UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
R | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2008
or
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 333-147066
(Exact name of registrant as specified in its charter)
Delaware | 74-3117058 | ||||
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | ||||
1000 Louisiana St, Suite 4300 Houston, Texas | 77002 | ||||
(Address of principal executive offices) | (Zip Code) |
(713) 584-1000
(Registrant’s telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered | |
None | Not applicable |
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes * No R
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes * No R
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No *
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. R
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer * | Accelerated filer * | Non-accelerated filer R | Smaller reporting company * |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes * No R.
All outstanding shares of our common stock are held by an affiliate. As of February 25, 2009, 1,000 shares of our common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
DESCRIPTION
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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” as well as the following risks and uncertainties:
· | our ability to access the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations; |
· | the amount of collateral required to be posted from time to time in our transactions; |
· | our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; |
· | the level of creditworthiness of counterparties to transactions; |
· | changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment; |
· | the timing and extent of changes in natural gas, natural gas liquids (“NGL”) and other commodity prices, interest rates and demand for our services; |
· | weather and other natural phenomena; |
· | industry changes, including the impact of consolidations and changes in competition; |
· | our ability to obtain necessary licenses, permits and other approvals; |
· | the level and success of natural gas drilling around our assets, and our success in connecting natural gas supplies to our gathering and processing systems, and NGL supplies to our logistics and marketing facilities; |
· | our ability to grow through acquisitions or internal growth projects, and the successful integration and future performance of such assets; |
· | general economic, market and business conditions; and |
· | the risks described elsewhere in this Annual Report on Form 10-K (“Annual Report”). |
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Annual Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the heading Risk Factors in this Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
As generally used in the energy industry and in this Annual Report on Form 10-K, the identified terms have the following meanings:
Bbl | Barrels (equal to 42 gallons) | |
BBtu | Billion British thermal units, a measure of heating value | |
Bcf | Billion cubic feet | |
Btu | British thermal unit, a measure of heating value | |
/d | Per day | |
Gal | Gallons | |
MBbl | Thousand barrels | |
Mcf | Thousand cubic feet | |
MMBbl | Million barrels | |
MMBtu | Million British thermal units | |
MMcf | Million cubic feet | |
Price Index Definitions | ||
IF-HSC | Inside FERC Gas Market Report, Houston Ship Channel/Beaumont, Texas | |
IF-NGPL MC | Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent | |
IF-Waha | Inside FERC Gas Market Report, West Texas Waha | |
NY-HH | NYMEX, Henry Hub Natural Gas | |
NY-WTI | NYMEX, West Texas Intermediate Crude Oil | |
OPIS-MB | Oil Price Information Service, Mont Belvieu, Texas |
As used in this Annual Report, unless the context otherwise requires, “Targa,” “our,” “we,” “us” and similar terms refer to Targa Resources, Inc., together with its consolidated subsidiaries, including its publicly traded master limited partnership, Targa Resources Partners LP, which we refer to in this Annual Report as the “Partnership.”
Overview
We are a leading provider of midstream natural gas and NGL services in the U.S. 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/Bend Arch 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 U.S.
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, 2008, we had total assets of $3.6 billion. We own interests in or operate approximately 11,000 miles of natural gas pipelines and approximately 800 miles of NGL pipelines, with natural gas gathering systems covering approximately 21,900 square miles and 22 natural gas processing plants with access to natural gas supplies in the Permian Basin, North Texas, the onshore region of the Louisiana Gulf Coast and the Gulf of Mexico. Additionally, we have an integrated NGL logistics and marketing business, with net NGL fractionation capacity of approximately 300 MBbl/d, 36 owned and operated storage wells with a net storage capacity of approximately 65 MMBbl, and 17 storage, marine and transport terminals with above ground NGL storage capacity of approximately 900 MBbl.
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, disciplined risk management and prudent growth, organic projects and acquisitions.
The successful execution of our business strategies is heavily dependent on our ability to access the equity and debt capital markets as well as the general health of the domestic and world economies. Given the current challenging conditions in the capital markets and the outlook for weak commodity prices, we expect that growth opportunities will be subject to more stringent evaluation criteria and that expenditure levels will be moderate to preserve capital until economic and financial market conditions improve.
We intend to accomplish our primary objective by executing the strategies described below:
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, as a function of historical contract structures and the competitive dynamics of our gathering areas, 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.
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, acquisitions in other related midstream businesses and/or expansion into new geographic areas of operation and, to the extent available, assets with fee-based arrangements. Among the factors we will consider in deciding whether to acquire assets include, but are not limited to, the economic characteristics of the acquisition (such as return on capital and cash flow stability), 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 securities. Current disruptions in the financial markets have made obtaining equity or debt funding on acceptable terms more difficult, which could limit our ability to successfully complete acquisitions.
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 (“dropped-down”) 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. The Partnership intends to finance drop-downs from us through a combination of debt and equity securities, including commercial debt facilities and public and private offerings of debt and equity securities. Current disruptions in the financial markets may make obtaining equity or debt funding on acceptable terms more difficult, which could limit our ability to drop-down additional assets into the Partnership.
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.
· | Significant scale of operations. We own interests in or operate approximately 11,000 miles of natural gas pipelines and approximately 800 miles of NGL pipelines, with natural gas gathering systems covering approximately 21,900 square miles and 22 natural gas processing plants with access to natural gas supplies in the Permian Basin, the Fort Worth Basin, the onshore region of the Louisiana Gulf Coast and the Gulf of Mexico. Additionally, we have an integrated NGL logistics and marketing business with net NGL fractionation capacity of approximately 300 MBbl/d, 36 owned and operated storage wells with a net storage capacity of approximately 65 MMBbl, and 17 storage, marine and transport terminals with above ground NGL storage capacity of approximately 900 MBbl. 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. |
· | Multiple producing basins. Our major gathering and processing systems source natural gas volumes from four producing areas: the Permian Basin, the Fort Worth Basin, the onshore region of The Louisiana Gulf Coast, and the Gulf of Mexico basin. 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. |
· | 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 any one customer. As of December 31, 2008, 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 agreements with Chevron, see “—Significant Customers.”
· | 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 percent-of-proceeds or fee-based 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 risk associated with a portion of our expected natural gas, NGL and condensate equity volumes for the years 2009 through 2012 by entering into financially settled derivative transactions including swaps and purchased puts (or floors). 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 specific NGL products or baskets of NGL products and to approximate our actual NGL and residue 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 $59.0 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 potentially grow our volumes and related cash flows as our supply areas continue to benefit from exploration and development. Generally, higher oil and gas prices 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 drilling and production activity in those areas and on emerging opportunities for Gulf Coast assets associated with liquefied natural gas (“LNG”) imports and liquefied petroleum gas (“LPG”) imports. Our existing infrastructure has the capacity to handle incremental volumes without significant capital investments. We believe that as domestic demand for natural gas and NGL grows over the long term our infrastructure will increase in value as such infrastructure takes on increasing importance in meeting that demand.
Experienced and Incentivized Management Team
Our executive 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 our executive and senior management team members have worked together effectively in prior roles. 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.
While we have set forth our strategies and competitive strengths above, our business involves numerous risks and uncertainties which may prevent us from executing our strategies. These risks include the adverse impact of changes in natural gas, NGL and condensate prices, on our inability to access sufficient additional production to replace natural declines in production and our dependence on a single natural gas producer for a significant portion of our natural gas supply. For a more complete description of the risks associated with an investment in us, see “Item 1A. Risk Factors.”
Our Business
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.
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. The natural gas we process is supplied through our gathering systems which, in aggregate, consist of approximately 11,000 miles of natural gas pipelines or through third-party owned pipelines (primarily from the Gulf of Mexico to our coastal straddle plants). Our processing plants include 16 facilities that we own (either wholly or jointly) and operate as well as six facilities in which we have an ownership interest but are operated by others. In 2008, we processed an average of approximately 2.1 Bcf per day of natural gas and produced an average of approximately 102 MBbl/d of NGLs.
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.
Facility | % Owned | Location | Approximate Gross Processing Capacity (MMcf/d) | 2008 Approximate Gross Inlet Throughput Volume (MMcf/d) | 2008 Approximate Gross NGL Production (MBbl/d) | Process Type (1) | ||||||||||||
Targa | ||||||||||||||||||
Permian Basin | ||||||||||||||||||
Sand Hills | 100.0 | Crane, TX | 150 | 105.8 | 13.1 | Cryo | ||||||||||||
Saunders (2) | 63.0 | Lea, NM | 70 | 55.4 | 5.9 | Cryo | ||||||||||||
Eunice (2) | 63.0 | Lea, NM | 120 | 85.0 | 9.3 | Cryo | ||||||||||||
Monument (2) | 63.0 | Lea, NM | 90 | 70.6 | 6.3 | Cryo | ||||||||||||
Area Total | 430 | 316.8 | 34.6 | |||||||||||||||
Louisiana Gulf Coast | ||||||||||||||||||
Barracuda | 100.0 | Cameron, LA | 200 | 109.2 | 2.7 | Cryo | ||||||||||||
Lowry | 100.0 | Cameron, LA | 265 | 158.8 | 4.4 | Cryo | ||||||||||||
Stingray | 100.0 | Cameron, LA | 300 | 175.8 | 2.8 | RA | ||||||||||||
Calumet(3) | 35.0 | St. Mary, LA | 1,650 | 107.1 | 2.7 | RA | ||||||||||||
Yscloskey(3) | 29.3 | St. Bernard, LA | 1,850 | 276.7 | 2.5 | RA | ||||||||||||
VESCO(4) | 76.8 | Plaquemines, LA | 725 | 395.6 | 6.8 | Cryo | ||||||||||||
Bluewater(3) | 21.8 | Acadia, LA | 425 | 18.7 | 0.6 | Cryo | ||||||||||||
Terrebonne(3) | 5.8 | Terrebonne, LA | 950 | 25.9 | 0.8 | RA | ||||||||||||
Toca(3) | 10.4 | St. Bernard, LA | 1,000 | 53.1 | 1.1 | Cryo/RA | ||||||||||||
Iowa (5) | 52.7 | Jeff. Davis, LA | 500 | - | - | Cryo | ||||||||||||
Sea Robin | 0.8 | Vermillion, LA | 700 | 24.8 | 0.8 | Cryo | ||||||||||||
Area Total | 8,565 | 1,345.7 | 25.2 | |||||||||||||||
The Partnership | ||||||||||||||||||
North Texas System | ||||||||||||||||||
Chico (6) | 100.0 | Wise, TX | 265 | Cryo | ||||||||||||||
Shackelford | 100.0 | Shackelford,TX | 13 | Cryo | ||||||||||||||
Area Total | 278 | 162.8 | 19.0 | |||||||||||||||
SAOU System | ||||||||||||||||||
Mertzon | 100.0 | Irion, TX | 48 | Cryo | ||||||||||||||
Sterling | 100.0 | Sterling, TX | 62 | Cryo | ||||||||||||||
Conger (7) | 100.0 | Sterling, TX | 25 | Cryo | ||||||||||||||
Area Total | 135 | 90.3 | 14.1 | |||||||||||||||
LOU System | ||||||||||||||||||
Gillis (6) | 100.0 | Calcasieu,LA | 180 | Cryo | ||||||||||||||
Acadia | 100.0 | Acadia, LA | 80 | Cryo | ||||||||||||||
Area Total | 260 | 168.1 | 9.0 |
________
(1) | Cryo—Cryogenic Processing; RA—Refrigerated Absorption Processing. |
(2) | These plants are part of our Versado Gas Processors L.L.C. joint venture with Chevron (“Versado”). |
(3) | Our ownership is adjustable and subject to annual redetermination. |
(4) | On July 31, 2008, we acquired Chevron’s ownership interest in Venice Energy Services Company (“VESCO”), thereby increasing our ownership interest from 22.9% to 76.8%. |
(5) | The Iowa plant is currently shut down. |
(6) | The Chico and Gillis plants have fractionation capacities of approximately 15 MBbl/d and 13 MBbl/d. |
(7) | The Conger plant is not currently operating, but is on standby and can be quickly reactivated on short notice and minimal incremental cost to meet additional needs for processing capacity. |
We believe we are well positioned as a gatherer and processor in the Permian Basin. We have broad geographic scope, covering portions of 29 counties and approximately 12,400 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 two or more 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 gas processing 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. The gathering systems consist of approximately 3,100 miles of natural gas gathering pipelines. The Saunders, Eunice and Monument refrigerated cryogenic processing plants have aggregate processing capacity of 280 MMcf per day (176 MMcf per day, net to our ownership interest). These plants have residue gas connections to pipelines owned by affiliates of El Paso, MidAmerican Energy Company and Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”). Our ownership in the Versado System is through Versado Gas Processors, L.L.C., a joint venture that is 63% owned by us and 37% owned by Chevron.
SAOU System (also located in West Texas and the Permian Basin; 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 onshore region of the Louisiana Gulf Coast and 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 U.S., and a substantial NGL distribution system with access to markets throughout Louisiana and the southeast U.S.
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 Pelican and Seahawk pipeline systems with a combined mileage of approximately 175 miles. These pipeline systems have a combined capacity of 230 MMcf per day and supply a portion of the natural gas delivered to the Barracuda and Lowry processing facilities. The gathering systems are unregulated pipelines that gather natural gas from the shallow water central Gulf of Mexico shelf. The Seahawk gathering system also gathers some natural gas from the onshore regions of the Louisiana Gulf Coast. 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 U.S. 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.
North Texas System. The North Texas System includes two interconnected gathering systems with approximately 4,100 miles of pipelines, covering portions of 12 counties and approximately 5,700 square miles, gathering wellhead natural gas for the Chico and Shackelford natural gas processing facilities. During 2008, the North Texas System gathered approximately 169MMcf/d of natural gas.
Gathering. The Chico Gathering System consists of approximately 2,000 miles of primarily low pressure gathering pipelines. Wellhead natural gas is either gathered for the Chico plant located in Wise County, Texas, and then compressed for processing, or it is compressed in the field at numerous compressor stations and then moved via one of several high-pressure gathering pipelines to the Chico plant. The Shackelford Gathering System consists of approximately 2,100 miles of intermediate-pressure gathering pipelines which gather wellhead natural gas largely for the Shackelford plant in Albany, Texas. Natural gas gathered from the northern and eastern portions of the Shackelford Gathering System is typically compressed in the field at numerous compressor stations and then transported to the Chico plant for processing.
Processing. The Chico processing plant includes two cryogenic processing trains with a combined capacity of approximately 265 MMcf/d and an NGL fractionator with the capacity to fractionate up to approximately 15 MBbl/d of raw NGL mix. The Shackelford plant is a cryogenic plant with a nameplate capacity of approximately 15 MMcf/d, but effective capacity is limited to approximately 13 MMcf/d due to capacity constraints on the residue gas pipeline that serves the facility.
SAOU System. Covering portions of 10 counties and approximately 4,00 square miles in West Texas, the SAOU System includes approximately 1,350 miles of pipelines in the Permian Basin that deliver wellhead natural gas to the Mertzon, Sterling and when reactivated the Conger processing plants. During 2008, the system gathered approximately 99 MMcf/d of natural gas.
Gathering. The SAOU System is connected to numerous producing wells and/or central delivery points. The system has approximately 850 miles of low-pressure gathering systems and approximately 500 miles of high-pressure gathering pipelines to deliver the natural gas to our processing plants. The gathering system has numerous compressor stations to inject low-pressure gas into the high-pressure pipelines.
Processing. The SAOU System includes two currently operating refrigerated cryogenic processing plants, the Mertzon plant and the Sterling plant, which have an aggregate processing capacity of approximately 110 MMcf/d. The system also includes the Conger cryogenic plant with a capacity of approximately 25 MMcf/d, which is on standby and can be quickly reactivated on short notice and minimal incremental cost to meet additional needs for processing capacity.
LOU System. The LOU System consists of approximately 850 miles of gathering system pipelines, covering approximately 3,800 square miles in Southwest Louisiana. During 2008, the system gathered approximately 178 Mcf/d of natural gas.
Gathering. The LOU System is connected to numerous 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.
Processing. The LOU System includes the Gillis and Acadia processing plants, both of which are cryogenic plants. These processing plants have an aggregate processing capacity of approximately 260 MMcf/d. In addition, the Gillis plant has integrated fractionation with operating capacity of approximately 13 MBbl/d of capacity.
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 U.S. 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 U.S. We own or commercially manage terminal assets in a number of states, including Texas, Louisiana, Nevada, California, Florida, Alabama, Mississippi, Tennessee, Kentucky and New Jersey and a new terminal scheduled to become operational in Arizona in the second quarter of 2009. 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 business is 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. Dew point specifications implemented by individual pipelines and potentially enacted by FERC across the industry should result 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 location, 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:
Facility | % Owned | Maximum Gross Capacity (MBbls/d) | 2008 Gross Throughput (MBbls/d) | |||||||||
Operated Fractionation Facilities: (1) | ||||||||||||
Lake Charles Fractionator (Lake Charles, LA) | 100.0 | 55 | 26.3 | |||||||||
Cedar Bayou Fractionator (Mont Belvieu, TX) (2) | 88.0 | 215 | 185.9 | |||||||||
Equity Fractionation Facilities (non-operated): | ||||||||||||
Gulf Coast Fractionator (Mont Belvieu, TX) | 38.8 | 109 | 105.2 | |||||||||
Partnership Operated Fractionation Facilities: | ||||||||||||
Gillis Plant Fractionator (Lake Charles, LA) (3) | 100.0 | 13 | 10.0 | |||||||||
Chico Plant Fractionator (Wise, TX) (3) | 100.0 | 15 | 3.4 |
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(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 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.
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 36 storage wells at our facilities with a net storage capacity of approximately 65 MMBbl, the usage of which may be limited by brine handling capacity, which is utilized to displace NGLs from storage. We also have 17 terminal facilities (15 wholly owned) in Texas, Kentucky, Mississippi, Tennessee, Louisiana, Florida, New Jersey and Arizona.
We operate our storage and terminalling facilities based on the needs and requirements of our customers in the NGL, petrochemical, refining, propane distribution 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 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 800 miles of company-owned pipelines to transport mixed NGL and specification products.
The following tables detail our NGL storage and terminalling assets:
NGL Storage Facilities | |||||||||||||
Facility | % Owned | County/Parish State | Number of Active Wells | Gross Storage Capacity (MMBbl) | |||||||||
Hackberry Storage (Lake Charles) | 100.0 | Cameron, LA | 12 | (2) | 20.0 | ||||||||
Mont Belvieu Storage | 100.0 | Chambers, TX | 20 | (3) | 41.4 | ||||||||
Easton Storage | 100.0 | Evangeline, LA | 1 | 0.8 | |||||||||
Hattiesburg Storage | 50.0 | Forrest, MS | 3 | 4.5 | |||||||||
VESCO (1) | 76.8 | Plaquemines, LA | 0 | - | |||||||||
Versado (1) | 63.0 | Lea, NM | 0 | - |
(1) | Not in service. |
(2) | Four of the twelve owned wells are leased to Citgo Petroleum Corporation (“Citgo”) under a long-term lease; one of the twelve wells is being permitted for hydrocarbon service. |
(3) | We own and operate 20 wells and operate 6 wells owned by CPC. |
Terminal Facilities | ||||||||||
% Owned | County/Parish, State | Description | 2008 Throughput (million gallons) | |||||||
Galena Park Terminal | 100 | Harris, TX | NGL import/export terminal | 899.0 | ||||||
Calvert City Terminal | 100 | Marshall, KY | Propane terminal | 49.6 | ||||||
Greenville Terminal (1) | 100 | Washington, MS | Marine propane terminal | 18.3 | ||||||
Pt. Everglades Terminal | 100 | Broward, FL | Marine propane terminal | 25.9 | ||||||
Tampa Terminal | 100 | Hillsborough, FL | Marine propane terminal | - | ||||||
Tyler Terminal | 100 | Smith, TX | Propane terminal | 7.9 | ||||||
Abilene Transport (2) | 100 | Taylor, TX | Raw NGL transport terminal | 14.7 | ||||||
Bridgeport Transport (2) | 100 | Jack, TX | Raw NGL transport terminal | 69.2 | ||||||
Gladewater Transport (2) | 100 | Gregg, TX | Raw NGL transport terminal | 63.3 | ||||||
Hammond Transport | 100 | Tangipahoa, LA | Transport terminal | 33.1 | ||||||
Chattanooga Terminal | 100 | Hamilton, TN | Propane terminal | 23.2 | ||||||
Mont Belvieu Terminal (3) | 100 | Chambers, TX | Transport and storage terminal | 2,910.4 | ||||||
Venice Terminal | 77 | Plaquemines, LA | Storage terminal | 0.7 | ||||||
Hackberry Terminal | 100 | Cameron, LA | Storage terminal | 316.9 | ||||||
Sparta Terminal | 100 | Sparta, NJ | Propane terminal | 11.3 | ||||||
Hattiesburg Terminal | 50 | Forrest, MS | Propane terminal | 147.2 | ||||||
Winona Terminal (4) | 100 | Flagstaff, AZ | Propane terminal | - |
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(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) | Anticipated commencement of operations in second quarter of 2009. |
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, 2008, include:
· | approximately 770 railcars that we lease and manage; |
· | approximately 70 owned and leased transport tractors and approximately 100 company-owned tank trailers; and |
· | 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 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 2008, we bought and sold an average of approximately 26 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 2008, we sold an average of approximately 37 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 2008, our distribution and marketing services business sold an average of approximately 219 MBbl/d of NGLs to third parties in North America, not including approximately 26 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 and 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 increased significantly following hurricanes Katrina and Rita. Insurance premiums, deductibles and co-insurance requirements increased substantially, and terms were generally less favorable than terms that were obtained prior to those hurricanes. The insurance market conditions have worsened as a result of industry losses including those sustained from hurricanes Gustav and Ike in September 2008, and as a result of volatile conditions in the financial markets. As a result, we expect to experience further increases in deductibles and premiums, and further reductions in coverage and limits, with some coverages potentially unavailable at any cost.
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 named windstorm coverage, and possibly contingent business interruption coverage for our onshore operations.
Significant Customers
During 2008 and 2007, approximately 22% and 26% of our consolidated revenues, and approximately 9% and 13% of our consolidated product purchases, 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 76.8% ownership interest, 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 (propane only) 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.
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 and a related services agreement, to which we provide storage and logistical services to CPC for feedstocks and products produced from the petrochemical plants. The services contract was renegotiated in 2008 with key components having a 10 year term. We previously gave notice on the feedstock supply agreement, which started a two year clock, effective August 2007, to renegotiate this agreement for the mutual benefit of both companies. We believe that 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. In addition to these two agreements, we have fractionation agreements in place with CPC for y-grade streams and butanes.
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 Atlas Gas Pipeline Company, Copano Energy, L.L.C. (“Copano”), WTG Gas Processing L.P. (“WTG”), DCP Midstream Partners LP(“DCP”), Devon Energy Corp (“Devon”), Enbridge Inc., GulfSouth Pipeline Company, LP, Hanlan Gas Processing, Ltd., J W Operating Company, Louisiana Intrastate Gas and several other interstate pipeline companies. 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 (76.8% 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: transportation of natural gas; rates and charges for natural gas transportation; certification and construction of new facilities; extension or abandonment of services and facilities; maintenance of accounts and records; commercial relationships and communications between pipelines and certain affiliates; terms and conditions of service and service contracts with customers; depreciation and amortization policies; and acquisition and disposition of facilities.
VGS holds a certificate of public convenience and necessity issued by FERC 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. 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 investment. Key determinants in the ratemaking process are costs of providing service, allowed rate of return and volume throughput and contractual capacity commitment assumptions. 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 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.
Gathering Pipeline Regulation
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. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. 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. 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.
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 issued a final rule, effective August 18, 2008, that implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of having been denied open and nondiscriminatory access to pipelines on the OCS. We cannot predict the ultimate impact of these regulatory changes to our OCS natural gas operations. We do not believe that we would be affected by any such regulatory changes materially differently than other gathering lines operating on the OCS with whom we compete.
Regulation of our onshore gathering facilities. Our onshore natural gas gathering operations are subject to ratable take and common purchaser statutes in the states in which we operate. 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.
Though our natural gas gathering facilities are not subject to regulation by FERC as natural gas companies under the NGA, our gathering facilities may be subject to certain FERC annual natural gas transaction reporting requirements and daily scheduled flow and capacity posting requirements depending on the volume of natural gas transactions and flows in a given period. See below the discussion of “Other Federal Laws and Regulations Affecting Our Industry – FERC Market Transparency Rules.”
In 2007, Texas enacted new laws regarding rates, competition and confidentiality for natural gas gathering and transmission pipelines (“Competition Statute”) and new informal complaint procedures for challenging determinations of lost and unaccounted for gas by gas gatherers, processors and transporters (“LUG Statute”). The Competition Statute gives the Railroad Commission of Texas (“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. This statute 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 Statute modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. Such statute also 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, these statutes might have on our future 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. Further, the states in which we operate require that services be provided on a non-discriminatory basis.
Our Texas intrastate pipeline, 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 intrastate pipeline that transports natural gas from a third party gathering system into the Chico System in Denton County, Texas. Targa Intrastate is a Gas Utility subject to regulation by the RRC and has a tariff on file with such agency.
Targa Permian Intrastate LLC (“Targa Permian”) owns an 18 mile intrastate pipeline that transports gas in the Permian Basin. Targa Permian is a newly-formed Gas Utility, subject to regulation by the RRC, including the obligation to file a tariff with such agency.
Our Louisiana intrastate pipeline, Targa Louisiana Intrastate LLC, or TLI, owns an approximately 60-mile intrastate natural gas pipeline system that receives all of the natural gas it transports within 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 full FERC regulation. On November 20, 2008, FERC issued a Notice of Inquiry (“NOI”) seeking comment on whether it should impose additional posting and reporting requirements on Hinshaw pipelines providing interstate service under limited blanket certificates and intrastate pipelines providing interstate service under Section 311 of the Natural Gas Policy Act, or NGPA. If FERC issues a proposed rulemaking based on the NOI, it would not cover TLI as currently written, as TLI only provides service governed by the Hinshaw amendment. TLI does not provide interstate service pursuant to any limited blanket certificate. FERC has not yet determined whether a rulemaking proceeding is necessary and we cannot predict what, if any, additional rules FERC will propose as a result of its inquiry or the ultimate impact of any such regulatory changes to our Hinshaw pipeline.
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.
Though our natural gas intrastate pipelines are not subject to regulation by FERC as natural gas companies under the NGA, our intrastate pipelines may be subject to certain FERC-imposed daily scheduled flow and capacity posting requirements depending on the volume of natural gas flows in a given period and the design capacity of the pipelines’ receipt and delivery meters. See below the discussion of “Other Federal Laws and Regulations Affecting Our Industry – FERC Market Transparency Rules.”
Regulation of our NGL intrastate pipelines. Our intrastate NGL pipelines in Louisiana gather raw NGL streams that we own from processing plants in Louisiana and deliver such streams to our NGL storage facility in Hackberry, Louisiana, and our fractionators in Lake Charles, Louisiana, where the raw NGL streams are fractionated into various products. We deliver such refined products (ethane, propane, butane and natural gasoline) out of our fractionators to and from Targa-owned storage, to other third party facilities and to various third party pipelines in Louisiana. 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 gathering and processing operations are not presently subject to FERC regulation. Starting May 1, 2009, we may be required to report to FERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transacted during the prior calendar year. See below the discussion of “FERC Market Transparency Rules.” There can be no assurance that our processing operations will continue to be exempt from other FERC regulation in the future.
Sales of Natural Gas and NGLs
The price at which we buy and sell natural gas and NGLs is currently not subject to federal rate 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”). See below the discussion of “Other Federal Laws and Regulations Affecting Our Industry – Energy Policy Act of 2005.” 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. In addition, pursuant to Order 704 some of our operations may be required to annually report to FERC, starting May 1, 2009, information regarding natural gas purchase and sale transactions depending on the volume of natural gas transacted during the prior calendar year. See below the discussion of “Other Federal Laws and Regulations Affecting Our Industry – FERC Market Transparency Rules.”
Availability, Terms and Cost of Pipeline Transportation
Our processing operations and our marketing of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. 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 processing operations and our natural gas and NGL marketing operations. We do not believe that we would be affected by any such FERC action materially differently than other natural gas processors and natural gas and NGL marketers with whom we compete.
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. In 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.
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, See “Item 1A. Risk Factors—Risks Related to Our Business”.
Interstate Common Carrier Liquids Pipeline Regulation
Targa NGL Pipeline Company LLC (“Targa NGL”), is an interstate NGL common carrier subject to regulation by FERC under the Interstate Commerce Act, or ICA. Targa NGL owns a twelve-inch (12”) diameter pipeline that runs between Lake Charles, Louisiana and Mont Belvieu, Texas. This pipeline can move mixed NGLs and purity NGL products. Targa NGL also owns an eight-inch (8”) diameter pipeline and a twenty-inch (20”) diameter pipeline each of which run between Mont Belvieu, Texas and Galena Park, Texas. The eight-inch (8”) and the twenty-inch (20”) pipelines are part of an extensive mixed NGL and purity NGL pipeline receipt and delivery system that provides services to domestic and foreign import and export customers. The ICA requires that we maintain tariffs on file with FERC for each of these pipelines. Those tariffs set forth the rates we charge for providing transportation services as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits challenges to newly proposed or changed rates and authorizes FERC to suspend the effectiveness of such rates and to investigate such rates to determine whether they are just and reasonable. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation and, in some cases, reparations for the two (2) year period prior to the filing of a complaint.
Other Federal Laws and Regulations Affecting Our Industry
Energy Policy Act of 2005
The Domenici-Barton Energy Policy Act of 2005 (“EP Act 2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. With respect to regulation of natural gas transportation, the EP Act 2005 amended the NGA and the NGPA by increasing the criminal penalties available for violations of each Act. The EP Act 2005 also added a new section to the NGA, which provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and $1,000,000 per violation per day for violations of the NGPA. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce, including VGS. EP Act 2005 also amended the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC. In 2006, FERC issued Order No. 670, to implement the anti-market manipulation provision of EP Act 2005. Order 670 makes it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit any statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. Order 670 does not apply to activities that relate only to non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704 and the daily scheduled flow and capacity posting requirements under Order 720. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.
