parties in North America, not including approximately 9 MBbl/d sold by Targa and recorded in its gathering and processing business.
We generally purchase raw NGL mix from producers at a monthly pricing index less applicable fractionation, transportation and marketing fees and resell these products to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical settlement business in which we earn margins from purchasing and selling NGL products from producers under contract. We also earn margins by purchasing and reselling NGL products in the spot and forward physical markets. To effectively serve our customers in the NGL Distribution and Marketing segment, we contract for and use many of the assets included in our Logistics Assets segment.
Operational Risks and Insurance
We are subject to all risks inherent in the midstream natural gas business. These risks include, but are not limited to, explosions, fires, mechanical failure, terrorist attacks, product spillage, weather, nature and inadequate maintenance of rights-of-way; which could result in damage to or destruction of operating assets and other property, or could result in personal injury, loss of life or pollution of the environment, as well as curtailment or suspension of operations at the affected facility. We maintain general public liability, property, boiler and machinery and business interruption insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles that we consider reasonable and not excessive given the current insurance market environment. The costs associated with these insurance coverages have increased significantly during recent periods, and may continue to do so in the future. For example, following Hurricanes Katrina and Rita, insurance premiums, deductibles and co-insurance requirements have increased substantially, and terms generally are less favorable than terms that could be obtained prior to such hurricanes. We believe that recent increases in insurance premiums, deductibles and co-insurance requirements represent the near-term impact of Hurricanes Katrina and Rita. Although we do not anticipate that insurance terms and coverage will return to
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levels experienced prior to such hurricanes, we do expect that, barring a recurrence of significant hurricane related losses, more favorable insurance terms and coverage will be available over the next several years.
The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. While we currently maintain levels and types of insurance that we believe to be prudent under current insurance industry market conditions, our inability to secure these levels and types of insurance in the future could negatively impact our business operations and financial stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintain these levels of insurance in the future at rates we consider commercially reasonable, particularly in the area of contingent business interruption insurance for our offshore gathering systems.
Significant Customers
During 2007 and 2006, approximately 26% and 28% of our consolidated revenues, and approximately 13% and 20% of our consolidated product purchases, respectively, were derived from transactions with Chevron and CPC. No other third party customer accounted for more than 10% of our consolidated revenues or product purchases during these periods.
Gas Gathering and Processing Contracts with Chevron
Under gas gathering and processing agreements with us or the Versado and VESCO entities in which we have a 63.0% and 22.9% ownership interest, respectively, Chevron has dedicated, on a life-of-field basis, substantially all of the natural gas it produces from committed areas in New Mexico, Texas and the Gulf of Mexico. Under these contracts, we receive a percentage of the volumes of NGLs and residue gas attributable to the processed natural gas in Texas and New Mexico and a percentage of the volumes of NGLs or a fee depending on processing economics for the Gulf of Mexico. These contracts provide that either party has the right to periodically renegotiate the processing terms. If the parties are unable to agree, then the matter is settled by binding arbitration.
Refinery Services and Related Contracts With Chevron
Our master refinery services agreement for Chevron refineries was renegotiated and replaced on September 1, 2006 with liquid product purchase and sale agreements which allow us to purchase propane (and in some cases to purchase and sell butanes) for the Elk Hills, Kettleman Hills, McKittrick and Taft 1C Gas plants, the El Segundo (propane and polypropylene mix), Maysville (butane only), Pascagoula, Richmond and Salt Lake City refineries; barge time charter agreements in which we provide transportation for Chevron’s propane/propylene mix and butane produced at the Pascagoula Refinery; and fractionation agreements in which we fractionate Chevron’s raw product and butane at our Mont Belvieu facility. These contracts have one to three year terms. We are well positioned to retain Chevron as a customer based on these contractual positions and customer relationships, our long-standing history of customer service, established relationship with each facility, criticality of the service provided, competitive rate structure, competitive-cost provision of non-traditional services and potentially high costs of replacing the infrastructure assets that we have in place to serve Chevron’s needs.
In addition to our agreements with Chevron, we have agreements with CPC, a separate joint venture affiliate of Chevron, pursuant to which we supply a significant portion of CPC’s NGL feedstock needs for petrochemical plants in the Texas Gulf Coast area. Through a related services agreement, we provide storage and logistical services to CPC for feedstocks and products produced from the petrochemical plants. Under provisions of the services contract, we have given CPC notice of termination, which starts a two year termination clock to renegotiate the agreement, for the mutual benefit of both companies. Similarly, we have given notice on the
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feedstocks agreement, which also starts a two year clock, effective August 2007, to renegotiate this agreement for the mutual benefit of both companies. We are well positioned to retain CPC as a customer based on our long-standing history of customer service, criticality of the service provided, the integrated nature of facilities and the difficulty and high cost associated with replicating our assets.
Competition
We face strong competition in acquiring new natural gas supplies. Competition for natural gas supplies is primarily based on the location of gathering and processing facilities, pricing arrangements, reputation, efficiency, flexibility, reliability and access to end-use markets or liquid marketing hubs. Competitors to our gathering and processing operations include other natural gas gatherers and processors, such as major interstate and intrastate pipeline companies, master limited partnerships and oil and gas producers. Our major competitors for natural gas supplies in our current operating regions, include DCP Midstream (“DCP”), Enterprise Products Partners L.P., ET Fuel Pipeline, L.P., Enbridge Inc., and Southern Union Gas Company (formerly Sid Richardson Energy Services Company). Many of our competitors have greater financial resources than we possess.
We also compete for NGL products to market through our NGL Logistics and Marketing division. Our competitors include major oil and gas producers who market NGL products for their own account and for others. Additionally, we compete with several other NGL marketing companies, including Enterprise Products Partners L.P., TEPPCO Partners, L.P., DCP, ONEOK and BP p.l.c.
Additionally, we face competition for raw NGL mix supplies at our fractionation facilities. Our competitors include large oil, natural gas and petrochemical companies. The fractionators in which we own an interest in the Mont Belvieu region compete for volumes of raw NGL mix with other fractionators also located at Mont Belvieu. Among the primary competitors are Enterprise Products Partners L.P. and ONEOK, Inc. In addition, certain producers fractionate raw NGL mix for their own account in captive facilities. Our Mont Belvieu fractionators also compete on a more limited basis with fractionators in Conway, Kansas and a number of decentralized, smaller fractionation facilities in Texas, Louisiana and New Mexico. Our other fractionation facilities compete for raw NGL mix with the fractionators at Mont Belvieu as well as other fractionation facilities located in Louisiana. Our customers who are significant producers of raw NGL mix and NGL products or consumers of NGL products may develop their own fractionation facilities in lieu of using our services.
Regulation of Operations
Regulation of Our Interstate Natural Gas Pipeline
We are the commercial operator and part-owner (22.9 percent equity interest) of Venice Gathering System, L.L.C. (“VGS”), a natural gas pipeline that originates on the Outer Continental Shelf (“OCS”). VGS is regulated by FERC under the Natural Gas Act of 1938 (“NGA”), and the Natural Gas Policy Act of 1978 (“NGPA”). VGS operates under a FERC-approved, open-access tariff that establishes rates and terms and conditions under which the system provides services to its customers. Pursuant to FERC’s jurisdiction, existing pipeline rates and/or terms and conditions of service may be challenged by customer complaint or by FERC and proposed rate changes or changes in the terms and conditions of service may be challenged by protest.
Generally, FERC’s authority extends to:
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transportation of natural gas;
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rates and charges for natural gas transportation;
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certification and construction of new facilities;
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extension or abandonment of services and facilities;
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maintenance of accounts and records;
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commercial relationships and communications between pipelines and certain affiliates;
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terms and conditions of service and service contracts with customers;
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depreciation and amortization policies; and
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acquisition and disposition of facilities.
VGS holds a certificate of public convenience and necessity issued by FERC pursuant to Section 7 of the NGA permitting the construction, ownership, and operation of its interstate natural gas pipeline facilities and the provision of transportation services. This certificate authorization requires VGS to provide on a non-discriminatory basis open-access services to all customers who qualify under its FERC gas tariff. Under Section 8 of the NGA, FERC has the power to prescribe the accounting treatment of items for regulatory purposes. Thus, the books and records of VGS may be periodically audited by FERC.
The maximum recourse rates that may be charged by VGS for its services are established through FERC’s ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline’s actual prudent historical cost investment. Key determinants in the ratemaking process are costs of providing service, allowed rate of return and volume throughput and contractual capacity commitment assumptions. The maximum applicable recourse rates and terms and conditions for service are set forth in each pipeline’s FERC approved tariff. Rate design and the allocation of costs also can impact a pipeline’s profitability. Natural gas companies may not charge rates that have been determined to be unjust and unreasonable. VGS is permitted to discount its firm and interruptible rates without further FERC authorization down to the variable cost of performing service, provided they do not “unduly discriminate.”
The design, construction, and operation of our natural gas pipelines are also subject to regulation by the Office of Pipeline Safety of the Department of Transportation (“DOT”). The DOT has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. In Louisiana, the Department of Natural Resources, Pipeline Division implements DOT’s safety rules. In Texas, the Railroad Commission of Texas (“RRC”), implements those safety rules. In New Mexico, the New Mexico Public Regulation Commission implements the DOT’s safety rules.
Gathering Pipeline Regulation
Section 1(b) of the Natural Gas Act of 1938 (“NGA’), exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Index to Financial Statements Regulation of our offshore gathering facilities. Our Seahawk and Pelican gathering systems gather gas on the OCS. Seahawk and Pelican are subject to the jurisdiction of the applicable Louisiana regulatory agencies to the extent that those gathering systems traverse state land and/or waters. State regulation of gathering facilities generally includes various safety, environmental, nondiscriminatory take, and common purchaser requirements, and complaint-based rate regulation.
Seahawk and Pelican are also subject to the jurisdiction of the Minerals Management Service, or MMS, since they traverse the OCS pursuant to MMS-issued easements. The MMS has issued a notice of proposed rulemaking to determine whether to revise its regulations to better ensure that pipelines subject to MMS’ jurisdiction provide open and non-discriminatory access to both owner and non-owner shippers as required under section 5(f) of the Outer Continental Shelf Lands Act. No final determination has yet been reached in this proceeding.
Regulation of our onshore gathering facilities. Our onshore natural gas gathering operations are subject to ratable take and common purchaser statutes in Louisiana, Texas, and New Mexico. The common purchaser statutes generally require our gathering pipelines to purchase or take without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Our gathering facilities in New Mexico are not subject to rate regulation. Louisiana and Texas have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. The rates we charge for gathering in Texas and Louisiana are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.
During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (“Competition Bill”) and H.B. 1920 (“LUG Bill”). The Competition Bill gives the RRC the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and intrastate transportation pipelines in formal rate proceedings. It also gives the RRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The Competition Bill also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale, transportation, or gathering of natural gas. The LUG Bill modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested, provides producers with an annual audit right, and provides the RRC with the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. We cannot predict what effect, if any, either the Competition Bill or the LUG Bill might have on our operations in Texas.
Intrastate Pipeline Regulation
Regulation of our natural gas intrastate pipelines. Our intrastate natural gas transportation pipelines are subject to regulation by applicable state regulatory commissions. Proposed and existing rates are subject to state regulation and are subject to challenge by protest and complaint, respectively. Further, the states we operate in require that services be provided on a non-discriminatory basis.
Targa Intrastate Pipeline LLC (“Targa Intrastate”) owns the intrastate pipeline that transports natural gas from our Shackelford processing plant to an interconnect with Atmos-Texas that in turn delivers gas to the West Texas Utilities Company’s Paint Creek Power Station. Targa Intrastate also owns a 1.65 mile, 10-inch diameter
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intrastate pipeline that transports natural gas from a third party gathering system into the Chico System in Denton, County, Texas. Targa Intrastate is subject to regulation by the Railroad Commission of Texas (“RRC”) and has a tariff on file with such agency.
Targa Louisiana Intrastate LLC owns an approximately 60-mile intrastate pipeline system that receives all of the natural gas it transports within or at the boundary of the State of Louisiana. Because all such gas ultimately is consumed within Louisiana, and since the pipeline’s rates and terms of service are subject to regulation by the Office of Conservation of the Louisiana Department of Natural Resources (“DNR”), the pipeline qualifies as a Hinshaw pipeline under Section 1(c) of the NGA and thus is exempt from most FERC jurisdiction.
Texas and Louisiana have adopted complaint-based regulation of intrastate natural gas transportation activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to pipeline access and rate discrimination. The rates we charge for intrastate transportation are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.
As discussed above in the context of regulation of our onshore gathering operations, the Competition Bill and LUG Bill contain provisions applicable to intrastate transportation pipelines. We cannot predict what effect, if any, either the Competition Bill or the LUG Bill might have on our operations in Texas.
Regulation of our NGL intrastate pipelines. Our intrastate NGL pipelines in Louisiana, owned and operated by Targa Louisiana Field Services LLC, gather raw NGL streams that we own from our processing plants in Louisiana to our fractionator in Lake Charles, Louisiana, where the raw NGL streams are fractionated into various products. These pipelines are not subject to FERC regulation or rate regulation by the DNR, but are regulated by DOT safety regulations.
Natural Gas Processing
Our natural gas processing operations are not presently subject to FERC regulation. However, there can be no assurance that our processing operations will continue to be exempt from FERC regulation in the future.
Our processing facilities are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation can be subject to extensive federal and in Texas and Louisiana, if a complaint is filed, state regulation. FERC is continually proposing and implementing new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of NGLs. These initiatives also may indirectly affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of these regulatory changes to our processing operations.
The ability of our processing facilities and pipelines to deliver natural gas into third party natural gas pipeline facilities is directly impacted by the gas quality specifications required by those pipelines. On June 15, 2006, FERC issued a policy statement on provisions governing gas quality and interchangeability in the tariffs of interstate gas pipeline companies and a separate order declining to set generic prescriptive national standards. FERC strongly encouraged all natural gas pipelines subject to its jurisdiction to adopt, as needed, gas quality and interchangeability standards in their FERC gas tariffs modeled on the interim guidelines issued by a group of industry representatives, headed by the Natural Gas Council (the “NGC+ Work Group”), or to explain how and why their tariff provisions differ. We do not believe that the adoption of the NGC+ Work Group’s gas quality interim guidelines by a pipeline that either directly or indirectly interconnects with our facilities would materially affect our operations. We have no way to predict, however, whether FERC will approve of gas quality specifications that materially differ from the NGC+ Work Group’s interim guidelines for such an interconnecting pipeline.
Index to Financial Statements Sales of Natural Gas and NGLs
The price at which we buy and sell natural gas and NGLs is currently not subject to federal regulation and, for the most part, is not subject to state regulation. However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission (“CFTC”). Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.
Our sales of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation can be subject to extensive federal and, if a complaint is filed, state regulation. FERC is continually proposing and implementing new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of NGLs. These initiatives also may indirectly affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of these regulatory changes to our natural gas and NGL marketing operations, and we do not believe that we would be affected by any such FERC action materially differently than other natural gas and NGL marketers with whom we compete.
Other State and Local Regulation of Our Operations
Our business activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters. For additional information regarding the potential impact of federal, state or local regulatory measures on our business, please see “Item 1A.
Item 1A. Risk Factors
The nature of our business activities subject us to certain hazards and risks. You should carefully consider the following risks together with all of the other information contained in this Annual Report. The risks and uncertainties described below are not the only risks facing us. Additional risks not presently known to us or which we consider immaterial based on information currently available to us may also materially adversely affect us. If any of the following risks or uncertainties actually occur, our business, financial condition and results of operations could be materially adversely affected.
Risks Related to Our Business
Our cash flow is affected by supply and demand for natural gas and NGL products, natural gas and NGL prices, and decreases in these prices could adversely affect our results of operations and financial condition.
Our operations can be affected by the level of natural gas and NGL prices and the relationship between these prices. The prices of natural gas and NGLs have been volatile and we expect this volatility to continue. Our future cash flow will be materially adversely affected if we experience significant, prolonged pricing deterioration below general price levels experienced over the past few years in our industry. The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:
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the impact of seasonality and weather;
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general economic conditions;
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the level of domestic crude oil and natural gas production and consumption;
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the availability of imported natural gas, liquefied natural gas, NGLs and crude oil;
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actions taken by foreign oil and gas producing nations;
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the availability of local, intrastate and interstate transportation systems;
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the availability and marketing of competitive fuels;
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the impact of energy conservation efforts; and
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the extent of governmental regulation and taxation.
Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. For 2007, our percent-of-proceeds arrangements accounted for approximately 43% of our gathered natural gas volume. Under percent-of-proceeds arrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage of an index price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. Under these types of arrangements, our revenues and our cash flows increase or decrease,
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whichever is applicable, as the price of natural gas, NGLs and crude oil fluctuates. For additional information regarding our hedging activities, please see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk”.
Because of the natural decline in production from existing wells in our operating regions, our success depends on our ability to obtain new sources of supplies of natural gas and NGLs, which depends on certain factors beyond our control. Any decrease in supplies of natural gas and NGLs could adversely affect our business and operating results.
Our gathering systems are connected to natural gas wells from which the production will naturally decline over time, which means that our cash flows associated with these wells will likely also decline over time. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas supplies. Additionally, our profitability is materially affected by the volume of raw NGL mix fractionated at our fractionation facilities. A material decrease in natural gas production from producing areas that we rely on for raw NGL mix, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of NGL products delivered to our fractionation facilities. Our ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near our gathering systems.
We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, availability of drilling rigs and other production and development costs and the availability and cost of capital. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. In the past, the prices of natural gas have been extremely volatile, and we expect this volatility to continue. Natural gas prices reached relatively high levels in 2005 and early 2006, but declined substantially in the second half of 2006 and continued to decline until late August 2007. Reductions in exploration or production activity or shut-ins by producers in the areas in which we operate as a result of a sustained decline in natural gas prices would lead to reduced utilization of our gathering and processing assets.
Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. If, due to reductions in drilling activity or competition, we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, throughput on our pipelines and the utilization rates of our treating, processing and fractionation facilities would decline, which could reduce our revenue.
Some of our business is seasonal, requires that we build inventory to meet seasonal demand, and is potentially impacted by weather.
While the volumes of raw NGL mix that we fractionate are generally stable on an average annual basis, they often vary on a seasonal basis. For example, we typically fractionate lower volumes during the winter months, when more raw NGL mix is fractionated by facilities closer to the field to capture propane for heating purposes and when natural gas wells and certain oil wells tend to be less productive. Conversely, we typically fractionate greater volumes during the summer months, when less raw NGL mix is locally fractionated for heating purposes, when natural gas wells tend to be more productive and when refineries have excess supply of raw NGL mix due to various regulatory restrictions. This seasonality in demand may cause our results of operations to lack predictability on a quarter to quarter basis.
Similarly, weather conditions have a significant impact on the demand for propane because end-users depend on propane principally for heating purposes. Warmer-than-normal temperatures in one or more regions in
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which we operate can significantly decrease the total volume of propane we sell. Lack of consumer demand for propane may also adversely affect the retailers we transact with in our wholesale propane marketing operations, exposing us to their inability to satisfy their contractual obligations to us.
If we fail to balance our purchases of natural gas and our sales of residue gas and NGLs, our exposure to commodity price risk will increase.
We may not be successful in balancing our purchases of natural gas and our sales of residue gas and NGLs. In addition, a producer could fail to deliver promised volumes to us or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause an imbalance between our purchases and sales. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.
Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the percentage of our expected equity commodity volumes that are hedged decreases substantially over time.
We have entered into derivative transactions related to only a portion of our equity volumes. As a result, we will continue to have direct commodity price risk to the unhedged portion. Our actual future volumes may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a reduction of our liquidity. The percentages of our expected equity volumes that are covered by our hedges decrease over time. The derivative instruments we utilize for these hedges are based on posted market prices, which may be lower than the actual natural gas, NGL and condensate prices that we realize in our operations. These pricing differentials may be substantial and could materially impact the prices we ultimately realize. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and in certain circumstances may actually increase the variability of our cash flows. To the extent we hedge our commodity price risk, we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. For additional information regarding our hedging activities, please see “Item7A. Quantitative and Qualitative Disclosures About Market Risk”.
If third party pipelines and other facilities interconnected to our natural gas pipelines and facilities become partially or fully unavailable to transport natural gas and NGLs, our revenues could be adversely affected.
We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation is not within our control. If any of these third party pipelines and other facilities become partially or fully unavailable to transport natural gas and NGLs, or if the gas quality specification for their pipelines or facilities changes so as to restrict our ability to transport gas on these pipelines or facilities, our revenues could be adversely affected.
Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.
We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil, natural gas and petrochemical companies or integrated midstream energy companies that have greater financial resources and access to supplies of natural gas and NGLs than we do. Some of these competitors may expand or construct gathering, processing and transportation systems that would create additional competition for
Index to Financial Statements
the services we provide to our customers. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers in the gathering and processing business, as well as the natural gas logistics and marketing business, at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition.
We typically do not obtain independent evaluations of natural gas reserves dedicated to our gathering pipeline systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate.
We typically do not obtain independent evaluations of natural gas reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves dedicated to our gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas transported on our gathering systems in the future could be less than we anticipate. A decline in the volumes of natural gas on our systems could have a material adverse effect on our business, results of operations, and financial condition.
A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect our business, results of operations and financial condition.
The NGL products we produce have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general economic conditions, new government regulations, reduced demand by consumers for products made with NGL products, increased competition from petroleum-based products due to pricing differences, mild winter weather or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Our NGL products and their demand are affected as follows:
Ethane. Ethane is typically supplied as purity ethane and as part of ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas producers to leave the ethane in the natural gas stream thereby reducing the volume of NGLs delivered for fractionation and marketing. We have experienced periods where natural gas producers have retained ethane in the natural gas stream and may experience such periods in the future.
Propane. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of warmer-than-normal weather.
Normal Butane. Normal butane is used in the production of isobutane, as a refined product blending component, as a fuel gas, either alone or in a mixture with propane, and in the production of ethylene and propylene. Changes in the mandated composition resulting from governmental regulation of refined products, demand for heating fuel and for ethylene and propylene could adversely affect demand for normal butane.
Index to Financial Statements Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.
Natural Gasoline. Natural gasoline is used as a blending component for certain refined products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition resulting from governmental regulation of motor gasoline and in demand for ethylene and propylene could adversely affect demand for natural gasoline.
Any reduced demand for ethane, propane, normal butane, isobutane or natural gasoline for any of the reasons stated above could adversely affect demand for the services we provide as well as NGL prices, which would negatively impact our results of operations and financial condition.