FERC Standards of Conduct for Transmission Providers
On October 16, 2008, the FERC issued new standards of conduct for transmission providers (“Order 717”) to regulate the manner in which interstate natural gas pipelines may interact with their marketing affiliates based on an employee separation approach. A “Transmission Provider” includes an interstate natural gas pipeline that provides open access transportation pursuant to FERC’s regulations. Under these rules, a Transmission Provider’s transmission function employees (including the transmission function employees of any of its affiliates) must function independently from the Transmission Provider’s marketing function employees (including the marketing function employees of any of its affiliates). Our only Transmission Provider, VGS, does not engage in any transactions with marketing affiliates, and we do not believe that our operations will be affected by the new standards of conduct. Requests for rehearing of Order 717 have been filed and are currently pending before FERC. We have no way to predict with certainty whether and to what extent FERC will revise the new standards of conduct in response to those requests for rehearing.
FERC Market Transparency Rules
In 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers are now required to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704.
On November 20, 2008, FERC issued a final rule on daily scheduled flows and capacity posting requirements (“Order 720”). Under Order 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three (3) calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu per day. Requests for clarification and rehearing of Order 720 have been filed at FERC and a decision on those requests is pending.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other natural gas companies with whom we compete.
Environmental Health and Safety Matters
General
Our operations are subject to stringent and complex federal, state, and local laws and regulations pertaining to health, safety and the environment. For more information on our operations, see “Item 1. Business—Our Operations.” As with the industry generally, compliance with these laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. These laws and regulations may, among other things, require the acquisition of various permits to conduct regulated activities, require the installation of pollution control equipment or otherwise restrict the way we can handle or dispose of our wastes; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; and require remedial activities or capital expenditures to mitigate pollution conditions caused by our operations or attributable to former operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of removal or remedial obligations, and the issuance of injunctions limiting or prohibiting our activities.
We have implemented programs and policies designed to keep our pipelines, plants, and other facilities in compliance with existing environmental laws and regulations. The clear trend in environmental regulation, however, is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that current conditions will continue in the future. Our estimated capital expenditures for environmental control facilities are approximately $24 million for 2009 and $10 million for 2010.
The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous Substances and Waste
The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA” or the “Superfund” law), and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the federal Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. 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 or other pollutants into the environment. We generate materials in the course of our operations that are regulated as “hazardous substances” under CERCLA or similar state statutes and, as a result, may be jointly and severally liable under CERCLA or such statutes for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations we generate petroleum product wastes and ordinary industrial wastes such as paint wastes, waste solvents, and waste compressor oils that are regulated as hazardous wastes. Certain materials generated in the exploration, development, or production of crude oil and natural gas are excluded from RCRA’s hazardous waste regulations. However, it is possible that future changes in law or regulation could result in these wastes, including wastes currently generated during our operations, being designated as “hazardous wastes” and therefore subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses as well as those of the industry in general.
We currently own or lease, and have in the past owned or leased, properties that for many years have been used for midstream natural gas and NGL activities. Although we have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater), or to perform remedial activities to prevent future contamination. We are responsible for several remedial projects that have cleanup costs for which we have accrued reserves of $3.8 million as of December 31, 2008.
Air Emissions
The Clean Air Act, as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources, including processing plants and compressor stations, and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions. We are currently reviewing the air emissions monitoring systems at certain of our facilities. We may be required to incur capital expenditures in the next few years to implement various air emissions leak detection and monitoring programs as well as to install air pollution control equipment or non-ambient storage tanks as a result of our review or in connection with maintaining, amending or obtaining operating permits and approvals for air emissions. We currently believe, however, that such requirements will not have a material adverse affect on our operations.
Our failure to comply with the requirements of the Clean Air Act and comparable state laws and regulations could subject us to monetary penalties, injunctions, restrictions on operations, and potentially criminal enforcement actions. For instance, we have been in discussions with the New Mexico Environment Department (“NMED”) to resolve alleged air emissions violations at the Eunice, Monument and Saunders gas processing plants. In May 2007, the NMED initially provided us with a draft compliance order proposing to resolve certain of these alleged violations, which were identified in the course of an inspection of the Eunice plant conducted by the NMED in August 2005. In December 2007, the NMED offered a settlement containing a proposed penalty of approximately $2 million to resolve the alleged violations arising out of the August 2005 inspection of the Eunice plant. We have since 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 and to install air pollution control technology and we may 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.
Global Warming and Climate Control
In response to concerns suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” (including carbon dioxide (“CO2”) and methane), are contributing to the warming of the Earth’s atmosphere, the United States Congress has been considering legislation to reduce such emissions. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs. As an alternative to cap and trade programs, Congress may consider the implementation of a carbon tax program. The cap and trade programs could require major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations (e.g., compressor stations) or from combustion of fuels (e.g., natural gas or NGLs) we process. Depending on the design and implementation of carbon tax programs, our operations could face additional taxes and higher cost of doing business. Although we would not be impacted to a greater degree than other similarly situated gatherers and processors of natural gas or NGLs, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the natural gas and NGLs we gather and process.
Also, as a result of the United States Supreme Court’s decision in 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases including CO2 fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of CO2 and other greenhouse gas emissions from stationary sources. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court's decision in Massachusetts. In the notice, EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such new federal or state restrictions on emissions of CO2 that may be imposed in areas in which we conduct business could also have an adverse affect on our cost of doing business and demand for the natural gas and NGLs we gather and process.
Water Discharges
The Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act” or “CWA”), and analogous state laws impose restrictions and controls on the discharge of pollutants into navigable waters. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the U.S. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of a permit issued by EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff. The CWA and analogous state laws can impose substantial civil and criminal penalties for non-compliance including spills and other non-authorized discharges.
The Oil Pollution Act of 1990, as amended (“OPA”), which amends and augments the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under OPA includes owners and operators of vessels, including barges, offshore platforms, and onshore facilities, such as our plants, pipelines and marine terminals. Under OPA, owners and operators of vessels and facilities that handle, store, or transport oil are required to develop and implement oil spill response plans, and establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties could be statutorily responsible. We believe that we are in substantial compliance with the CWA, OPA and analogous state laws.
Endangered Species Act
The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Pipeline Safety
The pipelines we use to gather and transport natural gas and transport NGLs are subject to regulation by the DOT under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas and NGL pipeline facilities. Pursuant to these acts, 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. Where applicable, the NGPSA and HLPSA require any entity that owns or operates pipeline facilities to comply with the regulations under these acts, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable NGPSA and HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA and HLPSA could result in increased costs.
Our pipelines are also subject to regulation by the DOT under the Pipeline Safety Improvement Act of 2002, which was amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006. The DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), has established a series of rules, which require pipeline operators to develop and implement integrity management programs for gas transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility, and areas where people gather that are located along the route of a pipeline. Similar rules are also in place for operators of hazardous liquid pipelines including lines transporting NGLs and condensates.
In addition, states have adopted regulations, similar to existing DOT regulations, for intrastate gathering and transmission lines. New Mexico, Texas and Louisiana have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines transporting natural gas and NGLs. We currently estimate an annual average cost of $1.8 million for years 2009 through 2011 to perform necessary integrity management program testing on our 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. However, we do not expect that any such costs would be material to our financial condition or results of operations.
More recently, in September 2008, PHMSA issued a proposed rule mandated by the PIPES Act focusing on how human interactions of control room personnel, such as avoidance of error or the performance of mitigating actions, may impact pipeline system integrity. Among other things, the proposed rule would require operators of hazardous liquid and gas pipelines to amend their existing written operations and maintenance procedures, operator qualification programs, and emergency plans to take into account such items as specificity of the responsibilities and roles of control room personnel; listing of planned pipeline-related occurrences during a particular shift that may be easily shared with other controllers during a shift turnover; establishment of appropriate shift rotations to protect against controller fatigue; and development of appropriate communications between controllers, management and field personnel when planning and implementing changes to pipeline equipment or operations. While we do not anticipate that the rule, as proposed, will result in substantial costs with respect to our operations, the rule is not yet finalized and thus we cannot provide assurance on how significant an impact the rule ultimately will have on our operations, once it is adopted.
Employee Health and Safety
We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.
Other Laws and Regulations
As a supplier of component parts from raw NGL mixtures, including ethane, propane, normal butane, isobutane and natural gasoline, to end-users by pipeline, rail, truck, and barge, we are further subject to regulation by federal transportation-related agencies such as the United States Surface Transportation Board (the successor federal agency to the Interstate Commerce Commission), the DOT, and the United States Coast Guard, as well as by analogous state agencies. These regulatory authorities have broad powers over such regulated activities as carrier operations, operational safety and employee fitness, accounting systems, tariff filings of freight rates, and financial reporting. In addition, the potential for releases and spills of these component parts in the course of our deliveries are an inherent risk that could result in potentially significant costs and liabilities. We believe that our transportation-related services are in substantial compliance with applicable laws and regulations.
In the wake of the September 11, 2001 terrorist attacks on the United States, the Coast Guard has developed a security guidance document for marine terminals and has issued a security circular that defines appropriate countermeasures for protecting them and explains how the Coast Guard plans to verify that operators have taken appropriate action to implement satisfactory security procedures and plans. Using the guidelines provided by the Coast Guard, we have specifically identified certain of our facilities as marine terminals and therefore potential terrorist targets. In compliance with the Coast Guard guidance, we performed vulnerability analyses on such marine terminals. Future analyses of our security measures may result in additional measures and procedures, which measures or procedures have the potential for increasing costs of doing business. Regardless of the steps taken to increase security, however, we cannot provide assurance that our marine terminals will not become the subject of a terrorist attack. In addition, our operations and the operations of the natural gas and oil industry in general may be subject to laws and regulations regarding the security of industrial facilities, including natural gas and oil facilities.
The Department of Homeland Security Appropriations Act of 2007 required the Department of Homeland Security (“DHS”) to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” In 2007, the DHS issued an interim final rule, known as the Chemical Facility Anti-Terrorism Standards interim rule regarding risk-based performance standards to be attained pursuant to the act and an Appendix A to the interim rule that established the chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules.
In January 2008, we prepared and submitted to the DHS initial screening surveys for facilities operated by us that possess regulated chemicals of interest in excess of the Appendix A threshold levels. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information. Three of our facilities may pose a high level of security risk associated with the aforementioned standard and therefore we prepared Security Vulnerability Assessments for these three facilities and submitted them to the DHS in late 2008 for the agency’s further consideration. We are currently awaiting a response from the DHS with respect to the Security Vulnerability Assessments submitted to the agency as well as the continued participation of one or more of these facilities in this program. It is possible that costs associated with continued participation in this program ultimately could be substantial.
Title to Properties and Rights-of-Way
Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to ground leases between us, as lessee, and the fee owner of the lands, as lessors, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.
We may continue to hold record title to portions of certain of the Partnership’s assets until the Partnership makes the appropriate filings in the jurisdictions in which such assets are located and obtains any consents and approvals that were not obtained prior to transfer of such assets to the Partnership. Such consents and approvals would include those required by federal and state agencies or political subdivisions. In some cases, we may, where required consents or approvals have not been obtained, temporarily hold record title to property as nominee for the Partnership’s benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, cause our affiliates to retain title, as nominee for the Partnership’s benefit, until a future date.
Employees
Financial Information by Segment
See Note 19 to our consolidated financial statements beginning on page F-1 of this Annual Report for a presentation of financial results by segment.
Available Information
We make certain filings with the Securities and Exchange Commission (“SEC”), including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports, available free of charge through our website, http://www.targaresources.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. Our press releases and recent analyst presentations are also available on our website.
The nature of our business activities subjects 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 occurs, 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 and by 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 may be materially adversely affected if we experience significant, prolonged pricing deterioration. 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:
· | the impact of seasonality and weather; |
· | general economic conditions and economic conditions impacting our primary markets; |
· | the economic conditions of our customers; |
· | the level of domestic crude oil and natural gas production and consumption; |
· | the availability of imported natural gas, liquefied natural gas, NGLs and crude oil; |
· | actions taken by foreign oil and gas producing nations; |
· | the availability of local, intrastate and interstate transportation systems and storage for residue natural gas and NGLs; |
· | the availability and marketing of competitive fuels and/or feedstocks; |
· | the impact of energy conservation efforts; and |
· | 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 2008, our percent-of-proceeds arrangements accounted for approximately 55% 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-based 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, whichever is applicable, as the price of natural gas, NGLs and crude oil fluctuates. For additional information regarding our hedging activities, 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 or NGLs could adversely affect our business and operating results.
Our gathering systems are connected to natural gas wells from which 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 and NGL supplies. A material decrease in natural gas production from producing areas on which we rely, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of natural gas that we process and NGL delivered to our fractionation facilities. Our ability to obtain additional sources of natural gas and NGL depends, in part, on the level of successful drilling and production activity near our gathering systems. We have no control over the level of such 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 and production activity generally decreases as oil and natural gas prices decrease. Prices of oil and natural gas have been extremely volatile and we expect this volatility to continue. Energy commodity prices and demand have recently declined substantially, leading many exploration and production companies, including several in our areas of operation, to announce reduced capital expenditure levels for 2009, and could lead producers in our areas of operation to shut-in wells during the coming year. Consequently, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. Reductions in exploration and production activity, competitor actions or shut-ins by producers in the areas in which we operate may prevent us from obtaining supplies of natural gas to replace the natural decline in volumes from existing wells, which could result in reduced volumes through our facilities, and reduced utilization of our gathering, treating, processing and fractionation assets.
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 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. 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. The derivative instruments we utilize for these hedges are based on posted market prices, which may be higher or lower than the actual natural gas, NGLs and condensate prices that we realize in our operations. These pricing differentials may be substantial and could materially impact the prices we ultimately realize. In addition, current market and economic conditions may adversely affect our hedge counterparties’ ability to meet their obligations. Given the current volatility in the financial and commodity markets, we may experience defaults by our hedge counterparties in the future. As a result of these and other 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. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk. – Commodity Price Risk”
If third party pipelines and other facilities interconnected to our natural gas pipelines and processing facilities become partially or fully unavailable to transport natural gas and NGLs, our revenues could be adversely affected.
We depend upon third party pipelines, storage and other facilities that provide delivery options to and from our pipelines and processing facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third party facilities become partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict our ability to utilize them, 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 natural gas liquid 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 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 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 other industries or by the fuel markets 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 or industry specific economic conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products (for example; reduced petrochemical demand recently observed due to lower activity in the automobile and construction industries), increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications 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 processors to leave the ethane in the natural gas stream thereby reducing the volume of NGLs delivered for fractionation and marketing.
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, and in the production of ethylene and propylene. Changes in the composition of refined products resulting from governmental regulation, changes in feedstocks, products and economics, demand for heating fuel and for ethylene and propylene could adversely affect demand for normal butane.
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.
NGLs and products produced from NGLs also compete with global markets. Any reduced demand for ethane, propane, normal butane, isobutane or natural gasoline in the markets we access 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 2008 and 2007, approximately 13% and 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 2008 and 2007, approximately 22% and 26% of our consolidated revenues, and approximately 9% and 13% of our consolidated product purchases, were derived from transactions with Chevron and CPC. We are in the process of renegotiating our feedstock supply agreement 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 Internal Revenue Service (“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. Despite the fact that the Partnership is a limited partnership under Delaware law, it is possible for an entity such as the Partnership to be treated as a corporation for federal income tax purposes unless 90 percent or more of the gross income of the Partnership for every taxable year consists of “qualifying income’ under section 7704 of the Internal Revenue Code. Although the Partnership has not requested a ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes, the Partnership has requested a ruling with respect to the qualifying nature of the income earned as a result of a purchase of its debt at a discount. There can be no assurance that the Partnership will obtain a favorable ruling from the IRS with respect to this request.
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.
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 considered that would have eliminated partnership tax treatment for certain publicly traded partnerships. Although such legislation would not have appeared to apply to the Partnership as considered, it could be reintroduced in a manner that does apply to the Partnership. We are unable to predict whether any such changes, or other proposals will be reintroduced or 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 compression facilities are located, which could disrupt our operations.
We do not own most of the land on which our pipelines and compression 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.
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 disruptions and in some cases suspension of our operations. For example, unseasonably wet weather, extended periods of below-freezing weather and hurricanes may cause disruptions or suspensions of our operations. Disruptions or suspension of our operations caused by weather could adversely affect our operating results.
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:
§ | 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; |
§ | inadvertent damage from third parties, including from construction, farm and utility equipment; |
§ | 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 |
§ | 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, 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 Louisiana and Texas Gulf Coast was similarly impacted in September 2008 as a result of hurricanes Gustav and Ike. 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 incidents 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, following hurricanes Katrina and Rita, insurance premiums, deductibles and co-insurance requirements increased substantially, and terms were generally less favorable than terms that were obtained prior to such hurricanes. The insurance market conditions have worsened as a result of industry losses sustained from hurricanes Gustav and Ike in September 2008, and of volatile conditions in the financial markets. As a result, we expect to experience further increases in deductibles and premiums, and further reductions in coverage and limits, with some coverages potentially unavailable at any cost.
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 VGS, our operations are generally exempt from FERC regulation under the NGA, but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived from these businesses. FERC has recently issued Order 704 requiring certain participants in the natural gas market, including interstate and intrastate pipelines, natural gas gatherers, natural gas marketers, and natural gas processors, that engage in a minimum level of natural gas sales or purchases to submit annual reports regarding those transactions to FERC. In addition, FERC has issued Order 720 requiring major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three calendar years, to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has design capacity equal to or greater than 15,000 MMBtu per day.
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 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 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 systems other than VGS have traditionally not been subject to full FERC regulation, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity 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, see “Item 1. Business—Regulation of Operations.”
We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental laws or regulations or an accidental release of hazardous substances, hydrocarbons or wastes 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. For more information on our operations, 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 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 attain or 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. For further information on environmental matters, see “Business—Environmental and Other Matters.”
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:
· | perform ongoing assessments of pipeline integrity; |
· | identify and characterize applicable threats to pipeline segments that could impact a high consequence area; |
· | improve data collection, integration and analysis; |
· | repair and remediate the pipeline as necessary; and |
· | implement preventive and mitigating actions. |
In addition, states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. We currently estimate that we will incur an aggregate cost of approximately $5.4 million for years 2009 through 2011 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 the 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. 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. However, resulting regulatory requirements and/or related business decisions associated with security are likely to increase our costs.
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.
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, 2008, our total indebtedness, including the indebtedness of the Partnership, was $1,564.9 million, which represents approximately 51 of our capitalization. Our interest expense in 2008 was $102.0 million. In addition, as of December 31, 2008, we had issued $114.0 million in irrevocable standby letters of credit under our $300 million senior secured synthetic letter of credit facility and the Partnership had issued $9.7 million in irrevocable standby letters of credit under its senior secured revolving credit facility (the “Partnership’s credit facility”), neither of which are reflected on our balance sheet.
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:
§ | 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; |
§ | 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; |
§ | 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; |
§ | our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and |
§ | 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. 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, 2008, our total indebtedness was $1,564.9 million, of which $1,105.9 million was at variable interest rates. In order to mitigate the risk of changes in cash flow attributable to changes in market interest rates, the Partnership entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300 million in borrowings. Our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Interest Rate Risk”.
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:
§ | incur or guarantee additional indebtedness or issue preferred stock; |
§ | pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; |
§ | make investments; |
§ | create restrictions on the payment of dividends or other distributions to us from our non-guarantor restricted subsidiaries; |
§ | engage in transactions with our affiliates; |
§ | sell assets, including capital stock of the subsidiaries; |
§ | make certain acquisitions; |
§ | transfer assets; |
§ | enter into sale and lease back transactions; |
§ | consolidate or merge; and |
§ | incur liens. |
The senior secured credit agreement also includes covenants that, among other things, restrict our ability to:
§ | prepay, redeem and repurchase certain debt, other than loans under the senior secured credit facilities; |
§ | make capital expenditures; |
§ | amend debt and other material agreements; and |
§ | 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.
Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.
In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.
For example, Lehman Commercial Paper Inc. (“Lehman Paper”) recently defaulted on a borrowing request under our senior secured revolving credit facility (“credit facility”) and Lehman Brothers Commercial Bank (“Lehman Bank”) defaulted on a borrowing request under the Partnership’s credit facility, which effectively reduced our total remaining availability under these facilities by approximately $10.2 million and $10.0 million. As a result, we can provide no assurance that other lending counterparties will be willing or able to meet their existing funding obligations under.
Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to grow our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures any of which could have a material adverse effect on our revenues and results of operations.
We require a significant amount of cash to service our indebtedness. Our ability to generate cash depends on many factors beyond our control.
Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures depends on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that we will generate sufficient cash flow from operations or that future borrowings will be available to us under our credit agreement or otherwise in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness at or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness on commercially reasonable terms or at all.
None
A description of our properties is contained in “Item 1. Business” 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.
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), 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. In 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. 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 $3.0 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. On April 4, 2008, the Supreme Court of Texas granted review of the petitions. On September 9, 2008, the parties presented oral arguments, and the appeal is currently pending before the Supreme Court of Texas.
On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc. and three other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa 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 Targa’s 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. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal. On February 3, 2009, the parties presented oral arguments and the appeal is pending before the 14th Court of Appeals in Houston, Texas. We are contesting WTG’s appeal, but can give no assurances regarding the outcome of the proceeding. We have agreed to indemnify the Partnership for any claim or liability arising out of the WTG suit.
None
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.
During 2008, we paid $53.9 million in cash dividends to our stockholder. For a discussion of the dividend and of the restrictions on our ability to pay cash dividends, see Note 10 to our Consolidated Financial Statements beginning on Page F-1 of this Annual Report. We did not declare a cash dividend to our stockholder during our 2007 or 2006 fiscal years.
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, 2008, 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 include 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 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 period presented. The assets acquired from ConocoPhillips were not a separate legal entity during the period presented. During the period 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. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation” for a discussion of factors that affect the comparability of the information reflected in the selected financial and operating data.
Targa Resources, Inc. | Predecessor | |||||||||||||||||||||||
Three and a Half Months Ended April 15, | ||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||
2008 | 2007 | 2006 | 2005 (1) | 2004 (2) | 2004 | |||||||||||||||||||
(In millions, except operating and price data ) | ||||||||||||||||||||||||
Statement of Operations data: | ||||||||||||||||||||||||
Revenues | $ | 7,970.2 | $ | 7,269.7 | $ | 6,132.9 | $ | 1,829.0 | $ | 602.4 | $ | 232.8 | ||||||||||||
Costs and expenses | ||||||||||||||||||||||||
Product purchases | 7,189.8 | 6,498.0 | 5,440.8 | 1,631.9 | 545.0 | 212.3 | ||||||||||||||||||
Operating expenses (3) | 275.2 | 247.1 | 224.2 | 52.1 | 15.3 | 9.3 | ||||||||||||||||||
Depreciation and amortization expense | 160.9 | 148.1 | 149.7 | 27.1 | 10.6 | 3.8 | ||||||||||||||||||
General and administrative expense | 95.9 | 96.1 | 82.2 | 28.3 | 11.1 | 0.8 | ||||||||||||||||||
Casualty loss | 19.3 | - | - | - | - | - | ||||||||||||||||||
Loss (gain) on sale of assets | (5.9 | ) | (0.1 | ) | 0.2 | - | - | - | ||||||||||||||||
Total costs and expenses | 7,735.2 | 6,989.2 | 5,897.1 | 1,739.4 | 582.0 | 226.2 | ||||||||||||||||||
Income from operations | 235.0 | 280.5 | 235.8 | 89.6 | 20.4 | 6.6 | ||||||||||||||||||
Other income (expense): | ||||||||||||||||||||||||
Interest expense, net | (102.0 | ) | (142.6 | ) | (180.2 | ) | (39.9 | ) | (6.4 | ) | - | |||||||||||||
Equity in earnings of unconsolidated investments (5) | 14.0 | 10.1 | 10.0 | (3.8 | ) | 2.4 | - | |||||||||||||||||
Minority interest | (33.1 | ) | (28.7 | ) | (26.0 | ) | (7.4 | ) | - | - | ||||||||||||||
Non-controlling interest in Targa Resources Partners LP | (64.9 | ) | (19.4 | ) | - | - | - | - | ||||||||||||||||
Other | 30.2 | - | - | (59.2 | ) | - | - | |||||||||||||||||
Income (loss) before income taxes | 79.2 | 99.9 | 39.6 | (20.7 | ) | 16.4 | 6.6 | |||||||||||||||||
Income tax (expense) benefit | (26.3 | ) | (31.3 | ) | (16.2 | ) | 6.5 | (5.2 | ) | (2.6 | ) | |||||||||||||
Net income (loss) | 52.9 | 68.6 | 23.4 | (14.2 | ) | 11.2 | 4.0 | |||||||||||||||||
Dividends on redeemable preferred stock | - | - | - | (7.2 | ) | (5.9 | ) | - | ||||||||||||||||
Net income (loss) to common stock | $ | 52.9 | $ | 68.6 | $ | 23.4 | $ | (21.4 | ) | $ | 5.3 | $ | 4.0 | |||||||||||
Financial and Operating data: | ||||||||||||||||||||||||
Financial data: | ||||||||||||||||||||||||
Operating margin | $ | 505.2 | $ | 524.6 | $ | 467.9 | $ | 145.0 | $ | 42.1 | $ | 11.2 | ||||||||||||
Adjusted EBITDA (4) | 364.9 | 375.8 | 344.9 | 120.7 | 33.5 | 10.4 | ||||||||||||||||||
Operating data (5): | ||||||||||||||||||||||||
Gathering throughout, MMcf/d | 1,886.7 | 2,025.9 | 1,999.2 | 477.9 | 285.6 | 316.5 | ||||||||||||||||||
Plant natural gas inlet, MMcf/d | 1,846.4 | 1,982.8 | 1,863.3 | 400.8 | 262.6 | 313.5 | ||||||||||||||||||
Gross NGL production, MBbl/d | 101.9 | 106.6 | 106.8 | 31.8 | 22.8 | 24.8 | ||||||||||||||||||
Natural gas sales, BBtu/d | 532.1 | 526.5 | 501.2 | 313.5 | 252.7 | 297.4 | ||||||||||||||||||
NGL sales, MBbl/d | 286.9 | 320.8 | 300.2 | 58.2 | 22.8 | 24.8 | ||||||||||||||||||
Condensate sales, MBbl/d | 3.8 | 3.9 | 3.8 | 1.6 | ||||||||||||||||||||
Average realized prices: | ||||||||||||||||||||||||
Natural gas, $/MMBtu | 8.20 | 6.56 | 6.79 | 8.45 | 6.45 | 5.42 | ||||||||||||||||||
NGL, $/gal | 1.38 | 1.18 | 1.02 | 0.84 | 0.70 | 0.55 | ||||||||||||||||||
Condensate, $/Bbl | 91.28 | 70.01 | 63.67 | 55.17 | ||||||||||||||||||||
Balance Sheet data (at year end): | ||||||||||||||||||||||||
Property plant and equipment, net | $ | 2,617.4 | $ | 2,430.1 | $ | 2,464.5 | $ | 2,436.6 | $ | 240.2 | $ | 266.0 | ||||||||||||
Total assets | 3,648.6 | 3,790.0 | 3,458.0 | 3,396.6 | 443.2 | 288.8 | ||||||||||||||||||
Long-term debt, less current maturities | 1,552.4 | 1,398.5 | 1,471.9 | 2,184.4 | 157.5 | - | ||||||||||||||||||
Redeemable preferred stock | - | - | - | - | 135.1 | - | ||||||||||||||||||
Total stockholders’ equity (6) | 579.6 | 492.4 | 514.3 | 434.4 | 7.0 | 170.9 | ||||||||||||||||||
Cash Flow data: | ||||||||||||||||||||||||
Net cash provided by (used in): | ||||||||||||||||||||||||
Operating activities | $ | 300.7 | $ | 142.6 | $ | 233.3 | $ | 108.9 | $ | 33.1 | $ | 11.5 | ||||||||||||
Investing activities | (223.31 | ) | (95.9 | ) | (117.8 | ) | (2,328.9 | ) | (353.2 | ) | (1.2 | ) | ||||||||||||
Financing activities | 107.3 | (11.5 | ) | (14.2 | ) | 2,250.6 | 330.7 | (10.3 | ) |
(1) | Reflects acquisition of DMS effective October 31, 2005. |
(2) | Targa commenced operations on April 16, 2004 with the closing of the acquisition of certain assets in Texas and Louisiana from ConocoPhillips. Prior to April 16, 2004, certain investors in Targa had previous investments in Pipeco, f.k.a. Targa Resources, Inc., f.k.a. Warburg Pincus VIII Development Company, Inc. Pipeco was the entity that performed due diligence and other acquisition-specific activities associated with the asset acquisitions from ConocoPhillips. |
(3) | Includes taxes other than income taxes for the predecessor’s financial information. |
(4) | We define Adjusted EBITDA as net income before interest, income taxes, depreciation, and amortization and non-cash income or loss related to derivative instruments. We define operating margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas and NGL purchases, less operating expense. See “Non-GAAP Financial Measures—Adjusted EBITDA” and “Non-GAAP Financial Measures—Operating Margin,” included in this Item 6. |
(5) | Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period. Volumes from assets acquired in the DMS acquisition are included from the acquisition date, October 31, 2005. NGL-related statistics included in this Item 6. |
(6) | The comparable line-item in the predecessor’s historical financial statements is “Parent company investment”. |
Non-GAAP Financial Measures
Adjusted EBITDA. We define Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments. Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks and others, to assess:
· | the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
· | our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and |
· | the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
The economic substance behind management’s use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions to our investors.
The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities and GAAP net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into management’s decision-making processes.
Operating Margin. We define operating margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases, and operating expense. Management reviews operating margin monthly for consistency and trend analysis. Based on this monthly analysis, management takes appropriate action to maintain positive trends or to reverse negative trends. Management uses operating margin as an important performance measure of the core profitability of our operations.
The GAAP measure most directly comparable to operating margin is net income. Our non-GAAP financial measure of operating margin should not be considered as an alternative to GAAP net income. Operating margin is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because operating margin excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition
of operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Management compensates for the limitations of operating margin as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into management’s decision-making processes.
We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Operating margin provides useful information to investors because it is used as a supplemental financial measure by our management and by external users of our financial statements, including such investors, commercial banks and others, to assess:
· | the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
· | our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and |
· |
Targa Resources, Inc. | Predecessor | |||||||||||||||||||||||
Three and a | ||||||||||||||||||||||||
Half Months | ||||||||||||||||||||||||
Year Ended December 31, | Ended | |||||||||||||||||||||||
April 15, | ||||||||||||||||||||||||
2008 | 2007 | 2006 | 2005 (1) | 2004 (2) | 2004 | |||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Reconciliation of net cash provided by operating activities to Adjusted EBITDA: | ||||||||||||||||||||||||
Net cash provided by operating activities | $ | 300.7 | $ | 142.6 | $ | 233.3 | $ | 108.9 | $ | 33.1 | $ | 11.5 | ||||||||||||
Interest expense, net | 102.0 | 142.6 | 180.2 | 39.9 | 6.4 | - | ||||||||||||||||||
Amortization in interest expense | (8.4 | ) | (12.9 | ) | (13.0 | ) | (6.7 | ) | (1.0 | ) | - | |||||||||||||
Amortization of issue discount | - | - | - | (0.5 | ) | (0.1 | ) | - | ||||||||||||||||
Gain on debt extinguishment | 13.1 | - | - | - | - | - | ||||||||||||||||||
Early termination of commodity derivatives | 87.4 | - | - | - | - | - | ||||||||||||||||||
Current income tax expense | 1.2 | 0.2 | - | 0.2 | - | 3.2 | ||||||||||||||||||
Other | 26.7 | 28.0 | 15.0 | 3.9 | 2.1 | (0.5 | ) | |||||||||||||||||
Changes in operating assets and liabilities which used (provided) cash: | ||||||||||||||||||||||||
Accounts receivable and other assets | (674.5 | ) | 362.0 | (33.6 | ) | 113.9 | 78.2 | (25.2 | ) | |||||||||||||||
Accounts payable and other liabilities | 516.7 | (286.7 | ) | (37.0 | ) | (138.9 | ) | (85.2 | ) | 21.4 | ||||||||||||||
Adjusted EBITDA | $ | 364.9 | $ | 375.8 | $ | 344.9 | $ | 120.7 | $ | 33.5 | $ | 10.4 | ||||||||||||
Reconciliation of net income (loss) to Adjusted EBITDA: | ||||||||||||||||||||||||
Net income (loss) | $ | 52.9 | $ | 68.6 | $ | 23.4 | $ | (14.2 | ) | $ | 11.2 | $ | 4.0 | |||||||||||
Add: | ||||||||||||||||||||||||
Interest expense, net | 102.0 | 142.6 | 180.2 | 39.9 | 6.4 | - | ||||||||||||||||||
Income tax expense (benefit) | 26.3 | 31.3 | 16.2 | (6.5 | ) | 5.2 | 2.6 | |||||||||||||||||
Depreciation and amortization expense | 160.9 | 148.1 | 149.7 | 27.1 | 10.6 | 3.8 | ||||||||||||||||||
Non-cash (gain) loss related to derivatives | 22.8 | (14.8 | ) | (24.6 | ) | 74.4 | 0.1 | - | ||||||||||||||||
Adjusted EBITDA | $ | 364.9 | $ | 375.8 | $ | 344.9 | $ | 120.7 | $ | 33.5 | $ | 10.4 | ||||||||||||
Reconciliation of net income (loss) to operating margin: | ||||||||||||||||||||||||
Net income (loss) | $ | 52.9 | $ | 68.6 | $ | 23.4 | $ | (14.2 | ) | $ | 11.2 | $ | 4.0 | |||||||||||
Add: | ||||||||||||||||||||||||
Depreciation and amortization expense | 160.9 | 148.1 | 149.7 | 27.1 | 10.6 | 3.8 | ||||||||||||||||||
Income tax expense (benefit) | 26.3 | 31.3 | 16.2 | (6.5 | ) | 5.2 | 2.6 | |||||||||||||||||
Other, net | 67.2 | 37.9 | 16.2 | 70.4 | (2.4 | ) | - | |||||||||||||||||
Interest expense, net | 102.0 | 142.6 | 180.2 | 39.9 | 6.4 | - | ||||||||||||||||||
General and administrative expense | 95.9 | 96.1 | 82.2 | 28.3 | 11.1 | 0.8 | ||||||||||||||||||
Operating margin | $ | 505.2 | $ | 524.6 | $ | 467.9 | $ | 145.0 | $ | 42.1 | $ | 11.2 |
________
(1) | Reflects acquisition of DMS effective October 31, 2005. |
(2) | Targa commenced operations on April 16, 2004 with the closing of the acquisition of certain assets in Texas and Louisiana from ConocoPhillips. Prior to April 16, 2004, certain investors in Targa had previous investments in Pipeco, f.k.a. Targa Resources, Inc., f.k.a. Warburg Pincus VIII Development Company, Inc. Pipeco was the entity that performed due diligence and other acquisition-specific activities associated with the asset acquisitions from ConocoPhillips. |
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 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 U.S.
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 through our pipeline systems, which we refer to as throughput volume. Throughput volumes 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 (which maybe impacted by economic, political and regulatory development factors beyond our control).
Contract Mix. Our processing contract arrangements can have a significant impact on our profitability. Because of the significant volatility of natural gas and NGL prices, the contract mix of our natural gas gathering and processing segment can have a significant impact on our profitability. Negotiated contract terms are based upon a variety of factors, including natural gas quality, geographic location, the competitive environment at the time the contract is executed and customer preferences. Contract mix and, accordingly, exposure to natural gas and NGL prices may change over time as a result of changes in these underlying factors.
Set forth below is a table summarizing the contract mix of our natural gas gathering and processing division for 2008 and the potential impacts of commodity prices on operating margins:
Percent of | ||||||
Contract Type | Throughput | Impact of Commodity Prices | ||||
Percent-of-Proceeds / Percent-of-Liquids | 55 | % | Decreases in natural gas and or NGL prices generate decreases in operating margins | |||
Fee-Based | 17 | % | No direct impact from commodity price movements | |||
Wellhead Purchases /Keep-Whole | 7 | % | Decreases in NGL prices relative to natural gas prices generate decreases in operating margins | |||
Hybrid | 21 | % | In periods of favorable processing economics, similar to percent-of-liquids (or wellhead purchases/keep-whole in some circumstances, if economically advantageous to the processor). In periods of unfavorable processing economics, similar to fee-based |
Actual contract terms are based upon a variety of factors, including natural gas quality, geographic location, the competitive commodity and pricing environment at the time the contract is executed and customer requirements. Our gathering and processing contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of producer preferences, competition, and changes in production as wells decline at different rates or are added, our expansion into regions where different types of contracts are more common as well as other market factors. We prefer to enter into contracts with less commodity price sensitivity including fee-based and percent-of-proceeds arrangements.
We attempt to mitigate the impact of commodity prices on our results of operations through hedging activities which can materially impact our results of operations. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk”.
General Trends and Outlook
We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
Natural Gas Supply and Outlook. Fluctuations in energy prices can affect production rates and investments by third parties in the development of new natural gas reserves. Generally, drilling and production activity will increase as natural gas prices increase and decrease as natural gas prices decrease. In 2008, the sales prices we realized for natural gas, before the impact of hedging, increased to an average of $8.17 per MMBtu from an average of $6.40 per MMBtu for 2007. In 2007, excluding the impact of hedging, the prices we realized for natural gas declined to an average of $6.40 per MMBtu from an average of $6.61 per MMBtu for 2006.
As a result of the prevailing prices during these periods, our system has experienced significant levels of drilling activity, providing us with opportunities to access newly developed natural gas supplies. However, the recent substantial decline in natural gas prices has led many exploration and production companies to reduce planned capital expenditures and drilling plans for 2009 which could lead to a decrease in the level of natural gas production in our areas of operation. Our largest supplier of natural gas is Chevron, representing 13% of the natural gas supplied to our system for each of 2008 and 2007.
During 2008 and 2007, approximately 22% and 26% of our consolidated revenues, and approximately 9% and 13% of our consolidated product purchases, were derived from transactions with Chevron and CPC. No other third party customer accounted for more than 10% of our consolidated revenues during these periods.
Commodity Prices. Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices, primarily as a result of our percent-of-proceeds contracts. For 2008, excluding the impact of hedging activities, we sold an average of 286.9 MBbl/d of NGLs at an average price of $1.39 per gallon, as compared to 320.8 MBbl/d at an average price of $1.18 per gallon for 2007, and 300.2 MBbl/d at an average price of $1.02 per gallon for 2006. For 2008, excluding the impact of hedging activities, we sold an average of 3.8 MBbl/d of condensate at an average price of $93.85 per Bbl, as compared to 3.9 MBbl/d at an average price of $69.84 per Bbl for 2007, and 3.8 MBbl/d at an average price of $63.15 per Bbl for 2006. Our processing profitability is largely dependent upon pricing and market demand for natural gas, NGLs and condensate, which are beyond our control and have been volatile. The current weak economic conditions have negatively affected the pricing and market demand for natural gas, NGLs and condensate, which has caused a reduction in profitability of our processing operations. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. We have attempted to mitigate our exposure to commodity price movements by entering into hedging arrangements. For additional information regarding our hedging activities, See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk”.
Volatile Capital Markets. We are dependent on our ability to access the equity and debt capital markets in order to fund acquisitions and expansion expenditures. Global financial markets have been, and are expected to continue to be, extremely volatile and disrupted and the current weak economic conditions have recently caused a significant decline in commodity prices. As a result, we may be unable to raise equity or debt capital on satisfactory terms, or at all, which may negatively impact the timing and extent to which we execute growth plans. Prolonged periods of low commodity prices or volatile capital markets may impact our ability or willingness to enter into new hedges, fund organic growth, connect to new supplies of natural gas, execute acquisitions or implement expansion capital expenditures.
How We Evaluate Our Operations
Our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the natural gas, NGLs and condensate we sell, and the costs associated with conducting our operations, including the costs of wellhead natural gas that we purchase as well as operating and general and administrative costs. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for natural gas and NGLs, and the natural gas and NGL throughput on our system are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, demand for our products and changes in our customer mix.
Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (1) throughput volumes, (2) facility efficiencies and fuel consumption, (3) operating margin, (4) operating expenses, and (5) Adjusted EBITDA.
Throughput Volumes, Facility Efficiencies and Fuel Consumption. Our profitability is impacted by our ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to our systems. This is achieved by connecting new wells, adding new volumes in existing areas of production as well as by capturing supplies currently gathered by third parties.
In addition, we seek to increase operating margins by limiting volume losses and reducing fuel consumption by increasing compression efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes of natural gas received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. This information is tracked through our processing plants to determine customer settlements and helps us increase efficiency and reduce fuel consumption.
As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plants to monitor the fuel consumption and recoveries of the facilities. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis.
Operating Margin. We review performance based on the non-generally accepted accounting principle (“non-GAAP”) financial measure of operating margin. We define operating margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases, and operating expense. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges. Our operating margin is impacted by volumes and commodity prices as well as by our contract mix and hedging program, which are described in more detail below. We view our operating margin as an important performance measure of the core profitability of our operations. We review our operating margin monthly for consistency and trend analysis.
The GAAP measure most directly comparable to operating margin is net income. Our non-GAAP financial measure of operating margin should not be considered as an alternative to GAAP net income. Operating margin is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because operating margin excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
We compensate for the limitations of operating margin as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into our decision-making processes.
We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Operating margin provides useful information to investors because it is used as a supplemental financial measure by us and by external users of our financial statements, including such investors, commercial banks and others, to assess:
· | the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
· | our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and |
· | the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
Operating Expenses. Operating expenses are costs associated with the operation of a specific asset. Direct labor, ad valorem taxes, repair and maintenance, utilities and contract services compose the most significant portion of our operating expenses. These expenses generally remain relatively stable independent of the volumes through our systems but fluctuate depending on the scope of the activities performed during a specific period.
Adjusted EBITDA. Adjusted EBITDA is another non-GAAP financial measure that is used by us. We define Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others, to assess:
· | the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
· | our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and |
· | the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions to our investors.
The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities and GAAP net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
We compensate for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes.
Year Ended December 31, | ||||||||||||
Reconciliation of net cash provided by | 2008 | 2007 | 2006 | |||||||||
operating activities to Adjusted EBITDA: | (In millions) | |||||||||||
Net cash provided by operating activities | $ | 300.7 | $ | 142.6 | $ | 233.3 | ||||||
Interest expense, net | 102.0 | 142.6 | 180.2 | |||||||||
Amortization in interest expense | (8.4 | ) | (12.9 | ) | (13.0 | ) | ||||||
Gain on debt extinguishment | 13.1 | - | - | |||||||||
Early termination of commodity derivatives | 87.4 | - | - | |||||||||
Current income tax expense | 1.2 | 0.2 | - | |||||||||
Other | 26.7 | 28.0 | 15.0 | |||||||||
Changes in operating assets and liabilities which used (provided) cash: | ||||||||||||
Accounts receivable and other assets | (674.5 | ) | 362.0 | (33.6 | ) | |||||||
Accounts payable and other liabilities | 516.7 | (286.7 | ) | (37.0 | ) | |||||||
Adjusted EBITDA | $ | 364.9 | $ | 375.8 | $ | 344.9 | ||||||
Reconciliation of net income to Adjusted EBITDA: | ||||||||||||
Net income | $ | 52.9 | $ | 68.6 | $ | 23.4 | ||||||
Add: | ||||||||||||
Interest expense, net | 102.0 | 142.6 | 180.2 | |||||||||
Income tax expense | 26.3 | 31.3 | 16.2 | |||||||||
Depreciation and amortization | 160.9 | 148.1 | 149.7 | |||||||||
Non-cash (gain) loss related to derivatives | 22.8 | (14.8 | ) | (24.6 | ) | |||||||
Adjusted EBITDA | $ | 364.9 | $ | 375.8 | $ | 344.9 |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
Reconciliation of net income to operating margin: | (In millions) | |||||||||||
Net income | $ | 52.9 | $ | 68.6 | $ | 23.4 | ||||||
Add: | ||||||||||||
Depreciation and amortization expense | 160.9 | 148.1 | 149.7 | |||||||||
Income tax benefit | 26.3 | 31.3 | 16.2 | |||||||||
Other, net | 67.2 | 37.9 | 16.2 | |||||||||
Interest expense, net | 102.0 | 142.6 | 180.2 | |||||||||
General and administrative expense | 95.9 | 96.1 | 82.2 | |||||||||
Operating margin | $ | 505.2 | $ | 524.6 | $ | 467.9 |
Our operating margin by segment and in total is as follows for the periods indicated:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Natural Gas Gathering and Processing | $ | 423.9 | $ | 406.7 | $ | 404.9 | ||||||
Logistics Assets | 49.6 | 39.6 | 42.4 | |||||||||
NGL Distribution and Marketing Services | 18.5 | 55.5 | 10.6 | |||||||||
Wholesale Marketing | 13.2 | 22.8 | 10.0 | |||||||||
$ | 505.2 | $ | 524.6 | $ | 467.9 |
Results of Operations
The following table summarizes the key components of our results of operations for the periods indicated:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions, except operating and price data) | ||||||||||||
Revenues (1) | $ | 7,970.2 | $ | 7,269.7 | $ | 6,132.9 | ||||||
Product purchases | 7,189.8 | 6,498.0 | 5,440.8 | |||||||||
Operating expenses | 275.2 | 247.1 | 224.2 | |||||||||
Depreciation and amortization expense | 160.9 | 148.1 | 149.7 | |||||||||
General and administrative expense | 95.9 | 96.1 | 82.2 | |||||||||
Casualty loss | 19.3 | - | - | |||||||||
Loss (gain) on sales of assets | (5.9 | ) | (0.1 | ) | 0.2 | |||||||
Income from operations | 235.0 | 280.5 | 235.8 | |||||||||
Interest expense, net | (102.0 | ) | (142.6 | ) | (180.2 | ) | ||||||
Gain on insurance claims | 18.6 | - | - | |||||||||
Equity in earnings of unconsolidated investments (2) | 14.0 | 10.1 | 10.0 | |||||||||
Minority interest / non-controlling interest | (98.0 | ) | (48.1 | ) | (26.0 | ) | ||||||
Other | 11.6 | - | - | |||||||||
Income tax expense | (26.3 | ) | (31.3 | ) | (16.2 | ) | ||||||
Net income | $ | 52.9 | $ | 68.6 | $ | 23.4 | ||||||
Financial data: | ||||||||||||
Operating margin (3) | $ | 505.2 | $ | 524.6 | $ | 467.9 | ||||||
Adjusted EBITDA (4) | 364.9 | 375.8 | 344.9 | |||||||||
Operating statistics: | ||||||||||||
Gathering throughput MMcf/d (5) | 1,886.7 | 2,025.9 | 1,999.2 | |||||||||
Plant natural gas inlet, MMcf/d (6) (7) | 1,846.4 | 1,982.8 | 1,863.3 | |||||||||
Gross NGL production, MBbl/d | 101.9 | 106.6 | 106.8 | |||||||||
Natural gas sales, BBtu/d (7) | 532.1 | 526.5 | 501.2 | |||||||||
NGL sales, MBbl/d | 286.9 | 320.8 | 300.2 | |||||||||
Condensate sales, MBbl/d | 3.8 | 3.9 | 3.8 | |||||||||
Average realized prices: | ||||||||||||
Natural gas, $/MMBtu | 8.20 | 6.56 | 6.79 | |||||||||
NGL, $/gal | 1.38 | 1.18 | 1.02 | |||||||||
Condensate, $/Bbl | 91.28 | 70.01 | 63.67 |
________
(1) | Includes business interruption insurance revenues of $32.9 million, $7.3 million and $10.7 million for 2008, 2007 and 2006. |
(2) | Includes business interruption insurance revenues of $4.1 million, $3.1 million and $2.9 million for 2008, 2007 and 2006. |
(3) | Operating margin is total operating revenues less product purchases and operating expense. See “Non-GAAP Financial Measures—Operating Margin” included in this Item 7. |
(4) | Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments. See “Non-GAAP Financial Measures—Adjusted EBITDA” included in this Item 7. |
(5) | Gathering throughput represents the volume of natural gas gathered and passed through natural gas gathering pipelines from connections to producing wells and central delivery points. |
(6) | Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant. |
(7) | Plant natural gas inlet includes producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes. |
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Revenues increased by $700.5 million, or 10%, to $7,970.2 million for 2008 compared to $7,269.7 million for 2007. Revenues from the sale of natural gas increased by $336.1 million, consisting of increases of $319.2 million due to higher realized prices and $16.9 million due to higher sales volumes. Revenues from the sale of NGL increased by $283.2 million, consisting of an increase of $881.4 million due to higher realized prices, partially offset by a decrease of $598.2 million due to lower sales volumes. Revenues from the sale of condensate increased by $28.0 million, consisting of an increase of $29.8 million due to higher realized prices, partially offset by a decrease of $1.8 million due to lower sales volumes. Non-commodity revenues, which principally include revenues derived from fee-based services and business interruption insurance, increased by $53.2 million.
Our average realized prices for natural gas increased by $1.64 per MMBtu, or 25%, to $8.20 per MMBtu for 2008 compared to $6.56 per MMBtu for 2007. Our average realized prices for NGL increased by $0.20 per gallon, or 17%, to $1.38 per gallon for 2008 compared to $1.18 per gallon for 2007. Our average realized price for condensate increased by $21.27, or 30%, to $91.28 per barrel for 2008 compared to $70.01 per barrel for 2007.
Natural gas sales volumes increased by 5.6 BBtu per day, or 1%, to 532.1 BBtu per day for 2008 compared to 526.5 BBtu per day for 2007. NGL sales volumes decreased by 33.9 MBbl per day, or 11%, to 286.9 MBbl per day for 2008 compared to 320.8 MBbl per day for 2007. Condensate sales volumes decreased by 0.1 MBbl per day, or 3%, to 3.8 MBbl per day for 2008 compared to 3.9 MBbl per day for 2007. For information regarding the period to period changes in our commodity sales volumes, See “Results of Operations—By Segment” included in this Item 7.
Product purchases increased by $691.8 million, or 11%, to $7,189.8 million for 2008 compared to $6,498.0 million for 2007. See “Results of Operations—By Segment” included in this Item 7 for a detailed explanation of the components of the increase.
Operating expenses increased by $28.1 million, or 11%, to $275.2 million for 2008 compared to $247.1 million for 2007. See “Results of Operations—By Segment” included in this Item 7 for a detailed explanation of the components of the increase.
Depreciation and amortization expense increased by $12.8 million, or 9%, to $160.9 million for 2008 compared to $148.1 million for 2007. The increase is primarily attributable to a 12% increase in purchases of property, plant and equipment for 2008 compared to 2007.
General and administrative expense decreased by $0.2 million, or less than 1%, to $95.9 million for 2008 compared to $96.1 million for 2007.
Interest expense decreased by $40.6 million, or 28%, to $102.0 million for 2008 compared to $142.6 million for 2007. The decrease is primarily from lower average outstanding debt during 2008. See “Liquidity and Capital Resources” in this Item 7 for information regarding our outstanding debt obligations.
Our 2008 income tax expense was $26.3 million, or 33% of income before income taxes of $79.2 million, compared to income tax expense of $31.3 million, or 31% of income before income taxes of $99.9 million for 2007. See Note 14 to our Consolidated Financial Statements beginning on page F-1 of this Annual Report for information regarding our provision for income taxes for 2008 and 2007. Variances in our annual effective tax rate from the 35% federal statutory rate are primarily caused by state income taxes.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenues increased by $1,136.8 million, or 19%, to $7,269.7 million for 2007 compared to $6,132.9 million for 2006. Revenues from the sale of natural gas increased by $14.6 million, consisting of an increase of $62.8 million due to higher sales volume, partially offset by a decrease of $48.2 million due to lower realized prices. Revenues from the sale of NGLs increased by $1,094.0 million, consisting of increases of $321.7 million due to higher sales volumes and $772.3 million due to higher realized prices. Revenues from the sale of condensate increased by $10.9 million, consisting of an increase of $1.9 million due to higher sales volumes and $9.0 million due to higher realized prices. Non-commodity revenues, which principally include revenues derived from fee-based services and business interruption insurance, increased by $17.2 million.
Our average realized prices for natural gas decreased by $0.23 per MMBtu, or 3%, to $6.56 per MMBtu for 2007 compared to $6.79 per MMBtu for 2006. Our average realized prices for NGL increased by $0.16 per gallon, or 16%, to $1.18 per gallon for 2007 compared to $1.02 per gallon for 2006. Our average realized price for condensate increased by $6.34 per barrel, or 10%, to $70.01 per barrel for 2007 compared to $63.67 per barrel for 2006.
Natural gas sales volumes increased by 25.3 BBtu per day, or 5%, to 526.5 BBtu per day for 2007 compared to 501.2 BBtu per day for 2006. NGL sales volumes increased by 20.6 MBbl per day, or 7%, to 320.8 MBbl per day for 2007 compared to 300.2 MBbl per day for 2006. Condensate sales volumes increased by 0.1 MBbl per day, or 3%, to 3.9 MBbl per day for 2007 compared to 3.8 MBbl per day for 2006. For information regarding the period to period changes in our commodity sales volumes, see “Results of Operations—By Segment” included in this Item 7.
Product purchases increased by $1,057.2 million, or 19%, to $6,498.0 million for 2007 compared to $5,440.8 million for 2006. See “Results of Operations—By Segment” included in this Item 7 for a detailed explanation of the components of the increase.
Operating expenses increased by $22.9 million, or 10%, to $247.1 million for 2007 compared to $224.2 million for 2006. See “Results of Operations—By Segment” included in this Item 7 for a detailed explanation of the components of the increase.
General and administrative expense increased by $13.9 million, or 17%, to $96.1 million for 2007 compared to $82.2 million for 2006. The increase primarily consisted of increases of $15.4 million in compensation related expenses, $0.3 million in insurance expenses, partially offset by decreases of $1.1 million in professional services fees and $0.7 million miscellaneous expenses.
Interest expense decreased by $37.6 million, or 21%, to $142.6 million for 2007 compared to $180.2 million for 2006. The decrease is primarily the result of lower average debt during 2007, partially offset by the effect of higher interest rates during 2007. See “Liquidity and Capital Resources” in this Item 7 for information regarding our outstanding debt obligations.
During 2007, income tax expense was $31.3 million on pre-tax net income of $99.9 million, compared to income tax expense of $16.2 million on pre-tax net income of $39.6 million for 2006. Income tax expense for 2007 decreased by $8.3 million as a result of Texas House Bill 3928 (“HB 3928”), effective June 15, 2007, which required us to recognize changes in deferred tax assets related to a computational change of the temporary credit related to the Texas Margin Tax. Excluding the effect of HB 3928, our effective income tax rate would have been 40% for 2007, compared to 41% for 2006. Variances in our annual effective tax rate from the 35% federal statutory rate are primarily caused by state income taxes.
Results of Operations—By Segment
Natural Gas Gathering and Processing Segment
The following table provides summary financial data regarding results of operations in our Natural Gas Gathering and Processing segment for the periods indicated:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions, except operating and price data) | ||||||||||||
Revenues (1) | $ | 3,440.3 | $ | 2,917.9 | $ | 2,591.0 | ||||||
Product purchases | (2,880.6 | ) | (2,387.9 | ) | (2,067.4 | ) | ||||||
Operating expenses | (135.8 | ) | (123.3 | ) | (118.7 | ) | ||||||
Operating margin (2) | $ | 423.9 | $ | 406.7 | $ | 404.9 | ||||||
Equity in earnings of VESCO (3) (4) | $ | 10.2 | $ | 6.6 | $ | 7.2 | ||||||
Operating statistics: (5) | ||||||||||||
Gathering throughput, MMcf/d | 1,886.7 | 2,025.9 | 1,999.2 | |||||||||
Plant natural gas inlet, MMcf/d | 1,846.4 | 1,982.8 | 1,863.3 | |||||||||
Gross NGL production, MBbl/d | 101.9 | 106.6 | 106.8 | |||||||||
Natural gas sales, BBtu/d | 550.0 | 544.6 | 517.8 | |||||||||
NGL sales, MBbl/d | 85.8 | 91.6 | 88.7 | |||||||||
Condensate sales, MBbl/d | 5.0 | 5.0 | 4.9 | |||||||||
Average realized prices: | ||||||||||||
Natural gas, $/MMBtu | 8.23 | 6.57 | 6.78 | |||||||||
NGL, $/gal | 1.20 | 1.05 | 0.88 | |||||||||
Condensate, $/Bbl | 85.57 | 65.92 | 60.36 |
________
(1) | Includes business interruption insurance revenues of $14.3 million, $2.6 million and $3.7 million for 2008, 2007 and 2006. |
(2) | See “Non-GAAP Financial Measures – Operating Margin” included in this Item 7. |
(3) | Amounts are through July 31, 2008. VESCO is included in our consolidated results effective August 1, 2008. |
(4) | Includes business interruption insurance revenues of $4.1 million, $3.1 million and $2.9 million for 2008, 2007 and 2006. |
(5) | Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year. |
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Revenues increased $522.4 million, or 18%, to $3,440.3 million for 2008 compared to $2,917.9 million for 2007. The increase was primarily the result of:
§ | an increase in commodity prices that increased revenues by $578.0 million, consisting of increases in natural gas, NGL, and condensate revenues of $334.0 million, $208.3 million, and $35.7 million; |
§ | an offsetting decrease in commodity sales volumes that decreased revenues by $74.9 million, consisting of decreases in NGL and condensate revenues of $89.4 million and $1.8 million, partially offset by an increase in natural gas revenues of $16.3 million; |
§ | an increase in compression and gathering and other services, which increased revenues by $7.6 million; and |
§ | an increase of $11.7 million related to business interruption insurance revenues. |
Our average realized price for natural gas increased $1.66 per MMBtu, or 25%, to $8.23 per MMBtu for 2008 compared to $6.57 per MMBtu for 2007. Our average realized price for NGL increased $0.15 per gallon, or 14%, to $1.20 per gallon for 2008 compared to $1.05 per gallon for 2007. Our average realized price for condensate increased $19.65 per barrel, or 30%, to $85.57 per barrel for 2008 compared to $65.92 per barrel for 2007.
53
Our natural gas sales volumes increased 5.4 BBtu/d, or 1%, to 550.0 BBtu/d for 2008 compared to 544.6 BBtu/d for 2007. Natural gas sales volumes increased during 2008 due to a lower proportion of take-in-kind volumes increased marketing activity and the effect of unfavorable processing economics.
Our natural gas gathering throughput volumes, which were down 139.2 MMcf/d, were primarily impacted by lower gas volumes available for processing and facility disruptions due to hurricanes Gustav and Ike.
Our NGL sales volumes decreased 5.8 MBbl/d, or 6%, to 85.8 MBbl/d for 2008 compared to 91.6 MBbl/d for 2007. Gross NGL production was down during 2008 due to pipeline curtailments and, later in the year due to unfavorable processing economics.
Our condensate sales volumes were unchanged at 5.0 MBbl/d for each of 2008 and 2007.
Product purchases increased $492.7 million, or 21%, to $2,880.6 million for 2008 compared to $2,387.9 million for 2007. The 21% increase in product purchases correlates to an 18% increase in revenues from the sale of natural gas, NGL and condensate.