We have significant relationships with Chevron as a producer utilizing our gas processing operations, a purchaser of our NGLs and a customer for our marketing and refinery services. In some cases, these agreements are subject to renegotiation and termination rights.
We have several gas processing agreements with Chevron pursuant to which Chevron has dedicated, for the life of the fields, substantially all of the natural gas it produces from committed areas in New Mexico, Texas and the Gulf of Mexico. For each of 2007 and 2006, approximately 21% of our natural gas gathered for processing came from Chevron under these gas processing agreements. These contracts provide that either party has the right to periodically renegotiate the processing terms. If the parties are unable to agree on revised terms, then the agreements provide for the issue to be settled by binding arbitration. It is possible that the terms will be renegotiated or arbitrated on terms that are less favorable to us than the current terms of these agreements. In addition, to the extent that the volume of natural gas processed under these contracts declines as a result of depletion or otherwise, we would be adversely affected.
During 2007 and 2006, approximately 26% and 28% of our consolidated revenues, and approximately 13% and 20% of our consolidated product purchases, respectively, were derived from transactions with Chevron and CPC. We are in the process of renegotiating our contracts with CPC. See “Business-Significant Customers.” Under many of our Chevron contracts where we purchase or market NGLs on Chevron’s behalf, Chevron may elect to terminate the contracts or renegotiate the price terms. To the extent Chevron reduces the volumes of NGLs that it purchases from us or reduces the volumes of NGLs that we market on its behalf, or to the extent the economic terms of such contracts are changed, our revenues and cash available for debt service could decline.
The tax treatment of the Partnership depends on its status as a partnership for federal income tax purposes as well as its not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat the Partnership as a corporation for federal income tax purposes or the Partnership becomes subject to additional amounts of entity-level taxation for state tax purposes, then its cash available for distribution to its unitholders, including us, would be substantially reduced.
We currently own a 24.5% limited partner interest, a 2% general partner interest and incentive distribution rights in the Partnership. The anticipated after-tax economic benefit of our investment in the Partnership depends largely on its being treated as a partnership for federal income tax purposes. The Partnership has not requested, and does not plan to request, a ruling from the IRS on this or any other tax matter affecting it.
If the Partnership was treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. If such tax was imposed upon the Partnership as a corporation, its cash available for distribution would be substantially reduced. Therefore, treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, including us, and would likely cause a substantial reduction in the value of our investment.
Index to Financial Statements Current law may change so as to cause the Partnership to be treated as a corporation for federal income tax purposes or otherwise subject the Partnership to entity-level taxation. At the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to the Partnership as currently proposed, it could be amended prior to enactment in a manner that does apply to the Partnership. We are unable to predict whether any of these changes, or other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in the Partnership’s common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, the Partnership is required to pay Texas franchise tax at a maximum effective rate of 0.7% of its gross income apportioned to Texas in the prior year. Imposition of any such tax on the Partnership by any other state will reduce the cash available for distribution to us.
We do not own most of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own most of the land on which our pipelines and facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or leases or if such rights of way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere, and reduce our revenue.
We are dependent on cash flow generated by our subsidiaries to meet our obligations, including required principal and interest payments on our indebtedness.
We are a holding company. Our subsidiaries own substantially all of our operating assets and conduct substantially all of our operations. Accordingly, we are dependent, to a material extent, on the generation of cash flow by our subsidiaries and their ability to make such cash available to us, by dividend, debt repayment or otherwise. Our subsidiaries may not be able to, or be permitted to make distributions to enable us to meet our obligations. Each subsidiary is a distinct legal entity and, under certain circumstances, legal and contractual restrictions may limit our ability to obtain cash from our subsidiaries. In the event that we do not receive distributions from our subsidiaries, we may be unable to meet our obligations, including required principal and interest payment on our indebtedness.
We may be unable to cause our majority-owned joint ventures to take or not to take certain actions unless some or all of our joint venture participants agree.
We participate in several majority-owned joint ventures whose corporate governance structures require at least a majority in interest vote to authorize many basic activities and require a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, making distributions, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business, among others. Without the concurrence of joint venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take or not take certain actions, even though taking or preventing those actions may be in the best interest of us or the particular joint venture.
In addition, subject to certain conditions, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint owners. Any such transaction could result in our partnering with different or additional parties.
Index to Financial Statements If we lose our senior management or key business line personnel, our business may be adversely affected.
Our success is dependent upon the efforts of our senior management, as well as on our ability to attract and retain senior management. There is substantial competition for qualified personnel in the midstream natural gas industry. We may not be able to retain our existing senior management, fill new positions or vacancies created by expansion or turnover, or attract additional qualified senior management personnel. We have not entered into employment agreements with any of our key executive officers. In addition, we do not maintain “key man” life insurance on the lives of any members of our senior management. A loss of one or more of these key people could harm our business and prevent us from implementing our business strategy.
Weather may limit our ability to operate our business and could adversely affect our operating results.
The weather in the areas in which we operate can cause delays in our operations and, in some cases, work stoppages. For example, natural gas sales volumes could be negatively impacted by wet weather, which would limit our ability to complete connections to new wells. Any similar delays or work stoppages caused by the weather could adversely affect our operating results for the affected periods.
Our business involves many hazards and operational risks, some of which may not be insured or fully covered by insurance. If a significant accident or event occurs that is not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial results could be adversely affected.
Our operations are subject to many hazards inherent in the gathering, compressing, treating, processing and transporting of natural gas and the fractionation, storage and transportation of NGLs, including:
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damage to pipelines, plants, logistical assets and related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism;
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inadvertent damage from third parties, including from construction, farm and utility equipment;
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leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities; and
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other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. For example, Hurricanes Katrina and Rita damaged gathering systems, processing facilities, NGL fractionators and pipelines along the Gulf Coast, including certain of our facilities. These hurricanes disrupted the operations of our customers in August and September 2005, which curtailed or suspended the operations of various energy companies with assets in the region. The size and complexity of insurance claims associated with these storms resulted in longer than anticipated delays in some recoveries of insurance proceeds and these delays and any ultimate failure to recover insurance proceeds could adversely affect our financial results. We are not fully insured against all risks inherent to our business. We are not insured against all environmental accidents that might occur which may include toxic tort claims, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial condition could be adversely affected. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. For example,
Index to Financial Statements
following Hurricanes Katrina and Rita, insurance premiums, deductibles and co-insurance requirements increased substantially, and terms generally are less favorable than terms that could be obtained prior to such hurricanes. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
With the exception of our interest in Venice Gathering System, L.L.C.(“VGS”) we are generally exempt from FERC regulation under the Natural Gas Act of 1938 (“NGA”), but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC has recently proposed to require intrastate pipelines, possibly including natural gas gathering pipelines, to comply with certain Internet posting requirements, with the goal of promoting transparency in the interstate natural gas market. On December 21, 2007, the FERC issued a Final Rule with respect to the annual reporting requirements. With respect to the pipeline posting proposal, the FERC issued a notice of NOPR to require the posting of daily actual flow information by some intrastate pipelines. Non-interstate pipelines would be required to post daily scheduled flow information in addition to the earlier NOPR proposal to require posting capacity and daily actual flow information. Initial comments on the December 21, 2007 NOPR were due February 4, 2008 and reply comments were due on March 5, 2008. We may experience an increase in costs if the rule is adopted as proposed.
Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity.
Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress. In addition, the courts have determined that certain pipelines that would otherwise be subject to the Interstate Commerce Act of 1887 (“ICA”) are exempt from regulation by the FERC under the ICA as proprietary lines. The classification of a line as a proprietary line is a fact-based determination subject to FERC and court review. Accordingly, the classification and regulation of some of our gathering facilities and transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the EP Act 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have traditionally not been subject to FERC regulation, FERC has recently adopted and proposed regulations that may subject certain of our facilities to reporting and posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability. For more information regarding regulation of our operations, please see “Item 1. Business-Regulation of Operations”.
Index to Financial Statements We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances or hydrocarbons into the environment.
Our operations are subject to stringent and complex federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. (Please see “Item 1. Business-Our Operations”.) These laws include, for example, (1) the Clean Air Act and comparable state laws that impose obligations related to air emissions, (2) the RCRA, and comparable state laws that impose requirements for the handling, storage, treatment or disposal of solid and hazardous waste from our facilities, (3) the CERCLA and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which our hazardous substances have been transported for disposal, and (4) the Clean Water Act, and comparable state laws that regulate discharges of wastewater from our facilities to state and federal waters. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental laws, including CERCLA and analogous state laws, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
There is inherent risk of incurring environmental costs and liabilities in connection with our operations due to our handling of natural gas and other petroleum products, air emissions and water discharges related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, natural resource and property damages and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the cost of any remediation that may become necessary. In particular, we may incur expenditures in order to maintain compliance with legal requirements governing emissions of air pollutants from our facilities. We may not be able to recover all or any of these costs from insurance. Please see “Business-Environmental and Other Matters” for more information.
We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the DOT, through the PHMSA, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could do the most harm in “high consequence areas,” including high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators of covered pipelines to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
Index to Financial Statements We currently estimate that we will incur an aggregate cost of approximately $6.3 million for years 2008 through 2010 to implement necessary pipeline integrity management program testing along certain segments of our natural gas and NGL pipelines required by existing DOT and state regulations. This estimate does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. At this time, we cannot predict the ultimate cost of compliance with this regulation, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. Following this initial round of testing and repairs, we will continue our pipeline integrity testing programs to assess and maintain the integrity or our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of our pipelines.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition, potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.
Effective internal controls are necessary for us to provide timely and reliable financial reports and effectively prevent fraud. If we cannot provide timely and reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We continue to enhance our internal controls and financial reporting capabilities. These enhancements will require a significant commitment of additional resources, hiring additional personnel and developing formalized internal reporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could prevent us from timely and reliably reporting our financial results and may harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material effect on our business, results of operations, and financial condition.
Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.
The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on our industry in general, and on us in particular, is not known at this time.
Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for our products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.
Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.
Index to Financial Statements Risks Related to our Capital Structure
We have a substantial amount of indebtedness which may adversely affect our cash flow and our ability to operate our business, to comply with debt covenants and to make payments on our indebtedness.
We are highly leveraged. As of December 31, 2007, our total indebtedness, including the indebtedness of the Partnership, was $1,411.0 million, which represents approximately 52% of our capitalization. Our interest expense in 2007 was $142.6 million. In addition, as of December 31, 2007, we had issued approximately $272.4 million in irrevocable standby letters of credit under our $300 million senior secured synthetic letter of credit facility and the Partnership had issued $25.9 million in irrevocable standby letters of credit under its revolving credit facility, neither of which are reflected on our balance sheet. We may also utilize our $250 million senior secured revolving credit facility in the future.
Our substantial level of indebtedness increases the possibility that we may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect to our indebtedness. Our substantial indebtedness, combined with our lease and other financial obligations and contractual commitments, could have other important consequences, including the following:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
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satisfying our obligations with respect to our indebtedness may be more difficult and any failure to comply with the obligations of any of our debt instruments could result in an event of default under the agreements governing our indebtedness;
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we will need a portion of our cash flow to make interest payments on our debt, reducing the funds that would otherwise be available for operations and future business opportunities;
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our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
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our debt level may limit our flexibility in planning for, or responding to, changing business and economic conditions.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms, or at all. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources”.
Increases in interest rates could adversely affect our business.
We have significant exposure to increases in interest rates. As of December 31, 2007, our total indebtedness was $1,411.0 million, of which $1,161.0 million was at variable interest rates, In December 2007, the Partnership entered into interest rate swaps with an aggregate notional amount of $200.0 million. Our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates. Please see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk-Interest Rate Risk”.
Index to Financial Statements The terms of our senior secured credit facilities and the indenture governing our senior notes may restrict our current and future operations, particularly our ability to respond to changes in our business or to take certain actions.
The credit agreement governing our senior secured credit facilities and the indenture governing our senior notes contain, and any future indebtedness we incur would likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interests. The senior secured credit agreement and indenture governing our senior notes include covenants that, among other things, restrict our ability to:
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incur or guarantee additional indebtedness or issue preferred stock;
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pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;
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make investments;
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create restrictions on the payment of dividends or other distributions to us from our non-guarantor restricted subsidiaries;
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engage in transactions with our affiliates;
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sell assets, including capital stock of the subsidiaries;
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make certain acquisitions;
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transfer assets;
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enter into sale and lease back transactions;
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consolidate or merge; and
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incur liens.
The senior secured credit agreement also includes covenants that, among other things, restrict our ability to:
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prepay, redeem and repurchase certain debt, other than loans under the senior secured credit facilities;
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make capital expenditures;
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amend debt and other material agreements; and
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change business activities conducted by us.
In addition, our senior secured credit facilities require us to satisfy and maintain specified financial ratios and other financial condition tests, some of which will become more restrictive over time. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.
A breach of any of these covenants could result in an event of default under our senior secured credit facilities. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under the senior secured credit facilities to be immediately due and payable and terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders under our senior secured credit facilities could proceed against the collateral granted to them to secure that indebtedness. We have pledged substantially all of our assets as collateral under our senior secured credit facilities. If the lenders under our senior secured credit facilities accelerate the repayment of borrowings, we cannot assure you that we will have sufficient assets to repay our senior secured credit facilities, as well as our unsecured indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.
Index to Financial Statements
Item 1B.
Item 1B. Unresolved Staff Comments
None
Item 2.
Item 2. Properties
A description of our properties is contained in Item 1 of this Annual Report.
Our principal executive offices are located at 1000 Louisiana Street, Suite 4300, Houston, Texas 77002 and our telephone number is 713-584-1000.
Item 3.
Item 3. Legal Proceedings
We are a party to various legal proceedings and/or regulatory proceedings and certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against us. We believe all such matters are without merit or involve amounts, which, if resolved unfavorably, would not have a material effect on our financial position, results of operations, or cash flows, except for the items more fully described below.
In May 2002, Apache Corporation (“Apache”) filed suit in Texas state court against Versado Gas Processors, LLC (“Versado”), as purchaser and processor of Apache’s gas, and Dynegy Midstream Services, Limited Partnership (now known as Targa Midstream Services Limited Partnership, a wholly-owned subsidiary of ours (“TMSLP”)), as operator, of the Versado assets in New Mexico (“Versado Defendants”) alleging (i) excessive field losses of natural gas from wells owned by the plaintiff, (ii) that the Versado Defendants engaged in certain transactions with affiliates, resulting in the Versado Defendants not receiving fair market value when it sold gas and liquids, and (iii) that the formula for calculating the amount the Versado Defendants received from its buyers of gas and liquids is flawed since it is based on gas price indices that were allegedly manipulated. At trial, the jury found in favor of Apache on the lost gas claim, awarding approximately $1.6 million in damages. Apache’s claims with respect to the alleged “sham” transactions and index manipulation, among others, were severed by the trial court and abated for a future trial. The parties settled the severed lawsuit in May 2007.
In May 2004, the trial court granted the Versado Defendants’ motion to set aside the jury verdict on the lost gas claim and vacated the jury award to Apache. Apache filed its notice of appeal with the 14th Court of Appeals of Houston in October 2004 and its appellate brief in December 2004.
In September 2006, the Court of Appeals reinstated the jury verdict in Apache’s favor on the issue of lost gas and also awarded Apache legal fees and interest, bringing the total award against the Versado Defendants to approximately $2.7 million. In October 2006, the Versado Defendants filed a motion for rehearing with the Court of Appeals. After rehearing, the Court of Appeals affirmed its decision reinstating the original jury verdict in Apache’s favor. With interest and attorneys fees that verdict stands at approximately $2.9 million.
In January 2007, the Versado Defendants filed their petition for review with the Supreme Court of Texas and in March 2007, Apache filed its conditional petition for review with the Supreme Court of Texas. At the request of the Supreme Court of Texas, the Versado Defendants and Apache filed responses to the opposing party’s petition in June 2007. Pursuant to an additional request from the Supreme Court of Texas, the Versado Defendants and Apache filed briefs on the merits on October 29, 2007. The Versado Defendants and Apache filed responses to each other’s brief on December 14, 2007, and then filed replies to the responses on December 31, 2007. The appeal is currently pending before the Supreme Court of Texas.
As a result of damage caused by Hurricane Rita, TMSLP’s West Cameron 229A platform sank in late September 2005. On November 12, 2005, the submerged wreckage was struck by an integrated tug-barge, the M/T Rebel, owned by K-Sea Transportation (“K-Sea”). As much as 25,000 barrels of No. 6 fuel oil may have
Index to Financial Statements
entered Gulf of Mexico waters as the barge dragged part of the platform debris approximately three (3) miles from the sunken platform location. After receiving a letter from K-Sea threatening to hold TMSLP liable for all damages, TMSLP filed suit in federal district court in Galveston, Texas on November 21, 2005, seeking to hold K-Sea responsible for damage to the platform. In June 2007, the case was transferred to the federal district court in Houston, Texas.
In January 2006, Rios Energy (“Rios”), owner of the oil being transported in the barge, intervened in the existing suit and filed a new suit in the same federal court against both TMSLP and K-Sea alleging their negligence caused the loss of and damage to Rios’ oil. On March 8, 2006, K-Sea filed a counterclaim against TMSLP seeking to recover its alleged damages in excess of $90 million. In order to resolve K-Sea’s concerns over security for its claims, we agreed to provide a guarantee to K-Sea pursuant to which we would satisfy any final, non-appealable judgment or settlement against TMSLP if TMSLP is unable to pay any judgment against it.
On December 10, 2007, after a trial on the merits, the court concluded that K-Sea’s negligence caused 60% of the damages suffered by K-Sea and TMSLP. The court assessed 40% fault against TMSLP. Final judgment was entered on December 14, 2007. During trial, TMSLP and Rios settled their dispute.
For purposes of the trial, K-Sea and TMSLP stipulated to the amount of damages for K-Sea in the amount of $62.3 million and for TMSLP in the amount of $400,000. The parties also agreed that prejudgment interest, if any, would accrue at the rate of 4.45% simple interest per annum commencing May 1, 2006.
TMSLP and K-Sea entered into an agreement regarding the judgment, pursuant to which (i) TMSLP paid K-Sea $26.5 million on January 16, 2008, (ii) K-Sea acknowledged that the judgment has been satisfied, (iii) K-Sea released TMSLP and us from the guaranty, and (iv) TMSLP and K-Sea agreed not to appeal the judgment. TMSLP’s entire liability for K-Sea’s claims was covered by insurance, except for a self-insured retention amount.
Prior to trial, K-Sea submitted a claim under the Oil Pollution Act of 1990 (“OPA 90”) seeking reimbursement of removal costs and cleanup damages from the Oil Spill Liability Trusts Fund (“Trust Fund”). K-Sea included the same removal costs and cleanup damages as a portion of its request for relief at the trial before the federal district court. K-Sea has indicated that it will adjust its request for reimbursement from the Trust Fund to reflect any recovery of removal and cleanup damages from TMSLP but has not yet done so. In the event K-Sea receives a reimbursement from the Trust Fund, the Trust Fund may seek to recover from TMSLP some or all of any reimbursement to K-Sea. TMSLP anticipates that liability to the Trust Fund, if any, would be covered by insurance. TMSLP intends to contest liability in any action or proceeding to recover amounts reimbursed to K-Sea, but we can give no assurances regarding the outcome of any such action or proceeding.
On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including us, three other Targa entities and private equity funds affiliated with Warburg Pincus, seeking damages from the defendants. The suit alleges that we and private equity funds affiliated with Warburg Pincus, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase the SAOU System from ConocoPhillips, and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from our competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. On October 2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. We have agreed to indemnify the Partnership for any claim or liability arising out of the WTG suit. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal. We will contest any appeal filed by WTG, but can give no assurances regarding the outcome of the proceeding.
Index to Financial Statements For a discussion of the state of New Mexico’s Environment Department’s inspection of Versado’s Eunice gas processing plant, please see Note 11 to our Consolidated Financial Statements beginning on page of this Annual Report.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
None
Index to Financial Statements PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is not listed on a national securities exchange or in an automated inter-dealer quotation system of a national securities association and there is no established public trading market for our common stock. All of our common stock is held indirectly by Targa Investments.
We did not declare a cash dividend to our stockholder during our 2007, 2006 or 2005 fiscal years. On March 7, 2008, we paid a $50.0 million cash dividend to our stockholder. For a discussion of the dividend and of the restrictions on our ability to pay cash dividends, please see Note 7 and Note 17 to our Consolidated Financial Statements beginning on Page of this Annual Report.
Item 6.
Item 6. Selected Financial Data
SELECTED HISTORICAL FINANCIAL AND OPERATING DATA
The following table summarizes selected historical financial and operating data of Targa and the predecessor for the periods and as of the dates indicated. The selected historical financial information included in this Annual Report reflects the results of operations of Targa as of and for the years ended December 31, 2007, 2006, 2005 and 2004, and is derived from the audited consolidated financial statements of Targa. Targa’s consolidated financial results for the year ended December 31, 2004 includes the results of operations for the eight and a half month period commencing with its April 16, 2004 acquisition of the predecessor business from ConocoPhillips, and the activities of Targa for the period from January 1 to April 15, 2004.
The selected combined historical financial information of the predecessor as of and for the year ended December 31, 2003 and as of and for the three and a half months ended April 15, 2004 is derived from the audited financial statements of the predecessor. The historical financial statements of the predecessor were prepared on a going-concern basis, as if certain midstream assets of ConocoPhillips, which Targa acquired on April 16, 2004, had existed as an entity separate from ConocoPhillips during the periods presented. The assets acquired from ConocoPhillips were not a separate legal entity during the periods presented. During the periods presented, ConocoPhillips charged the predecessor operations a portion of its corporate support costs, including engineering, legal, treasury, planning, environmental, tax, auditing, information technology and other corporate services, based on usage, actual costs or other allocation methods considered reasonable by ConocoPhillips’ management. Accordingly, expenses included in the predecessor’s financial statements may not be indicative of the level of expenses that might have been incurred had the predecessor been operating as a separate stand-alone company.
This information should be read together with and is qualified in its entirety by reference to, the historical combined financial statements and the accompanying notes included elsewhere in this Annual Report. Please see “Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
We are a Delaware corporation formed in 2004 by our management team and Warburg Pincus LLC to acquire, own and operate assets in the midstream natural gas business.
Our gathering and processing assets are located primarily in the Permian Basin in west Texas and southeast New Mexico, the Louisiana Gulf Coast primarily accessing the offshore region of Louisiana, and, through the Partnership, the Fort Worth Basin in north Texas, the Permian Basin in west Texas and the onshore region of the Louisiana Gulf Coast. Our NGL logistics and marketing assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana, with terminals and transportation assets across the United States.