Operating expenses increased $12.5 million, or 10%, to $135.8 million for 2008 compared to $123.3 million for 2007. The increase is primarily due to an increase in expenditures for maintenance, repairs and supplies and chemicals and lubricants.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenues increased $326.9 million, or 13%, to $2,917.9 million for 2007 compared to $2,591.0 million for 2006. This increase is primarily due to:
· | an increase in commodity sales volumes that increased revenues by $108.6 million, consisting of increases in natural gas, NGL, and condensate revenues of $66.3 million, $38.3 million, and $4.0 million; |
· | an increase in commodity prices that increased revenues by $212.3 million, consisting of increases in NGL and condensate revenues of $244.4 million and $10.2 million, partially offset by a $42.3 million decrease in natural gas revenue; |
· | an increase in compression and gathering, processing, and other services, which increased revenues by $4.9 million; and |
· | a decrease of $1.1 million related to business interruption insurance revenues. |
Our average realized price for natural gas decreased $0.21 per MMBtu, or 3%, to $6.57 per MMBtu for 2007 compared to $6.78 per MMBtu for 2006. Our average realized price for NGLs increased $0.17 per gallon, or 19%, to $1.05 per gallon for 2007 compared to $0.88 per gallon for 2006. Our average realized price for condensate increased $5.56 per barrel , or 9%, to $65.92 per barrel for 2007 compared to $60.36 per barrel for 2006.
Our natural gas sales volumes increased 26.8 BBtu/d, or 5%, to 544.6 BBtu/d for 2007 compared to 517.8 BBtu/d for 2006. The net increase in gas sales volumes is due to:
· | increases in North Texas and New Mexico gas sales volumes due to increased drilling and connections in those regions; offset by |
· | a decrease in sales from our West Texas operations, resulting from the fourth quarter 2006 termination of a gas supply contract in the Sand Hills area. |
Our NGL sales volumes increased 2.9 MBbl/d, or 3%, to 91.6 MBbl/d for 2007 compared to 88.7 MBbl/d for 2006. The increase in NGL sales volumes is primarily from increased production from our coastal straddle plants compared to 2006. During 2006, several of these plants were either shut-down or severely curtailed as a result of damage suffered from Hurricanes Katrina and Rita during 2005.
Our condensate sales volumes increased 0.1 MBbl/d, or 2%, to 5.0 MBbl/d for 2007 compared to 4.9 MBbl/d for 2006.
Product purchases increased $320.5 million, or 16%, to $2,387.9 million for 2007 compared to $2,067.4 million for 2006. During 2007 and 2006, product purchases were 82% and 80% of total revenue. The increase in product purchases for 2007 corresponds with the increase in revenue for the same period. Excluding the impact on product purchases from the corresponding purchases for natural gas resold on behalf of other Targa entities results in an increase in product purchases of $263.7 million, or 13%, to $2,274.5 million in 2007 from $2,010.8 million in 2006.
Operating expenses increased $4.6 million, or 4%, to $123.3 million for 2007 compared to $118.7 million for 2006. This increase is primarily related to the increased compensation cost of field personnel.
Logistics Assets Segment
The following table provides summary financial data regarding results of operations of our Logistics Assets segment for the periods indicated:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions, except operating statistics) | ||||||||||||
Revenues from services | $ | 235.5 | $ | 195.2 | $ | 178.1 | ||||||
Other revenues (1) | 2.5 | - | 0.4 | |||||||||
238.0 | 195.2 | 178.5 | ||||||||||
Operating expenses | (188.4 | ) | (155.6 | ) | (136.1 | ) | ||||||
Operating margin (2) | $ | 49.6 | $ | 39.6 | $ | 42.4 | ||||||
Equity in earnings of GCF | $ | 3.9 | $ | 3.5 | $ | 2.8 | ||||||
Operating statistics: | ||||||||||||
Fractionation volumes, MBbl/d | 212.2 | 209.2 | 181.9 | |||||||||
Treating volumes, MBbl/d (3) | 20.7 | 9.1 | - |
________
(1) | Includes business interruption insurance revenues of $2.5 million, nil and $0.4 million for 2008, 2007 and 2006. |
(2) | See “Non-GAAP Financial Measures–Operating Margin” included in this Item 7. |
(3) | Consists of the volumes treated in our low sulfur natural gasoline (“LSNG”) unit, which began commercial operations in June 2007 |
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Revenues from fractionation, terminalling and storage, transport, and treating increased $40.3 million, or 21%, to $235.5 million for 2008 compared to $195.2 million for 2007. The increase was due to higher service rates, a full year of commercial operations at our LSNG unit in 2008 compared to six months of operations in 2007, increased treating and related service revenues, additional transport fees from spot barge activity and additional terminalling revenue from a new common carrier connection.
Operating expenses increased $32.8 million, or 21%, to $188.4 million for 2008 compared to $155.6 million for 2007. The increase was primarily the result of higher fuel and utilities expense, increased LSNG unit and other facility maintenance costs, plant turnaround costs and third-party fractionation expense, additional barge activity, inventory adjustments and pipeline integrity costs.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenues from fractionation, terminalling and storage, transport, and treating increased $17.1 million, or 10%, to $195.2 million for 2007 compared to $178.1 million for 2006. The increase was primarily the result of higher service rates for 2007 compared to 2006, the commencement of commercial operations at our LSNG unit in June 2007 and higher fractionation volumes. These increases were partially offset by the effect of lower terminalling and storage and transport volumes.
Higher service rates for 2007 compared to 2006 were derived primarily from commercial transportation activities. These include new barge transportation contracts for mixed butanes and propane/propylene mix, new railcar lease revenue earned from the NGL Distribution and Marketing and Wholesale Marketing segment and increased truck transportation fees as a result of an increased fuel surcharge.
The overall volume increase was due to higher fractionation and LSNG related service volumes in 2007 compared to 2006, partially offset by lower terminalling and storage volumes primarily due to lower imports. Our fractionation facilities operated at 75% and 66% of design capacity for 2007 and 2006.
Operating expenses increased $19.5 million, or 14%, to $155.6 million for 2007 compared to $136.1 million for 2006. This increase is primarily due to:
· | increased railcar lease expense as a result of new railcar leases following the termination of a railcar sharing agreement. Under the railcar sharing agreement, rail transportation costs were included in product purchases in our NGL Distribution and Marketing and Wholesale Marketing Segments; |
· | the June 2007 commencement of commercial operations at our new LSNG unit, which added to operating expenses; |
· | increased fractionation-related expenses due to higher fractionation volumes and increased fuel costs; |
· | higher barge transportation costs, caused by an increase in tug rates; and |
· | increased terminalling and storage costs due to the timing of well workovers at Mont Belvieu. |
NGL Distribution and Marketing Services Segment
The following table provides summary financial data regarding results of operations of our NGL Distribution and Marketing Services segment for the periods indicated:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions, except operating and price data) | ||||||||||||
NGL sales revenues | $ | 5,172.2 | $ | 4,889.3 | $ | 3,728.4 | ||||||
Other revenues (1) | 12.5 | 6.5 | 10.4 | |||||||||
5,184.7 | 4,895.8 | 3,738.8 | ||||||||||
Product purchases | (5,164.5 | ) | (4,838.8 | ) | (3,726.2 | ) | ||||||
Operating expenses | (1.7 | ) | (1.5 | ) | (2.0 | ) | ||||||
Operating margin (2) | $ | 18.5 | $ | 55.5 | $ | 10.6 | ||||||
Operating data: | ||||||||||||
NGL sales, MBbl/d | 244.6 | 275.6 | 246.3 | |||||||||
NGL realized price, $/gal | 1.38 | 1.16 | 0.99 |
________
(1) | Includes business interruption insurance revenues of $9.6 million, $3.8 million and $5.5 million for 2008, 2007 and 2006. |
(2) | See “Non-GAAP Financial Measures – Operating Margin” included in this Item 7. |
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Revenues increased $288.9 million, or 6%, to $5,184.7 million for 2008 compared to $4,895.8 million for 2007. Higher market prices increased revenue $820.6 million partially offset by lower sales volume, which decreased revenue by $537.8 million. The increase in other revenues was primarily from increased business interruption insurance revenues during 2008.
NGL sales decreased 31.0 MBbl/d, or 11%, to 244.6 MBbl/d for 2008 compared to 275.6 MBbl/d for 2007. The decrease was primarily the result of disruptions due to hurricanes Gustav and Ike as well as reduced petrochemical operating rates for 2008 as compared to 2007.
Product purchases increased $325.7 million, or 7%, to $5,164.5 million for 2008 compared to $4,838.8 million for 2007. Higher market prices increased product purchases by $857.9 million partially offset by lower volumes, which decreased product purchases by $532.2 million.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenues increased $1,157.0 million, or 31%, to $4,895.8 million for 2007 compared to $3,738.8 million for 2006. The net increase comprised a $443.6 million increase as a result of higher sales volumes, a $717.3 million increase due to higher commodity prices, a $2.2 million decrease in non-commodity revenues, which are principally derived from fee-based services, and a $1.7 million decrease in business interruption insurance revenues.
NGL sales increased 29.3 MBbl/d, or 12%, to 275.6 MBbl/d for 2007 compared to 246.3 MBbl/d for 2006. The increase was primarily the result of a new source of raw product supply; sales of production from Gillis, Mertzon, and Sterling plants which prior to April 2006 were marketed by our Natural Gas Gathering and Processing segment; increased sales of production from our Yscloskey facility which was not in operation during a portion of 2006 as a result of damage from hurricanes Katrina and Rita during 2005.
Our average realized price for NGLs increased $0.17 per gallon, or 17%, to $1.16 per gallon for 2007 compared to $0.99 per gallon for 2006.
Product purchases increased $1,112.6 million, or 30%, to $4,838.8 million for 2007 compared to $3,726.2 million for 2006. Higher average market prices increased product purchases by $669.3 million and higher volumes increased product purchases by $443.1 million.
Wholesale Marketing Segment
The following table provides summary financial data regarding results of operations of our Wholesale Marketing segment for the periods indicated:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions, except operating and price data) | ||||||||||||
NGL sales revenues | $ | 1,453.3 | $ | 1,301.4 | $ | 1,322.7 | ||||||
Other revenues (1) | 6.8 | 1.2 | 7.9 | |||||||||
1,460.1 | 1,302.6 | 1,330.6 | ||||||||||
Product purchases | (1,446.8 | ) | (1,279.8 | ) | (1,320.6 | ) | ||||||
Operating expenses | (0.1 | ) | - | - | ||||||||
Operating margin (2) | $ | 13.2 | $ | 22.8 | $ | 10.0 | ||||||
Operating data: | ||||||||||||
NGL sales, MBbl/d | 62.5 | 64.0 | 74.4 | |||||||||
NGL realized price, $/gal | 1.51 | 1.33 | 1.16 |
________
(1) | Includes business interruption insurance revenues of $6.5 million, $0.8 million and $1.1 million for 2008, 2007 and 2006. |
(2) | See “Non-GAAP Financial Measures – Operating Margin” included in this Item 7. |
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Revenues increased $157.5 million, or 12%, to $1,460.1 million for 2008 compared to $1,302.6 million for 2007. Higher NGL market prices increased revenue $178.6 million partially offset by lower sales volume, which decreased revenue by $26.8 million. The increase in other revenues consists primarily of a $5.7 million increase in business interruption insurance revenues.
Our average realized price for NGL increased $0.18 per gallon, or 14%, to $1.51 per gallon for 2008 compared to $1.33 per gallon for 2007. The increase was primarily due to higher overall market prices for all components. However, market prices dropped significantly in the fourth quarter of 2008 quarter due to overall market conditions. NGL sales decreased 1.5 MBbl/d, or 2%, to 62.5 MBbl/d for 2008 compared to 64.0 MBbl/d for 2007. The decrease in volumes is due primarily to the expiration of refinery supply agreements and an operating disruption at a customer facility.
Product purchases increased $167.0 million, or 13%, to $1,446.8 million for 2008 compared to $1,279.8 million for 2007. Higher NGL market prices and lower of cost or market adjustments increased product purchases by $187.3 million and $6.0 million partially offset by lower volumes, which decreased product purchases by $26.3 million.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenues decreased $28.0 million, or 2%, to $1,302.6 million for 2007 compared to $1,330.6 million for 2006. Lower NGL sales volumes decreased revenues by $184.3 million and higher commodity prices increased revenues by $163.0 million. The decrease in other revenues consists primarily of a $6.7 million decrease in fee-based service revenue due to the termination of certain refinery service contracts.
NGL sales decreased 10.4 MBbl/d, or 14%, to 64.0 MBbl/d for 2007 compared to 74.4 MBbl/d for 2006. The decrease is primarily due to direct and indirect impacts of terminated feedstock contracts with Chevron that ended in September 2006.
Product purchases decreased $40.8 million, or 3%, to $1,279.8 million for 2007 compared to $1,320.6 million for 2006. Higher NGL market prices increased product purchases by $143.2 million partially offset by lower volumes, which decreased product purchases by $184.0million. We incurred a smaller lower of cost or market adjustment in 2007 versus 2006 by $3.0 million.
Hurricane Update
Certain of our Louisiana and Texas facilities sustained damage during the 2005 hurricane season from two Gulf Coast hurricanes—Katrina and Rita. All repairs to our plant facilities relating to these two hurricanes have been completed.
During 2008, we received $48.3 million and $37.0 million related to property damage and business interruption insurance claims, most of which was in connection with the final resolution of our claims related to Katrina under the onshore property insurance program.
In September 2008, certain of our facilities in Louisiana and Texas sustained damage and had disruption to their operations from hurricanes Gustav and Ike.
Hurricane Gustav made landfall near Cocodrie, Louisiana on September 1, 2008. Hurricane Ike made landfall at Galveston, Texas on September 13, 2008. Our Venice and Yscloskey gas processing plants were impacted by the storm surge caused by both hurricanes, though damage at these two facilities was not substantial. The Venice gas plant was processing gas by early October. The Yscloskey gas plant start-up and commissioning timing was delayed as a result of hurricane damage to the Tennessee Gas Pipeline Bluewater offshore system, which has now been substantially repaired, enabling the plant to start up in January 2009. Volumes available for processing at both facilities were impacted by third-party offshore production shut-ins ahead of the hurricanes, and continued to be impacted by damage to third-party facilities from the hurricanes.
In Texas, our Galena Park marine terminal sustained a significant storm surge from Ike, resulting in damage to the docks, associated piping and related infrastructure. Temporary repairs restored limited barge and ship cargo transfers by late September, with full loading/offloading capabilities restored in the fourth quarter. Some remaining permanent repairs are ongoing and expected to be completed early in the second quarter of 2009. Galena Park’s shore-side facilities sustained relatively minor flood damage. Our Mont Belvieu complex sustained relatively minor wind damage and was fully operational by late September. Ike’s storm surge significantly impacted our Stingray and Barracuda gas processing facilities and our Hackberry storage facility, all of which are located in Cameron Parish, Louisiana. Operations at Hackberry resumed partial functionality in late September and full functionality by the end of the fourth quarter; with some permanent repairs ongoing and expected to be completed in the first quarter 2009. Gas processing operations at Stingray and Barracuda are anticipated to resume during the second quarter of 2009.
We currently estimate the cost associated with our interest for repairs to the impacted facilities to be approximately $65 million. We believe that we have adequate insurance coverage (subject to customary deductibles, limits and sub-limits) to cover the respective facility repair costs and to offset the majority of the associated lost profits as a result of the hurricanes. The property damage deductibles under our insurance coverage will reduce our ultimate property damage insurance recoveries by approximately $14 million. We will have additional out of pocket costs associated with improvements (e.g., elevating critical equipment) that may not be covered by insurance. During 2008, we recorded a loss provision of $19.3 million ($17.9 million, net to our ownership interest) for our estimated out-of-pocket cleanup and repair costs related to these two hurricanes, after estimated insurance proceeds.
We are still in the process of analyzing the factors affecting the amount of our business interruption claims. We maintain a 30 day time-element business interruption waiting period for our onshore facilities, and a 45 day time-element contingent business interruption waiting period for third-party offshore property damage related income impacts to our onshore facilities. Based on the information currently available to us we believe that we could receive business interruption claim proceeds in excess of $10 million. We will recognize income from business interruption claims in the period that a proof of loss is executed with the insurance company.
Liquidity and Capital Resources
Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for natural gas and NGLs, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. See “Item 1A. Risk Factors.”
Our main sources of liquidity and capital resources are internally generated cash flow from operations, borrowings under our credit facility, the issuance of additional units by the Partnership and access to debt markets. The credit markets are undergoing significant volatility. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit crisis includes our credit facility, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets. In order to increase our cash position in the face of the credit and capital market disruptions, on October 16, 2008, we requested a $100 million funding under our credit facility. Lehman Paper, a lender under our credit facility, defaulted on its portion of this borrowing request, resulting in actual funding of $95.9 million. As a result, we believe the availability under our credit facility has been effectively reduced by $10.2 million. On the same date, the Partnership requested a $100 million funding under the Partnership’s credit facility, and Lehman Bank, a lender under the Partnership’s credit facility, defaulted on its portion of the Partnership’s borrowing request resulting in actual funding of $97.8 million. As a result of the default, we believe the availability under the Partnership’s credit facility has been effectively reduced by approximately $10.0 million.
Current market conditions also elevate the concern over counterparty risks related to our commodity derivative contracts and trade credit. We have all of our commodity derivatives with major financial institutions. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices. We sell a significant portion of our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.
Crude oil and natural gas prices are also volatile and have recently declined significantly. In a continuing effort to reduce the volatility of our cash flows, we have periodically entered into commodity derivative contracts for a portion of our estimated equity volumes through 2012. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.” The current market conditions may also impact our ability to enter into future commodity derivative contracts. In the event of a global recession, commodity prices may stay depressed or fall further thereby causing a prolonged downturn, which could reduce our operating margins and cash flow from operations.
As of December 31, 2008, we and the Partnership had liquidity of $506.7 million and $424.3 million, including $362.8 million and $81.8 million of cash and $143.9 million and $342.5 million of available borrowings under our respective credit facilities. We will continue to monitor our liquidity and the credit markets. Additionally, we will continue to monitor events and circumstances surrounding each of the other sixteen lenders in our credit facility and the other twenty three lenders in the Partnership’s credit facility. To date, other than the Lehman Paper and Lehman Bank defaults, neither we nor the Partnership have experienced any disruptions in the ability to access our respective bank credit facilities. However, we cannot predict with any certainty the impact to us of any further disruption in the credit environment. See “Item 1A. Risk Factors.”
Historically, our cash generated from operations has been sufficient to finance our operating expenditures and non-acquisition related capital expenditures. Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow and borrowings available under our senior secured credit facilities should provide sufficient resources to finance our operations, non-acquisition related capital expenditures, hurricane-related repair expenditures, long-term indebtedness obligations and collateral requirements for at least the next twelve months.
A significant portion of our capital resources are utilized in the form of cash and letters of credit to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade status and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. At December 31, 2008, our total outstanding letter of credit postings were $123.7 million.
The Partnership is obligated to make minimum quarterly cash distributions to unit holders from available cash, as defined in the partnership agreement. As of December 31, 2008, such minimum amounts payable to non-Targa unit holders total approximately $46.8 million annually.
Cash Flow
The following table summarizes cash flow provided by or used in operating activities, investing activities and financing activities for the periods indicated.
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Net cash provided by (used in): | ||||||||||||
Operating activities | $ | 300.7 | $ | 142.6 | $ | 233.3 | ||||||
Investing activities | (223.1 | ) | (95.9 | ) | (117.8 | ) | ||||||
Financing activities | 107.3 | (11.5 | ) | (14.2 | ) |
Operating Activities
Net cash provided by operating activities was $300.7 million for 2008 compared to $142.6 million for 2007. The $158.1 million increase was primarily due to changes in operating assets and liabilities, which provided $157.8 million in cash during 2008, compared to using $75.2 million in cash during 2007, partially offset by an $87.4 million payment during 2008 to terminate certain out-of-the-money commodity derivatives.
Net cash provided by operating activities was $142.6 million for 2007 compared to $233.3 million for 2006. Changes in operating assets and liabilities used $75.2 million in cash during 2007, compared to providing $70.6 million in cash during 2006. The difference resulted primarily from the delay until early 2006 of sales of our 2005 seasonal-built propane inventory. The delay was due to disruptions in demand as a result of hurricanes Katrina and Rita. Our normal cycle of accumulation and distribution resumed during the summer of 2006. The negative impact of working capital changes was partially offset by higher operating margin in 2007 due to higher revenue as a result of higher sales volumes and higher NGL and condensate average realized sales prices.
Investing Activities
Net cash used in investing activities was $223.1 million for 2008 compared to $95.9 million for 2007. The $127.2 million increase is primarily due to our acquisition of an approximate 54% interest in VESCO and increased capital expenditures during 2008.
Net cash used in investing activities was $95.9 million for 2007 compared to $117.8 million for 2006. The $21.9 million decrease is primarily due to a decrease of cash paid for purchases of property, plant and equipment of $17.9 million, lesser contributions to unconsolidated investments during 2007, and lesser proceeds received from property insurance, partially offset by a slight increase of sales proceeds from the sale of assets.
Financing Activities
Net cash provided by financing activities was $107.3 million for 2008 compared to net cash used by financing activities of $11.5 million for 2007. The $118.8 million increase is primarily from borrowings under our credit facility of $95.9 million and under the Partnership’s credit facilities of $185.3 million, partially offset by cash outflows of $53.9 million for cash distribution to Targa Investments and $26.8 million for repurchases of a portion of the Partnership’s senior notes.
Net cash used in financing activities was $11.5 million for 2007 compared to $14.2 million for 2006. For 2007, repayments of $1,494.7 million to retire indebtedness and $7.5 million incurred in connection with financing arrangements were partially offset by $721.3 million borrowed under the Partnership’s credit facility and $771.8 million in net proceeds from the Partnership’s sales of common units to the public.
Capital Requirements
The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. A significant portion of the cost of constructing new gathering lines to connect to our gathering system is generally paid for by the natural gas producer. We expect to make significant expenditures during the next year for the construction of additional natural gas gathering and processing infrastructure and to enhance the value of our natural gas logistics and marketing assets.
We categorize our capital expenditures as either: (i) maintenance expenditures or (ii) expansion expenditures. Maintenance expenditures are those expenditures that are necessary to maintain the service capability of our existing assets including the replacement of system components and equipment which is worn, obsolete or completing its useful life, the addition of new sources of natural gas supply to our systems to replace natural gas production declines and expenditures to remain in compliance with environmental laws and regulations. Expansion expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues.
Our planned capital expenditures for 2009, excluding expenditures for the repair of previously discussed hurricane damage, are approximately $160 million. We are currently funding the cost of hurricane damage related repairs for our facilities through operating cash flow.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.
Credit Facilities and Long-Term Debt
At December 31, 2008, we had approximately $144 million of availability under our credit facility, and the Partnership had approximately $342.5 million of availability under the Partnership’s credit facility.
We and the Partnership also have senior unsecured debt outstanding of $250 million and $209 million. We consolidate the debt of the Partnership with that of our own; however, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership. See Note 10 to our Consolidated Financial Statements beginning on page F-1 of this Annual Report for a discussion of our and the Partnership’s various credit agreements.
Contractual Obligations
Following is a summary of our contractual cash obligations over the next several fiscal years, as of December 31, 2008:
Payments due by period | ||||||||||||||||||||
Total | Less than 1 year | 1-3 years | 4-5 years | More than 5 years | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Debt obligations (1) | $ | 1,564.9 | $ | 12.5 | $ | 120.9 | $ | 1,222.4 | $ | 209.1 | ||||||||||
Interest on debt obligations (2) | 385.2 | 81.7 | 162.7 | 97.7 | 43.1 | |||||||||||||||
Operating lease obligations (3) | 72.9 | 12.3 | 19.6 | 15.9 | 25.1 | |||||||||||||||
Capacity payments (4) | 20.0 | 8.2 | 8.2 | 3.6 | - | |||||||||||||||
Right of way | 17.6 | 1.1 | 2.0 | 1.8 | 12.7 | |||||||||||||||
Asset retirement obligations | 34.0 | - | - | - | 34.0 | |||||||||||||||
Other contractual obligations (5) | 0.9 | 0.4 | 0.5 | - | - | |||||||||||||||
$ | 2,095.5 | $ | 116.2 | $ | 313.9 | $ | 1,341.4 | $ | 324.0 |
________
(1) | Represents our scheduled future maturities of consolidated debt obligations for the periods indicated. See Note 10 of the Notes to Consolidated Financial Statements included beginning on page F-1 of this Annual Report for information regarding our debt obligations. |
(2) | Represents interest expense on our debt obligations based on interest rates as of December 31, 2008 and the scheduled future maturities of those debt obligations. |
(3) | Operating lease obligations include minimum lease payment obligations associated with gas processing plant site leases, railcar leases, office space leases and pipeline right-of-way. |
(4) | Consist of capacity payments for firm transportation contracts. |
(5) | Primarily consist of information technology contractual obligations. |
Credit Ratings
At January 30, 2009 we had the following credit ratings, all of which are speculative ratings:
Moody's Investor Services | Standard & Poor's | |
Corporate rating | B1 | B |
Senior secured credit facilities | Ba3 | B+ |
Senior unsecured notes | B3 | CCC+ |
A speculative rating signifies a higher risk that we will default on our obligations than does an investment grade rating.
Critical Accounting Policies
Revenue Recognition. Our primary types of sales and service activities reported as operating revenues include:
· | sales of natural gas, NGLs and condensate; |
· | natural gas processing, from which we generate revenues through the compression, gathering, treating, and processing of natural gas, and |
· | 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. 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.
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 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.
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 the our functional asset groups are as follows:
Asset Group | Range of Years | |||
Natural gas gathering systems and processing facilities | 15 to 25 | |||
Fractionation, terminalling and natural gas liquids storage facilities | 25 | |||
Transportation assets | 5 to 10 | |||
Other property and equipment | 3 to 7 |
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.
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.
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.
Price Risk Management (Hedging). 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 hedge, the effective portion of the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (“OCI”), a component of partners’ capital, 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 our 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.
Recent Accounting Pronouncements.
For a discussion of recent accounting pronouncements that will affect us, see Note 2 to our Consolidated Financial Statements beginning on page F-1 of this Annual Report.
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, 2008, we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2009 through 2012 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease 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 for volumes less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge the commodity price exposure associated with 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 specific NGL products or 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 recognized market hubs, 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 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.
At December 31, 2008, we had the following open commodity derivatives which have been designated as cash-flow hedges:
Natural Gas | ||||||||||||||||||||||||||
Avg. Price | MMBtu per day | |||||||||||||||||||||||||
Instrument Type | Index | $/MMBtu | 2009 | 2010 | 2011 | 2012 | Fair Value | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||
Natural Gas Sales | ||||||||||||||||||||||||||
Swap | IF-Waha | 6.62 | 21,918 | - | - | - | $ | 11,010 | ||||||||||||||||||
Swap | IF-Waha | 7.40 | - | 9,300 | - | - | 3,403 | |||||||||||||||||||
Swap | IF-Waha | 7.36 | - | - | 5,500 | - | 1,503 | |||||||||||||||||||
Swap | IF-Waha | 7.18 | - | - | - | 5,500 | 1,197 | |||||||||||||||||||
Total Sales | 21,918 | 9,300 | 5,500 | 5,500 | ||||||||||||||||||||||
$ | 17,113 |
NGLs | ||||||||||||||||||||||||||
Avg. Price | Barrels per day | |||||||||||||||||||||||||
Instrument Type | Index | $/gal | 2009 | 2010 | 2011 | 2012 | Fair Value | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||
NGL Sales | ||||||||||||||||||||||||||
Swap | OPIS-MB | 0.79 | 3,347 | - | - | - | $ | 9,515 | ||||||||||||||||||
Swap | OPIS-MB | 0.87 | - | 2,750 | - | - | 7,388 | |||||||||||||||||||
Swap | OPIS-MB | 0.91 | - | - | 1,550 | - | 3,971 | |||||||||||||||||||
Swap | OPIS-MB | 0.92 | - | - | - | 1,250 | 2,999 | |||||||||||||||||||
Total Swaps | 3,347 | 2,750 | 1,550 | 1,250 | ||||||||||||||||||||||
Floor | OPIS-MB | 1.44 | - | - | 54 | - | 490 | |||||||||||||||||||
Floor | OPIS-MB | 1.43 | - | - | - | 63 | 527 | |||||||||||||||||||
Total Floors | - | - | 54 | 63 | ||||||||||||||||||||||
Total Sales | 3,347 | 2,750 | 1,604 | 1,313 | ||||||||||||||||||||||
$ | 24,890 |
At December 31, 2008, the Partnership had the following open commodity derivatives, which have been designated as cash-flow hedges:
Natural Gas | ||||||||||||||||||||||||||
Avg. Price | MMBtu per day | |||||||||||||||||||||||||
Instrument Type | Index | $/MMBtu | 2009 | 2010 | 2011 | 2012 | Fair Value | |||||||||||||||||||
Natural Gas Sales | (In thousands) | |||||||||||||||||||||||||
Swap | IF-HSC | 7.39 | 1,966 | - | - | - | $ | 1,159 | ||||||||||||||||||
1,966 | - | - | - | |||||||||||||||||||||||
Swap | IF-NGPL MC | 9.18 | 6,256 | - | - | - | 9,466 | |||||||||||||||||||
Swap | IF-NGPL MC | 8.86 | - | 5,685 | - | - | 5,129 | |||||||||||||||||||
Swap | IF-NGPL MC | 7.34 | - | - | 2,750 | - | 843 | |||||||||||||||||||
Swap | IF-NGPL MC | 7.18 | - | - | - | 2,750 | 738 | |||||||||||||||||||
6,256 | 5,685 | 2,750 | 2,750 | |||||||||||||||||||||||
Swap | IF-Waha | 8.73 | 6,936 | - | - | - | 8,627 | |||||||||||||||||||
Swap | IF-Waha | 7.52 | - | 5,709 | - | - | 2,294 | |||||||||||||||||||
Swap | IF-Waha | 7.36 | - | - | 3,250 | - | 886 | |||||||||||||||||||
Swap | IF-Waha | 7.18 | - | - | - | 3,250 | 708 | |||||||||||||||||||
6,936 | 5,709 | 3,250 | 3,250 | |||||||||||||||||||||||
Total Swaps | 15,158 | 11,394 | 6,000 | 6,000 | ||||||||||||||||||||||
Floor | IF-NGPL MC | 6.55 | 850 | - | - | - | 574 | |||||||||||||||||||
850 | - | - | - | |||||||||||||||||||||||
Floor | IF-Waha | 6.55 | 565 | - | - | - | 326 | |||||||||||||||||||
565 | - | - | - | |||||||||||||||||||||||
Total Floors | 1,415 | - | - | - | ||||||||||||||||||||||
Total Sales | 16,573 | 11,394 | 6,000 | 6,000 | ||||||||||||||||||||||
$ | 30,750 |
NGL | ||||||||||||||||||||||||||
Avg. Price | Barrels per day | |||||||||||||||||||||||||
Instrument Type | Index | $/gal | 2009 | 2010 | 2011 | 2012 | Fair Value | |||||||||||||||||||
NGL Sales | (In thousands) | |||||||||||||||||||||||||
Swap | OPIS-MB | 1.32 | 6,248 | - | - | - | $ | 66,137 | ||||||||||||||||||
Swap | OPIS-MB | 1.27 | - | 4,809 | - | - | 39,122 | |||||||||||||||||||
Swap | OPIS-MB | 0.92 | - | - | 3,400 | - | 8,288 | |||||||||||||||||||
Swap | OPIS-MB | 0.92 | - | - | - | 2,700 | 6,018 | |||||||||||||||||||
Total Swaps | 6,248 | 4,809 | 3,400 | 2,700 | ||||||||||||||||||||||
Floor | OPIS-MB | 1.44 | - | - | 199 | - | 1,807 | |||||||||||||||||||
Floor | OPIS-MB | 1.43 | - | - | - | 231 | 1,932 | |||||||||||||||||||
Total Floors | - | - | 199 | 231 | ||||||||||||||||||||||
Total Sales | 6,248 | 4,809 | 3,599 | 2,931 | ||||||||||||||||||||||
$ | 123,304 |
Condensate | ||||||||||||||||||||||||||
Avg. Price | Barrels per day | |||||||||||||||||||||||||
Instrument Type | Index | $/Bbl | 2009 | 2010 | 2011 | 2012 | Fair Value | |||||||||||||||||||
Condensate Sales | (In thousands) | |||||||||||||||||||||||||
Swap | NY-WTI | 69.00 | 322 | - | - | - | $ | 1,655 | ||||||||||||||||||
Swap | NY-WTI | 68.10 | - | 301 | - | - | 431 | |||||||||||||||||||
Total Swaps | 322 | 301 | - | - | ||||||||||||||||||||||
Floor | NY-WTI | 60.00 | 50 | - | - | - | 239 | |||||||||||||||||||
Total Floors | 50 | - | - | - | ||||||||||||||||||||||
Total Sales | 372 | 301 | - | - | ||||||||||||||||||||||
$ | 2,325 |
Interest Rate Risk
We are exposed to changes in interest rates primarily as a result of variable rate debt under our senior secured credit facilities. To the extent that interest rates increase, interest expense on our revolving debt will also increase. As of December 31, 2008, we had approximately $1,564.9 million of indebtedness, of which $459.1 million was at fixed interest rates and $1,105.8 million was at variable interest rates. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates the Partnership entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:
Expiration | Fixed | Notional | |||||||
Date | Rate | Amount | Fair Value | ||||||
(In thousands) | |||||||||
January 24, 2011 | 4.00 | % | $100 million | $ | (5,282 | ) | |||
January 24, 2012 | 3.75 | % | 200 million | (12,294 | ) | ||||
$ | (17,576 | ) |
Each swap fixes the applicable 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 $8.1 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. Financial Statements and Supplementary Data
Our consolidated financial statements, together with the report of our independent registered public accounting firm begin on page F-1 of this Annual Report.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item 9A(T). Controls and Procedures
Disclosure Controls and Procedures
Our chief executive officer and chief financial officer, after evaluating the effectiveness of the Company’s “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)), as of December 31, 2008, have concluded that as of December 31, 2008, the Company’s disclosure controls and procedures were effective and designed to provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms, and accumulated and communicated to the Company’s management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
(a) Management’s Annual Report on Internal control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of this evaluation, our management concluded that internal control over financial reporting was effective as of December 31, 2008.