We own interests in or operate approximately 11,000 miles of natural gas pipelines and approximately 700 miles of NGL pipelines, with natural gas gathering systems covering approximately 14,500 square miles and 22 natural gas processing plants with access to natural gas supplies in the Permian Basin, north Texas, onshore southern Louisiana and the Gulf of Mexico. Additionally, we have an integrated NGL logistics and marketing business, with 16 storage, marine and transport terminals with above ground NGL storage capacity of approximately 900 MBbl, net NGL fractionation capacity of approximately 300 MBbl/d and 43 owned and operated storage wells with a net storage capacity of approximately 67 MMBbl.
Index to Financial Statements We conduct our business operations through two divisions and report our results of operations under four segments: Our Natural Gas Gathering and Processing division, which includes the Partnership, is a single segment consisting of our natural gas gathering and processing facilities, as well as certain fractionation capability integrated within those facilities; and the NGL Logistics and Marketing division, which consists of three segments: Logistics Assets, NGL Distribution and Marketing, and Wholesale Marketing.
Factors That Significantly Affect Our Results
Our results of operations are substantially impacted by changes in commodity prices as well as increases and decreases in the volume of natural gas that we gather and transport through our pipeline systems, which we refer to as throughput volume. Throughput volumes and capacity utilization rates generally are driven by wellhead production, our competitive position on a regional basis and more broadly by prices and demand for natural gas and NGLs.
Our processing contract arrangements can have a significant impact on our profitability. We process natural gas under a combination of percent-of-proceeds contracts (representing approximately 43% of our throughput volumes), fee-based contracts (representing approximately 22% of our throughput volumes), wellhead purchases / keep-whole contracts (representing approximately 10% of our throughput volumes) and hybrid contracts (representing approximately 25% of our throughput volumes), each of which, other than fee-based contracts, exposes us to commodity price risk. We attempt to mitigate this risk through hedging activities which can materially impact our results of operations. Please see “Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, and interest rates, as well as nonpayment or nonperformance by our customers.
Commodity Price Risk
A significant portion of our revenue is derived from percent-of-proceeds contracts under which we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. We also enter into hedges with certain of our customers and for operational purposes. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.
The primary purpose of our commodity risk management activities is to hedge our exposure to commodity price risk inherent in our contract mix and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of December 31, 2007, we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2007 through 2012 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are covered by our hedges is approximately 60% to 80% through 2009 and decreases over time. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs, and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge the commodity price exposure associated with additional expected equity commodity volumes without creating volumetric risk. We intend to continue to manage our exposure to commodity prices in the future by entering into similar hedge transactions using swaps, collars, purchased puts (or floors) or other hedge instruments as market conditions permit.
We have tailored our hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. Our NGL hedges cover baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Additionally, our NGL hedges are based on published index prices for delivery at Mont Belvieu, and our natural gas hedges are based on published index prices for delivery at Waha, Houston Ship Channel and Mid-Continent, which closely approximate our actual NGL and natural gas delivery points. We hedge a portion of our condensate sales using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.
Our commodity price hedging transactions are typically documented pursuant to a standard International Swap Dealers Association (“ISDA”) form with customized credit and legal terms. Our principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations in connection with substantially all of these hedging transactions, and any additional credit exposure due to a rise in natural gas and NGL prices relative to the fixed prices set forth in the hedges, are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit, or other additional collateral to secure these hedges at any time even if our
Index to Financial Statements
counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not create credit exposure to us for our counterparties.
We had the following open commodity derivatives at December 31, 2007:
Natural Gas
NGL
Index to Financial Statements At December 31, 2007, the Partnership had the following open derivatives designated as hedges:
Natural Gas
NGL
Index to Financial Statements Condensate
Interest Rate Risk
We are exposed to interest rate risk primarily through our borrowing activities. As of December 31, 2007, we had approximately $1,411 million of indebtedness, of which $250 million was at fixed interest rates and $1,161 million was at variable interest rates.
In December 2007, the Partnership entered into interest rate swaps with a notional amount of $200 million. At December 31, 2007, the Partnership had the following open interest rate swaps:
Each swap fixes the three month LIBOR rate, prior to credit margin, at the indicated rates for the specified notional amount of related debt outstanding over the term of each swap agreement. We have designated all interest rate swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the interest rate swaps are deferred in accumulated other comprehensive income until the interest expense on the related debt is recognized in earnings. A hypothetical increase of 100 basis points in the underlying interest rate, after taking into account the Partnership’s interest rate swaps, would increase our annual interest expense by $9.6 million.
Credit Risk
We are subject to risk of losses resulting from nonpayment or nonperformance by our customers. We monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our credit policy.
Item 8.
Item 8. Financial Statements and Supplementary Data
Our consolidated financial statements, together with the report of our independent registered public accounting firm begin on page of this report.
Index to Financial Statements
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item 9A.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures were effective to provide reasonable assurance that (i) all material information relating to us required to be included in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and (ii) such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.
Item 9B.
Item 9B. Other Information
Not applicable
Index to Financial Statements Part III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The following table sets forth certain information with respect to our executive officers and directors as of March 24, 2008.
Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.
Rene R. Joyce has served as a director and Chief Executive Officer of Targa since its formation in February 2004 and of the general partner of the Partnership since October 2006, and was a consultant for the Targa predecessor company during 2003. He is also a member of the supervisory directors of Core Laboratories N.V. Mr. Joyce served as a consultant in the energy industry from 2000 through 2003 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. Mr. Joyce served as President of onshore pipeline operations of Coral Energy, LLC, a subsidiary of Shell Oil Company (“Shell”) from 1998 through 1999, and President of energy services of Coral Energy Holding, L.P. (“Coral”), a subsidiary of Shell which was the gas and power marketing joint venture between Shell and Tejas Gas Corporation (“Tejas”) during 1999. Mr. Joyce served as President of various operating subsidiaries of Tejas, a natural gas pipeline company, from 1990 until 1998 when Tejas was acquired by Shell.
Joe Bob Perkins has served as President of Targa since February 2004 and of the general partner of the Partnership since October 2006, and was a consultant for the Targa predecessor company during 2003. Mr. Perkins also served as a consultant in the energy industry from 2002 through 2003 and was an active partner in RTM Media (an outdoor advertising firm) during such time period. Mr. Perkins served as President and Chief Operating Officer for the Wholesale Businesses, Wholesale Group, and Power Generation Group of Reliant Resources, Inc. and its parent/predecessor companies, from 1998 to 2002, and as Vice President, Corporate Planning and Development, of Houston Industries from 1996 to 1998. He served as Vice President, Business Development, of Coral from 1995 to 1996 and as Director, Business Development, of Tejas from 1994 to 1995. Prior to 1994, Mr. Perkins held various positions with the consulting firm of McKinsey & Company and with an exploration and production company.
James W. Whalen has served as President-Finance and Administration of Targa since January 2006 and of the general partner of the Partnership since October 2006, and as a director of Targa since May 2004 and of the general partner of the Partnership since February 2007. Since November 2005, Mr. Whalen has served as President-Finance and Administration for various Targa subsidiaries. Between October 2002 and October 2005, Mr. Whalen served as the Senior Vice President and Chief Financial Officer of Parker Drilling Company.
Index to Financial Statements
Between January 2002 and October 2002, he was the Chief Financial Officer of Diversified Diagnostic Products, Inc. He served as Chief Commercial Officer of Coral from February 1998 through January 2000. Previously, he served as Chief Financial Officer for Tejas from 1992 to 1998. Mr. Whalen is also a director of Parker Drilling Company and Equitable Resources, Inc.
Roy E. Johnson has served as Executive Vice President of Targa since April 2004 and of the general partner of the Partnership since October 2006, and was a consultant for the Targa predecessor company during 2003. Mr. Johnson also served as a consultant in the energy industry from 2000 through 2003 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. He served as Vice President, Business Development and President of the International Group, of Tejas from 1995 to 2000. In these positions, he was responsible for acquisitions, pipeline expansion and development projects in North and South America. Mr. Johnson served as President of Louisiana Resources Company, a company engaged in intrastate natural gas transmission, from 1992 to 1995. Prior to 1992, Mr. Johnson held various positions with a number of different companies in the upstream and downstream energy industry.
Michael A. Heim has served as Executive Vice President and Chief Operating Officer of Targa since April 2004 and of the general partner of the Partnership since October 2006, and was a consultant for the Targa predecessor company during 2003. Mr. Heim also served as a consultant in the energy industry from 2001 through 2003 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. Mr. Heim served as Chief Operating Officer and Executive Vice President of Coastal Field Services, a subsidiary of The Coastal Corp. (“Coastal”) a diversified energy company, from 1997 to 2001 and President of Coastal States Gas Transmission Company from 1997 to 2001. In these positions, he was responsible for Coastal’s midstream gathering, processing, and marketing businesses. Prior to 1997, he served as an officer of several other Coastal exploration and production, marketing, and midstream subsidiaries.
Jeffrey J. McParland has served as Executive Vice President and Chief Financial Officer of Targa since April 2004 and of the general partner of the Partnership since October 2006, and was a consultant for the Targa predecessor company during 2003. Mr. McParland served as a director of the general partner of the Partnership between October 2006 and February 2007. Mr. McParland served as Treasurer of Targa from April 2004 until May 2007 and of the general partner of the Partnership from October 2006 until May 2007. Mr. McParland served as Secretary of Targa between February 2004 and May 2004, at which time he was elected as Assistant Secretary. Mr. McParland served as Senior Vice President, Finance, Dynegy Inc., a company engaged in power generation, the midstream natural gas business and energy marketing, from 2000 to 2002. In this position, he was responsible for corporate finance and treasury operations activities. He served as Senior Vice President, Chief Financial Officer and Treasurer of PG&E Gas Transmission, a midstream natural gas and regulated natural gas pipeline company, from 1999 to 2000. Prior to 1999, he worked in various engineering and finance positions with companies in the power generation and engineering and construction industries.
Paul W. Chung has served as Executive Vice President, General Counsel and Secretary of Targa since May 2004 and of the general partner of the Partnership since October 2006. Mr. Chung served as Executive Vice President and General Counsel of Coral from 1999 to April 2004; Shell Trading North America Company, a subsidiary of Shell, from 2001 to April 2004; and Coral Energy, LLC from 1999 to 2001. In these positions, he was responsible for all legal and regulatory affairs. He served as Vice President and Assistant General Counsel of Tejas from 1996 to 1999. Prior to 1996, Mr. Chung held a number of legal positions with different companies, including the law firm of Vinson & Elkins L.L.P.
Charles R. Crisp has served as a director of Targa since February 2004. Mr. Crisp was President and Chief Executive Officer of Coral Energy, LLC, a subsidiary of Shell Oil Company from 1999 until his retirement in November 2000, and was President and Chief Operating Officer of Coral from January 1998 through February 1999. Prior to this, Mr. Crisp served as President of the power generation group of Houston Industries and,
Index to Financial Statements
between 1988 and 1996, as President and Chief Operating Officer of Tejas. Mr. Crisp is also a director of AGL Resources Inc., EOG Resources Inc. and IntercontinentalExchange, Inc.
Joe B. Foster has served as a director of Targa since May 2004. Mr. Foster was founder of Newfield Exploration Company and most recently served as the Non-Executive Chairman from January 2000 to May 2005, at which time he retired. He was previously Chief Executive Officer and Chairman of the Board of Newfield from May 1999 to January 2000, and President and Chief Executive Officer from 1989 to January 2000.
In Seon Hwang has served as a director of Targa since May 2006. Mr. Hwang is a principal in the Energy Group of Warburg Pincus LLC, where he has been employed since 2004. Prior to joining Warburg Pincus, Mr. Hwang worked at GSC Partners, a distressed investment firm, from 2002 until 2004, the M&A group at Goldman Sachs from 1998 to 2000, and the Boston Consulting Group from 1997 to 1998. He is also a director of APT Generation, CoalTek, Competitive Power Ventures and Floridian Natural Gas Storage Company. He also serves on the investment committee of Sheridan Production Partners LLC.
Chansoo Joung has served as a Director of Targa since December 2005 and of the general partner of the Partnership since February 2007. Mr. Joung is a Member and Managing Director of Warburg Pincus LLC, where he has been employed since 2005, and became a partner of Warburg Pincus & Co. in 2005. Prior to joining Warburg Pincus, Mr. Joung was head of the Americas Natural Resources Group in the investment banking division of Goldman Sachs. He joined Goldman Sachs in 1987 and served in the Corporate Finance and Mergers and Acquisitions departments and also founded and led the European Energy Group. He is a director of APT Generation, Broad Oak Energy, Ceres, Inc. and Floridian Natural Gas Storage Company.
Peter R. Kagan has served as a director of Targa since February 2004 and of the general partner of the Partnership since February 2007. Mr. Kagan is a Managing Director of Warburg Pincus LLC, where he has been employed since 1997, and became a partner of Warburg Pincus & Co. in 2002. He is a member of Warburg Pincus’ Executive Management Group. He is also a director of Antero Resources Corporation, Broad Oak Energy, Inc., Cambriam Energy, Fairfield Energy Limited, Laredo Petroleum, MEG Energy Corp. and Universal Space Network, Inc.
Chris Tong has served as a director of Targa since January 2006. Mr. Tong is a Senior Vice President and Chief Financial Officer of Noble Energy, Inc. and has held this position since January 2005. He served as Senior Vice President and Chief Financial Officer for Magnum Hunter Resources, Inc. from August 1997 until December 2004. Prior thereto, he was Senior Vice President of Finance of Tejas Acadian Holding Company and its subsidiaries, including Tejas Gas Corp., Acadian Gas Corporation and Transok, Inc., all of which were wholly-owned subsidiaries of Tejas Gas Corporation. Mr. Tong held these positions from August 1996 until August 1997, and had served in other treasury positions with Tejas since August 1989.
Board of Directors
Our board of directors (the “Board”) consists of eight members. Please see “Item 13. Certain Relationships and Related Transactions, and Director Independence-Stockholders’ Agreement” for a description of arrangements pursuant to which directors of Targa Investments are selected.
Board Independence
We do not have securities listed on a national securities exchange or in an automated inter-dealer quotation system of a national securities association and, as such, are not subject to the director independence requirements of such an exchange or association. In addition, we are a controlled company as defined in Rule 4350(c)(5) of The NASDAQ Stock Market LLC (“NASDAQ”). If our securities were listed on NASDAQ, then, as a controlled company, we would be exempt from NASDAQ’s independence requirements as they relate to the composition of
Index to Financial Statements
the board of directors and committees thereof. However, for audit committee purposes, we would be subject to the committee independence requirements of the Securities Exchange Act of 1934.
The Board has made no formal determination as to the independence of our directors because we are not subject to independence requirements. Nonetheless, if NASDAQ’s independence requirements applied to us, it is likely that Messrs. Kagan, Joung, Hwang, Tong, Crisp and Foster would be determined to be independent for purposes of serving on the Board.
Board Committees
The Board has appointed three committees: an audit committee (the “Audit Committee”), a compensation committee (the “Compensation Committee”) and a risk management committee. The members of the Audit Committee are Messrs. Joung, Hwang and Tong, and the members of the Compensation Committee are Messrs. Kagan, Crisp and Foster.
The Board has made no formal determination as to the independence of our directors for purposes of committee membership because we are not subject to independence requirements. If NASDAQ’s committee independence requirements applied to us (including the applicable rules and regulations of the Exchange Act), then it is likely that Mr. Tong would be determined to be independent and that Messrs. Hwang and Joung would be determined not to be independent for purposes of serving on the audit committee. Please see “Item 13. Certain Relationships and Related Transactions, and Director Independence-Relationships with Warburg Pincus” for a discussion of Warburg Pincus’ relationships with us.
The Board has determined that at least one member of the Audit Committee meets the qualifications of an “audit committee financial expert” in accordance with rules established by the SEC. Chris Tong is the director who has been determined to be an audit committee financial expert.
Code of Ethics
We have adopted a Code of Ethics for our Chief Executive Officer and Senior Financial Officers (the “Code of Ethics”), which applies to our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Controller and all other senior financial and accounting officers. In accordance with the disclosure requirements of applicable law or regulation, we intend to disclose any amendment to, or waiver from, any provision of the Code of Ethics under Item 10 of a current report on Form 8-K.
We make available, free of charge within the “Corporate Governance” section of our website at www.targaresources.com, and in print to any shareholder who so requests, the Code of Ethics and the Audit Committee Charter. Requests for print copies may be directed to: Investor Relations, Targa Resources, Inc., 1000 Louisiana, Suite 4300, Houston, Texas 77002, or telephone (713) 584-1000. The information contained on, or connected to, our internet website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report that we file with, or furnish to the SEC.
Item 11.
Item 11. Executive Compensation
Compensation Discussion and Analysis
The following discussion and analysis contains statements regarding our and our executive officers’ future performance targets and goals. These targets and goals are disclosed in the limited context of our compensation programs and should not be understood to be statements of management’s expectations or estimates of results or other guidance.
Overview
Targa Resources Investments Inc. (“Targa Investments”) is our indirect parent, with its only significant asset being its ownership of all of the outstanding capital stock of an intermediate holding company, whose sole asset
Index to Financial Statements
is its ownership of all of our outstanding capital stock. As our parent, Targa Investments has ultimate decision making authority with respect to the compensation of our executive officers identified in the Summary Compensation Table (“named executive officers”). Under the terms of the Targa Investments Amended and Restated Stockholders’ Agreement, as amended (the “Stockholders’ Agreement”), compensatory arrangements with our named executive officers are required to be submitted to a vote of Targa Investments’ stockholders unless such arrangements have been approved by the Compensation Committee of Targa Investments (the “TRII Compensation Committee”). As such, the TRII Compensation Committee is responsible for overseeing the development of an executive compensation philosophy, strategy and framework for our named executive officers that is based on Targa Investments’ business priorities.
The following Compensation Discussion and Analysis describes the material elements of compensation for our named executive officers. These elements, and the TRII Compensation Committee’s decisions with respect to determinations on payments, are not subject to approval by our board of directors (the “Targa Board”). However, members of the Targa Board, including its compensation committee, are members of the board of directors of Targa Investments (the “Targa Investments Board”), including the TRII Compensation Committee.
Compensation Philosophy
The TRII Compensation Committee believes that total compensation of executives should be competitive with the market in which we compete for executive talent-the energy industry and midstream natural gas companies. The following compensation objectives guide the TRII Compensation Committee in its deliberations about executive compensation matters:
•
Provide a competitive total compensation program that enables us to attract and retain key executives;
•
Ensure an alignment between our strategic and financial performance and the total compensation received by our named executive officers;
•
Provide compensation for performance relative to expectations and our peer group;
•
Ensure a balance between short-term and long-term compensation while emphasizing at-risk, or variable, compensation as a valuable means of supporting our strategic goals and aligning the interests of our named executive officers with those of our shareholders; and
•
Ensure that our total compensation program supports our business objectives and priorities.
As a result of this philosophy, we do not pay for perquisites for any of our named executive officers, other than parking subsidies.
The Role of Peer Groups and Benchmarking
Our chief executive officer (the “CEO”), president and chief financial officer (collectively, “Senior Management”) review compensation practices at peer companies at a general level to ensure that our total compensation is within a comparable range. In addition, when evaluating compensation levels for each named executive officer, the TRII Compensation Committee reviews publicly available compensation data for executives in our peer group, compensation surveys, and compensation levels for each named executive officer with respect to their roles with the Company and levels of responsibility, accountability and decision-making authority. Senior Management and the TRII Compensation Committee, however, do not attempt to set compensation components to meet specific benchmarks, such as salaries “above the median” or total compensation “at the 50th percentile.”
For 2007, Senior Management identified peer companies that competed with us in the midstream natural gas industry and reviewed compensation information filed by the peer companies with the SEC. The peer group reviewed by Senior Management for 2007 consisted of the following companies: Atlas America, Copano Energy,
Index to Financial Statements
Crosstex Energy, DCP Midstream, Enbridge Energy Partners, Energy Transfer Partners, Magellan Midstream, MarkWest Energy Partners, Martin Midstream, Oneok Partners, Plains All American Pipeline, Regency Energy Partners, TEPPCO Partners and Williams Energy Partners.
Senior Management intends to review our compensation practices and performance against peer companies on an annual basis.
Role of Senior Management in Establishing Compensation for Named Executive Officers
Typically, Senior Management consults with compensation consultants and reviews market data to determine relevant compensation levels and compensation program elements. Based on these consultations and a review of publicly available information for the peer group, Senior Management submits a proposal to the chairman of the TRII Compensation Committee. The proposal includes a recommendation of base salary, annual bonus and any new long term compensation to be paid or awarded to executive officers and employees. The chairman of the TRII Compensation Committee considers this proposal (which he may request Senior Management to modify based on information available to him or that he requests of Senior Management) and his resulting recommendation is then submitted to the TRII Compensation Committee for consideration. The final compensation decisions are reported to the Targa Investments Board.
Our Senior Management has no other role in determining compensation for our executive officers, but our executive officers are delegated the authority and responsibility to determine the compensation for all other employees.
Elements of Compensation for Named Executive Officers
The compensation philosophy for our executive officers centers on long-term equity awards to attract, motivate and retain our executive team. For this reason, in connection with our formation in 2004 and with the DMS Acquisition in 2005, the named executive officers were granted restricted stock and options to purchase restricted stock of Targa Investments. As a result, executive compensation has been weighted toward long-term equity awards. Our executive officers have also invested a significant portion of their personal investable assets in the equity of Targa Investments. Within this context, elements of compensation for our named executive officers are the following: (i) annual base salary; (ii) discretionary annual cash awards; (iii) performance awards under Targa Investments’ long-term incentive plan, (iv) contributions under our 401(k) and profit sharing plan; and (v) participation in our health and welfare plans on the same basis as all of our other employees.
Base Salary. The base salaries for our named executive officers are set and reviewed annually by the TRII Compensation Committee. The salaries are based on historical salaries paid to our named executive officers for services rendered to us, the extent of their equity ownership in Targa Investments, market data and responsibilities of our named executive officers. Base salaries are intended to provide fixed compensation comparable to market levels for similarly situated executive officers.
Annual Cash Incentives. The discretionary annual cash awards paid to our named executive officers are designed to supplement the annual base salary of our named executive officers so that, on a combined basis, the annual cash compensation for our named executive officers yield competitive cash compensation levels and drive performance in support of our business strategies. It is Targa Investments’ general policy to pay these awards prior to the end of the first quarter of the next fiscal year. The payment of individual cash bonuses to employees, including our named executive officers, are subject to the sole discretion of the TRII Compensation Committee.
Our 2007 Annual Incentive Plan (the “Bonus Plan”) was adopted on January 23, 2007 to reward our employees for contributions towards our achievement of financial and operational goals approved by the TRII Compensation Committee and to aid us in retaining and motivating employees. Under the Bonus Plan and similar plans expected to be adopted in subsequent years, a discretionary cash bonus pool is expected to be funded annually
Index to Financial Statements
based on our achievement of certain strategic, financial and operational objectives recommended by our CEO and approved by the TRII Compensation Committee. The Bonus Plan is administered by the TRII Compensation Committee, which considers certain recommendations by the CEO. Following the end of each year, the CEO recommends to the TRII Compensation Committee the total amount of cash to be allocated to the bonus pool based upon our overall performance relative to these objectives. Upon receipt of the CEO’s recommendation, the TRII Compensation Committee, in its sole discretion, determines the total amount of cash to be allocated to the bonus pool. Additionally, the TRII Compensation Committee, in its sole discretion, determines the amount of the cash bonus award to each of our executive officers, including the CEO. The executive officers determine the amount of the cash bonus pool to be allocated to certain of our departments, groups and employees (other than our executive officers) based on the recommendation of their supervisors, managers and line officers.
For 2007, the TRII Compensation Committee aligned the cash bonus pool with the following six key business priorities: (i) involving employees in improving our businesses; (ii) proactively and aggressively investing in our businesses and developing the pipeline of projects and opportunities; (iii) bringing closure to hurricane repair and recovery; (iv) identifying and pursuing new opportunities in the downstream sector; (v) debt reduction and achievement of capital structure goals; and (vi) executing on all fronts (including the financial business plan). The Bonus Plan established goals that the TRII Compensation Committee will consider when making awards under the Bonus Plan and also established the following overall threshold, target and maximum levels for the Company’s bonus pool: 50% of the cash bonus pool for the threshold level; 100% for the target level and 200% for the maximum level. The funding of the cash bonus pool and the payment of individual cash bonuses to employees, including our named executive officers, are subject to the sole discretion of the TRII Compensation Committee.
LTIP Awards. In connection with the initial public offering of the Partnership, Targa Investments issued to our named executive officers cash-settled performance unit awards linked to the performance of the Partnership’s common units that will vest in August of 2010, with the amounts vesting under such awards dependent on the Partnership’ performance compared to a peer-group consisting of the Partnership and 12 other publicly traded partnerships. These performance unit awards are made pursuant to a plan adopted by Targa Investments.
Retirement Benefits. We offer eligible employees a Section 401(k) tax-qualified, defined contribution plan to enable employees to save for retirement through a tax-advantaged combination of employee and Company contributions and to provide employees the opportunity to directly manage their retirement plan assets through a variety of investment options. Our employees, including our named executive officers, are eligible to participate in our 401(k) plan and may elect to defer up to 30% of their annual compensation on a pre-tax basis and have it contributed to the plan, subject to certain limitations under the Internal Revenue Code. In addition, we make the following contributions to the 401(k) Plan for the benefit of our employees, including our named executive officers: (i) 3% of the employees eligible compensation; (ii) an amount equal to the employee’s contributions to the 401(k) Plan up to 5% of the employee’s eligible compensation and (iii) a discretionary amount depending on Targa’s performance.
Health and Welfare Benefits. All full-time employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, health, life insurance, and dental coverage and disability insurance.
Perquisites. We believe that the elements of executive compensation should be tied directly or indirectly to the actual performance of the Company. It is the TRII Compensation Committee’s policy not to pay for perquisites for any of our named executive officers, other than parking subsidies.
Relation of Compensation Elements to Compensation Philosophy
Our named executive officers, other senior managers and directors, through a combination of personal investment and equity grants, own approximately 20% of the fully diluted equity of Targa Investments. The TRII Compensation Committee believes that the elements of its compensation program fit the established overall
Index to Financial Statements
compensation objectives in the context of management’s substantial ownership of our parent’s equity, which allows Targa to provide competitive compensation opportunities to align and drive the performance of the named executive officers in support of Targa Investments’ and our own business strategies and to attract, motivate and retain high quality talent with the skills and competencies required by Targa Investments and us.
Application of Compensation Elements
Base Salary. In 2007, base salaries for our named executive officers were generally lower than similar positions in our peer group.
Annual Cash Incentives. In January 2008, the TRII Compensation Committee approved a cash bonus pool of 200% of the target level for the employee group, including our named executive officers, under the Bonus Plan for performance during 2007. The executive officers received bonus awards equivalent to the same percentage of target as the Company bonus pool. The TRII Compensation Committee paid maximum level bonuses under the Bonus Plan in recognition of outstanding organizational performance in 2007. Our named executive officers received cash bonuses under the Bonus Plan based on our achievement of overall goals in 2007 as follows:
Equity / Stock Option Exchange. In May 2007, options relating to Targa Investments’ preferred stock held by the employees, including the named executive officers, were exchanged for (i) a grant of 10 shares of Targa Investments common stock for each option and (ii) a right to receive a cash payment in the amount of $27.69 for each option. Except for the grant of shares in the stock option exchange, the TRII Compensation Committee did not award additional equity to our named executive officers.
Long-term Cash Incentives. In connection with the Partnership’s initial public offering in February 2007, Targa Investments issued to key employees and the executive officers of the General Partner cash-settled performance unit awards linked to the performance of the Partnership’s common units that will vest in August of 2010, with the amounts vesting under such awards dependent on the Partnership’s performance compared to a peer-group consisting of the Partnership and 12 other publicly traded partnerships. The peer group companies for 2007 were: Energy Transfer Partners, Oneok Partners, Copano Energy, DCP Midstream, Regency Energy Partners, Plains All American Pipeline, MarkWest Energy Partners, Williams Energy Partners, Magellan Midstream, Martin Midstream, Enbridge Energy Partners, Crosstex Energy and Targa Resources Partners LP. These performance unit awards were made pursuant to a plan adopted by Targa Investments and administered by Targa Resources LLC. The TRII Compensation Committee has the ability to modify the peer-group in the event a peer company is no longer determined to be one of the Partnership’s peers. The cash settlement value of each performance unit award will be the value of an equivalent Partnership common unit at the time of vesting plus associated distributions over the vesting period, which may be higher or lower than the Partnership’s common unit price at the time of the award. If the Partnership’s performance equals or exceeds the performance for the median of the group, 100% of the award will vest. If the Partnership ranks tenth in the group, 50% of the award will vest, between tenth and seventh, 50% to 100% will vest, and for a performance ranking lower than tenth, no amounts will vest. In February 2007, our named executive officers, who are also executive officers of the General Partner, received an initial award of performance units as follows: 15,000 performance units to Mr. Joyce, 8,200 performance units to Mr. McParland, 10,800 performance units to Mr. Perkins, 10,800 performance units to Mr. Whalen and 10,000 performance units to Mr. Heim.
Retirement Benefits. For 2007, the discretionary amount contributed to the 401(k) Plan equaled 2.25% of the employee’s eligible compensation.
Index to Financial Statements Health and Welfare Benefits. For 2007, our named executive officers participated in our health and welfare benefit programs, including medical, health, life insurance, and dental coverage and disability insurance.
Perquisites. Consistent with our compensation philosophy, we did not pay for perquisites for any of our named executive officers during 2007, other than parking subsidies.
Changes for 2008
Annual Cash Incentives. In connection with the development of our 2008 business plan and discussion of the plan with the Targa Investments Board, Senior Management proposed a set of strategic priorities. In January 2008, the TRII Compensation Committee approved the Targa Investments 2008 Annual Incentive Compensation Plan (the “2008 Bonus Plan”), the cash bonus plan for performance during 2008, and, with input from the Targa Investments Board, established the following six key business priorities: (i) identify opportunities to strengthen organization and develop plans to address them; (ii) expand on existing processes to enhance the involvement of the organization in making our businesses better; (iii) aggressively develop attractive return projects and opportunities and proactively invest in and expand the Company’s businesses; (iv) improve insurance recovery situation with resolution or clear path to resolution; (v) make a significant third-party acquisition(s) at the Partnership and/or continue to effectively drop down Company assets to the Partnership; and (iv) execute on all fronts (including the 2008 business plan and above priorities). As with the Bonus Plan, funding of the cash bonus pool and the payment of individual cash bonuses to employees, including our named executive officers, are subject to the sole discretion of the TRII Compensation Committee.
Long-term Cash Incentives. In January 2008, our named executive officers, who are also executive officers of the General Partner, received an award of performance units under Targa Investments’ long-term incentive plan as follows: 4,000 performance units to Mr. Joyce, 2,700 performance units to Mr. McParland, 3,500 performance units to Mr. Perkins, 3,500 performance units to Mr. Whalen and 3,500 performance units to Mr. Heim.
Compensation Committee Interlocks and Insider Participation
The Compensation Committee members whose names appear on the Compensation Committee Report below were committee members during all of fiscal year 2007. No member of the Compensation Committee is or has been a former or current executive officer of the Company. None of the Company’s executive officers served as a director or a member of a compensation committee (or other committee serving an equivalent function) of any other entity, the executive officers of which served as a director or member of the Compensation Committee during fiscal year 2007. Please see “Item 13. Certain Relationships and Related Transactions, and Director Independence” for a description of relationships requiring disclosure under the SEC’s rules requiring disclosure of certain relationships and related-party transactions.
Compensation Committee Report
The Compensation Committee has reviewed and discussed the disclosure set forth above under the heading “Compensation Discussion and Analysis” with management and, based on this review and discussion, it has recommended to the Targa Board that the “Compensation Discussion and Analysis” be included in this Annual Report on Form 10-K.
The information contained in this report shall not be deemed to be “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings with the SEC, or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that the company specifically incorporates it by reference into a document filed under the Securities Act of 1933, as amended, or the “Exchange Act”.
The Compensation Committee
Peter R. Kagan, Chairman
Charles R. Crisp
Joe B. Foster
Index to Financial Statements EXECUTIVE COMPENSATION
The following Summary Compensation Table sets forth the compensation of our named executive officers for 2007. Additional details regarding the applicable elements of compensation in the Summary Compensation Table are provided in the footnotes following the table.
(1) The amounts reported in these columns reflect the aggregate dollar amounts recognized for stock awards (including performance units) and option awards, as applicable, for financial statement reporting purposes with respect to fiscal year 2007 (disregarding any estimate of forfeitures related to service-based vesting conditions). No stock awards or option awards granted to the named executive officers were forfeited during 2007. Detailed information about the amount recognized for specific awards is reported in the table under “Outstanding Equity Awards at 2007 Fiscal Year-End” below. For a discussion of the assumptions and methodologies used to value the awards reported in these columns, please see the discussion of stock awards and option awards in Note 8 to our Consolidated Financial Statements beginning on page of this Annual Report
(2) For 2007 “All Other Compensation” includes the (i) payments under the Change of Control Bonus Plan and individual Bonus Agreements made in August 2007 in connection with the termination of the Change of Control Bonus Plan and the Bonus Agreements, (ii) aggregate value of matching, non-matching and discretionary contributions to our 401(k) plan and (iii) the dollar value of life insurance coverage.
Index to Financial Statements Grants of Plan-Based Awards
The following table and the footnotes thereto provide information regarding grants of plan-based equity and non-equity awards made to the named executive officers during 2007:
(1) These awards were granted under the Bonus Plan. At the time the Bonus Plan was adopted, the estimated future payouts in the above table under the heading “Estimated Possible Payouts Under Non-Equity Incentive Plan Awards” represented the cash bonus pool available for awards to the named executive officers under the Bonus Plan.
(2) These performance unit awards were granted under the Targa Investments Long-Term Incentive Plan and are discussed in more detail under the heading “Compensation Discussion & Analysis-Application of Compensation Elements-Long-Term Cash Incentives.”
(3) These awards were granted in exchange for options relating to Targa Investments’ preferred stock held by the named executive officers.
(4) The dollar amounts shown are determined by multiplying the number of units reported in the table by $29.83 (the per unit fair value under FAS 123R on the grant date) and assume full payout under the awards at the time of vesting.
Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards table
A discussion of 2007 salaries and bonuses is included in “-Compensation Discussion and Analysis.”
Targa Investments 2005 Stock Incentive Plan
Stock Option Grants. Under the Targa Investments 2005 Stock Incentive Plan, as amended (the “2005 Incentive Plan”), incentive stock options and non-incentive stock options to purchase, in the aggregate, up to 5,159,786 shares of Targa Investments’ restricted stock may be granted to our employees, directors and consultants. Subject to the terms of the applicable stock option agreement, options granted under the 2005 Incentive Plan have a vesting period of four years, remain exercisable for ten years from the date of grant and
Index to Financial Statements
have an exercise price at least equal to the fair market value of a share of restricted stock on the date of grant. Additional details relating to previously granted non-incentive stock options under the 2005 Incentive Plan are included in “-Outstanding Equity Awards at 2007 Fiscal Year-End” below.
Restricted Stock Grants. Under the 2005 Incentive Plan, up to 7,293,882 shares of restricted stock of Targa Investments may be granted to our employees, directors and consultants. Subject to the terms of the restricted stock agreement, restricted stock granted under the Incentive Plan has a vesting period of four years from the date of grant. Additional details relating to previously granted shares of common stock are included in “-Outstanding Equity Awards at 2007 Fiscal Year-End” below.
Targa Investments 2004 Stock Incentive Plan
Stock Option Grants. No awards have been, or may be, made under the Targa Investments 2004 Stock Incentive Plan, as assumed and amended (the “2004 Incentive Plan”), from and after December 31, 2004. The 2004 Stock Incentive Plan governs options to purchase shares of Targa Investments’ Series B Convertible Participating Preferred Stock (“Preferred Stock”). Subject to the terms of the applicable stock option agreement, options granted under the 2004 Incentive Plan have a vesting period of four years and remain exercisable for ten years from the date of grant. Additional details relating to previously granted stock options under the 2004 Incentive Plan are included in “-Outstanding Equity Awards at 2007 Fiscal Year-End” below. On May 1, 2007, employees and directors of Targa Investments surrendered all options to acquire shares of Preferred Stock in exchange for a cash payment of $27.69 and ten shares of restricted stock of Targa Investments for each option surrendered.
Index to Financial Statements Outstanding Equity Awards at 2007 Fiscal Year-End
Targa Investments indirectly owns all of our equity interests. The following table and the footnotes related thereto provide information regarding each stock option and other equity-based awards of Targa Investments outstanding as of December 31, 2007 for each of our named executive officers.
(1) Represents options to purchase shares of Targa Investments common stock awarded on October 31, 2005. These options vest on the following schedule: 70% vest on April 30, 2008, an additional 10% vest on October 31, 2008 and the remaining options vest on October 31, 2009.
(2) Represents options to purchase shares of Targa Investments common stock awarded on December 20, 2005. These options vest on the following schedule: 70% vest on June 20, 2008, an additional 10% vest on December 20, 2008 and the remaining options vest on December 20, 2009.
(3) Represents options to purchase shares of Targa Investments common stock awarded on November 1, 2005. These options vest on the following schedule: 50% vest on each of November 1, 2008 and 2009.
(4) Represents options to purchase shares of Targa Investments common stock awarded on December 20, 2005. These options vest on the following schedule: 50% vest on each of December 20, 2008 and 2009.
(5) Represents shares of restricted common stock of Targa Investments awarded on October 31, 2005. These shares vest on the following schedule: 70% on April 30, 2008; an additional 10% on October 31, 2008 and the remaining shares on October 31, 2009.
(6) Represents shares of restricted common stock of Targa Investments awarded on December 20, 2005. These shares vest on the following schedule: 70% on June 20, 2008; an additional 10% on December 20, 2008 and the remaining shares on December 20, 2009.
(7) Represents shares of restricted common stock of Targa Investments awarded on October 31, 2005 (2,721 shares) and November 1, 2005 (502,975 shares). These shares vest on the following schedule: 50% vest on each of October 31, 2008 and 2009 (with respect to the October 31, 2005 awards) and November 1, 2008 and 2009 (with respect to the November 1, 2005 awards).
Index to Financial Statements
(8) Represents shares of restricted common stock of Targa Investments awarded on December 20, 2005. These shares vest on the following schedule: 50% vest on each of December 20, 2008 and 2009.
(9) Represents shares of restricted common stock of Targa Investments awarded on May 1, 2007 in connection with the exchange of options relating to Targa Investments’ preferred stock held by the named executive officers. These shares vest on the following schedule: 80% vest on January 1, 2008 and the remaining vest on April 16, 2008.
(10) Represents shares of restricted common stock of Targa Investments awarded on May 1, 2007 in connection with the exchange of options relating to Targa Investments’ preferred stock held by the named executive officer. These shares vest on the following schedule: 80% vest on January 1, 2008 and the remaining vest on May 7, 2008.
(11) The dollar amounts shown are determined by multiplying the number of shares or units reported in the table by $3.45 (the value determined by an independent consultant pursuant to a valuation of Targa Investments’ common stock as of October 24, 2007, which management believes is a reasonable approximation of the value of such stock as of December 31, 2007).
(12) Represents the number of performance units awarded on February 14, 2007 under the Targa Investments Long-Term Incentive Plan. These awards vest in August of 2010 based on the Partnership’s performance over such period measured against a peer group of companies. These awards are discussed in more detail under the heading “Compensation Discussion & Analysis-Application of Compensation Elements-Long-Term Cash Incentives.”
(13) The dollar amounts shown are determined by multiplying the number of units reported in the table by $29.62 (the closing price of a common unit of the Partnership on December 31, 2007) and assume full payout under the awards at the time of vesting.
Option Exercises and Stock Vested in 2007
The following table provides the amount realized during 2007 by each named executive officer upon the exercise of options and upon the vesting of restricted common stock.
(1) Represents shares of restricted common stock of Targa Investments awarded on May 1, 2007 in connection with the exchange of options relating to Targa Investments’ preferred stock held by the named executive officers. At the time of exchange, the restricted common stock had a value of $1.10 per share. This value was determined by an independent consultant pursuant to a valuation of Targa Investments common stock as of December 31, 2006. The named executive officers received 10 shares of restricted common stock of Targa Investments for each option exchanged.
(2) This value includes a cash payment to the named executive officers of $27.69 per option exchanged.
(3) On October 31, 2007 and December 20, 2007, 101,139 and 1,110 shares, respectively, vested. The value realized on vesting used a per share price of $3.45. This value was determined by an independent consultant pursuant to a valuation of Targa Investments common stock as of October 24, 2007, which management believes is a reasonable approximation of the value of such stock as of December 31, 2007.
Change in Control and Termination Benefits
2005 Incentive Plan. If a Change of Control or a Liquidation Event (each as defined below), or in the case of restricted stock, certain drag-along transactions, occurs during a named executive officer’s employment with us, the options granted to him under Targa Investments form of Non-Statutory Stock Option Agreement (the “Option Agreement”) and/or the restricted stock granted to him under Targa Investment’s form of Restricted Stock Agreement (the “Stock Agreement”) will fully vest and be exercisable (in the case of options) by him so long as he remains an employee of Targa Investments.
Options granted to a named executive officer under the Option Agreement will terminate and cease to be exercisable upon the termination of his employment with Targa Investments, except that: (i) if his employment is
Index to Financial Statements
terminated by reason of a disability, he (or his estate or the person who acquires the options by will or the laws of descent and distribution or otherwise by reason of his death ) may exercise the options in full for 180 days following such termination; (ii) if he dies while employed by Targa Investments, his estate or the person who acquires the options by will or the laws of descent and distribution or otherwise by reason of his death, may exercise the options in full for 180 days following his death; or (iii) if he resigns or is terminated by Targa Investments without Cause (as defined below), then he (or his estate or the person who acquires the options by will or the laws of descent and distribution or otherwise by reason of his death) may exercise the options for three months following such resignation or termination, but only as to the options he was entitled to exercise as of the date his employment terminates.
Restricted stock granted to a named executive officer under the Stock Agreement will fully vest if his employment is terminated by reason of a disability or his death. If a named executive officer resigns or he is terminated by Targa Investments without Cause, then his unvested restricted stock is forfeited to Targa Investments for no consideration. If a named executive officer is terminated by Targa Investments for Cause, then all restricted stock (both vested and unvested) granted to him under the Stock Agreement is forfeited to Targa Investments for no consideration. For one year following a named executive officer’s termination of employment, Targa Investments has the right to repurchase all of his restricted stock and other Capital Stock (as defined below), after any applicable forfeitures, at a purchase price equal to, in the case of a termination by death, disability, resignation or without Cause, the then fair market value of such restricted stock and Capital Stock determined in accordance with the Stockholders Agreement, and, in the case of a termination with Cause, the lower of the Original Cost (as defined below) or the then Fair Market Value (as defined below) of such Capital Stock.