This Annual Report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.
(b) Changes in Internal Control Over Financial Reporting
During the quarter ended December 31, 2008, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B. Other Information
Not applicable
Item 10. Directors, Officers and Corporate Governance
The following table sets forth certain information with respect to our executive officers and directors as of February 25, 2009.
Name | Age | Position | ||
Rene R. Joyce | 61 | Chief Executive Officer and Director | ||
Joe Bob Perkins | 48 | President | ||
James W. Whalen | 67 | President-Finance and Administration and Director | ||
Roy E. Johnson | 64 | Executive Vice President | ||
Michael A. Heim | 60 | Executive Vice President and Chief Operating Officer | ||
Jeffrey J. McParland | 54 | Executive Vice President and Chief Financial Officer | ||
Paul W. Chung | 48 | Executive Vice President, General Counsel and Secretary | ||
Charles R. Crisp | 61 | Director | ||
Joe B. Foster | 74 | Director | ||
In Seon Hwang | 32 | Director | ||
Chansoo Joung | 48 | Director | ||
Peter R. Kagan | 40 | Director | ||
Chris Tong | 52 | Director |
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. 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, 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 Member and Managing Director of Warburg Pincus LLC and a General Partner of Warburg Pincus & Co., 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 CoalTek, and Competitive Power Ventures. 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 and a General Partner of Warburg Pincus & Co., where he has been employed since 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 Broad Oak Energy and Ceres, Inc. He also serves on the investment committee of Sheridan Production Partners LLC.
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 Member and Managing Director of Warburg Pincus LLC and a General Partner of Warburg Pincus & Co., where he has been employed since 1997. He is a member of Warburg Pincus’ Executive Management Group. He is also a director of Antero Resources Corporation, Broad Oak Energy, Inc., Canbriam 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. 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 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 members of the risk management committee are Messrs. Kagan, Hwang, Joung and Tong
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. 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. Executive Compensation
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 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, framework and individual compensation elements 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. |
Consistent with this philosophy and compensation objectives, 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, as well as broader industry compensation practices, at a general level to ensure that our total compensation is reasonably comparable and meets our compensation objectives. 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. Although Senior Management and the TRII Compensation Committee consider compensation data from other companies, they 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 2008, Senior Management identified peer companies in the midstream energy industry and reviewed compensation information filed by the peer companies with the SEC. The peer group reviewed by Senior Management for 2008 consisted of the following companies: Atlas America, Copano Energy, Crosstex Energy, DCP Midstream, Enbridge Energy Partners, Energy Transfer Partners, Magellan Midstream, MarkWest Energy Partners, Martin Midstream, NuStar Energy, Oneok Partners, Plains All American Pipeline, Regency Energy Partners, TEPPCO Partners and Williams Energy Partners.
Senior Management reviews 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 a compensation consultant engaged by the TRII Compensation Committee 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 reviews and discusses this proposal with Senior Management and may request Senior Management to provide additional information or reconsider their recommendation. The 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
Our compensation philosophy for executive officers emphasizes our executives having a significant long-term equity stake. 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 to attract, motivate and retain our executive team. 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 and have made significant investments in the equity of the Partnership. With these equity interests as 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, is subject to the sole discretion of the TRII Compensation Committee.
Our 2008 Annual Incentive Plan (the “Bonus Plan”) was adopted on January 17, 2008 to reward our employees for contributions towards our achievement of financial and operational business priorities (which includes business priorities of the Partnership) 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, funding of a discretionary cash bonus pool is expected to be recommended by our CEO and approved by the TRII Compensation Committee annually based on our achievement of certain strategic, financial and operational objectives. 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 performance and on the recommendation of their supervisors, managers and line officers.
For 2008, the TRII Compensation Committee approved funding of the cash bonus pool with 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 rate of 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 level and/or continue to effectively drop down Company assets to the Partnership; and (vi) execute on all fronts (including the 2008 business plan and above priorities). The Bonus Plan established business priorities that the TRII Compensation Committee considers 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 January 2008, Targa Investments granted to the named executive officers cash-settled performance unit awards linked to the performance of the Partnership’s common units that will vest in June of 2011, 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. These performance unit awards are made pursuant to a plan adopted by Targa Investments. These awards are designed to further align the interests of the named executive officers with those of the Partnership’s equity holders.
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 employee’s 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. Based on our named executive officers’ ownership interests in Targa Investments and their direct ownership of the Partnership’s common units, they own, directly and indirectly, approximately 3% of the Partnership’s limited partner interests. The TRII Compensation Committee believes that the elements of its compensation program fit the established overall 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
Equity Ownership. The TRII Compensation Committee did not award additional equity to the named executive officers in 2008.
Base Salary. In 2008, base salaries for our named executive officers were established based on historical levels for these officers, taking into consideration officer salaries in our peer group and the long term equity component of our compensation program.
Annual Cash Incentives. In January 2009, the TRII Compensation Committee approved a cash bonus pool of 150% of the target level for the employee group, including our named executive officers, under the Bonus Plan for performance during 2008. The TRII Compensation Committee paid above target level bonuses under the Bonus Plan in recognition of significant efforts and organizational performance in 2008. The executive officers received bonus awards equivalent to the same percentage of target as the Company bonus pool based on our achievement of overall goals in 2008 as follows:
Rene R. Joyce | $ | 247,500 | ||
Jeffrey J. McParland | 194,250 | |||
Joe Bob Perkins | 222,750 | |||
James W. Whalen | 222,750 | |||
Michael A. Heim | 206,250 |
Long-term Cash Incentives. In January 2008, Targa Investments granted 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 June of 2011, 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 2008 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 January 2008, our named executive officers, who are also executive officers of the General Partner, received an award of performance units 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.
Health and Welfare Benefits. For 2008, 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 2008, other than parking subsidies.
Changes for 2009
Annual Cash Incentives. In light of recent economic and financial events, Senior Management developed and proposed a set of strategic priorities to the TRII Compensation Committee. In January 2009, the TRII Compensation Committee approved the Targa Investments 2009 Annual Incentive Compensation Plan (the “2009 Bonus Plan”), the cash bonus plan for performance during 2009, and, established the following eight key business priorities: (i) manage controllable costs to levels at or below plan levels – with a continuous effort to improve costs for 2009 and beyond; (ii) examine, prioritize, and approve each capital project closely for economics (or necessity) in the current environment; (iii) increase scrutiny and proactively manage credit and liquidity across finance, credit and commercial areas; (iv) reduce (eliminate where appropriate) downstream’s inventory exposure (for TRI only); (v) continue to invest in our businesses primarily within existing cash flow; (vi) pursue selected opportunities including new shale play gathering and processing build outs, other fee-based capital projects and the potential to purchase distressed strategic assets; (vii) analyze and recommend approaches to achieve maximum value; and (viii) execute on the above priorities, including the 2009 financial business plan. 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 2009, 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: 34,000 performance units to Mr. Joyce, 15,500 performance units to Mr. McParland, 20,800 performance units to Mr. Perkins and 20,800 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 2008. 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 2008. See “Item 13. Certain Relationships and Related Transactions, and Director Independence” for a description of certain relationships and related-party transactions.
Compensation Committee Report
In fulfilling its oversight responsibilities, the Compensation Committee has reviewed and discussed with management the compensation discussion and analysis contained in this Annual Report on Form 10-K. Based on these reviews and discussions, the Compensation Committee recommended to the Targa Board that the compensation discussion and analysis be included in the Annual Report on Form 10-K for the year ended December 31, 2008 for filing with the SEC.
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 |
Executive Compensation
The following Summary Compensation Table sets forth the compensation of our named executive officers for 2008, 2007 and 2006. Additional details regarding the applicable elements of compensation in the Summary Compensation Table are provided in the footnotes following the table.
Summary Compensation Table for 2008 | |||||||||||||||||||||||||
Non-Equity | |||||||||||||||||||||||||
Stock | Option | Incentive Plan | All Other | Total | |||||||||||||||||||||
Name | Year | Salary | Awards ($)(1) | Awards ($)(2) | Compensation | Compensation(3) | Compensation | ||||||||||||||||||
Rene R. Joyce | 2008 | $ | 322,500 | $ | 148,218 | $ | 1,524 | $ | 247,500 | $ | 19,205 | $ | 738,947 | ||||||||||||
Chief Executive Officer | 2007 | 293,750 | 459,769 | 3,244 | 300,000 | 817,963 | 1,874,726 | ||||||||||||||||||
2006 | 266,530 | 312,513 | 3,244 | 264,000 | 25,236 | 871,523 | |||||||||||||||||||
Jeffrey J. McParland | 2008 | 253,000 | 114,247 | 1,524 | 194,250 | 19,031 | 582,052 | ||||||||||||||||||
Executive Vice President and | 2007 | 230,000 | 316,770 | 3,244 | 235,000 | 674,292 | 1,459,306 | ||||||||||||||||||
Chief Financial Officer | 2006 | 210,280 | 236,720 | 3,244 | 206,400 | 23,086 | 679,730 | ||||||||||||||||||
Joe Bob Perkins | 2008 | 290,250 | 126,228 | 1,524 | 222,750 | 19,124 | 659,876 | ||||||||||||||||||
President | 2007 | 265,000 | 366,318 | 3,244 | 270,000 | 817,888 | 1,722,450 | ||||||||||||||||||
2006 | 244,030 | 260,294 | 3,244 | 240,000 | 23,174 | 770,742 | |||||||||||||||||||
James W. Whalen | 2008 | 290,250 | 66,488 | - | 222,750 | 18,871 | 598,359 | ||||||||||||||||||
President—Finance and | 2007 | 265,000 | 224,796 | - | 270,000 | 817,888 | 1,577,684 | ||||||||||||||||||
Administration | 2006 | 244,030 | 227,546 | - | 240,000 | 21,926 | 733,502 | ||||||||||||||||||
Michael A. Heim | 2008 | 268,750 | 127,172 | 1,524 | 206,250 | 19,071 | 622,767 | ||||||||||||||||||
Executive Vice President and | 2007 | 243,750 | 366,318 | 3,244 | 250,000 | 817,838 | 1,681,150 | ||||||||||||||||||
Chief Operating Officer | 2006 | 217,791 | 260,294 | 3,244 | 216,000 | 23,111 | 720,440 |
__________
(1) | Amounts represent expense recognized for financial statement reporting purposes in accordance with SFAS 123(R) with respect to restricted stock awards and performance unit awards, disregarding any estimate of forfeitures related to service-based vesting conditions. No stock awards or performance unit awards granted to the named executive officers were forfeited during 2008. No stock awards were granted to the named executive officers during 2008. Detailed information about the amount recognized for specific awards is reported in the table under “Outstanding Equity Awards at 2008 Fiscal Year-End” below. For a discussion of the assumptions and methodologies used to value the awards reported in this column, please see the discussions of share-based compensation and stock and performance unit awards in Note 2 and Note 12 to our Consolidated Financial Statements included in this Annual Report. |
(2) | Amounts represent expense recognized for financial statement reporting purposes in accordance with SFAS 123(R) with respect to option awards, disregarding any estimate of forfeitures related to service-based vesting conditions. No option awards granted to the named executive officers were forfeited during 2008. No option awards were granted to the named executive officers during 2008. Detailed information about the amount recognized for specific awards is reported in the table under “Outstanding Equity Awards at 2008 Fiscal Year-End” below. For a discussion of the assumptions and methodologies used to value the awards reported in this column, please see the discussion of option awards in Note 12 to our Consolidated Financial Statements included in this Annual Report. |
(3) | For 2008 “All Other Compensation” includes the (i) aggregate value of matching and non-matching contributions to our 401(k) plan and (ii) the dollar value of life insurance coverage. |
Name | 401(k) and Profit Sharing Plan | Dollar Value of Life Insurance | Total | |||||||||
Rene R. Joyce | $ | 18,400 | $ | 805 | $ | 19,205 | ||||||
Jeffrey J. McParland | 18,400 | 631 | 19,031 | |||||||||
Joe Bob Perkins | 18,400 | 724 | 19,124 | |||||||||
James W. Whalen | 18,400 | 471 | 18,871 | |||||||||
Michael A. Heim | 18,400 | 671 | 19,071 |
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 2008:
Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | Estimated Future Payouts Under Equity Incentive Plan Awards(2) | |||||||||||||||||||||||||
Name | Grant Date | Threshold | Target | 2X Target | Threshold | Target (Units) | Maximum | Grant Date Fair Value of Stock and Option Awards(3) | ||||||||||||||||||
Mr. Joyce | N/A | $ | 82,500 | $ | 165,000 | $ | 330,000 | |||||||||||||||||||
01/17/08 | 4,000 | $ | 148,400 | |||||||||||||||||||||||
Mr. McParland | N/A | 58,750 | 117,500 | 259,000 | ||||||||||||||||||||||
01/17/08 | 2,700 | 100,170 | ||||||||||||||||||||||||
Mr. Perkins | N/A | 74,250 | 148,500 | 297,000 | ||||||||||||||||||||||
01/17/08 | 3,500 | 129,850 | ||||||||||||||||||||||||
Mr. Whalen | N/A | 74,250 | 148,500 | 297,000 | ||||||||||||||||||||||
01/17/08 | 3,500 | 129,850 | ||||||||||||||||||||||||
Mr. Heim | N/A | 68,750 | 137,500 | 275,000 | ||||||||||||||||||||||
01/17/08 | 3,500 | 129,850 |
_____
(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) | The dollar amounts shown are determined by multiplying the number of units reported in the table by $37.10 (the per unit fair value under SFAS 123(R) 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 2008 salaries, bonuses and incentive plans 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 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 2008 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 2008 Fiscal Year-End” below.
Outstanding Equity Awards at 2008 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, 2008 for each of our named executive officers.
Outstanding Equity Awards at 2008 Fiscal Year-End | |||||||||||||||||||||||||||||||
Option Awards | Stock Awards | ||||||||||||||||||||||||||||||
Name | �� | # Exercisable | # Unexercisable | Option Exercise Price | Option Expiration Date | Number of Shares of Stock That Have Not Vested | Market Value of Shares of Stock That Have Not Vested(7) | Equity Incentive Plan Awards: Number of Unearned Performance Units That Have Not Vested(8) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Performance Units That Have Not Vested(9) | ||||||||||||||||||||||
Rene R. Joyce | 17,417 | 4,355 | (1 | ) | $ | 0.75 | 10/31/15 | 146,840 | (4 | ) | $ | 132,156 | 19,000 | $ | 194,962 | ||||||||||||||||
233,101 | 58,275 | (1 | ) | 3.00 | 10/31/15 | 1,423 | (5 | ) | 1,281 | ||||||||||||||||||||||
197,239 | 49,310 | (1 | ) | 15.00 | 10/31/15 | ||||||||||||||||||||||||||
2,405 | 601 | (2 | ) | 3.00 | 12/20/15 | ||||||||||||||||||||||||||
2,047 | 512 | (2 | ) | 15.00 | 12/20/15 | ||||||||||||||||||||||||||
Jeffrey J. McParland | 17,417 | 4,355 | (1 | ) | 0.75 | 10/31/15 | 111,024 | (4 | ) | 99,922 | 10,900 | 111,505 | |||||||||||||||||||
174,825 | 43,707 | (1 | ) | 3.00 | 10/31/15 | 1,067 | (5 | ) | 960 | ||||||||||||||||||||||
147,929 | 36,983 | (1 | ) | 15.00 | 10/31/15 | ||||||||||||||||||||||||||
1,803 | 451 | (2 | ) | 3.00 | 12/20/15 | ||||||||||||||||||||||||||
1,535 | 384 | (2 | ) | 15.00 | 12/20/15 | ||||||||||||||||||||||||||
Joe Bob Perkins | 17,417 | 4,355 | (1 | ) | 0.75 | 10/31/15 | 122,336 | (4 | ) | 110,102 | 14,300 | 146,322 | |||||||||||||||||||
188,811 | 47,203 | (1 | ) | 3.00 | 10/31/15 | 1,153 | (5 | ) | 1,038 | ||||||||||||||||||||||
159,765 | 39,940 | (1 | ) | 15.00 | 10/31/15 | ||||||||||||||||||||||||||
1,949 | 486 | (2 | ) | 3.00 | 12/20/15 | ||||||||||||||||||||||||||
1,658 | 415 | (2 | ) | 15.00 | 12/20/15 | ||||||||||||||||||||||||||
James W. Whalen | 45,454 | 45,454 | (3 | ) | 3.00 | 11/01/15 | 101,139 | (6 | ) | 91,026 | 14,300 | 146,322 | |||||||||||||||||||
153,847 | 38,461 | (3 | ) | 15.00 | 11/01/15 | 1,110 | (5 | ) | 999 | ||||||||||||||||||||||
469 | 468 | (2 | ) | 3.00 | 12/20/15 | ||||||||||||||||||||||||||
1,597 | 399 | (2 | ) | 15.00 | 12/20/15 | ||||||||||||||||||||||||||
Michael A. Heim | 17,417 | 4,355 | (1 | ) | 0.75 | 10/31/15 | 122,336 | (4 | ) | 110,102 | 13,500 | 137,971 | |||||||||||||||||||
188,811 | 47,203 | (1 | ) | 3.00 | 10/31/15 | 1,153 | (5 | ) | 1,038 | ||||||||||||||||||||||
159,765 | 39,940 | (1 | ) | 15.00 | 10/31/15 | ||||||||||||||||||||||||||
1,949 | 486 | (2 | ) | 3.00 | 12/20/15 | ||||||||||||||||||||||||||
1,658 | 415 | (2 | ) | 15.00 | 12/20/15 |
__________
(1) | Represents options to purchase shares of Targa Investments common stock awarded on October 31, 2005. These 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 December 20, 2009. |
(3) | Represents options to purchase shares of Targa Investments common stock awarded on November 1, 2005. These options vest on November 1, 2009. |
(4) | Represents shares of restricted common stock of Targa Investments awarded on October 31, 2005. These shares vest on October 31, 2009. |
(5) | Represents shares of restricted common stock of Targa Investments awarded on December 20, 2005. These shares vest on December 20, 2009. |
(6) | Represents shares of restricted common stock of Targa Investments awarded on October 31, 2005 (544 shares) and November 1, 2005 (100,595 shares). These shares vest on October 31, 2009 (with respect to the October 31, 2005 awards) and November 1, 2009 (with respect to the November 1, 2005 awards). |
(7) | The dollar amounts shown are determined by multiplying the number of shares or units reported in the table by $0.90 (the value determined by an independent consultant pursuant to a valuation of Targa Investments’ common stock as of December 31, 2008, which management believes is a reasonable approximation of the value of such stock as of December 31, 2008. |
(8) | Represents the number of performance units awarded on February 8, 2007 and January 17, 2008 under the Targa Investments Long-Term Incentive Plan. These awards vest in August 2010 and June 2011, based on the Partnership’s performance over the applicable 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.” |
(9) | The dollar amounts shown are determined by multiplying the number of performance units reported in the table by the sum of the closing price of a common unit of the Partnership on December 31, 2008 ($7.75) and the related distribution equivalent rights for each award and assume full payout under the awards at the time of vesting. |
Option Exercises and Stock Vested in 2008
The following table provides the amount realized during 2008 by each named executive officer upon the exercise of options and upon the vesting of restricted common stock.
Option Exercises and Stock Vested for 2008 | ||||||||||||||||||
Option Awards | Stock Awards | |||||||||||||||||
Name | Number of Shares Acquired on Exercise(1) | Value Realized on Exercise | Number of Shares Acquired on Vesting | Value Realized on Vesting(6) | ||||||||||||||
Rene R. Joyce | 677,162 | (2 | ) | $ | 2,537,948 | |||||||||||||
Jeffrey J. McParland | 517,456 | (3 | ) | 1,937,667 | ||||||||||||||
Joe Bob Perkins | 578,065 | (4 | ) | 2,162,061 | ||||||||||||||
James W. Whalen | 137,772 | $ | 475,313 | 127,389 | (5 | ) | 700,227 | |||||||||||
Michael A. Heim | 578,065 | (4 | ) | 2,162,061 |
__________
(1) | At the time of exercise of the stock options, the common stock acquired upon exercise had a value of $3.45 per share. This value was determined by an independent consultant pursuant to a valuation of Targa Investments common stock as of October 24, 2007. |
(2) | The shares vested as follows: 67,288 shares on January 2, 2008, 16,822 shares on April 16, 2008, 513,939 shares on April 30, 2008, 4,981 shares on June 20, 2008, 73,420 shares on October 31, 2008 and 712 shares on December 20, 2008. |
(3) | The shares vested as follows: 55,272 shares on January 2, 2008, 13,818 shares on April 16, 2008, 388,584 shares on April 30, 2008, 3,736 shares on June 20, 2008, 55,512 shares on October 31, 2008 and 534 shares on December 20, 2008. |
(4) | The shares vested as follows: 67,288 shares on January 2, 2008, 16,822 shares on April 16, 2008, 428,176 shares on April 30, 2008, 4,035 shares on June 20, 2008, 61,168 shares on October 31, 2008 and 576 shares on December 20, 2008. |
(5) | The shares vested as follows: 20,112 shares on January 2, 2008, 5,028 shares on April 16, 2008, 544 shares on October 31, 2008, 100,595 shares on November 1, 2008, and 1,110 shares on December 20, 2008. |
(6) | The value realized on vesting used a per share price based on the estimated market price of Targa Investments common stock on such date. These values were determined by an independent consultant pursuant to valuations of Targa Investments common stock prepared at various times during 2007 and 2008, which management believes are reasonable approximations of the value of such stock as of the applicable dates. |
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 Investments’ 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 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 (as defined below)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 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 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, 2008.
Name | Change of Control | Termination for Death or Disability | ||||||||||
Rene R. Joyce | $ | 134,090 | (1 | ) | $ | 134,090 | (1 | ) | ||||
Jeffrey J. McParland | 101,535 | (2 | ) | 101,535 | (2 | ) | ||||||
Joe Bob Perkins | 111,793 | (3 | ) | 111,793 | (3 | ) | ||||||
James W. Whalen | 92,025 | (4 | ) | 92,025 | (4 | ) | ||||||
Michael A. Heim | 111,793 | (5 | ) | 111,793 | (5 | ) |
__________
(1) | Of this amount, $132,156 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $1,281 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; and $653 relates to the unvested options to purchase Targa Investments common stock granted on October 31, 2005. |
(2) | Of this amount, $99,922 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $960 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; and $653 relates to the unvested options to purchase Targa Investments common stock granted on October 31, 2005. |
(3) | Of this amount, $110,102 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $1,038 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; $653 relates to the unvested options to purchase Targa Investments common stock granted on October 31, 2005. |
(4) | Of this amount, $490 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $90,536 relates to the unvested shares of restricted stock of Targa Investments granted on November 1, 2005; and $999 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005. |
(5) | Of this amount, $110,102 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $1,038 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; and $653 relates to the unvested options to purchase Targa Investments common stock granted on October 31, 2005. |
Long Term Incentive Plan. If a Change of Control (as defined below) occurs during the performance period established for the performance units and related distribution equivalent rights granted to a named executive officer under Targa Investments’ form of Performance Unit Grant Agreement (a “Performance Unit Agreement”), the performance units and related distribution equivalent rights then credited to a named executive officer will be cancelled and the named executive officer will be paid an amount of cash equal to the sum of (i) the product of (a) the Fair Market Value (as defined below) of a common unit of the Partnership multiplied by (b) the number of performance units granted to the named executive officer, plus (ii) the amount of distribution equivalent rights then credited to the named executive officer, if any.
Performance units and the related distribution equivalent rights granted to a named executive officer under a Performance Unit Agreement will be automatically forfeited without payment upon the termination of his employment with Targa Investments and its affiliates, except that: (i) if his employment is terminated by reason of his death, a disability that entitles him to disability benefits under Targa Investments’ long-term disability plan or by Targa Investments’ other than for Cause (as defined below), he will be vested in his performance units that he is otherwise qualified to receive payment for based on achievement of the performance goal at the end of the Performance Period.
The following terms have the specified meanings for purposes of the Long-Term Incentive Plan:
• | Change of Control means (i) any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Exchange Act, other than an affiliate of Targa Investments, becoming the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Partnership or its general partner, (ii) the limited partners of the Partnership approving, in one or a series of transactions, a plan of complete liquidation of the Partnership, (iii) the sale or other disposition by either the Partnership or its general partner of all or substantially all of its assets in one or more transactions to any person other than the Partnership’s general partner or one of such general partner’s affiliates, or (iv) a transaction resulting in a person other than the Partnership’s general partner or one of such general partner’s affiliates being the general partner of the Partnership. With respect to an award subject to Section 409A of the Code, Change of Control will mean a “change of control event” as defined in the regulations and guidance issued under Section 409A of the Code. |
• | Fair Market Value means the closing sales price of a common unit of the Partnership on the principal national securities exchange or other market in which trading in such common units occurs on the applicable date (or if there is not trading in the common units on such date, on the next preceding date on which there was trading) as reported in The Wall Street Journal (or other reporting service approved by the TRII Compensation Committee). In the event the common units are not traded on a national securities exchange or other market at the time a determination of fair market value is required to be made, the determination of fair market value shall be made in good faith by the TRII Compensation Committee. |
• | Cause means (i) failure to perform assigned duties and responsibilities, (ii) engaging in conduct which is injurious (monetarily of otherwise) to Targa Investments or its affiliates, (iii) breach of any corporate policy or code of conduct established by Targa Investments or its affiliates or breach of any agreement between the named executive officer and Targa Investments or its affiliates, or (iv) conviction of a misdemeanor involving moral turpitude or a felony. If the named executive officer is a party to an agreement with Targa Investments or its affiliates in which this term is defined, then that definition will apply for purposes of the Long-Term Incentive Plan and the Performance Unit Agreement. |
The following table reflects payments that would have been made to each of the named executive officers under the Long-Term Incentive Plan and related agreements in the event there was a Change of Control or their employment was terminated, each as of December 31, 2008.