The following terms have the specified meanings for purposes of the 2005 Incentive Plan:
•
Change of Control means, in one transaction or a series of related transactions, a consolidation, merger or any other form of corporate reorganization involving Targa Investments or a sale of Preferred Stock (or a sale of Targa Investments’ common stock following conversion of the Preferred Stock) by stockholders of Targa Investments with the result immediately after such merger, consolidation, corporate reorganization or sale that (A) a single person, together with its affiliates, owns, if prior to any firm commitment underwritten offering by Targa Investments of its common stock to the public pursuant to an effective registration statement under the Securities Act (x) for which the aggregate cash proceeds to be received by Targa Investments from such offering (without deducting underwriting discounts, expenses, and commissions) are at least $35,000,000, and (y) pursuant to which Targa Investments’ common stock is listed for trading on the New York Stock Exchange or is admitted to trading and quoted on the NASDAQ National Market System (a “Qualified Public Offering”), either a greater number of shares of Targa Investments’ common stock (calculated assuming that all shares of Preferred Stock have been converted at the specified conversion ratio) than Warburg Pincus and its affiliates then own or, in the context of a consolidation, merger or other corporate reorganization in which Targa Investments is not the surviving entity, more voting stock generally entitled to elect directors of such surviving entity (or in the case of a triangular merger, of the parent entity of such surviving entity) than Warburg Pincus and its affiliates then own or, if on or after a Qualified Public Offering, either a majority of Targa Investments’ common stock calculated on a fully-diluted basis (i.e. on the basis that all shares of Preferred Stock have been converted at the specified conversion ratio, that all Management Stock is outstanding, whether vested or not, and that all outstanding options to acquire Targa Investments’ common stock had been exercised (whether then exercisable or not)) or, in the context of a consolidation, merger or other corporate reorganization in which Targa Investments is not the surviving entity, a majority of the voting stock generally entitled to elect directors of such surviving entity (or in the case of a triangular merger, of the parent entity of such surviving entity) calculated on a fully diluted basis and (B) Warburg Pincus and its affiliates collectively own less than a majority of the initial shares of Capital Stock outstanding on October 31, 2005 owned by them (the “Initial Shares”) or, in the event such Initial Shares are converted or exchanged into other voting
Index to Financial Statements
securities of Targa Investment or such surviving or parent entity, less than a majority of such voting securities Warburg Pincus and its affiliates would have owned had they retained all such Initial Shares;
•
Management Stock means the shares of Targa Investments’ common stock granted pursuant to the terms of the 2005 Incentive Plan, any such shares transferred to a permitted transferee and any and all securities of any kind whatsoever of Targa Investments which may be issued in respect of, in exchange for, or upon conversion of such shares of common stock pursuant to a merger, consolidation, stock split, stock dividend, recapitalization of Targa Investments or otherwise;
•
Liquidation Event means the voluntary or involuntary liquidation, dissolution, or winding up of the affairs of Targa Investments; provided that neither the merger or consolidation of Targa Investments with or into another entity, nor the merger or consolidation of another entity with or into Targa Investments, nor the sale of all or substantially all of the assets of Targa Investments shall be deemed to be a Liquidation Event;
•
Cause means discharge by Targa Investments based on (A) an employee’s gross negligence or willful misconduct in the performance of duties, (B) conviction of a felony or other crime involving moral turpitude; (C) an employee’s willful refusal, after fifteen days’ written notice from the Targa Investments Board, to perform the material lawful duties or responsibilities required of him; (D) willful and material breach of any corporate policy or code of conduct established by Targa Investments; and (E) willfully engaging in conduct that is known or should be known to be materially injurious to Targa Investments or any of its subsidiaries;
•
Capital Stock means any and all shares of capital stock of, or other equity interests in, Targa Investments, and any and all warrants, options, or other rights to purchase or acquire any of the foregoing;
•
Original Cost means, with respect to a particular share of Capital Stock, the cash amount originally paid to Targa Investments to purchase such share (or if such share was issued in respect of other shares of Targa Investments issued in connection with the merger of one of Targa Investments’ subsidiaries with and into us, then the cash amount originally paid to us to purchase such other shares), subject to adjustment for subdivisions, combinations or stock dividends involving such Capital Stock, or, if no cash amount was originally paid to Targa Investments to purchase such share, then no consideration (or if such share was issued in respect of other shares of Targa Investments issued in connection with the merger of one of Targa Investments’ subsidiaries with and into us and such other shares were issued by us for no cash consideration, then no consideration); and
•
Fair Market Value means the value determined by the unanimous resolution of all directors of the Targa Investments Board, provided that if the Targa Investments Board does not or is unable to make such a determination, Fair Market Value means the value determined by an investment banking firm of recognized national standing selected by a majority of the directors of the Targa Investments Board.
The following table reflects payments that would have been made to each of the named executive officers under the 2005 Incentive Plan and related agreements in the event there was a Change of Control or their employment was terminated, each as of December 31, 2007.
(1) Of this amount, $2,532,987 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $24,549 relates to the unvested shares of restricted stock of Targa Investments granted
Index to Financial Statements
on December 20, 2005; $290,180 relates to the unvested shares of restricted stock of Targa Investments granted on May 1, 2007 in connection with the stock option exchange; $189,904 relates to the unvested options to purchase Targa Investments common stock granted on October 31, 2005; and $1,352 relates to the unvested options to purchase Targa Investments common stock granted on December 20, 2005.
(2) Of this amount, $1,915,164 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $18,412 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; $238,360 relates to the unvested shares of restricted stock of Targa Investments granted on May 1, 2007 in connection with the stock option exchange; $157,124 relates to the unvested options to purchase Targa Investments common stock granted on October 31, 2005; and $1,014 relates to the unvested options to purchase Targa Investments common stock granted on December 20, 2005.
(3) Of this amount, $2,110,296 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $19,886 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; $290,180 relates to the unvested shares of restricted stock of Targa Investments granted on May 1, 2007 in connection with the stock option exchange; $164,991 relates to the unvested options to purchase Targa Investments common stock granted on October 31, 2005; and $1,096 relates to the unvested options to purchase Targa Investments common stock granted on December 20, 2005.
(4) Of this amount, $3,754 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $694,106 relates to the unvested shares of restricted stock of Targa Investments granted on November 1, 2005; $7,660 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; $86,733 relates to the unvested shares of restricted stock of Targa Investments granted on May 1, 2007 in connection with the stock option exchange; $40,908 relates to the unvested options to purchase Targa Investments common stock granted on November 1, 2005; and $422 relates to the unvested options to purchase Targa Investments common stock granted on December 20, 2005.
(5) Of this amount, $2,110,296 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $19,886 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; $290,180 relates to the unvested shares of restricted stock of Targa Investments granted on May 1, 2007 in connection with the stock option exchange; $164,991 relates to the unvested options to purchase Targa Investments common stock granted on October 31, 2005; and $1,096 relates to the unvested options to purchase Targa Investments common stock granted on December 20, 2005.
Other Agreements
In connection with the DMS acquisition on October 31, 2005, we entered into bonus agreements (the “Bonus Agreements”) with Messrs. Crisp, Foster, Heim, Joyce, McParland, Perkins and Whalen and adopted the Targa Resources, Inc. Bonus Plan (the “Change of Control Bonus Plan”) applicable to eligible employees, including Messrs. Joyce, McParland, Perkins and Heim that provided these named executive officers certain benefits upon a Change of Control. In addition, on July 12, 2006, in order to ensure managerial transition in the face of a potential transaction, the TRII Compensation Committee approved the Targa Investments Change of Control Executive Officer Severance Program (the “TRII Severance Program”) in which all of our named executive officers were participants.
Bonus Agreements. Under the Bonus Agreements, following a Change of Control or a death or disability, our named executive officers and directors were entitled to receive the following lump sum cash bonus amounts: Mr. Crisp-$20,800; Mr. Foster-$21,802; Mr. Heim-$717,537; Mr. Joyce-$717,537; Mr. McParland-$574,028; Mr. Perkins-$717,537; and Mr. Whalen-$21,802.
Change of Control Bonus Plan. The Change of Control Bonus Plan provided a lump sum cash bonus payment in case there was a Change of Control or the plan was terminated. The bonus pool would have been $2 million if the weighted average sale price with respect to Targa Investments’ preferred stock sold by Warburg Pincus between November 1, 2005 and the change of control was equal to or greater than $100 per share. The
Index to Financial Statements
bonus pool would have been $0 if the weighted average sale price was equal to or less than $72.31 per share. The bonus pool would have been a prorated amount between $0 and $2 million if the weighted average sale price was between $72.31 and $100 per share.
TRII Severance Program. This program provided separation benefits to our executive officers who voluntarily terminated their employment or whose employment was terminated in connection with a change of control of Targa. In such event, executive officers would have received a lump sum cash payment, subsidized medical coverage for up to two years and minimal transition assistance. The lump sum cash payment would have been paid in an amount equal to (i) two multiplied by fifty percent of the executive officer’s annual base pay in effect on the date immediately preceding the change of control, multiplied by (ii) a fraction, the numerator of which was the number of days during the period beginning on the first day of such fiscal year and ending on the date of such termination, and the denominator of which was three hundred sixty-five.
Termination of Change in Control and Termination Benefits
In connection with Targa Investment’s entry into a credit facility in August 2007, which funded a distribution to Targa Investment’s investors, the Targa Board elected to terminate the Bonus Agreements and the Change of Control Bonus Plan and to trigger the payments due under the agreements and plan. The TRII Severance Program was terminated without any payments to the named executive officers when the Targa Investments Board determined the need to ensure managerial transition in the case of a Change of Control was no longer necessary. As a result, no payments would have been made to the named executive officers under the Bonus Agreements, the Change of Control Bonus Plan and the TRII Severance Program if a change of control occurred or their employment was terminated in connection therewith as of December 31, 2007.
Director Compensation
The following table sets forth the compensation earned by our non-employee directors for 2007:
(1) The amounts reported in these columns reflect the aggregate dollar amounts recognized for stock awards and option awards, as applicable, for financial statement reporting purposes with respect to fiscal year 2007 (disregarding any estimate of forfeitures related to service-based vesting conditions). No stock awards or option awards granted to the directors were forfeited during 2007. For a discussion of the assumptions and methodologies used to value the awards reported in these columns, please see the discussion of stock awards and option awards contained in Note 8 to our Consolidated Financial Statements beginning on page of this Annual Report.
(2) The grant date fair value of the 95,395 shares of common stock and 87,018 options to purchase shares of common stock granted to Mr. Crisp on October 31, 2005 is $110,658 and $7,430, respectively. This value was determined by an independent consultant pursuant to a FAS 123R valuation of Targa Investments common stock as of October 31, 2005. The grant date fair value of the 2,000 common units of the Partnership granted to Mr. Crisp on February 14, 2007 is $42,000, based on the initial public offering price of the common units. At December 31, 2007, Mr. Crisp held 9,709 shares of preferred stock, 120,535 shares
Index to Financial Statements
of common stock, 87,018 options to purchase shares of common stock and 3,100 common units of the Partnership.
(3) The grant date fair value of the 95,395 shares of common stock and 87,018 options to purchase shares of common stock granted to Mr. Foster on October 31, 2005 is $110,658 and $7,430, respectively. This value was determined by an independent consultant pursuant to a FAS 123R valuation of Targa Investments common stock as of October 31, 2005. The grant date fair value of the 2,000 common units of the Partnership granted to Mr. Foster on February 14, 2007 is $42,000, based on the initial public offering price of the common units. At December 31, 2007, Mr. Foster held 28,591 shares of preferred stock, 120,535 shares of common stock, 87,018 options to purchase shares of common stock and 6,700 common units of the Partnership.
(4) Messrs. Joung and Kagan each received 2,000 common units of the Partnership on February 14, 2007 in connection with their service on the Board of Directors of the Partnership’s general partner. The grant date fair value of the 2,000 common units granted to each of Messrs. Joung and Kagan is $42,000, based on the initial public offering price of the common units. At December 31, 2007, Messrs. Joung and Kagan each held 2,000 common units of the Partnership. During 2007, Messrs. Joung and Kagan each received $1,690 in distributions on the common units of the Partnership held by them. In addition, Messrs. Joung and Kagan earned $46,000 and $47,500 in fees, respectively, for service on the board of directors of the Partnership’s general partner. The Partnership also recognized $22,500 for each of Messrs. Joung and Kagan for stock awards held by them.
(5) The grant date fair value of the 72,564 shares of common stock and 51,672 options to purchase shares of common stock granted to Mr. Tong on January 26, 2006 is $84,174 and $10,872, respectively. This value was determined by an independent consultant pursuant to a FAS 123R valuation of Targa Investments common stock as of January 26, 2006. The grant date fair value of the 2,000 common units of the Partnership granted to Mr. Tong on February 14, 2007 is $42,000, based on the initial public offering price of the common units. At December 31, 2006, Mr. Tong held 72,564 shares of common stock, 51,672 options to purchase shares of common stock and 4,400 common units of the Partnership.
(6) For 2007 “All Other Compensation” includes the (i) payments under the Change of Control Bonus Plan and individual Bonus Agreements accrued in August 2007 in connection with the termination of the Change of Control Bonus Plan and the Bonus Agreements and (ii) dividends paid on common units of the Partnership.
Narrative to Director Compensation Table
In response to market developments identified by Apogee, a compensation consultant, the TRII Compensation Committee approved changes to director compensation for the 2007 fiscal year. For 2007, each independent director (other than the Warburg directors) receives an annual cash retainer of $34,000 and the chairman of the Audit Committee receives an additional annual retainer of $15,000. All of our independent directors (other than the Warburg directors) receive $1,500 for each Audit Committee and Compensation Committee meeting attended. No additional fees are paid for attending board meetings. Payment of independent director fees is generally made twice annually, at the second regularly scheduled meeting of the Board and the final meeting of the Board for the fiscal year. All independent directors (other than the Warburg directors) are reimbursed for out-of-pocket expenses incurred in attending Board and committee meetings.
A director who is also an employee receives no additional compensation for services as a director. Accordingly, the Summary Compensation Table reflects total compensation received by Messrs. Joyce and Whalen for services performed for us and our subsidiaries. In addition, a director who is also employed by Warburg Pincus receives no compensation for services as a director.
Index to Financial Statements Director Long-term Equity Incentives. The Partnership made equity-based awards in February 2007 in connection with its initial public offering to the General Partners’ nonmanagement and independent directors under the Partnership’s long-term incentive plan. These awards were determined by Targa Investments and approved by the board of directors of the General Partner. Each of these directors received an initial award of 2,000 restricted units, which will settle with the delivery of Partnership common units. The Partnership has made similar grants under its long-term incentive plan to our independent directors. All of these awards are subject to three year vesting, without a performance condition, and vest ratably on each anniversary of the grant. The awards are intended to align the long-term interests of executive officers and directors of the General Partner with those of the Partnership’s unitholders. The independent and non-management directors of the General Partner and the independent directors of Targa Investments currently participate in the Partnership’s plan.
Changes for 2008
Director Long-term Equity Incentives. In March 2008, each of the General Partners’ nonmanagement and independent directors received an award of 2,000 restricted units under the Partnership’s long-term incentive plan, which will settle with the delivery of Partnership common units. The Partnership has made similar grants under its long-term incentive plan to our independent directors.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table is based on our records and reports filed with the Commission and sets forth the beneficial ownership of our common stock and equity securities of our subsidiaries as of March 25, 2008 that are held by:
•
each person who beneficially owns 5% or more of our outstanding common stock (only with respect to our common stock);
•
all of the directors of Targa Resources, Inc.;
•
each named executive officer of Targa Resources, Inc.; and
•
all directors and executive officers of Targa Resources, Inc. as a group.
Index to Financial Statements
* Less than 1%.
(1) Unless otherwise indicated, the address for all beneficial owners in this table is 1000 Louisiana, Suite 4300, Houston, Texas 77002. The nature of the beneficial ownership for all the equity securities is sole voting and investment power.
(2) Warburg Pincus Private Equity VIII, L.P. (“WP VIII”) and Warburg Pincus Private Equity IX, L.P. (“WP IX”) in the aggregate beneficially own 73.6% of Targa Resources Investments Inc. The general partner of WP VIII is Warburg Pincus Partners, LLC (“WP Partners LLC”) and the general partner of WP IX is Warburg Pincus IX, LLC, of which WP Partners LLC is sole member. Warburg Pincus & Co. (“WP”) is the managing member of WP Partners LLC. WP VIII and WP IX are managed by Warburg Pincus LLC (“WP LLC”). The address of the Warburg Pincus entities is 466 Lexington Avenue, New York, New York 10017. Chansoo Joung and Peter R. Kagan, two of our directors, are each a general partner of WP and a Managing Director and Member of WP LLC. In Seon Hwang, one of our directors, is a principal of WP LLC. Charles R. Kaye and Joseph P. Landy are each Managing General Partners of WP and Co-Presidents and Managing Members of WP LLC and may be deemed to control the Warburg Pincus entities. Messrs. Joung, Kagan, Hwang, Kaye and Landy disclaim beneficial ownership of all shares held by the Warburg Pincus entities.
(3) The subordinated units of the Partnership presented as being beneficially owned by our directors and executive officers represent the number of units held indirectly by Targa Resources Investments Inc. that are attributable to such directors and officers based on their ownership of equity interests in Targa Resources Investments Inc. Targa Resources Investments Inc. indirectly holds all 11,528,231 subordinated units of the Partnership.
Index to Financial Statements
(4) Of this amount, 391,787 shares of restricted common stock reflect options to acquire shares of restricted common stock, which are exercisable within 60 days of the date hereof.
(5) Of this amount, 320,244 shares of restricted common stock reflect options to acquire shares of restricted common stock, which are exercisable within 60 days of the date hereof.
(6) Of this amount, 297,650 shares of restricted common stock reflect options to acquire shares of restricted common stock, which are exercisable within 60 days of the date hereof.
(7) Of this amount, 254,356 shares of restricted common stock reflect options to acquire shares of restricted common stock, which are exercisable within 60 days of the date hereof.
(8) Of this amount, 52,213 shares of restricted common stock reflect options to acquire shares of restricted common stock, which are exercisable within 60 days of the date hereof.
(9) Of this amount, 31,005 shares of restricted common stock reflect options to acquire shares of restricted common stock, which are exercisable within 60 days of the date hereof.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Stockholders’ Agreement
Stockholders of Targa Investments, our indirect parent, including our named executive officers, certain of our directors, Warburg Pincus and Merrill Lynch, are party to the Targa Resources Investments Inc. Amended and Restated Stockholders’ Agreement dated October 31, 2005, as amended (the “Stockholders’ Agreement”). The Stockholders’ Agreement (i) provides certain holders of Targa Investments’ preferred stock with preemptive rights relating to certain issuances of securities by Targa Investments or its subsidiaries, (ii) imposes restrictions on the disposition and transfer of securities of Targa Investments, (iii) establishes vesting and forfeiture provisions for securities held by our management, (iv) provides Targa Investments with the option to repurchase its securities held by our management and directors upon the termination of their employment or service to Targa Investments in certain circumstances, and (v) imposes on Targa Investments the obligation to furnish financial information to Warburg Pincus and Merrill Lynch as long as they maintain a certain ownership level in Targa Investments’ securities.
The Stockholders’ Agreement also requires the stockholders party thereto to vote to elect to the Board of Directors of Targa Investments two individuals that are executive officers of Targa Investments (one of whom shall be the chief executive officer of Targa Investments unless otherwise agreed by the majority holders), five individuals that will be designated by Warburg Pincus and one individual (two individuals if there are only four Warburg nominees or three individuals if there are only three Warburg nominees) who shall be independent that will be selected by Warburg Pincus, after consultation with the chief executive officer of Targa Investments and approved by the majority holders.
Relationships with Warburg Pincus
Warburg Pincus beneficially owns approximately 74% of the outstanding voting stock of our parent on a fully diluted basis. Warburg Pincus is able to elect members of our board of directors, appoint new management and approve any action requiring the approval of our stockholders, including amendment of our certificate of incorporation and mergers or sales of substantially all of our assets. The directors elected by Warburg Pincus will be able to make decisions affecting our capital structure, including decisions to issue additional capital stock, implement stock repurchase programs and declare dividends.
Relationships with Merrill Lynch, Pierce, Fenner & Smith Incorporated (“Merrill Lynch”)
Equity
An affiliate of Merrill Lynch holds a non-voting equity interest in the general partner of Warburg Pincus Private Equity VIII, L.P. and Warburg Pincus Private Equity IX, L.P., the principal shareholders of Targa Investments. Merrill Lynch Ventures L.P. 2001, an affiliate of Merrill Lynch, owns approximately 6.5% of the outstanding voting stock of our parent on a fully diluted basis.
Index to Financial Statements Financial Services
Merrill Lynch was an initial purchaser of our senior notes, and acted as our financial advisor with respect to our purchase of all the equity interests in DMS. An affiliate of Merrill Lynch is a lender and an agent under our existing senior secured credit facilities.
Hedging Arrangements
We have entered into various commodity derivative transactions with Merrill Lynch Commodities Inc. (“MLCI”), an affiliate of Merrill Lynch. Under the terms of these various commodity derivative transactions, MLCI has agreed to pay us specified fixed prices in relation to specified notional quantities of natural gas, NGLs, and condensate over periods ending in 2010, and we have agreed to pay Merrill Lynch floating prices based on published index prices of such commodities for delivery at specified locations. The following table shows our open commodity derivatives with Merrill Lynch as of December 31, 2007:
The Partnership had the following open commodity derivatives with Merrill Lynch as of December 31, 2007:
At December 31, 2007, the aggregate fair value of these derivatives is a liability of $79.5 million. During 2007, we paid Merrill Lynch $14.2 million in commodity derivative settlements. During 2006, Merrill Lynch paid us $6.8 million in commodity derivative settlements. There were no commodity derivative settlements with Merrill Lynch prior to 2006.
Commercial Relationships
In April 2004, we entered into a base agreement for the purchase and sale of natural gas with Entergy-Koch Trading, LP, pursuant to which Entergy-Koch Trading, LP typically purchases natural gas for fuel at its affiliated cogeneration facility in Lake Charles. On November 1, 2004, MLCI acquired Entergy-Koch, LP and became a successor to this agreement. Pricing terms under the agreement are governed by reference to specified index prices plus a premium.
Index to Financial Statements Commodity Transactions
For the years indicated, we completed natural gas and NGL purchases and sales transactions with related parties as follows:
These transactions were at market prices consistent with similar transactions with nonaffiliated entities.
Other Relationships
On December 16, 2004, we acquired a 40% ownership interest in Bridgeline. During 2005 we had net purchases of natural gas of $11.4 million from Bridgeline. During the period from December 16, 2004 to December 31, 2004, we purchased $1.4 million of natural gas from Bridgeline. These transactions were at market prices consistent with those paid to non-affiliate entities. We sold our interest in Bridgeline in August 2005.
Initial Public Offering of Partnership
On February 14, 2007, the Partnership completed its initial public offering (the “IPO”) and borrowed $294.5 million under its newly established credit facility. In return for our contribution of North Texas to the Partnership we received a 2% general partner interest and a 36.6% limited partner interest in the Partnership and cash proceeds of $665.7 million. We used the proceeds received from contributing North Texas to the Partnership and cash on hand to retire in full the outstanding balance (including accrued interest) of our $700 million senior secured asset sale bridge loan facility.
Purchase and Sale Agreement
On October 24, 2007, we completed a purchase and sale agreement (the “Purchase Agreement”) with the Partnership pursuant to which we transferred the assets of the SAOU and LOU systems for aggregate consideration of $705 million, subject to certain adjustments, consisting of $697.6 million in cash and the issuance to the Partnership’s general partner of 275,511 general partner units, enabling the general partner to maintain its general partner interest in the Partnership. On September 25 and 26, 2007, we completed transactions that terminated certain out of the money NGL hedges associated with the SAOU and LOU systems and entered into new hedges for approximately the same volume and term at then current market prices. Pursuant to the Purchase Agreement, these hedging transactions resulted in a $24.2 million increase to the purchase price the Partnership paid to us for the SAOU and LOU systems. Pursuant to the Purchase Agreement, we agreed to indemnify the Partnership from and against (i) all losses that it incurs arising from any breach of our
Index to Financial Statements
representations, warranties or covenants in the Purchase Agreement, (ii) certain environmental matters and (iii) certain litigation matters. The Partnership agreed to indemnify us from and against all losses that we incur arising from or out of (i) the business or operations of Targa Resources Texas GP LLC, Targa Texas, Targa Louisiana and Targa Louisiana Intrastate LLC (whether relating to periods prior to or after the closing of the acquisition of the SAOU and LOU systems) to the extent such losses are not matters for which we had indemnified the Partnership or (ii) any breach of the Partnership’s representations, warranties or covenants in the Purchase Agreement. Certain of our indemnification obligations are subject to an aggregate deductible of $10 million and a maximum limit equal to $80 million. In addition, the parties’ reciprocal indemnification obligations for certain tax liability and losses are not subject to the deductible and cap.
Omnibus Agreement
Upon the closing of the IPO, we entered into an omnibus agreement with the Partnership and others that addresses: (i) the reimbursement of the general partner for costs incurred on the Partnership’s behalf, (ii) competition and (iii) indemnification matters. Any or all of the provisions of the omnibus agreement, other than the indemnification provisions described below, are terminable by us at our option if the general partner is removed without cause and units held by the general partner and its affiliates are not voted in favor of that removal. The omnibus agreement will also terminate in the event of a change of control of the Partnership or its general partner.
Reimbursement of Operating and General and Administrative Expense
Under the terms of the Omnibus Agreement, the Partnership reimburses us for the payment of certain operating expenses, including compensation and benefits of operating personnel, and for the provision of various general and administrative services for the Partnership’s benefit. With respect to the North Texas System, the Partnership reimburses us for the following expenses:
•
general and administrative expenses, which are capped at $5 million annually for three years, subject to increases based on increases in the Consumer Price Index and subject to further increases in connection with expansions of the Partnership’s operations through the acquisition or construction of new assets or businesses with the concurrence of its conflicts committee; thereafter, the general partner will determine the general and administrative expenses to be allocated to the Partnership in accordance with the partnership agreement; and
•
operations and certain direct expenses, which are not subject to the $5 million cap for general and administrative expenses.
With respect to the SAOU and LOU systems, the Partnership reimburses us for the following expenses:
•
general and administrative expenses, which are not capped, allocated to the SAOU and LOU systems according to our allocation practice; and
•
operating and certain direct expenses, which are not capped.
Pursuant to these arrangements, we perform centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. The Partnership reimburses us for the direct expenses to provide these services as well as other direct expenses we incur on its behalf, such as compensation of operational personnel performing services for its benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits.
General and administrative costs will continue to be allocated to the SAOU and LOU systems according to our allocation practice.
Index to Financial Statements Competition
We are not restricted, under either the Partnership’s partnership agreement or the Omnibus Agreement, from competing with the Partnership. We may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer the Partnership the opportunity to purchase or construct those assets.
Indemnification
Under the Omnibus Agreement, we will indemnify the Partnership until February 14, 2010 against certain potential environmental claims, losses and expenses associated with the operation of North Texas and occurring before February 14, 2007 that are not reserved on the books of the Predecessor Business as of February 14, 2007. Our maximum liability for this indemnification obligation does not exceed $10.0 million and we do not have any obligation under this indemnification until the Partnership’s aggregate losses exceed $250,000. The Partnership has agreed to indemnify us against environmental liabilities related to North Texas arising or occurring after February 14, 2007.
Additionally, we will indemnify the Partnership for losses attributable to rights-of-way, certain consents or governmental permits, pre-closing litigation relating to North Texas and income taxes attributable to pre-IPO operations that are not reserved on the books of the Predecessor Business as of February 14, 2007. We do not have any obligation under these indemnifications until the Partnership’s aggregate losses exceed $250,000. The Partnership will indemnify us for all losses attributable to the post-IPO operations of North Texas. Our obligations under this additional indemnification survive until February 14, 2010, except that the indemnification for income tax liabilities will terminate upon the expiration of the applicable statute of limitations.
Agreements Governing the Drop-Down Transactions
We have entered into various documents and agreements that affected the drop-down transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds therefrom. These agreements were not the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, were not effected on terms at least as favorable to the parties to these agreements as they could have obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, were paid from the proceeds of the transaction.
Contracts with Affiliates
NGL and Condensate Purchase Agreement for the North Texas System. We have entered into an NGL and high pressure condensate purchase agreement with the Partnership pursuant to which (i) the Partnership is obligated to sell all volumes of NGLs (other than high-pressure condensate) that it owns or controls to our subsidiary, Targa Liquids Marketing and Trade (“TLMT”) and (ii) the Partnership has the right to sell to TLMT or third parties the volumes of high-pressure condensate that it owns or controls, in each case at a price based on the prevailing market price less transportation, fractionation and certain other fees. This agreement has an initial term of 15 years and automatically extends for a term of five years, unless the agreement is otherwise terminated by either party. Furthermore, either party may elect to terminate the agreement if either party ceases to be one of our affiliates.
NGL Purchase Agreements for the SAOU and LOU Systems. We have entered into an NGL purchase agreements with the Partnership pursuant to which the Partnership is obligated to sell all of the LOU System and SAOU Systems’ volumes of mixed NGLs, or raw product, that the Partnership owns or controls to TLMT at a price based on either TLMT’s sales price to third parties or the prevailing market price, less transportation, fractionation and certain other fees. The NGL purchase agreements have an initial term of one year and automatically extend for additional terms of one year, unless the agreements are otherwise terminated by either party.
Index to Financial Statements Natural Gas Purchase Agreements. We have entered into natural gas purchase agreements with the Partnership at a price based on Targa Gas Marketing LLC’s (“TGM”) sale price for such natural gas, less TGM’s costs and expenses associated therewith. These agreements have an initial term of 15 years and automatically extend for a term of five years, unless the agreements are otherwise terminated by either party. Furthermore, either party may elect to terminate the agreements if either party ceases to be one of our affiliates. In addition, we manage the Partnership’s natural gas sales to third parties under contracts that remain in the name of the Partnership.
Policies and Procedures
Our policies and procedures for approval or ratification of transactions with “related persons” are not contained in a single policy or procedure. Instead, they are contained in Targa Investments’ Stockholders Agreement and are reflected in the general operation of Targa Investments’ Board of Directors and our Board.
The Targa Investments Stockholders Agreement prohibits us from entering into, modifying, amending or terminating any transaction (other than certain compensatory arrangements and sales or purchases of capital stock) with an executive officer, director or affiliate of Targa Investments without the prior written consent of the holders of at least a majority of the outstanding shares of Targa Investments’ Series B preferred stock (or Targa Investments’ common stock if no Series B preferred stock is outstanding). In addition, we cannot enter into any material transaction with Warburg Pincus and its affiliates (other than Targa Investments, any of its subsidiaries or any manager, director or officer of Targa Investments or any of its subsidiaries) without the prior written consent of Merrill Lynch Ventures L.P. 2001.
We distribute and review a questionnaire to our executive officers and directors requesting information regarding, among other things, certain transactions with us in which they or their family members have an interest.
Item 14.
Item 14. Principal Accountant Fees and Services
We have engaged PricewaterhouseCoopers LLP as our principal accountant. The following table summarizes fees we have paid PricewaterhouseCoopers for independent auditing, tax and related services for each of the last two fiscal years:
(1) Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the audit of our annual financial statements, (ii) the review of our quarterly financial statements or (iii) those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. This information is presented as of the latest practicable date for this Annual Report on Form 10-K.
(2) Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews. This category primarily includes services relating to internal control assessments and accounting-related consulting.
Index to Financial Statements
(3) Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice, and tax planning. This category primarily includes services relating to the preparation of unitholder annual K-1 statements regarding the Partnership.
(4) All other fees represent amounts we were billed in each of the years presented for services not classifiable under the other categories listed in the table above.
All services provided by our independent auditor are subject to pre-approval by our audit committee. The Audit Committee is informed of each engagement of the independent auditor to provide services under the policy. The Audit Committee of our general partner has approved the use of PricewaterhouseCoopers as our independent principal accountant.
Index to Financial Statements PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)(1) Financial Statements
Our consolidated financial statements are included under Part II, Item 8 of this Annual Report. For a listing of these statements and accompanying footnotes, please see “Index to Financial Statements” on page of this Annual Report.
(a)(2) Financial Statement Schedules
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
Index to Financial Statements
Index to Financial Statements
Index to Financial Statements
+ Management contract or compensation plan or arrangement.
* Filed herewith.
Index to Financial Statements Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Targa Resources, Inc.
(Registrant)
By:
/s/ JEFFREY J. MCPARLAND
Jeffrey J. McParland
Executive Vice President
and Chief Financial Officer
(Principal Financial Officer)
Date: March 31, 2008
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 indicated on March 31, 2008.
Index to Financial Statements Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act.
We have not sent an annual report covering our fiscal year ended December 31, 2007 or proxy materials relating to an annual or other meeting of security holders to our security holder.
Index to Financial Statements
Index to Financial Statements
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors of Targa Resources, Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of changes in stockholder’s equity, and of cash flows present fairly, in all material respects, the financial position of Targa Resources, Inc. and its subsidiaries (the “Company”) at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 26, 2008
Index to Financial Statements
TARGA RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
See notes to consolidated financial statements
Index to Financial Statements
TARGA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
See notes to consolidated financial statements
Index to Financial Statements
TARGA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
See notes to consolidated financial statements
Index to Financial Statements
TARGA RESOURCES, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER’S EQUITY
See notes to consolidated financial statements
Index to Financial Statements
TARGA RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
See notes to consolidated financial statements
Index to Financial Statements
TARGA RESOURCES, INC.
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
Note 1-Organization and Operations
Organization and Operations
Targa Resources, Inc. is a Delaware corporation formed on February 26, 2004. Unless the context requires otherwise, references to “we”, “us”, “our”, “the Company” or “Targa” are intended to mean the consolidated business and operations of Targa Resources, Inc.
We are a second-tier, wholly owned subsidiary of our parent holding company, Targa Resources Investments Inc. (“Targa Investments”). The only significant asset of Targa Investments is its ownership of 100% of the outstanding capital stock of an intermediate holding company, whose sole asset is its ownership of 100% of our outstanding capital stock, which consists of one thousand shares of common stock.
We commenced initial operations on April 16, 2004, with the purchase from ConocoPhillips of certain midstream natural gas assets located in West Texas and South Louisiana.
Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of NGLs. Please see “Note 15-Segment Information” for a description of our segments and segment operations.
Basis of Presentation
The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2007 and 2006, and the results of our operations, cash flows and changes in stockholder’s equity for the years ended December 31, 2007, 2006 and 2005.
We currently own approximately 26.5% of Targa Resources Partners LP (the “Partnership”), including our 2% general partnership interest, which is wholly owned by us. The Partnership is consolidated within our Gas Gathering and Processing segment in accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.”
The non-controlling interest in the Partnership on our December 31, 2007 consolidated balance sheet represents the investment by the partners other than Targa Resources, Inc., plus those partners’ share of the net income, less those partners’ share of distributions of the Partnership since its initial public offering on February 14, 2007. Non-controlling interest in net income of the Partnership on our consolidated statements of operations represents those partners’ share of the net income of the Partnership.
Note 2-Accounting Policies and Related Matters
Asset Retirement Obligations. We account for asset retirement obligations (“AROs”) using Statement of Financial Accounting Standards (“SFAS”) 143, “Accounting for Asset Retirement Obligations,” as interpreted by Financial Interpretation (“FIN”) 47, “Accounting for Conditional Asset Retirement Obligations.” Asset retirement obligations are legal obligations associated with the retirement of tangible long-lived assets that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, an entity records an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. The consolidated cost of the asset and the capitalized asset retirement obligation is depreciated using a systematic and rational allocation method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO
Index to Financial Statements
recognition, the ARO will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing. Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Upon settlement, AROs will be extinguished by the entity at either the recorded amount or the entity will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost.
The changes in our aggregate asset retirement obligations are as follows:
Cash and Cash Equivalents. Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
Comprehensive Income. Comprehensive income includes net income and other comprehensive income, which includes unrealized gains and losses on derivative instruments that are designated as hedges, our equity interest in the other comprehensive income changes of unconsolidated investments accounted for under the equity method and unrealized foreign exchange gains and losses.
Concentration of Credit Risk. Financial instruments which potentially subject Targa to concentrations of credit risk consist primarily of trade accounts receivable and derivative instruments. Management believes the risk is limited, as our customers represent a broad and diverse group of energy marketers and end-users.
We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met.
Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the level of established reserves, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required.
Index to Financial Statements Significant Commercial Relationships
The following table lists the percentage of our consolidated sales and consolidated purchases by customer and supplier, respectively, which accounted for more than 10% of our consolidated revenues and consolidated product purchases for the years indicated:
Consolidation Policy. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, and our proportionate share of assets, liabilities, revenues and expenses of undivided interests in certain gas processing facilities after the elimination of all material intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling interest.
We follow the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the operating and financial policies of the investee. Our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates are eliminated in consolidation to the extent such amounts are material and remain on our equity method investees’ balance sheet in inventory or similar accounts.
If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.
Debt Issue Costs. Costs incurred in connection with the issuance of long-term debt are capitalized and charged to interest expense over the term of the related debt on a straight-line basis, which approximates the interest method.
Earnings per Share. Upon completion of our equity reorganization in 2005, our capital stock consisted of one thousand shares of common stock, owned by our parent company. As such, earnings per share information would not be meaningful and is not presented herein.
Environmental Liabilities. Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated.
Exchanges. Exchanges are movements of NGL products between parties to satisfy timing and logistical needs of the parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, a price differential may be billed or owed. The price differential is recorded as either accounts receivable or an accrued liability.
Impairment of Long-Lived Assets. Management reviews property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. The carrying amount is deemed not recoverable if it exceeds the undiscounted sum of the cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows
Index to Financial Statements
represent management’s best estimate based on reasonable and supportable assumptions. If the carrying amount is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors.
Impairment Testing for Unconsolidated Investments. We evaluate equity method investments (which include excess cost amounts attributable to tangible or intangible assets) for impairment whenever events or changes in circumstances indicate that there is a loss in value of the investment which is other than a temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the investee or long-term negative changes in the investee’s industry. In the event that we determine that the loss in value of an investment is other than a temporary decline, we would record a charge to earnings to adjust the carrying value to fair value.
Income Taxes. We follow the guidance in SFAS 109, “Accounting for Income Taxes”, which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheets.
We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.
We believe future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize assets for which no reserve has been established. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made.
In May 2006, Texas adopted a margin tax, consisting generally of a 1% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas. Accordingly, we have estimated our current and deferred liabilities for this tax.
We adopted the provisions of FIN 48 “Accounting for Uncertainty in Income Taxes” on January 1, 2007. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Based on our evaluation, we have determined that there are no significant uncertain tax positions requiring recognition in our financial statements at the date of adoption or at December 31, 2007. There are no unrecognized tax benefits that, if recognized, would affect the effective rate, and there are no unrecognized tax benefits that are reasonably expected to increase or decrease in the next twelve months. We file tax returns in the United States federal and various state and foreign jurisdictions, and are open to income tax examinations for years 2004 forward. Presently, no income tax examinations are underway, and none have been announced. No potential interest or penalties were recognized at December 31, 2007.
Index to Financial Statements Intangible Assets. Intangible assets consist of the value of customer and supplier contracts and relationships obtained in the acquisition from ConocoPhillips. These assets are amortized over the estimated useful lives of the related gathering systems on a straight-line basis. Amortization expense was $0.1 million for each of the years ended December 31, 2007, 2006 and 2005.
We review intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. This review consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. If such a review should indicate that the carrying amount of intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value.
Inventories. Product inventories consist primarily of NGLs. Most product inventories turn over monthly, but some inventory, primarily propane, is held during the year for strategic purposes to meet anticipated heating season requirements of our customers. Product inventories are valued at the lower of cost or market using the average cost method.
Quantities of natural gas over-delivered or under-delivered related to operational balancing agreements are recorded monthly as inventory or as a payable using weighted average prices at the time the imbalance was created. Monthly, gas imbalances receivable are valued at the lower of cost or market, gas imbalances payable are valued at replacement cost. These imbalances are typically settled in the following month with deliveries or receipts of natural gas. Certain contracts require cash settlement of imbalances on a current basis. Under these contracts, imbalance cash-outs are recorded as a sale or purchase of natural gas, as appropriate.
Due to fluctuating commodity prices for natural gas liquids, we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceeds their net realizable value. These non-cash adjustments are charged to product purchases within operating costs and expenses in the period they are recognized, with the related cash impact in the subsequent period. For 2007 and 2006 we recognized $0.2 million and $13.1 million, respectively, of lower of cost or market adjustments.
Inventory consisted of the following at the dates indicated:
Minority Interest. Minority interest represents third party ownership interests in the net assets of our subsidiaries that are joint ventures. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third party investor’s interest in our consolidated balance amounts shown as minority interest. In the statement of operations, minority interest reflects the allocation of joint venture earnings to third party investors. Distributions to and contributions from minority interests represent cash payments and cash contributions, respectively, from such third party investors.
Price Risk Management (Hedging). We account for derivative instruments in accordance with SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Under SFAS 133, all derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If a derivative qualifies for hedge accounting and is designated as a
Index to Financial Statements
hedge, the effective portion of the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (“OCI”), a component of stockholder’s equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.
The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.
Our policy is to formally document all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Hedge effectiveness is measured on a quarterly basis. Any ineffective portion of the unrealized gain or loss is reclassified to earnings in the current period.
Property, Plant and Equipment. Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The estimated service lives of our functional asset groups are as follows:
Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Upon disposition or retirement of property, plant, and equipment, any gain or loss is charged to operations.
Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. From time to time, we utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve.
We may capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs. Upon disposition or retirement of property, plant and equipment, any gain or loss is charged to operations.
In accordance with SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses and the market and business environments to identify indicators that may suggest an asset may not be recoverable.
Index to Financial Statements We evaluate an asset for recoverability by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize an impairment loss to write down the carrying amount of the asset to its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our Consolidated Statements of Operations.
Revenue Recognition. The primary types of sales and service activities reported as operating revenues include:
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sales of natural gas, NGLs and condensate;
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natural gas processing, from which we generate revenues through the compression, gathering, treating, and processing of natural gas, and
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fractionation, storage, terminalling and transportation of NGLs, from which we generate fee-based revenue.
In general, we recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured.
For processing services, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under percent-of-proceeds contracts, we receive either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed-upon percentage based on index-related prices for the natural gas and NGLs. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we keep the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above. Under fee-based contracts, we receive a fee based on throughput volumes.
We generally report revenues gross in the consolidated statements of operations, in accordance with EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Except for fee-based contracts, we act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership.
Share-Based Employee Compensation. Targa Investments and the Partnership have stock-based compensation plans covering our employees and their respective Boards of Directors. We account for awards under these plans utilizing the fair value recognition provisions of SFAS 123R, “Share-Based Payment.” See Note 8.
Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial
Index to Financial Statements
statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing tangible and intangible assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from estimated amounts.
Recent Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” which establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The FASB partially deferred the effective date of SFAS 157 for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis while the effective date for nonfinancial and financial assets and liabilities that are recognized on a recurring basis is effective beginning January 1, 2008. The Company has determined that the adoption of SFAS 157 will not have a material impact on its consolidated financial statements.
In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115,” which is effective for fiscal years beginning after November 15, 2007, with early adoption permitted. SFAS 159 expands opportunities to use fair value measurements in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. We are currently reviewing this new accounting standard and the impact, if any, it will have on our financial statements.
In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements-An Amendment of ARB No. 51.” SFAS 160 establishes new accounting and reporting standard for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 is effective for fiscal periods, and interim periods within those fiscal years, beginning on or after December 15, 2008. We are currently reviewing this new accounting standard and the impact, if any, it will have on our financial statements.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”). SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling interest in the acquiree and the goodwill acquired. SFAS 141R also establishes disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. SFAS 141R is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008. We are currently reviewing this new accounting standard and the impact, if any, it will have on our financial statements.
Note 3-Acquisitions
Acquisition of DMS
On October 31, 2005, we acquired Dynegy’s midstream natural gas business for approximately $2,452 million, including certain acquisition-related costs. Under the terms of the agreement, we acquired Dynegy’s ownership interests in DMS, which held Dynegy’s natural gas gathering and processing assets, and its NGL fractionation, terminalling, storage, transportation, distribution and marketing assets. We acquired DMS to expand our natural gas gathering and processing asset base in Texas, Louisiana and New Mexico, and to gain greater access to marketing and distribution channels for our produced NGLs.
We have accounted for the acquisition under the purchase method of accounting in accordance with SFAS 141, “Business Combinations.” We retained a third party to perform certain valuation services in relation to the DMS acquisition. These services included providing a report stating an opinion of the fair value of certain tangible and intangible assets, unconsolidated equity interests, and product inventory. The third party applied
Index to Financial Statements
standard valuation approaches and methodologies utilizing publicly available economic and pricing data, historical DMS operations and financial data, and assumptions provided by our management. The third party’s analyses, opinions, and conclusions were developed and its report was prepared in conformity with the Uniform Standards of Professional Appraisal Practice.
Certain of the DMS property, plant and equipment sustained damage from the effects of Hurricane Katrina and Hurricane Rita. Our final purchase price allocation reflects our estimate of the damage incurred and the amount we expect to recover from property damage insurance claims.
The purchase price and the final allocation to assets and liabilities based on their estimated fair values as of October 31, 2005 are shown below (in thousands):
Acquisition and Sale of Equity Interest in Bridgeline
In December 2004, we purchased a 40% ownership interest in Bridgeline from Enron North America Corporation (“Enron”) and certain of its affiliates, for $101.3 million, including certain acquisition-related costs. Bridgeline was originally formed by Enron and certain affiliates of Chevron to own and operate certain natural gas pipeline and storage facilities in southern Louisiana.
On August 5, 2005, we sold our interest in Bridgeline to Chevron for $117.0 million. We recognized a pre-tax gain of $18.0 million from the sale. We used the proceeds from this sale primarily for debt repayment, including repayment in full of a $45 million term loan related to Bridgeline.