Name | Change of Control | Termination for Death or Disability | ||||||||||
Rene R. Joyce | $ | 194,962 | (1 | ) | $ | 194,962 | (1 | ) | ||||
Jeffrey J. McParland | 111,505 | (2 | ) | 111,505 | (2 | ) | ||||||
Joe Bob Perkins | 146,322 | (3 | ) | 146,322 | (3 | ) | ||||||
James W. Whalen | 146,322 | (3 | ) | 146,322 | (3 | ) | ||||||
Michael A. Heim | 137,971 | (4 | ) | 137,971 | (4 | ) |
_______
(1) | Of this amount, $116,250 and $40,332 relate to the performance units and related distribution equivalent rights granted on February 7, 2007, respectively; and $31,000 and $7,380 relate to the performance units and related distribution equivalent rights granted on January 17, 2008, respectively. |
(2) | Of this amount, $63,550 and $22,048 relate to the performance units and related distribution equivalent rights granted on February 7, 2007, respectively; and $20,925 and $4,982 relate to the performance units and related distribution equivalent rights granted on January 17, 2008, respectively. |
(3) | Of this amount, $83,700 and $29,039 relate to the performance units and related distribution equivalent rights granted on February 7, 2007, respectively; and $27,125 and $6,458 relate to the performance units and related distribution equivalent rights granted on January 17, 2008, respectively. |
(4) | Of this amount, $77,500 and $26,888 relate to the performance units and related distribution equivalent rights granted on February 7, 2007, respectively; and $27,125 and $6,458 relate to the performance units and related distribution equivalent rights granted on January 17, 2008, respectively. |
The following table reflects the aggregate payments that would have been made to each of the named executive officers under the 2005 Incentive Plan, the Long-Term Incentive Plan and related agreements in the event there was a Change of Control or their employment was terminated, each as of December 31, 2008.
Name | Change of Control | Termination for Death or Disability | ||||||
Rene R. Joyce | $ | 329,052 | $ | 329,052 | ||||
Jeffrey J. McParland | 213,040 | 213,040 | ||||||
Joe Bob Perkins | 258,115 | 258,115 | ||||||
James W. Whalen | 238,347 | 238,347 | ||||||
Michael A. Heim | 249,764 | 249,764 |
Director Compensation
The following table sets forth the compensation earned by our non-employee directors for 2008:
Name | Fees Earned or Paid in Cash | Stock Awards ($)(1) | Option Awards ($)(2) | All Other Compensation(6) | Total Compensation | |||||||||||||||
Charles R. Crisp (3)(5) | $ | 47,500 | $ | 46,642 | $ | 786 | $ | 6,585 | $ | 101,513 | ||||||||||
Joe B. Foster (3)(5) | 46,000 | 46,642 | 786 | 6,585 | 100,013 | |||||||||||||||
In Seon Hwang | - | - | - | - | - | |||||||||||||||
Chansoo Joung (3)(4)(5) | - | - | - | - | - | |||||||||||||||
Peter R. Kagan (3)(4)(5) | - | - | - | - | - | |||||||||||||||
Chris Tong (3)(5) | 64000 | 45378 | 1350 | 6,585 | 117,313 |
__________
(1) | Amounts represent expense recognized for financial statement reporting purposes in accordance with SFAS 123(R) with respect to stock awards for fiscal year 2008, disregarding any estimate of forfeitures related to service-based vesting conditions. No stock awards granted to the directors were forfeited during 2008. For a discussion of the assumptions and methodologies used to value the awards reported in these columns, see the discussion of stock awards contained in the Notes to Consolidated Financial Statements at Note 12 included in this annual report. |
(2) | Amounts represent expense recognized for financial statement reporting purposes in accordance with SFAS 123(R) with respect to option awards for fiscal year 2008, disregarding any estimate of forfeitures related to service-based vesting conditions. No option awards granted to the directors were forfeited during 2008. For a discussion of the assumptions and methodologies used to value the awards reported in these columns, see the discussion of stock awards contained in the Notes to Consolidated Financial Statements at Note 12 included in this annual report. |
(3) | On March 25, 2008 Messrs. Crisp, Foster and Tong each received 2,000 common units of the Partnership in connection with their service on the Targa Board and Messrs. Joung and Kagan each received 2,000 common units of the Partnership 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 these named individuals was $22.86, based on the closing price of the common units on the day prior to the grant date. During 2008, each of the directors received $6,585 in distributions on the common units of the Partnership that were awarded to them. The Partnership also recognized $6,585 of expense for each of the stock awards held by Messrs. Joung and Kagan. |
(4) | Messrs. Joung and Kagan each earned $49,000 in fees for service on the board of directors of the Partnership’s general partner. |
(5) | At December 31, 2008, Mr. Crisp held 9,709 shares of preferred stock, 153,799 shares of common stock, 87,018 options to purchase shares of common stock and 5,100 common units of the Partnership. At December 31, 2008, 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 8,700 common units of the Partnership. At December 31, 2008, Mr. Tong held 89,358 shares of common stock, 51,672 options to purchase shares of common stock and 146,900 common units of the Partnership. At December 31, 2008, Mr. Joung and Kagan each held 4,000 common units of the Partnership. |
(6) | For 2008 “All Other Compensation” consists of the distributions paid on common units of the Partnership from unit awards. |
Narrative to Director Compensation Table
For 2008, each independent director (other than the Warburg Pincus 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 Pincus directors) receive $1,500 for each Board, Audit Committee and Compensation Committee meeting attended. 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 Pincus 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
Director Long-term Equity Incentives. The Partnership made equity-based awards in March 2008 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 2009
Director Long-term Equity Incentives. In January 2009, each of the General Partners’ nonmanagement and independent directors received an award of 4,000 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. 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 the equity securities of our subsidiaries as of February 25, 2009 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. |
Targa Resources, Inc. | Targa Resources Partners LP | Targa Resources Investments Inc. | ||||||||||||||||||||||||||||||||||||||||||||
Name of Beneficial Owner (1) | Common Stock Beneficially Owned | Percentage of Common Stock Beneficially Owned | Common Units Beneficially Owned | Percentage of Common Units Beneficially Owned | Subordinated Units Beneficially Owned (3) | Percentage of Subordinated Units Beneficially Owned | Percentage of Total Common and Subordinated Units Beneficially Owned | Series B Preferred Stock | Restricted Common Stock | Percentage of Series B Preferred Stock Beneficially Owned | Percentage of Restricted Common Stock Beneficially Owned | |||||||||||||||||||||||||||||||||||
Targa Resources Investments Inc. | 1,000 | 100 | % | - | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||||||
Rene R. Joyce | - | - | 81,000 | * | 294,107 | 2.55 | % | * | 56,208 | 1,277,634 | (4 | ) | * | 15.9 | % | |||||||||||||||||||||||||||||||
Joe Bob Perkins | - | - | 32,100 | * | 247,672 | 2.15 | % | * | 47,632 | 1,071,154 | (5 | ) | * | 13.5 | % | |||||||||||||||||||||||||||||||
Michael A. Heim | - | - | 8,000 | * | 234,164 | 2.03 | % | * | 39,192 | 1,071,154 | (5 | ) | * | 13.5 | % | |||||||||||||||||||||||||||||||
Jeffrey J. McParland | - | - | 16,500 | * | 208,398 | 1.81 | % | * | 32,856 | 973,056 | (6 | ) | * | 12.3 | % | |||||||||||||||||||||||||||||||
James W. Whalen | - | - | 111,152 | * | 164,483 | 1.43 | % | * | 14,978 | 875,525 | (7 | ) | * | 11.3 | % | |||||||||||||||||||||||||||||||
Charles R Crisp | - | - | 9,100 | * | 46,186 | * | * | 9,709 | 190,151 | (8 | ) | * | 2.5 | % | ||||||||||||||||||||||||||||||||
Joe B. Foster | - | - | 12,700 | * | 76,512 | * | * | 28,591 | 190,151 | (9 | ) | * | 2.5 | % | ||||||||||||||||||||||||||||||||
In Seon Hwang (2) | - | - | - | * | - | * | * | - | - | - | - | |||||||||||||||||||||||||||||||||||
Chansoo Joung (2) | - | - | 8,000 | * | - | * | * | - | - | - | - | |||||||||||||||||||||||||||||||||||
Peter R. Kagan (2) | - | - | 8,000 | * | - | * | * | - | - | - | - | |||||||||||||||||||||||||||||||||||
Chris Tong | - | - | 20,900 | * | 18,318 | * | * | - | 113,903 | (10 | ) | - | 1.5 | % | ||||||||||||||||||||||||||||||||
All directors and executive officers as a group (13 persons) | - | - | 334,952 | * | 1,683,922 | 14.61 | % | 4.37 | % | 279,414 | 7,720,957 | (11 | ) | 4.4 | % | 76.6 | % |
______________________
* 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., a Delaware limited partnership, and two affiliated partnerships (“WP VIII”), and Warburg Pincus Private Equity IX, L.P., a Delaware limited partnership (“WP IX”), in the aggregate own approximately 74% of Targa Resources Investments Inc. The general partner of WP VIII is Warburg Pincus Partners, LLC, a New York limited liability company (“WP Partners LLC”) and the general partner of WP IX is Warburg Pincus IX, LLC, a New York limited liability company, of which WP Partners LLC is the sole member. Warburg Pincus & Co., a New York general partnership (“WP”) is the managing member of WP Partners LLC. WP VIII and WP IX are managed by Warburg Pincus LLC, a New York limited liability company (“WP LLC”). The address of the Warburg Pincus entities is 466 Lexington Avenue, New York, New York 10017. Messrs. Kagan , and Joung, directors of Targa Resources Partners LP, are Partners of WP and Managing Directors and Members of WP LLC. Charles R. Kaye and Joseph P. Landy are Managing General Partners of WP and Managing Members and Co-Presidents of WP LLC and may be deemed to control the Warburg Pincus entities. Messrs. Joung, Kagan, 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. |
(4) | Of this amount, 452,209 shares of restricted common stock reflect options that are currently exercisable for shares of restricted common stock. |
(5) | Of this amount, 369,600 shares of restricted common stock reflect options that are currently exercisable for shares of restricted common stock. |
(6) | Of this amount, 343,509 shares of restricted common stock reflect options that are currently exercisable for shares of restricted common stock. |
(7) | Of this amount, 201,367 shares of restricted common stock reflect options that are currently exercisable for shares of restricted common stock. |
(8) | Of this amount, 36,352 shares of restricted common stock reflect options that are currently exercisable for shares of restricted common stock. |
(9) | Of this amount, 69,616 shares of restricted common stock reflect options that are currently exercisable for shares of restricted common stock. |
(10) | Of this amount, 24,545 shares of restricted common stock reflect options that are currently exercisable for shares of restricted common stock. |
(11) | Of this amount, 2,515,656 shares of restricted common stock reflect options that are currently exercisable for shares of restricted common stock. |
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 Pincus nominees or three individuals if there are only three Warburg Pincus 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.
Chansoo Joung and Peter Kagan, two of our directors, are Members and Managing Directors of Warburg Pincus and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from which we buy natural gas and NGL products. Affiliates of Warburg Pincus own a controlling interest in Broad Oak. We had $4.8 million of natural gas and NGL product purchases from Broad Oak during 2008. We had no commercial transactions with Broad Oak prior to 2008. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.
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.
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 MLCI floating prices based on published index prices of such commodities for delivery at specified locations. The following table shows our open commodity derivatives with MLCI as of December 31, 2008:
Period | Commodity | Daily Volumes | Average Price | Index | ||||||||
Jan 2009 - Dec 2009 | Natural gas | 21,918 | MMBtu | $ | 6.62 | per MMBtu | IF-Waha | |||||
Jan 2009 - Dec 2009 | NGL | 2,847 | Bbl | 0.74 | per gallon | OPIS-MB |
Period | Commodity | Daily Volumes | Average Price | Index | ||||||||
Jan 2009 - Dec 2009 | Natural gas | 3,556 | MMBtu | $ | 8.07 | per MMBtu | IF-Waha | |||||
Jan 2009 - Dec 2009 | Natural gas | 575 | MMBtu | 7.83 | per MMBtu | NY-HH | ||||||
Jan 2010 - Dec 2010 | Natural gas | 3,289 | MMBtu | 7.39 | per MMBtu | IF-Waha | ||||||
Jan 2010 - Dec 2010 | Natural gas | 247 | MMBtu | 8.17 | per MMBtu | NY-HH | ||||||
Jan 2009 - Dec 2009 | NGL | 3,000 | Bbl | 1.18 | per gallon | OPIS-MB | ||||||
Jan 2009 - Dec 2009 | Condensate | 202 | Bbl | 70.60 | per barrel | NY-WTI | ||||||
Jan 2010 - Dec 2010 | Condensate | 181 | Bbl | 69.28 | per barrel | NY-WTI |
As of December 31, 2008, the aggregate fair value of these derivatives was an asset of $49.3 million. During 2008, we paid MLCI $39.4 million in commodity derivative settlements. During 2007, we paid MLCI $16.1 million in commodity derivative settlements. During 2006, MLCI paid us $11.0 million in commodity derivative settlements.
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. For the years 2008, 2007 and 2006, our revenue from product sales to MLCI totaled $97.0 million, $81.2 million and 78.1 million. For the same periods, we had product purchases from MLCI were $5.1 million, $12.1 million and $15.2 million.
Relationships with Noble Energy
Chris Tong, one of our directors, is Senior Vice President and Chief Financial Officer of Noble Energy, Inc. (“Noble”). During 2008, 2007 and 2006, our net purchases of natural gas and NGL products from Noble totaled $3.8 million, $0.3 million and $1.9 million. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.
Transactions with unconsolidated affiliates
For the years indicated, our natural gas and NGL sales and purchases with our unconsolidated affiliates were:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Included in Revenues | ||||||||||||
GCF | $ | 469 | $ | 4,514 | $ | 1,366 | ||||||
VESCO (1) | 690 | 4,771 | 2,628 | |||||||||
$ | 1,159 | $ | 9,285 | $ | 3,994 | |||||||
Included in Costs and Expenses | ||||||||||||
GCF | $ | 3,501 | $ | 3,316 | $ | 3,336 | ||||||
VESCO (1) | 178,098 | 145,806 | 132,798 | |||||||||
$ | 181,599 | $ | 149,122 | $ | 136,134 |
(1) For 2008, our commercial transactions with VESCO are reflected through July 31, 2008. As a result of acquiring an additional ownership in VESCO, they are no longer considered an unconsolidated affiliate and we have consolidated the operations of VESCO in our financial results with effect from August 1, 2008.
These transactions were at market prices consistent with similar transactions with nonaffiliated entities.
Initial Public Offering of Partnership
On February 14, 2007, the Partnership completed its initial public offering (the “IPO”) and borrowed $294.5 million under the newly established Partnership’s 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 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 and (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 (ending February 2010), 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.
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 a 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 System 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.
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.
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 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. See “Certain Relationships and Related Transactions, and Director Independence —Relationships with Warburg Pincus” for a discussion of Warburg Pincus’ relationships with us in this “Item 13.”
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:
Year Ended December 31, | ||||||||
2008 | 2007 | |||||||
(In thousands) | ||||||||
Audit Fees (1) | $ | 5,129.1 | $ | 6,707.7 | ||||
Tax Fees (2) | 534.2 | 303.8 | ||||||
All Other Fees (3) | 7.2 | 4.3 | ||||||
$ | 5,670.5 | $ | 7,015.8 |
________
(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) | 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. |
(3) | 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 has approved the use of PricewaterhouseCoopers as our independent principal accountant.
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, see “ Index to Financial Statements ” on page F-1 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
3.1 | Amended and Restated Certificate of Incorporation of Targa Resources, Inc. (incorporated by reference to Exhibit 3.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.2 | Amended and Restated Bylaws of Targa Resources, Inc. (incorporated by reference to Exhibit 3.2 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.3 | Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.3 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.4 | Certificate of Amendment of the Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.4 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.5 | Bylaws of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.5 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
4.1 | Indenture dated October 31, 2005 among Targa Resources, Inc., Targa Resources Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.3 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
4.2 | Supplemental Indenture dated October 31, 2008, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Quarterly Report on Form 10-Q filed November 12. 2008 (File No. 333-147066)). |
4.3* | Supplemental Indenture dated February 14, 2007, among Targa Resources GP LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. |
4.4* | Supplemental Indenture dated March 15, 2006, among Targa LSNG GP LLC and Targa LSNG LP, subsidiaries of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. |
4.5* | Supplemental Indenture dated December 22, 2005, among Targa GP Inc., Targa LP Inc., Targa North Texas GP LLC, Targa Versado GP LLC, Targa Straddle GP LLC, Targa Permian GP LLC, Targa Downstream GP LLC, Targa North Texas LP, Targa Versado LP, Targa Straddle LP, Targa Permian LP, and Targa Downstream LP, subsidiaries of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. |
4.6* | Supplemental Indenture dated December 14, 2005, among Targa Gas Marketing LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. |
4.7 | Registration Rights Agreement, dated as of October 31, 2005, among Targa Resources, Inc., Targa Resources Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.4 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
4.8 | Indenture dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Form 10-Q filed August 11, 2008 (File No. 333-147066)). |
4.9 | Registration Rights Agreement dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporations, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources, Inc.’s Quarterly Report on Form 10-Q filed August 11, 2008 (File No. 333-147066)). |
10.1 | Credit Agreement dated October 31, 2005 between Targa Resources Inc., the Lenders named therein and Credit Suisse, as Administrative Agent, Swing Line Lender, Revolving L/C Issuer and Synthetic L/C Issuer (incorporated by reference to Exhibit 10.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
10.2 | Targa Resources Investments Inc. Amended and Restated Stockholders’ Agreement dated as of October 31, 2005 (incorporated by reference to Exhibit 10.2 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.3 | First Amendment to Amended and Restated Stockholders’ Agreement, dated January 26, 2006 (incorporated by reference to Exhibit 10.3 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.4 | Second Amendment to Amended and Restated Stockholders’ Agreement dated March 30, 2007 (incorporated by reference to Exhibit 10.4 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.5 | Third Amendment to Amended and Restated Stockholders’ Agreement dated May 1, 2007 (incorporated by reference to Exhibit 10.5 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.6 | Fourth Amendment to Amended and Restated Stockholders’ Agreement dated December 7, 2007 (incorporated by reference to Exhibit 10.6 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.7+ | Targa Resources, Inc. 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.7 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.8+ | Amendment to and Assumption of Targa Resources, Inc. 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.8 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.9+ | Amendment to Targa Resources, Inc. 2004 Stock Incentive Plan (as Assumed and Amended) (incorporated by reference to Exhibit 10.9 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.10+ | Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.10 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.11+ | First Amendment to Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.11 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.12+ | Second Amendment to Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.12 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.13+ | Form of Targa Resources Investments Inc. Nonstatutory Stock Option Agreement (Non-Employee Director) (incorporated by reference to Exhibit 10.13 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.14+ | Form of Targa Resources Investments Inc. Nonstatutory Stock Option Agreement (Non-Director Management and Other Employees) (incorporated by reference to Exhibit 10.14 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.15+ | Form of Targa Resources Investments Inc. Incentive Stock Option Agreement (incorporated by reference to Exhibit 10.15 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.16+ | Form of Targa Resources Investments Inc. Restricted Stock Agreement (incorporated by reference to Exhibit 10.16 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.17+ | Form of Targa Resources Investments Inc. Restricted Stock Agreement (relating to preferred stock option exchange for directors) (incorporated by reference to Exhibit 10.17 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.18+ | Form of Targa Resources Investments Inc. Restricted Stock Agreement (relating to preferred stock option exchange for employees) (incorporated by reference to Exhibit 10.18 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.19+ | Targa Resources, Inc. Bonus Plan (incorporated by reference to Exhibit 10.19 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.20+ | Form of Targa Resources, Inc. Bonus Agreement (for directors) (incorporated by reference to Exhibit 10.20 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.21+ | Form of Targa Resources, Inc. Bonus Agreement (for executives) (incorporated by reference to Exhibit 10.21 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.22+ | Targa Resources Investments Inc. Change of Control Executive Officer Severance Program (incorporated by reference to Exhibit 10.22 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.23+ | Targa Resources, Inc. 2008 Annual Incentive Plan (incorporated by reference to Exhibit 10.25 to Targa Resources, Inc.’s Annual Report on Form 10-K filed March 31, 2008 (File No. 333-147006)). |
10.24+* | Targa Resources, Inc. 2009 Annual Incentive Plan |
10.25+ | Targa Resources Partners LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.25 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.26+* | Amendment to Targa Resources Partners LP Long-Term Incentive Plan dated December 18, 2008. |
10.27+ | Form of Restricted Unit Grant Agreement (incorporated by reference to Exhibit 10.26 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.28+ | Targa Resources Investments Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.27 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.29+ | Form of Performance Unit Grant Agreement (incorporated by reference to Exhibit 10.2 .to Targa Resources, Inc.’s Current Report on Form 8-K filed January 28, 2009 (File No. 333-147066)). |
10.30 | Credit Agreement, dated February 14, 2007, by and among Targa Resources Partners LP, as Borrower, Bank of America, N.A., as Administrative Agent, Wachovia Bank, N.A., as Syndication Agent, Merrill Lynch Capital, Royal Bank of Canada and The Royal Bank of Scotland PLC, as Co-Documentation Agents, and the other lenders part thereto (incorporated by reference to Exhibit 10.29 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.31 | First Amendment to Credit Agreement dated October 24, 2007 by and among Targa Resources Partners LP, as Borrower, Bank of America, N.A., as Administrative Agent, Collateral Agent, Swing Line Lender and L/C Issuer and the other lenders party thereto (incorporated by reference to Exhibit 10.30 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.32 | Commitment Increase Supplement made as of October 24, 2007 by and among Targa Resources Partners LP, Bank of America, N.A., as Administrative Agent, Collateral Agent, Swing Line Lender and L/C Issuer and the other parties thereto (incorporated by reference to Exhibit 10.31 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.33 | Commitment Increase Supplement, dated June 18, 2008, by and among Targa Resources Partners LP, Bank of America, N.A. and other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources, Inc.’s Quarterly Report on Form 10-Q filed August 11, 2008 (File No. 333-147066)). |
10.34* | Amended and Restated Omnibus Agreement, dated October 24, 2007, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC. |
21.1* | Subsidiaries of Targa Resources, Inc. |
____
+ Management contract or compensation plan or arrangement. |
* Filed herewith. |
SIGNATURES |
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: February 26, 2009
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 February 26, 2009.
Signature | Title | |
/s/ RENE R. JOYCE Rene R. Joyce | Chief Executive Officer and Director (Principal Executive Officer) | |
/s/ JEFFREY J. MCPARLAND Jeffrey J. McParland | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | |
/s/ JOHN ROBERT SPARGER John Robert Sparger | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | |
/s/ CHARLES R. CRISP Charles R. Crisp | Director | |
/s/ JOE B. FOSTER Joe B. Foster | Director | |
/s/ IN SEON HWANG In Seon Hwang | Director | |
/s/ CHANSOO JOUNG Chansoo Joung | Director | |
/s/ PETER R. KAGAN Peter R. Kagan | Director | |
/s/ CHRIS TONG Chris Tong | Director | |
/s/ JAMES W. WHALEN James W. Whalen | Director |
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, 2008 or proxy materials relating to an annual or other meeting of security holders to our security holder.
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F-44 |
To the Stockholder 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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
Houston, Texas
February 25, 2009
December 31, | ||||||||
2008 | 2007 | |||||||
(In thousands) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 362,769 | $ | 177,949 | ||||
Trade receivables, net of allowances of $9,380 and $1,115 | 303,904 | 836,044 | ||||||
Inventory | 68,519 | 143,185 | ||||||
Deferred income taxes | - | 25,071 | ||||||
Assets from risk management activities | 112,341 | 9,487 | ||||||
Other current assets | 9,615 | 70,640 | ||||||
Total current assets | 857,148 | 1,262,376 | ||||||
Property, plant and equipment, at cost | 3,093,264 | 2,764,230 | ||||||
Accumulated depreciation | (475,895 | ) | (334,160 | ) | ||||
Property, plant and equipment, net | 2,617,369 | 2,430,070 | ||||||
Unconsolidated investments | 18,465 | 48,005 | ||||||
Long-term assets from risk management activities | 89,774 | 4,279 | ||||||
Investment in debt obligations of Targa Resources Investments Inc. | 10,953 | - | ||||||
Other assets | 54,868 | 45,235 | ||||||
Total assets | $ | 3,648,577 | $ | 3,789,965 | ||||
LIABILITIES AND STOCKHOLDER'S EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | 153,756 | $ | 470,860 | |||||
Accrued liabilities | 253,384 | 379,245 | ||||||
Current maturities of debt | 12,500 | 12,500 | ||||||
Liabilities from risk management activities | 11,664 | 75,568 | ||||||
Deferred income taxes | 36,240 | - | ||||||
Total current liabilities | 467,544 | 938,173 | ||||||
Long-term debt, less current maturities | 1,552,440 | 1,398,475 | ||||||
Long-term liabilities from risk management activities | 9,679 | 81,019 | ||||||
Deferred income taxes | 40,027 | 29,501 | ||||||
Other long-term obligations | 49,638 | 35,267 | ||||||
Minority interest | 126,685 | 100,826 | ||||||
Non-controlling interest in Targa Resources Partners LP | 822,923 | 714,300 | ||||||
Commitments and contingencies (see Note 15) | ||||||||
Stockholder's equity: | ||||||||
Common stock ($0.001 par value, 1,000 shares authorized, issued, | ||||||||
and outstanding at December 31, 2008 and 2007, | ||||||||
collateral for Targa Resources Investments Inc. debt, see Note 10) | - | - | ||||||
Additional paid-in capital | 420,067 | 473,784 | ||||||
Retained earnings | 127,640 | 74,736 | ||||||
Accumulated other comprehensive income (loss) | 31,934 | (56,116 | ) | |||||
Total stockholder's equity | 579,641 | 492,404 | ||||||
Total liabilities and stockholder's equity | $ | 3,648,577 | $ | 3,789,965 | ||||
See notes to consolidated financial statements |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Revenues | $ | 7,970,167 | $ | 7,269,660 | $ | 6,132,881 | ||||||
Costs and expenses: | ||||||||||||
Product purchases | 7,189,811 | 6,497,983 | 5,440,832 | |||||||||
Operating expenses | 275,202 | 247,066 | 224,169 | |||||||||
Depreciation and amortization expense | 160,948 | 148,101 | 149,687 | |||||||||
General and administrative expense | 95,898 | 96,053 | 82,182 | |||||||||
Casualty loss | 19,310 | - | - | |||||||||
Loss (gain) on sale of assets | (5,936 | ) | (99 | ) | 169 | |||||||
7,735,233 | 6,989,104 | 5,897,039 | ||||||||||
Income from operations | 234,934 | 280,556 | 235,842 | |||||||||
Other income (expense): | ||||||||||||
Interest expense, net | (102,030 | ) | (142,632 | ) | (180,189 | ) | ||||||
Equity in earnings of unconsolidated investments | 14,039 | 10,108 | 9,968 | |||||||||
Gain on insurance claims | 18,566 | - | - | |||||||||
Gain on debt extinguishment | 13,061 | - | - | |||||||||
Loss on mark-to-market derivative instruments | (1,311 | ) | - | - | ||||||||
Minority interest | (33,110 | ) | (28,713 | ) | (25,998 | ) | ||||||
Non-controlling interest in Targa Resources Partners LP | (64,916 | ) | (19,416 | ) | - | |||||||
Income before income taxes | 79,233 | 99,903 | 39,623 | |||||||||
Income tax expense: | ||||||||||||
Current | (1,245 | ) | (175 | ) | (34 | ) | ||||||
Deferred | (25,084 | ) | (31,156 | ) | (16,175 | ) | ||||||
(26,329 | ) | (31,331 | ) | (16,209 | ) | |||||||
Net income | $ | 52,904 | $ | 68,572 | $ | 23,414 | ||||||
See notes to consolidated financial statements |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Net income | $ | 52,904 | $ | 68,572 | $ | 23,414 | ||||||
Other comprehensive income (loss): | ||||||||||||
Commodity hedging contracts: | ||||||||||||
Change in non-controlling partners' share of other | ||||||||||||
comprehensive income of Targa Resources Partners LP | 120,343 | 54,415 | - | |||||||||
Change in fair value | (34,123 | ) | (200,821 | ) | 120,283 | |||||||
Reclassification adjustment for settled periods | 65,125 | (4,126 | ) | (31,243 | ) | |||||||
Related income taxes | (54,892 | ) | 58,594 | (35,376 | ) | |||||||
Interest rate swaps: | ||||||||||||
Change in non-controlling partners' share of other | ||||||||||||
comprehensive income of Targa Resources Partners LP | (12,019 | ) | 906 | - | ||||||||
Change in fair value | 5,002 | (473 | ) | 2,606 | ||||||||
Reclassification adjustment for settled periods | 2,693 | (2,191 | ) | (1,005 | ) | |||||||
Related income taxes | 1,463 | 699 | (639 | ) | ||||||||
Available for sale securities: | ||||||||||||
Change in fair value | (6,700 | ) | - | - | ||||||||
Related income taxes | 2,286 | - | - | |||||||||
Foreign currency items: | ||||||||||||
Foreign currency translation adjustment | (1,820 | ) | 1,925 | 59 | ||||||||
Related income taxes | 692 | (727 | ) | (21 | ) | |||||||
Other comprehensive income (loss) | 88,050 | (91,799 | ) | 54,664 | ||||||||
Comprehensive income (loss) | $ | 140,954 | $ | (23,227 | ) | $ | 78,078 | |||||
See notes to consolidated financial statements |
Accumulated | ||||||||||||||||||||||
Additional | Other | |||||||||||||||||||||
Common Stock | Paid-in | Retained | Comprehensive | |||||||||||||||||||
Shares | Amount | Capital | Earnings (Deficit) | Income (Loss) | Total | |||||||||||||||||
(In thousands) | ||||||||||||||||||||||
Balance, December 31, 2005 | 1 | $ | - | $ | 470,608 | $ | (17,250 | ) | $ | (18,981 | ) | $ | 434,377 | |||||||||
Distributions to parent | - | - | (969 | ) | - | - | (969 | ) | ||||||||||||||
Tax benefit on vesting of common stock | - | - | 7 | - | - | 7 | ||||||||||||||||
Contribution of noncash compensation | - | - | 2,777 | - | - | 2,777 | ||||||||||||||||
Other comprehensive income | - | - | - | - | 54,664 | 54,664 | ||||||||||||||||
Net income | - | - | - | 23,414 | - | 23,414 | ||||||||||||||||
Balance, December 31, 2006 | 1 | - | 472,423 | 6,164 | 35,683 | 514,270 | ||||||||||||||||
Distributions to parent | - | - | (991 | ) | - | - | (991 | ) | ||||||||||||||
Contribution of noncash compensation | - | - | 2,040 | - | - | 2,040 | ||||||||||||||||
Tax benefit on vesting of common stock | - | - | 312 | - | - | 312 | ||||||||||||||||
Other comprehensive loss | - | - | - | - | (91,799 | ) | (91,799 | ) | ||||||||||||||
Net income | - | - | - | 68,572 | - | 68,572 | ||||||||||||||||
Balance, December 31, 2007 | 1 | - | 473,784 | 74,736 | (56,116 | ) | 492,404 | |||||||||||||||
Distributions to parent | - | - | (53,861 | ) | - | - | (53,861 | ) | ||||||||||||||
Amortization of equity awards | - | - | 1,191 | - | - | 1,191 | ||||||||||||||||
Tax expense on vesting of common stock | - | - | (1,047 | ) | - | - | (1,047 | ) | ||||||||||||||
Other comprehensive income | - | - | - | - | 88,050 | 88,050 | ||||||||||||||||
Net income | - | - | - | 52,904 | - | 52,904 | ||||||||||||||||
Balance, December 31, 2008 | 1 | $ | - | $ | 420,067 | $ | 127,640 | $ | 31,934 | $ | 579,641 | |||||||||||
See notes to consolidated financial statements |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Cash flows from operating activities | ||||||||||||
Net income | $ | 52,904 | $ | 68,572 | $ | 23,414 | ||||||
Adjustments to reconcile net income to net cash provided | ||||||||||||
by operating activities: | ||||||||||||
Amortization in interest expense | 8,351 | 12,872 | 13,001 | |||||||||
Interest income on paid-in-kind investment | (953 | ) | - | - | ||||||||
Amortization in general and administrative expense | 1,471 | 2,220 | 2,777 | |||||||||
Depreciation and amortization expense | 160,948 | 148,101 | 149,687 | |||||||||
Accretion of asset retirement obligations | 1,943 | 987 | 888 | |||||||||
Deferred income tax expense | 25,084 | 31,156 | 16,175 | |||||||||
Equity in earnings of unconsolidated investments, net of distributions | (9,389 | ) | (6,233 | ) | (7,662 | ) | ||||||
Minority interest expense, net of distributions | (1,485 | ) | (702 | ) | (11,186 | ) | ||||||
Non-controlling interest in the Partnership, net of income distributions | 989 | - | - | |||||||||
Risk management activities | (64,532 | ) | (39,024 | ) | (24,618 | ) | ||||||
Loss (gain) on sale of assets | (5,936 | ) | (99 | ) | 169 | |||||||
Gain on debt extinguishment | (13,061 | ) | - | - | ||||||||
Gain on property damage insurance settlement (See Note 11) | (18,566 | ) | - | - | ||||||||
Asset impairment charges | 5,112 | - | - | |||||||||
Changes in operating assets and liabilities, net of assets acquired: | ||||||||||||
Accounts receivable and other assets | 601,652 | (335,754 | ) | (2,912 | ) | |||||||
Inventory | 72,826 | (26,229 | ) | 36,510 | ||||||||
Accounts payable and other liabilities | (516,696 | ) | 286,735 | 37,043 | ||||||||
Net cash provided by operating activities | 300,662 | 142,602 | 233,286 | |||||||||
Cash flows from investing activities | ||||||||||||
Purchases of property, plant and equipment | (132,289 | ) | (118,421 | ) | (136,325 | ) | ||||||
Acquisitions, net of cash acquired | (124,938 | ) | - | (340 | ) | |||||||
Proceeds from property insurance | 48,294 | 24,900 | 27,221 | |||||||||
Investment in debt obligations of Targa Investments | (16,400 | ) | - | - | ||||||||
Investment in unconsolidated affiliates | - | (4,648 | ) | (9,102 | ) | |||||||
Other | 2,201 | 2,280 | 734 | |||||||||
Net cash used in investing activities | (223,132 | ) | (95,889 | ) | (117,812 | ) | ||||||
Cash flows from financing activities | ||||||||||||
Senior secured credit agreement: | ||||||||||||
Borrowings under credit facility | 95,920 | - | - | |||||||||
Repayments of senior secured debt | (12,500 | ) | (1,399,700 | ) | (12,500 | ) | ||||||
Senior secured credit facility of the Partnership: | ||||||||||||
Borrowings | 185,265 | 721,300 | - | |||||||||
Repayments | (323,800 | ) | (95,000 | ) | - | |||||||
Proceeds from issuance of senior notes of the Partnership | 250,000 | - | - | |||||||||
Repurchases of senior notes of the Partnership | (26,832 | ) | - | - | ||||||||
Distribution to non-controlling interest in the Partnership | ||||||||||||
in excess of cumulative earnings | - | (1,455 | ) | - | ||||||||
Contribution from non-controlling interest in the Partnership | - | 771,834 | - | |||||||||
Contribution from minority interest | 300 | - | - | |||||||||
Distribution to Targa Resources Investments Inc. | (53,861 | ) | (991 | ) | (969 | ) | ||||||
Costs incurred in connection with financing arrangements: | (7,202 | ) | (7,491 | ) | (693 | ) | ||||||
Net cash provided by (used in) financing activities | 107,290 | (11,503 | ) | (14,162 | ) | |||||||
Net increase in cash and cash equivalents | 184,820 | 35,210 | 101,312 | |||||||||
Cash and cash equivalents, beginning of year | 177,949 | 142,739 | 41,427 | |||||||||
Cash and cash equivalents, end of year | $ | 362,769 | $ | 177,949 | $ | 142,739 | ||||||
See notes to consolidated financial statements |
TARGA RESOURCES, INC.