Note 4-Partnership Units and Related Matters
On February 14, 2007 the initial public offering (“IPO”) of 19,320,000 common units representing limited partner interests in the Partnership was completed. Concurrently with the IPO, the Partnership entered into a five year, $500 million senior secured revolving credit facility and borrowed $294.5 million under this newly established facility (see Note 7). The Partnership used the proceeds from this borrowing, together with $377.5 million of net proceeds from the IPO to pay offering expenses and debt issue costs and to retire $665.7 million of affiliate debt owed to us. We applied this amount along with cash on hand to retire in full the outstanding balance (including accrued interest) of our $700 million senior secured asset sale bridge loan facility.
In return for our contribution of our North Texas assets to the Partnership in connection with the IPO, we received a 2% general partner interest, incentive distribution rights and a 36.6% limited partner interest in the Partnership. Our limited partner interest is represented by 11,528,231 subordinated units. These units are subordinated for a period of time to the common units with respect to distribution rights.
Index to Financial Statements We continue to consolidate the Partnership’s assets, liabilities and results of operations due to our control of the Partnership through our general partner interest.
Secondary Public Offering. On October 24, 2007, the Partnership completed the purchase of our ownership interests in the SAOU System and the LOU System. This acquisition consisted of the SAOU System’s natural gas gathering and processing businesses located in the Permian Basin of west Texas and the LOU System’s natural gas gathering and processing businesses located in southwest Louisiana. The total value of the transaction was approximately $730.2 million. Concurrent with the acquisition, the Partnership sold 13,500,000 common units representing limited partnership interests at a price of $26.87 per common unit ($25.796 per common unit after the underwriting discount). Total consideration paid by the Partnership to us consisted of cash of approximately $722.5 million and 312,246 general partner units issued to us to allow us to maintain our 2% general partner interest in the Partnership. We continue to consolidate the Partnership due to our ability to exercise significant control of the Partnership through our general partner interest.
On November 20, 2007, the underwriters exercised their option to purchase an additional 1,800,000 common units at the same $26.87 price per the Partnership’s common unit. The net proceeds from the underwriters exercise were used to reduce borrowings under the Partnership’s credit facility by approximately $47 million. In addition, we contributed $1.0 million to the Partnership to maintain our 2% general partner interest.
Cash Distributions. In accordance with the Partnership’s partnership agreement, the Partnership must distribute all of its available cash, as defined in the partnership agreement, within 45 days following the end of each calendar quarter. Distributions will generally be made 98% to the common and subordinated unitholders and 2% to the general partner, subject to the payment of incentive distributions to the extent that certain target levels of cash distributions are achieved.
Under the quarterly incentive distribution provisions, generally the Partnership’s general partner is entitled to 13% of amounts distributed in excess of $0.3881 per unit, 23% of the amounts distributed in excess of $0.4219 per unit and 48% of amounts distributed in excess of $0.50625 per unit. No incentive distributions were earned by us through our general partner interest for the period from February 14, 2007 through September 30, 2007. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.3375 per unit, plus arrearages, prior to any distribution of available cash to the holders of subordinated units. Subordinated units will not accrue any arrearages with respect to distributions for any quarter.
Due to the timing of the Partnership’s IPO, a pro-rated distribution for the first quarter of 2007 of $0.16875 per unit (approximately $5.3 million) was paid. The following table shows the timing and payments of the Partnership’s distributions:
The Partnership’s acquisition of the SAOU and LOU systems was accounted for under common control accounting. Under common control accounting, the SAOU and LOU systems assets and liabilities are recorded at their book value with the balance of the acquisition proceeds recorded as an adjustment to parent equity.
Index to Financial Statements Note 5-Property, Plant, and Equipment
Our property, plant, and equipment and accumulated depreciation were as follows at the dates indicated:
Note 6-Unconsolidated Investments
At December 31, 2007 and 2006, our unconsolidated investments included a 22.8959% ownership interest in Venice Energy Services Company, LLC (“VESCO”), a venture that operates a natural gas liquids processing and extraction facility in the Gulf Coast region and a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that fractionates natural gas liquids on the Gulf Coast. In August 2005 we sold our interest in Bridgeline.
We acquired these equity method investments in the DMS acquisition. These ventures maintain independent capital structures and have financed their operations either on a non-recourse basis to us or through their ongoing commercial activities.
The following table shows our unconsolidated investments at the dates indicated.
Our equity in the net assets of VESCO and GCF exceeded our acquisition date investment account by approximately $5.9 million and $5.2 million, respectively. The difference is being amortized over the estimated remaining life of the net assets on a straight-line basis, and is included as a component of our equity in earnings of unconsolidated investments.
Index to Financial Statements The following table shows our equity earnings, cash contributions and cash distributions with respect to our unconsolidated investments for the periods indicated:
Our equity in earnings of VESCO for 2007, 2006 and 2005 includes $3.1 million, $2.9 million and $1.4 million, respectively, for partially settled business interruption insurance claims. For 2005, our equity in earnings of VESCO and GCF includes only our share of their results for the two months ended December 31, 2005.
The following table shows summarized financial information of our unconsolidated investments for the periods indicated:
(1) VESCO’s results include a $136.0 million non-cash impairment charge related to hurricane damage suffered in August.
Index to Financial Statements Note 7-Debt Obligations
Our consolidated debt obligations consisted of the following at the dates indicated:
(1) The entire amount was repaid in February 2007 concurrent with the closing of the Partnership’s IPO.
(2) The entire $250 million available under the senior secured revolving credit facility may also be utilized for letters of credit.
(3) The $300 million senior secured synthetic letter of credit facility terminates in October 2012. At December 31, 2007 we had $27.6 million available under this facility.
Information Regarding Variable Interest Rates Paid
The following table shows the range of interest rates paid and weighted-average interest rate paid on our significant consolidated variable-rate debt obligations during 2007:
(1) The entire amount was repaid in February 2007 concurrent with the closing of the Partnership’s IPO.
Index to Financial Statements Consolidated Debt Maturity Table
The following table presents the scheduled maturities of principal amounts of our debt obligations for the next five years and in total thereafter:
Description of Debt Obligations
Obligations of Targa Resources, Inc.
Senior Secured Credit Facility
On October 31, 2005, we entered into a senior secured credit agreement with a syndicate of financial institutions and other institutional lenders. The senior secured credit facility provides senior secured financing of $2,500 million, consisting of:
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a $1,250 million senior secured term loan facility;
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a $700 million senior secured asset sale bridge loan facility;
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a $250 million senior secured revolving credit facility; and
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a $300 million senior secured synthetic letter of credit facility.
The entire amount of the senior secured revolving credit facility is available for letters of credit and includes a limited borrowing capacity for borrowings on same-day notice referred to as swingline loans. The lenders under the senior secured synthetic letter of credit facility pre-funded the entire amount of their respective commitments by depositing such amounts in a designated deposit account that is held by the administration agent and which is used to support letters of credit.
We may add one or more incremental term loan facilities, and/or one or more incremental synthetic letter of credit facilities and/or increase the commitments under the senior secured revolving credit facility in an aggregate amount for all such increases of up to $400 million, subject to the satisfaction of certain conditions. No commitments for such incremental facilities have been requested by the Company or offered by the lenders and no lender under the senior secured credit facility will be obligated to provide any incremental credit extensions unless it so agrees.
Borrowings under the senior secured credit facilities, other than the senior secured synthetic letter of credit facility, will bear interest at a rate equal to an applicable margin plus, at our option, either (a) a base rate determined by reference to the higher of (1) the prime rate of Credit Suisse and (2) the federal funds rate plus 1/2 of 1% or (b) LIBOR as determined by reference to the costs of funds for dollar deposits for the interest period relevant to such borrowing adjusted for certain statutory reserves. At December 31, 2007, the applicable margin for borrowings under the senior secured revolving credit facility was 1.00% with respect to base rate borrowings and 2.00% with respect to LIBOR borrowings. The applicable margin for borrowings under the senior secured revolving credit facility may fluctuate based upon the Company’s leverage ratio as defined in the credit agreement.
Index to Financial Statements We are required to pay a facility fee, quarterly in arrears, to the lenders under the senior secured synthetic letter of credit facility equal to (i) 2.00% of the amount on deposit in the designated deposit account plus (ii) the administrative cost incurred by the deposit account agent for such quarterly period.
In addition to paying interest on outstanding principal under the senior secured credit facilities, we are required to pay a commitment fee equal to 0.375% of the currently unutilized commitments thereunder. The commitment fee rate may fluctuate based upon the Company’s leverage ratios.
The senior secured credit agreement requires us to prepay loans outstanding under the senior secured term loan facility, subject to certain exceptions, with:
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50% of our annual excess cash flow (which percentage will be reduced to 25% if our total leverage ratio is no more than 4.00 to 1.00 and to 0% if our total leverage ratio is no more than 3.00 to 1.00 commencing with the fiscal year-end December 31, 2006);
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100% of the net cash proceeds of all non-ordinary course asset sales, transfers, or other dispositions of property, subject to certain exceptions;
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100% of the net cash proceeds of any incurrence of debt, other than debt permitted under the senior secured credit agreement.
Prepayments, other than voluntary prepayments of outstanding amounts under the senior secured revolving credit facility, will be applied to the term loan facility to reduce remaining amortization payments of the term loan facility in chronological order of maturity. We may voluntarily reduce the unutilized portion of the commitments and prepay outstanding loans under the senior secured credit facilities at any time without premium or penalty, other than customary “breakage” costs with respect to LIBOR loans.
We are required to repay the term loan facility in quarterly principal amounts of 0.25% of the original principal amount, with the remaining amount payable October 31, 2012. Principal amounts outstanding under the senior secured asset sale bridge loan facility were due and payable in full on October 31, 2007, but were repaid in February 2007 prior to maturity.
Principal amounts outstanding under the senior secured revolving credit facility are due and payable in full on October 31, 2011.
Principal amounts outstanding under the senior secured synthetic letter of credit facility are due and payable in full on October 31, 2012.
All obligations under the senior secured credit agreement and certain secured hedging arrangements are unconditionally guaranteed, subject to certain exceptions, by each of our existing and future domestic restricted subsidiaries, referred to, collectively, as the guarantors.
All obligations under the senior secured credit facilities and certain secured hedging arrangements, and the guarantees of those obligations, are secured by substantially all of the following assets, subject to certain exceptions:
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a pledge of the capital stock and other equity interests held by us or any guarantor (except that we will not pledge more than 65% of the voting stock and other voting equity interests of any foreign subsidiary); and
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a security interest in, and mortgages on, our and our guarantors’ tangible and intangible assets.
The senior secured credit agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, our ability to incur additional indebtedness (including guarantees and hedging
Index to Financial Statements
obligations) or issue preferred stock; create liens on assets; enter into sale and leaseback transactions; engage in mergers or consolidations; sell assets; pay dividends and make distributions or repurchase capital stock and other equity interests; make investments, loans or advances; make capital expenditures; repay, redeem or repurchase certain indebtedness; make certain acquisitions; engage in certain transactions with affiliates; amend certain debt and other material agreements; change our lines of business; and impose certain restrictions on restricted subsidiaries that are not guarantors, including restrictions on the ability of such subsidiaries that are not guarantors to pay dividends.
In addition, beginning with the quarter ended March 31, 2006, the senior secured credit agreement required us to maintain certain specified maximum total leverage ratios and certain specified minimum interest coverage ratios.
The senior secured credit agreement will permit us to transfer, on one or more occasions:
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assets (including equity interests of a subsidiary or other entity) to one or more master limited partnerships (“MLPs”) and/or one or more subsidiaries of any MLP; and
•
equity interests in an MLP, or, in certain circumstances, the general partner of an MLP.
In each case we are required to comply with certain limitations, including minimum cash consideration requirements.
$250 Million Senior Notes Offering
On October 31, 2005 we completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of eight year senior unsecured notes (“the Notes”). Proceeds from the Notes plus borrowings under our senior secured credit facility were used to repay pre-existing debt and fund a portion of the DMS acquisition.
The Notes:
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are our unsecured senior obligations;
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rank pari passu in right of payment with all our existing and future senior indebtedness, including indebtedness under our new senior secured credit facility;
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are effectively subordinated to all our secured indebtedness to the extent of the value of the collateral securing such indebtedness, including indebtedness under the senior secured credit facilities;
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are structurally subordinated to all existing and future claims of creditors (including trade creditors) and holders of preferred stock of our subsidiaries that do not guarantee the Notes;
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rank senior in right of payment to any of our future subordinated indebtedness;
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are guaranteed on a senior unsecured basis by the subsidiary guarantors that guarantee the senior secured credit facilities; and
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are subject to registration with the SEC pursuant to a registration rights agreement.
Interest on the Notes accrues at the rate of 8 1/2% per annum and is payable in cash semi-annually in arrears on May 1 and November 1, commencing May 1, 2006. Interest is computed on the basis of a 360-day year comprised of twelve 30-day months. Additional interest may accrue on the Notes in certain circumstances pursuant to a registration rights agreement.
On and after November 1, 2009, we may redeem all or part of the Notes at our option, at 104.250% of the principal amount for the twelve-month period beginning November 1, 2009, at 102.125% of the principal amount
Index to Financial Statements
for the twelve-month period beginning November 1, 2010, and at 100% of the principal amount thereafter. In each case, accrued and unpaid interest is payable to the date of redemption. In addition, before November 1, 2009, we may redeem all or part of the Notes at the make-whole price set forth under the indenture. At any time prior to November 1, 2008, we may redeem up to 35% of the Notes with the net cash proceeds of certain equity offerings at a redemption price equal to 108.500% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon to the redemption date.
On December 18, 2007, we filed a registration statement on Form S-4/A in which we offered to exchange up to $250,000,000 of our outstanding 8 1/2 % Senior Notes due 2013 for new notes. The terms of the new notes were substantially identical to the outstanding notes, except that we registered the new notes under the Securities Act of 1933. The exchange of outstanding notes for new notes was completed on January 29, 2008.
Obligations of Targa Resources Partners LP
Senior Secured Revolving Credit Facility
On February 14, 2007 the Partnership entered into a credit agreement which provides for a $500 million five year revolving credit facility with a syndicate of financial institutions. The revolving credit facility bears interest, at the Partnership’s option, at the higher of the lender’s prime rate or the federal funds rate plus 0.5%, plus an applicable margin ranging from 0% to 1.25% dependent on the Partnership’s total leverage ratio, or LIBOR plus an applicable margin ranging from 1.0% to 2.25% dependent on the Partnership’s total leverage ratio.
The credit agreement restricts the Partnership’s ability to make distributions of available cash to unitholders if they are in any default or an event of default (as defined in the credit agreement) exists. The credit agreement requires them to maintain a leverage ratio (the ratio of consolidated indebtedness to our consolidated EBITDA, as defined in the credit agreement) of no more than 5.00 to 1.00 on the last day of any fiscal quarter ending on or after September 30, 2007. The credit agreement also requires the Partnership to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to their consolidated interest expense, as defined in the credit agreement) of no less than 2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination. In addition, the credit agreement contains various covenants that may limit, among other things, the Partnership’s ability to:
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incur indebtedness;
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grant liens; and
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engage in transactions with affiliates.
The credit facility matures on February 14, 2012, at which time all unpaid principal and interest is due. The credit agreement restricts the ability of the Partnership to make distributions of available cash to unitholders if it is in default or an event of default exists (as defined in the credit agreement).
On October 24, 2007, the Partnership entered into the First Amendment to Credit Agreement (the “Amendment”). The Amendment increased by $250 million the maximum amount of increases to the aggregate commitments that may be requested by the Partnership. The Amendment allows the Partnership to request commitments under the Credit Agreement, as supplemented and amended, up to $1 billion.
As of December 31, 2007, the Partnership had approximately $97.8 million available under its credit agreement, after giving effect to outstanding borrowings of $626.3 million and the issuance of a $25.9 million letter of credit.
Index to Financial Statements Holdco Loan Facility of Targa Investments
On August 9, 2007, Targa Investments borrowed $450 million under a newly arranged credit agreement. The net proceeds of $445.1 million (after payment of debt issuance costs) were used to pay a dividend on Targa Investments’ preferred stock.
Principal amounts outstanding under the credit agreement are due and payable in full on February 9, 2015. In connection with the agreement, Targa Investments pledged its indirect 100% ownership of our capital stock as collateral for amounts due under the agreement. Neither we nor any of our subsidiaries guaranty Targa Investments’ obligations under the loan, our assets are not pledged as collateral for the loan and we have no obligation to repay the loan.
Note 8-Stock and Other Compensation Plans
Accounting for Equity Awards
Effective January 1, 2006, we began to account for Targa Investments’ equity awards granted to our employees using the provisions of SFAS No. 123R, “Share-Based Payment”. SFAS 123R requires us to recognize compensation expense related to equity awards based on the grant date fair value of the award. The fair value of an award of nonvested common stock is measured at its fair value as if it were vested and issued on the grant date. The fair value of a stock option award is estimated using the Black-Scholes option pricing model. Under SFAS 123R, the fair value of all awards expected to vest is amortized to earnings on a straight-line basis over the requisite service period.
Prior to our adoption of SFAS 123R, we recognized compensation expense related to stock options only if the grant date fair value of the underlying stock was greater than the exercise price of the option. Our recognition of compensation expense in connection with awards of nonvested common stock did not change under SFAS 123R.
We apply SFAS 123R prospectively to new stock option awards and to stock option awards modified, repurchased, or cancelled on or after January 1, 2006. We shall continue to account for the nonvested portion of stock option awards outstanding on January 1, 2006 using the intrinsic value method. Stock-based compensation expense is based on the awards ultimately expected to vest, and has been reduced for estimated forfeitures. The effects of applying SFAS 123R during 2006 did not have a material effect on our net income.
Stock Option Plans
Under Targa Investments’ 2005 Incentive Compensation Plan (“the Plan”), options to purchase a fixed number of shares of its stock may be granted to our employees, directors and consultants. Generally, options granted under the Plan have a vesting period of four years and remain exercisable for ten years from the date of grant.
The fair value of each option granted since our adoption of SFAS 123R was estimated on the date of grant using the Black-Scholes option pricing model, which incorporates various assumptions for 2007 and 2006, including (i) expected term of the options of ten years, (ii) a risk-free interest rate of 4.6% and 4.5%, respectively, (iii) expected dividend yield of 0%, and (iv) expected stock price volatility on Targa Investments’ common stock of 29.7% and 23.8%, respectively. Our selection of the risk-free interest rate was based on published yields for United States government securities with comparable terms. Because Targa Investments is a non-public company, its expected stock price volatility was estimated based upon the historical price volatility of the Dow Jones MidCap Pipelines Index over a period equal to the expected average term of the options granted. The calculated fair value of options granted during the twelve months ended December 31, 2007 and the same period ended December 31, 2006 is $0.63 and $0.21 per share, respectively.
Index to Financial Statements The following table shows stock option activity for periods indicated:
We recognized $0.1 million of compensation expense associated with stock options during each of 2007, 2006 and 2005. As of December 31, 2007, we expect to incur an additional $0.1 million of expense related to non-vested stock options over a weighted-average period of approximately one year.
Non-vested (Restricted) Common Stock
Restricted stock awards entitle recipients to exchange restricted common shares for unrestricted common shares (at no cost to them) once the defined vesting period expires, subject to certain forfeiture provisions. The restrictions on the non-vested shares generally lapse four years from the date of grant. Compensation expense is recognized on a straight-line basis over the vesting period. The fair value of non-vested stock is measured on the grant date using the estimated market price of Targa Investments common stock on such date.
The following table provides a summary of Targa Investments’ non-vested common stock for the periods indicated:
(1) On May 1, 2007, each outstanding option on Targa Investments’ Series B preferred stock was exchanged for 10 shares of Targa Investments’ non-vested common stock (representing a total of 1,115,500 shares) and the right to receive a cash payment from Targa Investments of $27.69 on January 2, 2008. The exchange resulted in no additional compensation costs.
The total fair value of non-vested common shares that vested during 2007 was $0.6 million. We recognized $2.0 million, $2.7 million and $1.1 million of compensation expense associated with the vesting of restricted
Index to Financial Statements
stock during 2007, 2006 and 2005, respectively. As of December 31, 2007, we expect to incur an additional $1.3 million of expense related to non-vested shares issued to our employees, over a weighted-average period of approximately one year.
Non-Employee Director Grants and Incentive Plan related to the Partnership’s Common Units
In connection with the Partnership’s IPO in February 2007, Targa Investments adopted a long-term incentive plan (“LTIP”) for employees, consultants and directors who perform services for Targa Investments or its affiliates. The LTIP provides for the grant of cash-settled performance units which are linked to the performance of the Partnership’s common units and may include distribution equivalent rights (“DERs”). The LTIP is administered by the compensation committee of the board of directors of Targa Investments. Subject to applicable vesting criteria, a DER entitles the grantee to a cash payment equal to cash distributions paid on an outstanding common unit.
On February 21, 2007, Targa Investments granted 304,600 performance units under the LTIP. Each vested performance unit will entitle the grantee to a cash payment equal to the then value of a Partnership common unit, including DERs. Vesting of performance units is based on the total return per common unit of the Partnership through the end of the performance period, August 1, 2010, relative to the total return of a defined peer group.
Because the performance units require cash settlement, they have been accounted for as liability awards under SFAS 123R. Accordingly, the measurement date for the performance units is the date of settlement, subject to remeasurement at each reporting date until settlement. The percentage of the fair value that is accrued as compensation cost at the end of each reporting period is equal to the percentage of the requisite service that has been rendered at that date. Changes in fair value that occur after the end of the requisite service period are compensation cost of the period in which the changes occur.
The fair value of a performance unit is the sum of: (i) the closing price of a the Partnership common unit on the reporting date; (ii) the fair value of an at-the-money call option on a performance unit with a grant date equal to the reporting date and an expiration date equal to the last day of the performance period; and (iii) estimated DERs. The fair value of the call option was estimated with a Black-Scholes option pricing model using a risk-free rate of 3.06%, volatility of 20% and a dividend yield of zero.
At December 31, 2007, the aggregate fair value of performance units expected to vest was $10.6 million. For the twelve months ended December 31, 2007, we recognized compensation expense of $2.6 million related to the performance units. The total recognition period for the remaining unrecognized compensation cost is approximately three years.
Targa Resources GP LLC, the general partner of the Partnership, also made equity-based awards of 16,000 restricted common units of the Partnership (2,000 restricted common units in the Partnership to each of the Partnership’s and Targa Investments’ non-management directors) under the Targa Resources Partners Long-Term Incentive Plan. The awards will settle with the delivery of common units and are subject to three-year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date. During the twelve months ended December 31, 2007, we recognized compensation expense of $180,000 related to these awards. We estimate that the remaining fair value of $156,000 will be recognized in expense over the next 26 months.