NOTES TO 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.
Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of NGLs. See Note 19.
Basis of Presentation
The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2008 and 2007, and the results of our operations, cash flows and changes in stockholder’s equity for the years ended December 31, 2008, 2007 and 2006.
Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the previous years to conform to the 2008 presentation. These reclassifications do not affect net income.
We currently own approximately 26.5% of Targa Resources Partners LP (the “Partnership”), including our 2% general partner interest. Targa Resources GP LLC, the general partner of the Partnership, is wholly owned by us. The Partnership is consolidated within our Gas Gathering and Processing segment.
The non-controlling interest in the Partnership on our consolidated balance sheets represents the investment by partners other than us., including those partners’ share of the net income, distributions and accumulated other comprehensive income (loss) of the Partnership. 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 (“AROs”) 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, we record 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 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 us at either the recorded amount or we will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost.
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. As of December 31, 2008 and 2007, accounts payable included approximately $10.5 million and $21.2 million of outstanding checks that were reclassed from cash and cash equivalents.
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 us to concentrations of credit risk consist primarily of trade accounts receivable and commodity derivative instruments.
Trade Accounts Receivable. 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 an allowance for doubtful accounts may be required.
The following table presents the activity of our allowance for doubtful accounts for the periods indicated:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Balance at beginning of year | $ | 1,115 | $ | 781 | $ | 1,641 | ||||||
Additions | 8,226 | 415 | 546 | |||||||||
Acquisition-related additions | 39 | - | - | |||||||||
Deductions | - | (81 | ) | (1,406 | ) | |||||||
Balance at end of year | $ | 9,380 | $ | 1,115 | $ | 781 |
Commodity Derivative Instruments
As of December 31, 2008, affiliates of Goldman Sachs, Merrill Lynch and Barclays Bank accounted for 58%, 25% and 16% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, Merrill Lynch and Barclays Bank are major financial institutions, each possessing investment grade credit ratings, based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.
Significant Commercial Relationships
The following table lists the percentage of our consolidated sales and purchases with Chevron Corporation (“Chevron”) (including the Chevron Phillips Chemical Company LLC joint venture (“CPC”)), which accounted for more than 10% of our consolidated revenues and consolidated product purchases for the years indicated:
2008 | 2007 | 2006 | ||||||||||
% of consolidated revenues: | ||||||||||||
Chevron and CPC | 22 | % | 26 | % | 28 | % | ||||||
% of consolidated product purchases: | ||||||||||||
Chevron and CPC | 9 | % | 13 | % | 20 | % |
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.
Earnings per Share. Our capital stock consists of one thousand shares of common stock, owned by a subsidiary of Targa Investments. 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 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 an-other-than-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 decline in value of an investment is other than temporary, we would record a charge to earnings to adjust the carrying value to fair value.
Income Taxes. We account for income taxes using 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.
Inventory Imbalance. 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.
Investments in Debt Securities. Investments in debt securities that we have the positive intent and ability to hold to maturity are classified as “held-to-maturity” and reported at cost, adjusted for amortization or accretion of premiums or discounts. Securities not classified as held-to-maturity are classified as “available-for-sale” and are recorded at fair value. Unrealized gains and losses, net of the related tax effect, on available-for-sale securities are reported as accumulated other comprehensive income or loss which is a separate component of consolidated stockholder’s equity, and the annual change in such gains and losses are reported as other comprehensive income. A transfer of securities between categories is recorded at fair value on the date of transfer.
Realized gains and losses on the sale of available-for-sale securities are recorded on the trade date and are determined using the specific identification method. Discounts or premiums are accreted or amortized to interest income using the effective interest method over the expected terms of the related security.
Investment securities are evaluated for impairment when economic or market conditions warrant such an evaluation to determine whether a decline in their value below amortized cost is other-than-temporary. Once a decline in value is determined to be other-than-temporary, the value of the security is reduced and a corresponding charge to earnings is recognized.
The fair value of our available-for-sale securities is based on quoted market prices. In instances where quoted market prices are not available, fair values are based on indicative valuations provided by a bank.
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 statements 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 from such third party investors.
Price Risk Management (Hedging). 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 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.
Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our 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 ineffectiveness is measured on a quarterly basis. Any ineffective portion of the unrealized gain or loss is reclassified to earnings in the current period.
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 is terminated or ceases to be highly effective. 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 no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.
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:
Asset Group | Range of Years | |||
Natural gas gathering systems and processing facilities | 15 to 25 | |||
Fractionation, terminalling and natural gas liquids storage facilities | 25 | |||
Transportation assets | 5 to 10 | |||
Other property and equipment | 3 to 7 |
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
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.
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.
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:
· | sales of natural gas, NGLs and condensate; |
· | natural gas processing, from which we generate revenues through the compression, gathering, treating, and processing of natural gas; and |
· | fractionation, storage, terminalling and transportation of NGLs, from which we generate fee-based revenue. |
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 our Consolidated Statements of Operations. 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 Compensation. We award share-based compensation to employees and directors in the form of restricted stock, stock options and performance unit awards. Compensation expense on restricted stock and stock options is measured by the fair value of the award at the date of grant. Compensation expense on performance unit awards is initially measured by the fair value of the award at the date of grant, and remeasured subsequently at each reporting date through the settlement period. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. See Note 12.
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 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 long-lived 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.
Accounting Pronouncements Recently Adopted
In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 157, “Fair Value Measurements.” SFAS 157 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. We adopted SFAS 157 with respect to financial assets and liabilities that are recognized on a recurring basis on January 1, 2008. Although the adoption of SFAS 157 did not materially impact our financial condition, results of operations, or cash flows, we are now required to provide additional disclosures as part of our financial statements. See Note 6.
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.” 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. Our adoption of SFAS 159 on January 1, 2008 did not have a material impact on our consolidated financial statements.
In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133.” SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133, “Derivative Instruments and Hedging Activities” and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Early adoption is encouraged. Our adoption of SFAS 161 at December 31, 2008 did not impact our consolidated financial position, results of operations or cash flows. See Note 13.
Accounting Pronouncements Recently Issued
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. This new accounting standard will only impact how we account for business combinations on a prospective basis.
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 do not expect the adoption of Statement No. 160 to have a material impact on our financial statements and related disclosures.
Note 3—Inventory
Our product inventories consist primarily of NGLs. Most product inventories turn over monthly, but some inventory, primarily propane, is held during the year 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.
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 2008, 2007 and 2006 we recognized $6.0 million, $0.2 million and $13.1 million to reduce the carrying value of NGL inventory to its net realizable value.
Inventory consisted of the following at the dates indicated:
December 31, | ||||||||
2008 | 2007 | |||||||
(In thousands) | ||||||||
Natural gas and NGL | $ | 67,833 | $ | 142,650 | ||||
Materials and supplies | 686 | 535 | ||||||
$ | 68,519 | $ | 143,185 |
Note 4—Partnership Units and Related Matters
Initial Public Offering. 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 (the “Partnership credit facility”) and borrowed $294.5 million under this newly established facility. See Note 10. 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 limited partner interest in the Partnership 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. The earliest date at which the subordination period may end is May 19, 2009.
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.
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 credit facility by approximately $47 million. In addition, we contributed $1.0 million to the Partnership to maintain our 2% general partner interest.
We continue to consolidate the Partnership due to our ability to exercise control of the Partnership through our 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 paid to us as part of our general partner interest prior to the fourth quarter of 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.
The following table shows the amount of the Partnership’s cash distributions declared and paid for the periods from February 14, 2007 through December 31, 2008.
Distributions Paid | Distributions | |||||||||||||||||||||||||
Common | Subordinated | General Partner | per limited | |||||||||||||||||||||||
Date Declared | Date Paid | Units | Units | Incentive | 2 | % | Total | partner unit | ||||||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||||||||||||
October 24, 2008 | November 14, 2008 | $ | 17,934 | $ | 5,966 | $ | 1,931 | $ | 527 | $ | 26,358 | $ | 0.51750 | |||||||||||||
July 23, 2008 | August 14, 2008 | 17,759 | 5,908 | 1,711 | 518 | 25,896 | 0.51250 | |||||||||||||||||||
April 23, 2008 | May 15, 2008 | 14,467 | 4,813 | 208 | 398 | 19,886 | 0.41750 | |||||||||||||||||||
January 23, 2008 | February 14, 2008 | 13,768 | 4,582 | 66 | 376 | 18,792 | 0.39750 | |||||||||||||||||||
October 24, 2007 | November 14, 2007 | 11,082 | 3,891 | - | 305 | 15,278 | 0.33750 | |||||||||||||||||||
July 24, 2007 | August 14, 2007 | 6,526 | 3,890 | - | 212 | 10,628 | 0.33750 | |||||||||||||||||||
April 23, 2007 | May 15, 2007 | 3,263 | 1,945 | - | 107 | 5,315 | 0.16875 |
On January 23, 2009, we declared a cash distribution of $0.5175 per limited partner unit, payable on February 13, 2009 to unitholders of record on February 4, 2008, for the period October 1, 2008 through December 31, 2008. The total distribution paid was approximately $26.4 million, with approximately $17.9 million paid to the Partnership’s common unitholders and $6.0 million, $0.5 million and $1.9 million paid to us in respect of our subordinated units, general partner interest and incentive distribution rights.
Note 5—Property, Plant and Equipment
Our property, plant and equipment and accumulated depreciation were as follows at the dates indicated:
December 31, | ||||||||
2008 | 2007 | |||||||
(In thousands) | ||||||||
$ | 1,513,567 | 1,407,165 | ||||||
Processing and fractionation facilities | 911,389 | 869,416 | ||||||
Terminalling and natural gas liquids storage facilities | 234,270 | 221,370 | ||||||
Transportation assets | 264,613 | 150,389 | ||||||
Other property and equipment | 63,131 | 37,087 | ||||||
Land | 52,207 | 52,130 | ||||||
Construction in progress | 54,087 | 26,673 | ||||||
3,093,264 | 2,764,230 | |||||||
Accumulated depreciation | (475,895 | ) | (334,160 | ) | ||||
$ | 2,617,369 | $ | 2,430,070 |
Note 6—Fair Value Measurements
We account for the fair value of our financial assets and liabilities using three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.
Our derivative instruments consist of financially settled commodity and interest rate swap and option contracts and fixed price commodity contracts with certain customers. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are either readily available in public markets or are quoted by counterparties to these contracts. In situations where we obtain inputs via quotes from our counterparties, we verify the reasonableness of these quotes via similar quotes from another source for each date for which financial statements are presented. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative contracts we hold. We have categorized the inputs for these contracts as Level 2 or Level 3. The price quotes for the Level 3 inputs are provided by a counterparty with whom we regularly transact business.
In 2008, we paid $16.4 million to acquire from a third party $20.0 million of Targa Investments’ debt (see Note 7). We have determined the fair value of our investment using an indicative valuation provided by a bank. The indicative valuation was provided for information purposes only, and did not constitute a bid or offer, or a solicitation of a bid or offer, to initiate or conclude any transaction at the stated indicative value. As a result, we have categorized the indicative valuation as a Level 3 input.
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.
Total | Level 1 | Level 2 | Level 3 | |||||||||||||
(In thousands) | ||||||||||||||||
Assets from commodity derivative contracts | $ | 202,115 | $ | - | $ | 53,921 | $ | 148,194 | ||||||||
Available-for-sale securities (1) | 9,700 | - | - | 9,700 | ||||||||||||
Total assets | $ | 211,815 | $ | - | $ | 53,921 | $ | 157,894 | ||||||||
Liabilities from commodity derivative contracts | $ | 3,767 | $ | - | $ | 3,767 | $ | - | ||||||||
Liabilities from interest rate derivatives | 17,576 | - | 17,576 | - | ||||||||||||
Total liabilities | $ | 21,343 | $ | - | $ | 21,343 | $ | - |
_______
(1) | Excludes $1.0 million of interest paid in-kind and $0.3 million in discount amortization. |
The following table sets forth a reconciliation of the changes in the fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
Available | ||||||||||||
Derivatives | For Sale | |||||||||||
Contracts | Securities | Total | ||||||||||
(In thousands) | ||||||||||||
Balance, December 31, 2007 | $ | (124,282 | ) | $ | - | $ | (124,282 | ) | ||||
Total gains or losses (realized/unrealized) | ||||||||||||
Included in loss on mark-to-market derivatives | (1,311 | ) | - | (1,311 | ) | |||||||
Included in OCI | 77,344 | (6,700 | ) | 70,644 | ||||||||
Included in non-controlling interest in the Partnership | 73,590 | - | 73,590 | |||||||||
Purchases | 3,315 | 16,400 | 19,715 | |||||||||
Terminations | 77,792 | - | 77,792 | |||||||||
Settlements | 41,746 | - | 41,746 | |||||||||
Balance, December 31, 2008 | $ | 148,194 | $ | 9,700 | $ | 157,894 |
No unrealized gains or losses were reported relating to assets and liabilities still held as of December 31, 2008.
Note 7—Investment in Debt Obligations of Targa Investments
On June 10, 2008 we paid $16.4 million to acquire from a third party $20.0 million of Targa Investments’ outstanding variable rate indebtedness. The stated maturity date of the indebtedness is February 10, 2015, and as of December 31, 2008, the variable rate was 9.1%. We have classified this investment as an available-for-sale security. As of December 31, 2008, we have recorded an unrealized loss of $6.7 million in accumulated other comprehensive loss, based on an indicative valuation supplied by a bank. Interest earned on this investment is added to the principal balance (paid in-kind) and compounded quarterly.
Note 8—Unconsolidated Investments
As of December 31, 2008 our unconsolidated investments consisted of a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that fractionates natural gas liquids on the Gulf Coast.
Prior to July 31, 2008 our unconsolidated investments also 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. On July 31, 2008, we acquired an additional 53.8577% interest, giving us effective control. We have consolidated the operations of VESCO in our financial results with effect from August 1, 2008.
The following table shows our unconsolidated investments at the dates indicated.
December 31, | ||||||||
2008 | 2007 | |||||||
(In thousands) | ||||||||
Natural Gas Gathering and Processing - VESCO | $ | - | $ | 28,767 | ||||
Logistics Assets - GCF | 18,465 | 19,238 | ||||||
$ | 18,465 | $ | 48,005 |
Our equity in the net assets of GCF exceeded our acquisition date investment account by approximately $5.2 million. This amount 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.
The following table shows our equity earnings, cash contributions and cash distributions with respect to our unconsolidated investments for the periods indicated:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Equity in earnings of: | ||||||||||||
VESCO (1) | $ | 10,161 | $ | 6,597 | $ | 7,214 | ||||||
GCF | 3,878 | 3,511 | 2,754 | |||||||||
$ | 14,039 | $ | 10,108 | $ | 9,968 | |||||||
Cash contributions: | ||||||||||||
VESCO | $ | - | $ | 4,648 | $ | 9,102 | ||||||
Cash distributions: | ||||||||||||
GCF | $ | 4,650 | $ | 3,875 | $ | 2,306 |
________
(1) | For 2008, our equity in earnings of VESCO includes only our share of their results for the seven months ended July 31, 2008. |
Our equity in earnings of VESCO for 2008, 2007 and 2006 includes $4.1 million, $3.1 million and $2.9 million for business interruption insurance claims.
Note 9—Asset Retirement Obligations
The changes in our aggregate asset retirement obligations are as follows:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Beginning of period | $ | 12,608 | $ | 11,621 | $ | 14,104 | ||||||
Liabilities incurred (1) | 16,932 | - | - | |||||||||
Liabilities settled | (230 | ) | - | (6 | ) | |||||||
Change in cash flow estimate (2) | 2,732 | - | (3,365 | ) | ||||||||
Accretion expense | 1,943 | 987 | 888 | |||||||||
End of period | $ | 33,985 | $ | 12,608 | $ | 11,621 |
________
(1) | The entire amount relates to our consolidation of VESCO. |
(2) | The change in cash flow estimate is primarily from a reassessment of abandonment cost estimates for our offshore gathering systems. |
Our asset retirement obligations are included in our Consolidated Balance Sheet as a component of other long-term liabilities.
Note 10—Debt Obligations
Our consolidated debt obligations consisted of the following at the dates indicated:
December 31, | ||||||||
2008 | 2007 | |||||||
(In thousands) | ||||||||
Long-term debt: | ||||||||
Obligations of Targa: | ||||||||
Senior secured term loan facility, variable rate, due October 2012 | $ | 522,175 | $ | 534,675 | ||||
Senior unsecured notes, 8½% fixed rate, due November 2013 | 250,000 | 250,000 | ||||||
Senior secured revolving credit facility, variable rate, due October 2011 (1) | 95,920 | - | ||||||
Obligations of the Partnership: (2) | ||||||||
Senior secured revolving credit facility, variable rate, due February 2012 (3) | 487,765 | 626,300 | ||||||
Senior unsecured notes, 8¼% fixed rate, due July 2016 | 209,080 | - | ||||||
Total debt | 1,564,940 | 1,410,975 | ||||||
Current maturities of debt | (12,500 | ) | (12,500 | ) | ||||
Total long-term debt | $ | 1,552,440 | $ | 1,398,475 | ||||
Irrevocable standby letters of credit: | ||||||||
Letters of credit outstanding under synthetic letter of credit facility (4) | $ | 114,019 | $ | 272,409 | ||||
Letters of credit outstanding under senior secured revolving credit | ||||||||
facility of the Partnership | 9,651 | 25,900 | ||||||
$ | 123,670 | $ | 298,309 |
________
(1) | As of December 31, 2008, we had availability under this facility of $143.9 million, after giving effect to outstanding borrowings of $95.9 million and the Lehman Commercial Paper Inc. (“Lehman Paper”) default. In October 2008, Lehman Paper, a lender under our senior secured credit facility (“credit facility”), defaulted on a borrowing request. As a result of the default, we believe the availability under the facility has been effectively reduced by $10.2 million. |
(2) | We consolidate the debt of the Partnership with that of our own; however, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership. |
(3) | As of December 31, 2008, availability under the Partnership credit facility was $342.5 million, after giving effect to outstanding borrowings of $487.8 million and $9.7 million in outstanding letters of credit and the Lehman Brothers Commercial Bank (“Lehman Bank”) default. In October 2008, Lehman Bank, a lender under the Partnership credit facility defaulted on a borrowing request. As a result of the default, we believe the availability under the Partnership credit facility has been effectively reduced by approximately $10.0 million. |
(4) | The $300 million senior secured synthetic letter of credit facility terminates in October 2012. As of December 31, 2008, we had $186 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 2008:
Range of interest rates paid | Weighted average interest rate paid | ||||
Senior secured term loan facility | 3.5% to 6.9% | 5.9 | % | ||
Senior secured revolving credit facility | 2.7% to 6.2% | 4.3 | % | ||
Senior secured revolving credit facility of the Partnership | 1.5% to 6.4% | 4.4 | % |
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:
Targa | Partnership | Total | ||||||||||
(In thousands) | ||||||||||||
2009 | $ | 12,500 | $ | - | $ | 12,500 | ||||||
2010 | 12,500 | - | 12,500 | |||||||||
2011 | 108,420 | - | 108,420 | |||||||||
2012 | 484,675 | 487,765 | 972,440 | |||||||||
2013 | 250,000 | - | 250,000 | |||||||||
Thereafter | - | 209,080 | 209,080 | |||||||||
$ | 868,095 | $ | 696,845 | $ | 1,564,940 |
Description of Debt Obligations
Obligations of Targa
Senior Secured Credit Agreement
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 agreement (the “credit agreement”) provides senior secured financing of $2,500 million, consisting of:
· | $1,250 million senior secured term loan facility; |
· | $700 million senior secured asset sale bridge loan facility; |
· | $250 million senior secured revolving credit facility (the “credit facility”); and |
· | $300 million senior secured synthetic letter of credit facility. |
The entire amount of our 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 our 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 our credit facility will be obligated to provide any incremental credit extensions unless it so agrees.
Borrowings under the credit agreement, 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 0.5% 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, 2008, the applicable margin for borrowings under our credit facility was 0.75% with respect to base rate borrowings and 1.75% with respect to LIBOR borrowings. The applicable margin for borrowings under our credit facility may fluctuate based upon the Company’s leverage ratio as defined in the credit agreement.
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:
· | 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); |
· | 100% of the net cash proceeds of all non-ordinary course asset sales, transfers, or other dispositions of property, subject to certain exceptions; |
· | 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 our 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 our credit facility are due and payable in full on October 31, 2011.
All obligations under the 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 credit agreement and certain secured hedging arrangements, and the guarantees of those obligations, are secured by substantially all of the following assets, subject to certain exceptions:
· | 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 |
· | a security interest in, and mortgages on, our and our guarantors’ tangible and intangible assets. |
The 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 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.
The credit agreement requires us to maintain certain specified maximum total leverage ratios and certain specified minimum interest coverage ratios.
The credit agreement will permit us to transfer, on one or more occasions:
· | 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 credit agreement were used to repay pre-existing debt and fund a portion of our purchase of Dynegy Midstream Services (the “DMS acquisition”).
The Notes:
· | are our unsecured senior obligations; |
· | rank pari passu in right of payment with all our existing and future senior indebtedness, including indebtedness under our credit agreement; |
· | 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; |
· | 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; |
· | rank senior in right of payment to any of our future subordinated indebtedness; |
· | are guaranteed on a senior unsecured basis by the subsidiary guarantors that guarantee the senior secured credit facilities; and |
Interest on the Notes accrues at the rate of 8½% 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.
On and after November 1, 2009, we may redeem all or part of the Notes at our option, at 104.25% of the principal amount for the twelve-month period beginning November 1, 2009, at 102.125% of the principal amount 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.
On December 18, 2007, we filed a registration statement on Form S-4/A in which we offered to exchange up to $250 million of our outstanding 8½% 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 The Partnership
Senior Secured Revolving Credit Facility
On February 14, 2007 the Partnership entered into a credit agreement which provided for a $500 million five year senior secured revolving credit facility with a syndicate of financial institutions. The Partnership 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 the Partnership to maintain a leverage ratio (the ratio of consolidated indebtedness to our consolidated EBITDA, as defined in the credit agreement) of no more than 5.50 to 1.00 on the last day of any fiscal quarter. 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:
· | incur indebtedness; |
· | grant liens; and |
· | engage in transactions with affiliates. |
The Partnership credit agreement 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).
Concurrent with the Partnership’s acquisition of the SAOU and LOU Systems from us, the Partnership entered into a commitment increase supplement to the Partnership credit agreement, whereby the aggregate commitments under the credit agreement increased by $250 million to an aggregate $750 million. The Partnership paid for its acquisition of the SAOU and LOU Systems with the proceeds from its offering of common units and approximately $378.9 million in incremental borrowings under the Partnership credit facility. Substantially all of the Partnership’s assets (North Texas, SAOU and LOU Systems) are currently pledged as collateral on the Partnership credit facility.
On October 24, 2007, the Partnership credit agreement was amended to increase by $250 million the maximum amount of increases to the aggregate commitments that may be requested by the Partnership. The amended credit agreement allows the Partnership to request commitments of up to $1 billion.
On June 18, 2008, the Partnership entered into a second commitment increase supplement, whereby the commitments under the Partnership credit agreement were increased by $100 million to an aggregate $850 million. The Partnership may request additional commitments under the Partnership credit facility of up to $150 million, which would increase the total commitments under the Partnership credit facility to $1 billion.
On October 16, 2008, the Partnership requested a $100 million funding under the Partnership credit facility. Lehman Bank, a lender under the Partnership credit facility, defaulted on its portion of the borrowing request resulting in an actual funding of $97.8 million. As a result of the default, we believe the availability under the Partnership credit facility has been effectively reduced by approximately $10.0 million.
8¼% Senior Notes due 2016
On June 18, 2008, the Partnership completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 (“Rule 144A”) of $250 million in aggregate principal amount of 8¼% senior notes due 2016 (the “Notes”). Proceeds from the Notes were used to repay borrowings under the Partnership credit facility.
The Notes:
· | are the Partnership’s unsecured senior obligations; |
· | rank pari passu in right of payment with the Partnership’s existing and future senior indebtedness, including indebtedness under the Partnership credit facility; |
· | are senior in right of payment to any of the Partnership’s future subordinated indebtedness; and |
· | are unconditionally guaranteed by the Partnership. |
The Notes are effectively subordinated to all secured indebtedness under the Partnership credit agreement, which is secured by substantially all of its assets, to the extent of the value of the collateral securing that indebtedness.