Other Compensation Plans
We have a 401(k) plan whereby we match 100% of up to 5% of an employee’s contribution (subject to certain limitations in the plan). We also contribute an amount equal to 3% of each employee’s eligible compensation to the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa contributions are made 100% in cash. We made contributions to the 401(k) plan totaling $7.6 million, $6.0 million, and $2.4 million during 2007, 2006, and 2005, respectively.
Index to Financial Statements Note 9-Derivative Instruments and Hedging Activities
At December 31, 2007, OCI included $ 91.7 million ($57.2 million, net of tax) of unrealized net losses on commodity hedges, and $0.3 million ($0.2 million, net of tax) of unrealized net losses on interest rate hedges.
During 2007, 2006 and 2005 deferred net gains / (losses) on commodity hedges of $4.1 million, $31.2 million and $(7.5) million, respectively, were reclassified from OCI to revenues, and deferred net gains / (losses) on interest rate hedges of $2.2 million, $1.0 million and $(0.1) million, respectively, were reclassified from OCI to interest expense. Adjustments for hedge ineffectiveness decreased revenues by $0.4 million in 2005.
As of December 31, 2007, $40.2 million ($25.1 million, net of tax) of deferred net losses on commodity hedges and $68,000 ($42,000, net of tax) of deferred net losses on interest rate hedges recorded in OCI are expected to be reclassified to revenues during the next twelve months.
In connection with the transfer of assets to the Partnership in October 2007 (see Note 4), we de-designated and settled for cash of approximately $24.2 million derivative financial instruments designated as hedges of forecasted sales of NGLs through 2011. During 2007, we reclassified deferred net losses of $2.4 million related to these derivatives from OCI to revenues. During the years ended December 31, 2008, 2009, 2010 and 2011, we will reclassify additional deferred net losses of $9.9 million, $6.7 million, $1.8 million and $0.2 million, respectively, from OCI to revenues with respect to the de-designated hedges.
At December 31, 2007, our open derivatives designated as hedges consist of the following:
Natural Gas
NGL
Index to Financial Statements At December 31, 2007, the Partnership had the following open derivatives designated as hedges:
Natural Gas
NGL
Index to Financial Statements Condensate
These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us with protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices which we have hedged, we will receive less revenue on the hedge volumes than we would receive in the absence of hedges.
Customer Derivatives
At December 31, 2007, the Partnership had the following commodity derivative contracts directly related to short-term fixed price arrangements elected by certain customers in various natural gas purchase and sale agreements, which have been marked to market:
Interest Rate Swaps
In December 2007, the Partnership entered into the following interest rate swaps:
At December 31, 2007, the fair value of these interest rate swaps was $(0.3) million.
Index to Financial Statements Note 10-Income Taxes
Our provisions for income taxes for the periods indicated are as follows:
Our deferred income tax assets and liabilities at December 31, 2007 and 2006 consist of differences related to the timing of recognition of certain types of costs as follows:
(1) Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of the assets and liabilities of our wholly-owned partnerships and equity method investments.
At December 31, 2007, for federal income tax purposes, we had carryforwards of approximately $71 million of regular tax net operating losses (“NOL”). The NOL carryforwards expire in 2027.
Index to Financial Statements Set forth below is reconciliation between our income tax provision (benefit) computed at the United States statutory rate on income before income taxes and the income tax provision in the accompanying consolidated statements of operations for the periods indicated:
(1) During 2007 we recognized a deferred tax asset of $8.3 million related to a computational change of the temporary credit related to the Texas margin tax.
We adopted the provisions of FIN 48 on January 1, 2007. As a result of the adoption, no increases or decreases to income tax liabilities and retained earnings were necessary. During 2007, no uncertain tax positions were identified. We believe that our income tax filing positions and deductions will be sustained on audit and do not anticipate any adjustments that will result in a material adverse effect on our financial condition, results of operations or cash flow. Therefore, no reserves for uncertain income tax positions have been recorded pursuant to FIN 48.
We are a member of a group that files a consolidated tax return with the federal government as well as several states. We share tax expense and liability with our parent corporation, Targa Investments based on our relative contributions to consolidated income tax expense and liability. There has been no change in the method of allocation for the years presented in these financial statements.
Note 11-Commitments and Contingencies
Certain property and equipment is leased under non-cancelable leases that require fixed monthly rental payments and expire at various dates through 2099. Surface and underground access for gathering, processing, and distribution assets that are located on property not owned by us is obtained through right-of-way agreements, which require annual rental payments and expire at various dates through 2099. Future non-cancelable commitments related to these obligations and our asset retirement obligations are presented below:
(1) Operating lease obligations include minimum lease payment obligations associated with gas processing plant site leases, railcar leases, and office space leases.
(2) Consist of capacity payments for firm transportation contracts.
(3) Primarily consist of information technology contractual obligations.
Total expenses related to operating leases, right of way, and capacity payments were $16.4 million, $2.2 million, and $4.1 million, respectively for 2007, $16.7 million, $1.8 million, and $1.9 million, , respectively, for 2006, and $1.5 million, $0.5 million, and $0.2 million, respectively, for 2005.
Index to Financial Statements Environmental
For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated in accordance with the American Institute of Certified Public Accountants (“AICPA”) Statement of Position No. 96-1, “Environmental Remediation Liabilities” (“SOP 96-1”). Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success.
In August 2005, prior to Targa’s acquisition of Versado Gas Processors, L.L.C. (“Versado”), the State of New Mexico’s Environment Department (“NMED”) inspected Versado’s Eunice Gas Processing Plant and its books and records. Targa Midstream Services Limited Partnership (“TMS”) is the operator of Versado. In May 2007, the NMED sent Versado a draft compliance order relating to the 2005 inspection. In that draft order, the NMED alleged that Versado violated certain emissions standards and permit, monitoring and recordkeeping requirements. TMS provided its initial response to the NMED’s allegations in June 2007. The NMED disposed of certain alleged violations but requested additional information on certain other alleged violations. TMS provided supplemental responses to the NMED’s inquiries from August through November 2007, and in December 2007, the NMED responded with a settlement offer containing a proposed penalty of approximately $2.1 million to resolve the remaining alleged violations arising out of the Eunice inspection. More recently, however, we have discussed with the NMED an expansion of the proposed compliance order to include the resolution of other alleged violations associated with the operation of flares at the Eunice, Monument and Saunders plants. We may be required to incur capital expenditures to upgrade the flares at the Eunice, Monument and Saunders plants and incur additional operating costs to implement various leak detection and monitoring programs in order to resolve these alleged violations, the amount of which currently is not reasonably ascertainable. It is also possible that the NMED may assess a penalty for the alleged violations associated with the operation of the flares at the Eunice, Monument and Saunders plants as part of an overall settlement, although no such penalty has yet been proposed by the agency. At this time, we can not estimate the effect, if any, that this matter will have on our results of operations.
Our environmental liability at December 31, 2007 and 2006 was $4.8 million and $2.3 million, respectively. Our December 31, 2007 liability consisted of $0.9 million for gathering system leaks, $1.8 million for ground water assessment and remediation, and $2.1 million for the gas processing plant environmental violations.
Legal Proceedings
We are a party to various legal proceedings and/or regulatory proceedings and certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against us. We believe all such matters are without merit or involve amounts, which, if resolved unfavorably, would not have a material effect on our financial position, results of operations, or cash flows except for the items more fully described below.
In May 2002, Apache Corporation (“Apache”) filed suit in Texas state court against Versado Gas Processors, LLC (“Versado”) as purchaser and processor of Apache’s gas and Dynegy Midstream Services, Limited Partnership (now known as Targa Midstream Services Limited Partnership, a wholly-owned subsidiary of ours (“TMSLP”)), as operator, of the Versado assets in New Mexico (“Versado Defendants”) alleging (i) excessive field losses of natural gas from wells owned by the plaintiff, (ii) that the Versado Defendants engaged in certain transactions with affiliates, resulting in the Versado Defendants not receiving fair market value when it sold gas and liquids, and (iii) that the formula for calculating the amount the Versado Defendants received from its buyers of gas and liquids is flawed since it is based on gas price indices that were allegedly manipulated. At trial, the jury found in favor of Apache on the lost gas claim, awarding approximately $1.6 million in damages. Apache’s claims with respect to the alleged “sham” transactions and index manipulation,
Index to Financial Statements
among others, were severed by the trial court and abated for a future trial. The parties settled the severed lawsuit in May 2007.
In May 2004, the trial court granted the Versado Defendants’ motion to set aside the jury verdict on the lost gas claim and vacated the jury award to Apache. Apache filed its notice of appeal with the 14th Court of Appeals of Houston in October 2004 and its appellate brief in December 2004.
In September 2006, the Court of Appeals reinstated the jury verdict in Apache’s favor on the issue of lost gas and also awarded Apache legal fees and interest, bringing the total award against the Versado Defendants to approximately $2.7 million. In October 2006, the Versado Defendants filed a motion for rehearing with the Court of Appeals. After rehearing, the Court of Appeals affirmed its decision reinstating the original jury verdict in Apache’s favor. With interest and attorneys fees that verdict stands at approximately $2.9 million.
In January 2007, the Versado Defendants filed their petition for review with the Supreme Court of Texas and in March 2007, Apache filed its conditional petition for review with the Supreme Court of Texas. At the request of the Supreme Court of Texas, the Versado Defendants and Apache filed responses to the opposing party’s petition in June 2007. Pursuant to an additional request from the Supreme Court of Texas, the Versado Defendants and Apache filed briefs on the merits on October 29, 2007. The Versado Defendants and Apache filed responses to each other’s brief on December 14, 2007, and then filed replies to the responses on December 31, 2007. The appeal is currently pending before the Supreme Court of Texas.
As a result of damage caused by Hurricane Rita, TMSLP’s West Cameron 229A platform sank in late September 2005. On November 12, 2005, the submerged wreckage was struck by an integrated tug-barge, the M/T Rebel, owned by K-Sea Transportation (“K-Sea”). As much as 25,000 barrels of No. 6 fuel oil may have entered Gulf of Mexico waters as the barge dragged part of the platform debris approximately three (3) miles from the sunken platform location. After receiving a letter from K-Sea threatening to hold TMSLP liable for all damages, TMSLP filed suit in federal district court in Galveston, Texas on November 21, 2005, seeking to hold K-Sea responsible for damage to the platform. In June 2007, the case was transferred to the federal district court in Houston, Texas.
In January 2006, Rios Energy (“Rios”), owner of the oil being transported in the barge, intervened in the existing suit and filed a new suit in the same federal court against both TMSLP and K-Sea alleging their negligence caused the loss of and damage to Rios’ oil. On March 8, 2006, K-Sea filed a counterclaim against TMSLP seeking to recover its alleged damages in excess of $90 million. In order to resolve K-Sea’s concerns over security for its claims, we agreed to provide a guarantee to K-Sea pursuant to which we would satisfy any final, non-appealable judgment or settlement against TMSLP if TMSLP is unable to pay any judgment against it.
On December 10, 2007, after a trial on the merits, the court concluded that K-Sea’s negligence caused 60% of the damages suffered by K-Sea and TMSLP. The court assessed 40% fault against TMSLP. Final judgment was entered on December 14, 2007. During trial, TMSLP and Rios settled their dispute.
For purposes of the trial, K-Sea and TMSLP stipulated to the amount of damages for K-Sea in the amount of $62.3 million and for TMSLP in the amount of $400,000. The parties also agreed that prejudgment interest, if any, would accrue at the rate of 4.45% simple interest per annum commencing May 1, 2006.
TMSLP and K-Sea entered into an agreement regarding the judgment, pursuant to which (i) TMSLP paid K-Sea $26.5 million on January 16, 2008, (ii) K-Sea acknowledged that the judgment has been satisfied, (iii) K-Sea released TMSLP and us from the guaranty, and (iv) TMSLP and K-Sea agreed not to appeal the judgment. TMSLP’s entire liability for K-Sea’s claims was covered by insurance, except for a self-insured retention amount.
Index to Financial Statements Prior to trial, K-Sea submitted a claim under the Oil Pollution Act of 1990 (“OPA 90”) seeking reimbursement of removal costs and cleanup damages from the Oil Spill Liability Trusts Fund (“Trust Fund”). K-Sea included the same removal costs and cleanup damages as a portion of its request for relief at the trial before the federal district court. K-Sea has indicated that it will adjust its request for reimbursement from the Trust Fund to reflect any recovery of removal and cleanup damages from TMSLP but has not yet done so. In the event K-Sea receives a reimbursement from the Trust Fund, the Trust Fund may seek to recover from TMSLP some or all of any reimbursement to K-Sea. TMSLP anticipates that liability to the Trust Fund, if any, would be covered by insurance. TMSLP intends to contest liability in any action or proceeding to recover amounts reimbursed to K-Sea, but we can give no assurances regarding the outcome of any such action or proceeding.
On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including us, three other Targa entities and private equity funds affiliated with Warburg Pincus, seeking damages from the defendants. The suit alleges that we and private equity funds affiliated with Warburg Pincus, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase the SAOU System from ConocoPhillips, and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from our competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. On October 2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. We have agreed to indemnify the Partnership for any claim or liability arising out of the WTG suit. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal. We will contest any appeal filed by WTG, but can give no assurances regarding the outcome of the proceeding.
Note 12-Related-Party Transactions
Relationships with Warburg Pincus
Warburg Pincus beneficially owns approximately 74% of the outstanding voting stock of our parent. Warburg Pincus is able to elect members of our board of directors, appoint new management and approve any action requiring the approval of our stockholders, including amendment of our certificate of incorporation and mergers or sales of substantially all of our assets. The directors elected by Warburg Pincus will be able to make decisions affecting our capital structure, including decisions to issue additional capital stock, implement stock repurchase programs and declare dividends.
Relationships with Merrill Lynch, Pierce, Fenner & Smith Incorporated (“Merrill Lynch”)
Equity
An affiliate of Merrill Lynch holds a non-voting equity interest in the general partner of Warburg Pincus Private Equity VIII, L.P. and Warburg Pincus Private Equity IX, L.P., the principal shareholders of Targa Investments. On October 31, 2005, Merrill Lynch Ventures L.P. 2001, an affiliate of Merrill Lynch, purchased an equity interest in our parent holding company, Targa Investments, for $50 million in cash, which was then contributed to us by Targa Investments in connection with our equity reorganization.
Financial Services
Merrill Lynch was an initial purchaser of the notes, and acted as our financial advisor with respect to our purchase of all the equity interests in DMS. An affiliate of Merrill Lynch is a lender and an agent under our existing senior secured credit facilities.
Index to Financial Statements Hedging Arrangements
We have entered into various commodity derivative transactions with Merrill Lynch Commodities Inc. (“MLCI”), an affiliate of Merrill Lynch. Under the terms of these various commodity derivative transactions, MLCI has agreed to pay us specified fixed prices in relation to specified notional quantities of natural gas, NGLs, and condensate over periods ending in 2010, and we have agreed to pay Merrill Lynch floating prices based on published index prices of such commodities for delivery at specified locations. The following table shows our open commodity derivatives with Merrill Lynch as of December 31, 2007:
The Partnership had the following open commodity derivatives with Merrill Lynch as of December 31, 2007:
At December 31, 2007, the fair value of all these open positions is a liability of $79.5 million. During 2007, we paid MLCI $14.2 million to settle payments due under hedge transactions. At December 31, 2006, the fair value of these open positions was a liability of $2.8 million. During 2006, Merrill Lynch paid us $6.8 million in commodity derivative settlements. There were no commodity derivative settlements with Merrill Lynch prior to 2006.
Commercial Relationships
In April 2004, we entered into a base agreement for the purchase and sale of natural gas with Entergy-Koch Trading, LP, pursuant to which Entergy-Koch Trading, LP typically purchases natural gas for fuel at its affiliated cogeneration facility in Lake Charles. On November 1, 2004, MLCI acquired Entergy-Koch, LP and became a successor to this agreement. Pricing terms under the agreement are governed by reference to specified index prices plus a premium.
Index to Financial Statements Commodity Transactions
For the years indicated, we completed natural gas and NGL purchases and sales transactions with related parties as follows:
These transactions were at market prices consistent with similar transactions with nonaffiliated entities.
Other Relationships
On December 16, 2004, we acquired a 40% ownership interest in Bridgeline. During 2005 we had net purchases of natural gas of $11.4 million from Bridgeline. During the period from December 16, 2004 to December 31, 2004, we purchased $1.4 million of natural gas from Bridgeline. These transactions were at market prices consistent with those paid to non-affiliate entities. We sold our interest in Bridgeline in August 2005.
Note 13-Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS 107, “Disclosures About Fair Value of Financial Instruments.” The estimated fair value amounts have been determined using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value. The carrying amounts and fair values of our other financial instruments are as follows as of December 31, 2007:
Index to Financial Statements The carrying value of the senior secured revolving credit facility approximates its fair value, as its interest rate is based on prevailing market rates. The fair value of the senior secured term loan facility and the senior unsecured notes are based on quoted market prices based on trades of such debt.
Note 14-Supplemental Cash Flow Disclosure
Cash activity related to interest on indebtedness, income taxes and business interruption insurance were:
Note 15-Segment Information
We categorize the midstream natural gas industry into, and describe our business in, two divisions: (i) Natural Gas Gathering and Processing (also a segment) and (ii) NGL Logistics and Marketing. Our NGL Logistics and Marketing division consists of three segments: (a) Logistics Assets, (b) NGL Distribution and Marketing and (c) Wholesale Marketing.
Our Natural Gas Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. These assets are located in North Texas, Louisiana and the Permian Basin of West Texas and Southeast New Mexico. We are also party to natural gas processing agreements with third party plants.
Our Logistics Assets segment is involved with gathering and storing mixed NGLs and fractionating, storing, and transporting of finished NGLs. These assets are generally connected to and supplied, in part, by our Natural Gas Gathering and Processing segment and are predominantly located in Mont Belvieu, Texas and West Louisiana.
Our NGL Distribution and Marketing segment markets our own natural gas liquids production and also purchased natural gas liquids products in selected United States markets. We also had the right to purchase or market substantially all of Chevron’s natural gas liquids pursuant to a Master Natural Gas Liquids Purchase Agreement.
Our Wholesale Marketing segment includes our refinery services business and wholesale propane marketing operations. In our refinery services business, we provide LPG (liquefied petroleum gas) balancing services, purchasing natural gas liquids products from refinery customers and selling natural gas liquids products to various customers. Our wholesale propane marketing operations include the sale of propane and related logistics services to multi-state retailers, independent retailers and other end-users. Wholesale Marketing operates principally in the United States, and has a small marketing presence in Canada.
Eliminations and Other includes amounts related to general and administrative expenses not allocated to segment operations, corporate development, interest expense, income tax expense, and the depreciation and cost of equipment used in our headquarters office. Eliminations and Other also includes the elimination of intersegment revenues and expenses.
Index to Financial Statements Our reportable segment information is shown in the following tables:
Index to Financial Statements The following table is a reconciliation of operating margin to net income for each period presented:
Note 16-Significant Risks and Uncertainties
Nature of Operations in Midstream Energy Industry
We operate in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs and crude oil. As such, our results of operations, cash flows and financial condition may be affected by (i) changes in the commodity prices of these hydrocarbon products and (ii) changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, crude oil and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.
Our profitability could be impacted by a decline in the volume of natural gas, NGLs and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or crude oil production or
Index to Financial Statements
crude oil refining, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas, NGLs and condensate handled by our facilities. A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.
Credit Risk due to Industry Concentrations
A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries. This concentration could impact our overall exposure to credit risk since these customers may be impacted by similar economic or other conditions. To help reduce our credit risk, we evaluate our counterparties’ financial condition and, where appropriate, negotiate netting agreements. We generally do not require collateral for our accounts receivable; however, in certain circumstances we will call for prepayment, require automatic debit agreements or obtain collateral to minimize our potential exposure to defaults.
Counterparty Risk with Respect to Financial Instruments
Where we are exposed to credit risk in our financial instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral and we do not anticipate nonperformance by our counterparties.
Casualties and Other Risks
We maintain coverage in various insurance programs, which provide us with property damage, business interruption and other coverages which are customary for the nature and scope of our operations. The financial impact of storm events such as Hurricanes Katrina and Rita has affected many insurance carriers, and may affect their ability to meet their obligation or trigger limitations in certain insurance coverages. At present, there is no indication of any of our insurance carriers being unable or unwilling to meet its coverage obligations.
We believe that we maintain adequate insurance coverage, although insurance will not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.
If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by our consolidated operations, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our obligations under various agreements with our lenders.
Note 17-Subsequent Events
On February 14, 2008 the Partnership made its quarterly cash distribution for the fourth quarter of 2007. The cash distribution of 39.75¢ per unit, or $1.59 per unit on an annualized basis, was paid to all outstanding common and subordinated unit holders of record as of the close of business on February 4, 2008.
Index to Financial Statements On March 7, 2008 we paid a cash dividend of $50.0 million to Targa Investments. Targa Investments used the proceeds to retire $62.5 million of its Holdco Loan. Please see Note 7 for further discussion of this loan.
Note 18-Consolidating Financial Statements
We are the issuer of the notes discussed in Note 7. The notes are jointly and severally, irrevocably and unconditionally guaranteed by our wholly-owned subsidiaries (referred to as “Guarantor Subsidiaries”).
The following financial information presents condensed consolidating financial statements, which include:
•
The parent company only (“Parent”);
•
The Guarantor Subsidiaries on a consolidated basis;
•
The Non-Guarantor Subsidiaries;
•
Elimination entries necessary to consolidate the Parent, the Guarantor Subsidiaries, and the Non-Guarantor Subsidiaries; and
•
The Company on a consolidated basis.
Index to Financial Statements Targa Resources, Inc.
Condensed Consolidating Balance Sheet
December 31, 2007
(in thousands)
Index to Financial Statements Targa Resources, Inc.
Condensed Consolidating Balance Sheet
December 31, 2006
(in thousands)
Index to Financial Statements Targa Resources, Inc.
Condensed Consolidating Statement of Operations
Year Ended December 31, 2007
(in thousands)
Index to Financial Statements Targa Resources, Inc.
Condensed Consolidating Statement of Operations
Year Ended December 31, 2006
(In Thousands)
Index to Financial Statements Targa Resources, Inc.
Condensed Consolidating Statement of Operations
Year Ended December 31, 2005
(In Thousands)
Index to Financial Statements Targa Resources, Inc.
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2007
(In Thousands)
Index to Financial Statements Targa Resources, Inc.
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2006
(In Thousands)
Index to Financial Statements Targa Resources, Inc.
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2005
(In Thousands)