Interest on the Notes accrues at the rate of 8¼% per annum and is payable semi-annually in arrears on January 1 and July 1, commencing on January 1, 2009. Interest is computed on the basis of a 360-day year comprising twelve 30-day months.
At any time prior to July 1, 2011, the Partnership may on any one or more occasions redeem up to 35% of the aggregate principal amount of the Notes with the net cash proceeds of one or more equity offerings by the Partnership at a redemption price of 108.25% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any, to the redemption date provided that:
(1) | at least 65% of the aggregate principal amount of the Notes (excluding Notes held by the Partnership) remains outstanding immediately after the occurrence of such redemption; and |
(2) | the redemption occurs within 90 days of the date of the closing of such equity offering. |
At any time prior to July 1, 2012, the Partnership may also redeem all or a part of the Notes at a redemption price equal to 100% of the principal amount of the Notes redeemed plus the applicable premium as defined in the indenture agreement and accrued and unpaid interest and liquidated damages, if any, to the date of redemption.
On or after July 1, 2012, the Partnership may redeem all or a part of the Notes at the redemption prices set forth below (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidated damages, if any, on the Notes redeemed, if redeemed during the twelve-month period beginning on July 1 of each year indicated below:
Year | Percentage | |||
2012 | 104.125 | % | ||
2013 | 102.063 | % | ||
2014 and thereafter | 100.000 | % |
The Notes are subject to a registration rights agreement dated as of June 18, 2008. Under the registration rights agreement, the Partnership is required to file by June 19, 2009 a registration statement with respect to any Notes that are not freely transferable without volume restrictions by holders of the Notes that are not affiliates of the Partnership. If the Partnership fails to do so, additional interest will accrue on the principal amount of the Notes. The Partnership has determined that the payment of additional interest is not probable. As a result, the Partnership has not recorded a liability for any contingent obligation. Any subsequent accruals of a liability or payments made under this registration rights agreement will be charged to earnings as interest expense in the period they are recognized or paid.
Repurchases of Senior Notes
During 2008, the Partnership repurchased $40.9 million face amount of its outstanding Senior Notes in open market transactions at an aggregate purchase price of $28.3 million including $1.5 million of accrued interest. The Partnership recognized a gain of $13.1 million from these transactions. We also wrote-off the associated debt issue costs related to the repurchased notes. The repurchased Notes were retired and are not eligible for re-issue at a later date.
Holdco Loan Facility of Targa Investments
During 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 credit agreement, our assets are not pledged as collateral under the credit agreement and we have no obligation to repay the amounts borrowed under the credit agreement.
On March 7, 2008, we made a cash distribution of $50.0 million to Targa Investments. Targa Investments used the proceeds to retire $62.5 million of its outstanding borrowings under this credit agreement.
Note 11—Insurance Claims
We recognize income from business interruption insurance in our consolidated statements of operations in the period that a proof of loss is executed and submitted to the insurers for payment. The following table summarizes our income recognition of business interruption insurance for the periods indicated:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Included in revenues | ||||||||||||
Natural Gas Gathering and Processing (1) | $ | 14,269 | $ | 2,643 | $ | 3,721 | ||||||
Logistics Assets | 2,554 | (32 | ) | 383 | ||||||||
NGL Distribution and Marketing | 9,577 | 3,834 | 5,505 | |||||||||
Wholesale Marketing (1) | 6,516 | 826 | 1,110 | |||||||||
$ | 32,916 | $ | 7,271 | $ | 10,719 | |||||||
Included in equity in earnings of unconsolidated investments | ||||||||||||
Natural Gas Gathering and Processing | $ | 4,108 | $ | 3,088 | $ | 2,856 | ||||||
$ | 37,024 | $ | 10,359 | $ | 13,575 |
________
(1) Includes $0.7 million and $0.6 million for 2008 in non-hurricane business interruption proceeds related to fire damage claims at plants in our natural gas gathering and processing segment and our wholesale marketing segment.
Hurricanes Katrina and Rita
Katrina and Rita affected certain of our Gulf Coast facilities in 2005. Our final purchase price allocation for the DMS acquisition in October 2005 included an $81.1 million receivable for insurance claims related to property damage caused by Katrina and Rita. During 2008, our cumulative receipts exceeded such amount, and we recognized a gain of $18.6 million. The insurance claim process is now complete with respect to Katrina and Rita for property damage and business interruption insurance.
Hurricanes Gustav and Ike
In September 2008, certain of our facilities in Louisiana and Texas sustained damage and had disruption to their operations from Hurricanes Gustav and Ike.
We currently estimate the cost associated with our interest for repairs to the impacted facilities to be approximately $65 million. We believe that we have adequate insurance coverage (subject to customary deductibles, limits and sub-limits) to cover the respective facility repair costs and to offset the majority of the associated lost profits as a result of the hurricanes. The property damage deductibles under our insurance coverage will reduce our ultimate property damage insurance recoveries by approximately $14 million. We will have additional out of pocket costs associated with improvements (e.g., elevating critical equipment) that may not be covered by insurance. During 2008, we recorded a loss provision of $19.3 million ($17.9 million, net to our ownership interest) for our estimated out-of-pocket cleanup and repair costs related to these two hurricanes, after estimated insurance proceeds.
We are still in the process of analyzing the factors affecting the amount of our business interruption claims. We maintain a 30 day time-element business interruption waiting period for our onshore facilities, and a 45 day time-element contingent business interruption waiting period for third-party offshore property damage related income impacts to our onshore facilities. We will recognize income from business interruption claims in the period that a proof of loss is executed with the insurance company.
Note 12—Stock and Other Compensation Plans
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 was estimated on the date of grant using a Black-Scholes option pricing model, which incorporates various assumptions for 2008, 2007 and 2006, including (i) expected term of the options of ten years, (ii) a risk-free interest rate of 3.6%, 4.6% and 4.5%, (iii) expected dividend yield of 0%, and (iv) expected stock price volatility on Targa Investments’ common stock of 25.5%, 29.7% and 23.8%. 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 years ended December 31, 2008, 2007, and 2006 was $1.48, $0.63 and $0.21 per share.
The following table shows stock option activity for the periods indicated:
Number of Options | Weighted Average Exercise Price | Weighted Average Remaining Contractual Term (in years) | |||||||
Outstanding at December 31, 2005 | 5,108,114 | $ | 7.64 | ||||||
Granted | 51,672 | 8.50 | |||||||
Forfeited | (54,474 | ) | 8.50 | ||||||
Outstanding at December 31, 2006 | 5,105,312 | 7.64 | |||||||
Granted | 120,825 | 6.91 | |||||||
Exercised | (135,740 | ) | 0.75 | ||||||
Forfeited | (28,317 | ) | 8.50 | ||||||
Outstanding at December 31, 2007 | 5,062,080 | 7.80 | |||||||
Granted | 180,000 | 3.59 | |||||||
Exercised | (368,113 | ) | 2.41 | ||||||
Repurchased | (77,601 | ) | 7.80 | ||||||
Forfeited | (51,736 | ) | 7.80 | ||||||
Outstanding at December 31, 2008 | 4,744,630 | 8.06 | 6.97 | ||||||
Exercisable at December 31, 2008 | 3,528,284 | 8.39 | 6.89 |
We recognized compensation expense associated with stock options of $0.2 million, $0.1 million and $0.1 million during 2008, 2007 and 2006. As of December 31, 2008, we expect to incur an additional $0.2 million of expense related to non-vested stock options over a weighted-average period of approximately one year. The total intrinsic value of options exercised during 2008 was $0.5 million.
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.
The following table provides a summary of Targa Investments’ non-vested restricted common stock awards for the periods indicated:
Year ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
Outstanding at beginning of period | 5,467,154 | 4,887,848 | 5,501,132 | |||||||||
Granted (1) | 20,000 | 1,188,549 | 72,564 | |||||||||
Vested | (4,163,020 | ) | (609,243 | ) | (612,799 | ) | ||||||
Forfeited | (75,018 | ) | - | (73,049 | ) | |||||||
Outstanding at end of period | 1,249,116 | 5,467,154 | 4,887,848 | |||||||||
Weighted average grant date fair value per share | $ | 1.19 | $ | 1.15 | $ | 1.16 |
________
(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 restricted common shares that vested during 2008 was $16.6 million. We recognized $1.0 million, $2.0 million and $2.7 million of compensation expense associated with the vesting of restricted stock during 2008, 2007 and 2006. As of December 31, 2008, we expect to incur an additional $1.1 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.
Grants under Targa Investments’ LTIP were 295,600 under the 2007 program and 138,825 under the 2008 program. Grants under the 2007 and 2008 programs are payable in August 2010 and July 2011. 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, relative to the total return of a defined peer group.
Because the performance units require cash settlement, they have been accounted for as liabilities. The fair value of a performance unit is the sum of: (i) the closing price of a 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 options was estimated using a Black-Scholes option pricing model with a dividend yield of zero, and with risk-free rates and volatilities of 0.6% and 59% under the 2007 program and 0.9% and 41% under the 2008 program.
At December 31, 2008, the aggregate fair value of performance units expected to vest was $6.9 million. For the years ended December 31, 2008 and 2007, we recognized compensation expense of $0.1 million and $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 2008 and 2007, we recognized compensation expense of $0.3 million and $0.2 million related to these awards. We estimate that the remaining fair value of $0.2 million will be recognized in expense over approximately one year.
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 $8.4 million, $7.6 million, and $6.0 million during 2008, 2007, and 2006.
Note 13—Derivative Instruments and Hedging Activities
At December 31, 2008, OCI included $59.6 million ($39.3 million, net of tax) of unrealized net gains on commodity hedges, $4.7 million ($3.1 million, net of tax) of unrealized net losses on interest rate hedges and $6.7 million ($4.4 million, net of tax) of unrealized net losses on available-for-sale securities.
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.
In May 2008, Targa and the Partnership entered into certain NGL derivative contracts with Lehman Brothers Commodity Services Inc. (“Lehman”). Due to Lehman’s bankruptcy filings, it is unlikely that we will receive full or partial payment of any amounts that may become owed to us under these contracts. Accordingly, Targa and the Partnership discontinued hedge accounting treatment for these contracts as of July 1, 2008. Deferred losses of $0.2 million and $0.3 million will be reclassified from OCI to revenues during 2011 and 2012 when the forecasted transactions related to these contracts are expected to occur. Subsequent to the discontinuation of hedge accounting treatment, Targa and the Partnership recognized an aggregate non-cash loss on mark-to-market derivatives of $1.3 million to adjust the fair value of the Lehman derivative contracts to zero. On October 22, 2008, Targa and the Partnership terminated the Lehman derivative contracts.
In July 2008, the Partnership paid $87.4 million to terminate certain out-of-the-money natural gas and NGL commodity swaps. Prior to the terminations, these swaps were designated as hedges in accordance with SFAS 133. Deferred losses of approximately $38.2 million and $27.9 million will be reclassified from OCI as a non-cash reduction of revenue during 2009 and 2010 when the hedged forecasted sales transactions are expected to occur. For the year ended December 31, 2008, deferred losses related to the terminated swaps of $20.8 million were reclassified from OCI as a non-cash reduction to revenue. The Partnership also entered into new natural gas and NGL commodity swaps at then current market prices that match the production volumes of the terminated swaps through 2010.
During 2008, 2007 and 2006 deferred net gains / (losses) on commodity hedges of ($65.1) million, $4.1 million and $31.2 million were reclassified from OCI to revenues, and deferred net gains / (losses) on interest rate hedges of ($2.7) million, $2.2 million and $1.0 million were reclassified from OCI to interest expense. There were no adjustments for hedge ineffectiveness.
As of December 31, 2008, $33.8 million ($22.2 million, net of tax) of deferred net gains on commodity hedges and $8.0 million ($5.3 million, 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 2008 and 2007, we reclassified deferred net losses of $9.9 million and $2.4 million related to these derivatives from OCI to revenues. During the years ended December 31, 2009, 2010 and 2011, we will reclassify additional deferred net losses of $6.7 million, $1.8 million and $0.2 million, from OCI to revenues with respect to the de-designated hedges.
At December 31, 2008, we had the following open commodity derivatives designated as hedges, which have been designated as cash flow hedges:
Natural Gas | ||||||||||||||||||||||||||
Avg. Price | MMBtu per day | |||||||||||||||||||||||||
Instrument Type | Index | $/MMBtu | 2009 | 2010 | 2011 | 2012 | Fair Value | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||
Natural Gas Sales | ||||||||||||||||||||||||||
Swap | IF-Waha | 6.62 | 21,918 | - | - | - | $ | 11,010 | ||||||||||||||||||
Swap | IF-Waha | 7.40 | - | 9,300 | - | - | 3,403 | |||||||||||||||||||
Swap | IF-Waha | 7.36 | - | - | 5,500 | - | 1,503 | |||||||||||||||||||
Swap | IF-Waha | 7.18 | - | - | - | 5,500 | 1,197 | |||||||||||||||||||
Total Sales | 21,918 | 9,300 | 5,500 | 5,500 | ||||||||||||||||||||||
$ | 17,113 |
NGLs | ||||||||||||||||||||||||||
Avg. Price | Barrels per day | |||||||||||||||||||||||||
Instrument Type | Index | $/gal | 2009 | 2010 | 2011 | 2012 | Fair Value | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||
NGL Sales | ||||||||||||||||||||||||||
Swap | OPIS-MB | 0.79 | 3,347 | - | - | - | $ | 9,515 | ||||||||||||||||||
Swap | OPIS-MB | 0.87 | - | 2,750 | - | - | 7,388 | |||||||||||||||||||
Swap | OPIS-MB | 0.91 | - | - | 1,550 | - | 3,971 | |||||||||||||||||||
Swap | OPIS-MB | 0.92 | - | - | - | 1,250 | 2,999 | |||||||||||||||||||
Total Swaps | 3,347 | 2,750 | 1,550 | 1,250 | ||||||||||||||||||||||
Floor | OPIS-MB | 1.44 | - | - | 54 | - | 490 | |||||||||||||||||||
Floor | OPIS-MB | 1.43 | - | - | - | 63 | 527 | |||||||||||||||||||
Total Floors | - | - | 54 | 63 | ||||||||||||||||||||||
Total Sales | 3,347 | 2,750 | 1,604 | 1,313 | ||||||||||||||||||||||
$ | 24,890 |
At December 31, 2008, the Partnership had the following open commodity derivatives, which have been designated as cash flow hedges:
Natural Gas | ||||||||||||||||||||||||||
Avg. Price | MMBtu per day | |||||||||||||||||||||||||
Instrument Type | Index | $/MMBtu | 2009 | 2010 | 2011 | 2012 | Fair Value | |||||||||||||||||||
Natural Gas Sales | (In thousands) | |||||||||||||||||||||||||
Swap | IF-HSC | 7.39 | 1,966 | - | - | - | $ | 1,159 | ||||||||||||||||||
1,966 | - | - | - | |||||||||||||||||||||||
Swap | IF-NGPL MC | 9.18 | 6,256 | - | - | - | 9,466 | |||||||||||||||||||
Swap | IF-NGPL MC | 8.86 | - | 5,685 | - | - | 5,129 | |||||||||||||||||||
Swap | IF-NGPL MC | 7.34 | - | - | 2,750 | - | 843 | |||||||||||||||||||
Swap | IF-NGPL MC | 7.18 | - | - | - | 2,750 | 738 | |||||||||||||||||||
6,256 | 5,685 | 2,750 | 2,750 | |||||||||||||||||||||||
Swap | IF-Waha | 8.73 | 6,936 | - | - | - | 8,627 | |||||||||||||||||||
Swap | IF-Waha | 7.52 | - | 5,709 | - | - | 2,294 | |||||||||||||||||||
Swap | IF-Waha | 7.36 | - | - | 3,250 | - | 886 | |||||||||||||||||||
Swap | IF-Waha | 7.18 | - | - | - | 3,250 | 708 | |||||||||||||||||||
6,936 | 5,709 | 3,250 | 3,250 | |||||||||||||||||||||||
Total Swaps | 15,158 | 11,394 | 6,000 | 6,000 | ||||||||||||||||||||||
Floor | IF-NGPL MC | 6.55 | 850 | - | - | - | 574 | |||||||||||||||||||
850 | - | - | - | |||||||||||||||||||||||
Floor | IF-Waha | 6.55 | 565 | - | - | - | 326 | |||||||||||||||||||
565 | - | - | - | |||||||||||||||||||||||
Total Floors | 1,415 | - | - | - | ||||||||||||||||||||||
Total Sales | �� | 16,573 | 11,394 | 6,000 | 6,000 | |||||||||||||||||||||
$ | 30,750 |
NGL | ||||||||||||||||||||||||||
Avg. Price | Barrels per day | |||||||||||||||||||||||||
Instrument Type | Index | $/gal | 2009 | 2010 | 2011 | 2012 | Fair Value | |||||||||||||||||||
NGL Sales | (In thousands) | |||||||||||||||||||||||||
Swap | OPIS-MB | 1.32 | 6,248 | - | - | - | $ | 66,137 | ||||||||||||||||||
Swap | OPIS-MB | 1.27 | - | 4,809 | - | - | 39,122 | |||||||||||||||||||
Swap | OPIS-MB | 0.92 | - | - | 3,400 | - | 8,288 | |||||||||||||||||||
Swap | OPIS-MB | 0.92 | - | - | - | 2,700 | 6,018 | |||||||||||||||||||
Total Swaps | 6,248 | 4,809 | 3,400 | 2,700 | ||||||||||||||||||||||
Floor | OPIS-MB | 1.44 | - | - | 199 | - | 1,807 | |||||||||||||||||||
Floor | OPIS-MB | 1.43 | - | - | - | 231 | 1,932 | |||||||||||||||||||
Total Floors | - | - | 199 | 231 | ||||||||||||||||||||||
Total Sales | 6,248 | 4,809 | 3,599 | 2,931 | ||||||||||||||||||||||
$ | 123,304 |
Condensate | ||||||||||||||||||||||||||
Avg. Price | Barrels per day | |||||||||||||||||||||||||
Instrument Type | Index | $/Bbl | 2009 | 2010 | 2011 | 2012 | Fair Value | |||||||||||||||||||
Condensate Sales | (In thousands) | |||||||||||||||||||||||||
Swap | NY-WTI | 69.00 | 322 | - | - | - | $ | 1,655 | ||||||||||||||||||
Swap | NY-WTI | 68.10 | - | 301 | - | - | 431 | |||||||||||||||||||
Total Swaps | 322 | 301 | - | - | ||||||||||||||||||||||
Floor | NY-WTI | 60.00 | 50 | - | - | - | 239 | |||||||||||||||||||
Total Floors | 50 | - | - | - | ||||||||||||||||||||||
Total Sales | 372 | 301 | - | - | ||||||||||||||||||||||
$ | 2,325 |
Customer Derivatives
At December 31, 2008, the Partnership had the following commodity derivative contracts directly related to fixed price arrangements elected by certain customers in various natural gas purchase and sale agreements, which have been marked to market through earnings:
Period | Commodity | Instrument Type | Daily Volume | Average Price | Index | Fair Value | ||||||||||||||
Purchases | (In thousands) | |||||||||||||||||||
Jan 2009 - Dec 2009 | Natural gas | Swap | 6,005 | MMBtu | $ | 7.50 | per MMBtu | NY-HH | $ | (3,644 | ) | |||||||||
Jan 2010 - Jun 2010 | Natural gas | Swap | 1,304 | MMBtu | 8.03 | per MMBtu | NY-HH | (113 | ) | |||||||||||
Sales | ||||||||||||||||||||
Jan 2009 - Dec 2009 | Natural gas | Fixed price sale | 6,005 | MMBtu | 7.50 | per MMBtu | NY-HH | 3,610 | ||||||||||||
Jan 2010 - Jun 2010 | Natural gas | Fixed price sale | 1,304 | MMBtu | 8.03 | per MMBtu | NY-HH | 113 | ||||||||||||
$ | (34 | ) |
The fair value of derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.
Our earnings are also affected by use of the mark-to-market method of accounting for derivative financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. During 2008, we recorded mark-to-market losses of $1.3 million.
Interest Rate Swaps
At December 31, 2008, the Partnership had $487.8 million outstanding under the Partnership credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates the Partnership entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:
Expiration | Fixed | Notional | |||||||
Date | Rate | Amount | Fair Value | ||||||
(In thousands) | |||||||||
January 24, 2011 | 4.00 | % | $100 million | $ | (5,282 | ) | |||
January 24, 2012 | 3.75 | % | 200 million | (12,294 | ) | ||||
$ | (17,576 | ) |
The Partnership has designated all interest rate swaps and interest rate basis swaps as cash flow hedges of variable rate interest payments on borrowings under the Partnership credit facility.
The following schedules reflect the fair values of derivative instruments in our Consolidated Balance Sheets and the effects of derivative instruments on our Consolidated Statements of Operations.
Fair Value of Derivative Instruments
Asset Derivatives | Liability Derivatives | |||||||||||||||||
Balance Sheet | Fair Value | Balance Sheet | Fair Value | |||||||||||||||
Location | 2008 | 2007 | Location | 2008 | 2007 | |||||||||||||
Derivatives designated as | (In thousands) | (In thousands) | ||||||||||||||||
hedging instruments under | ||||||||||||||||||
Statement 133 | ||||||||||||||||||
Commodity contracts | Current assets | $ | 108,731 | $ | 9,202 | Current liabilities | $ | - | $ | 75,026 | ||||||||
Other assets | 89,774 | 4,279 | Other liabilities | 123 | 80,044 | |||||||||||||
Interest rate contracts | Current assets | - | - | Current liabilities | 8,020 | 257 | ||||||||||||
Other assets | - | - | Other liabilities | 9,556 | 975 | |||||||||||||
Total | 198,505 | 13,481 | 17,699 | 156,302 | ||||||||||||||
Derivatives not designated as | ||||||||||||||||||
hedging instruments under | ||||||||||||||||||
Statement 133 | ||||||||||||||||||
Commodity contracts | Current assets | 3,610 | 285 | Current liabilities | 3,644 | 285 | ||||||||||||
Other assets | - | - | Other liabilities | - | - | |||||||||||||
Total | 3,610 | 285 | 3,644 | 285 | ||||||||||||||
Total derivatives | $ | 202,115 | $ | 13,766 | $ | 21,343 | $ | 156,587 |
Effect of Derivative Instruments on our Consolidated Statements of Operations
Amount of Gain (Loss) | |||||||||||||||||||||||||
Amount of Gain (Loss) | Reclassified from | ||||||||||||||||||||||||
Derivatives in | Recognized in OCI on Derivatives | Location of Gain (Loss) | Accumulated OCI into | ||||||||||||||||||||||
Statement 133 | (Effective Portion) | Reclassified from | Income (Effective Portion) | ||||||||||||||||||||||
Cash Flow Hedging | Year Ended December 31, | Accumulated OCI into | Year Ended December 31, | ||||||||||||||||||||||
Relationships | 2008 | 2007 | 2006 | Income (Effective Portion) | 2008 | 2007 | 2006 | ||||||||||||||||||
(In thousands) | (In thousands) | ||||||||||||||||||||||||
Interest rate contracts | $ | (7,017 | ) | $ | 433 | $ | 2,606 | Interest expense, net | $ | (2,693 | ) | $ | 2,191 | $ | 1,005 | ||||||||||
Commodity contracts | 86,220 | (146,406 | ) | 120,283 | Revenues | (65,125 | ) | 4,126 | 31,243 | ||||||||||||||||
$ | 79,203 | $ | (145,973 | ) | $ | 122,889 | $ | (67,818 | ) | $ | 6,317 | $ | 32,248 |
Derivatives Not | Amount of Gain (Loss) Recognized | ||||
Designated as Hedging | Location of Gain (Loss) | in Income on Derivatives | |||
Instruments Under | Recognized in Income | Year Ended December 31, | |||
Statement 133 | on Derivatives | 2008 | 2007 | 2006 | |
(In thousands) | |||||
Commodity contracts | Other income (expense) | $(1,311) | $- | $- |
See also Note 2 and Note 17 for additional disclosures realted to derivative instruments and hedging activitiy.
Note 14—Income Taxes
Our provisions for income taxes for the periods indicated are as follows:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Current expense | $ | 1,245 | $ | 175 | $ | 34 | ||||||
Deferred expense | 25,084 | 31,156 | 16,175 | |||||||||
$ | 26,329 | $ | 31,331 | $ | 16,209 |
Our deferred income tax assets and liabilities at December 31, 2008 and 2007 consist of differences related to the timing of recognition of certain types of costs as follows:
December 31, | ||||||||
2008 | 2007 | |||||||
(In thousands) | ||||||||
Deferred tax assets: | ||||||||
Net operating loss | $ | 71,673 | $ | 26,730 | ||||
Commodity hedging contracts and other | - | 35,619 | ||||||
Tax credits | 16,798 | 10,690 | ||||||
88,471 | 73,039 | |||||||
Deferred tax liabilities: | ||||||||
Investments (1) | (125,853 | ) | (77,469 | ) | ||||
Commodity hedging contracts and other | (38,885 | ) | - | |||||
(164,738 | ) | (77,469 | ) | |||||
Net deferred tax liability | $ | (76,267 | ) | $ | (4,430 | ) | ||
Federal | $ | (85,779 | ) | $ | (12,074 | ) | ||
Foreign | 438 | 831 | ||||||
State | 9,074 | 6,813 | ||||||
$ | (76,267 | ) | $ | (4,430 | ) | |||
Balance sheet classification of deferred tax assets (liabilities): | ||||||||
Current asset | $ | - | $ | 25,071 | ||||
Long-term asset | - | - | ||||||
Current liability | (36,240 | ) | - | |||||
Long-term liability | (40,027 | ) | (29,501 | ) | ||||
$ | (76,267 | ) | $ | (4,430 | ) |
________
(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, 2008, for federal income tax purposes, we had carryforwards of approximately $176 million of regular tax net operating losses (“NOL”) and $47 million of alternative minimum tax (“AMT”) NOL. The NOL carryforwards expire in 2029.
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:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
U.S. federal income tax provision at statutory rate | $ | 27,532 | $ | 34,966 | $ | 13,868 | ||||||
State income taxes (1) | 920 | (4,433 | ) | 2,743 | ||||||||
Other | (2,123 | ) | 798 | (402 | ) | |||||||
Income tax provision | $ | 26,329 | $ | 31,331 | $ | 16,209 |
________
(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. |
During 2008 and 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.
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 15—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:
Payments Due by Period | ||||||||||||||||||||||||||||
Total | 2009 | 2010 | 2011 | 2012 | 2013 | Thereafter | ||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Operating leases (1) | $ | 72,847 | $ | 12,317 | $ | 10,897 | $ | 8,672 | $ | 8,199 | $ | 7,671 | $ | 25,091 | ||||||||||||||
Capacity payments (2) | 20,043 | 8,187 | 4,800 | 3,408 | 2,574 | 1,074 | - | |||||||||||||||||||||
Right-of -way | 17,683 | 1,086 | 1,036 | 974 | 957 | 892 | 12,738 | |||||||||||||||||||||
Asset retirement obligations | 33,991 | - | - | - | 6 | - | 33,985 | |||||||||||||||||||||
Other contractual obligations (3) | 905 | 375 | 280 | 237 | 13 | - | - | |||||||||||||||||||||
$ | 145,469 | $ | 21,965 | $ | 17,013 | $ | 13,291 | $ | 11,749 | $ | 9,637 | $ | 71,814 |
________
(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 $14.7 million, $3.1 million and $6.7 million for 2008, $16.4 million, $2.2 million and $4.1 million for 2007, and $16.7 million, $1.8 million and $1.9 million for 2006.
Hurricanes Gustav and Ike
Hurricanes Gustav and Ike affected certain of our Gulf Coast facilities in September 2008. For the year ended December 31, 2008, we recognized a loss provision of $17.9 million net to our ownership interest for our estimated out-of-pocket cleanup and repair costs related to Gustav and Ike, after estimated insurance proceeds and before estimated reimbursements from minority interest holders.
Environmental
Our environmental liability at December 31, 2008 and 2007 was $3.8 million and $4.8 million. Our December 31, 2008 liability consisted of $0.2 million for gathering system leaks, $1.5 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), 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. In 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. 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 $3.0 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. On April 4, 2008, the Supreme Court of Texas granted review of the petitions. On September 9, 2008, the parties presented oral arguments, and the appeal is currently pending before the Supreme Court of Texas.
On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc. and three other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa 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 Targa’s 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. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal. On February 3, 2009, the parties presented oral arguments and the appeal is pending before the 14th Court of Appeals in Houston, TX. We are contesting WTG’s appeal, but can give no assurances regarding the outcome of the proceeding. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit.
Note 16—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.
Chansoo Joung and Peter Kagan, two of our directors, are Managing Directors of Warburg Pincus and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus own a controlling interest in Broad Oak. We purchased $4.8 million of product from Broad Oak during 2008. We had no commercial transactions prior to 2008 with Broad Oak. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.
Relationships with 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.
Financial Services
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. The following table shows our open commodity derivatives with Merrill Lynch as of December 31, 2008:
Period | Commodity | Daily Volumes | Average Price | Index | ||||||||
Jan 2009 - Dec 2009 | Natural gas | 21,918 | MMBtu | $ | 6.62 | per MMBtu | IF-Waha | |||||
Jan 2009 - Dec 2009 | NGL | 2,847 | Bbl | 0.74 | per gallon | OPIS-MB |
As of December 31, 2008 the fair value of these open positions was an asset of $17.3 million. For the years ended December 31, 2008, 2007 and 2006 we paid to (received from) MLCI $30.3 million, $14.2 million and ($6.8) million in commodity derivative settlements.
The Partnership had the following open commodity derivatives with MLCI as of December 31, 2008:
Period | Commodity | Daily Volumes | Average Price | Index | ||||||||
Jan 2009 - Dec 2009 | Natural gas | 3,556 | MMBtu | $ | 8.07 | per MMBtu | IF-Waha | |||||
Jan 2009 - Dec 2009 | Natural gas | 575 | MMBtu | 7.83 | per MMBtu | NY-HH | ||||||
Jan 2010 - Dec 2010 | Natural gas | 3,289 | MMBtu | 7.39 | per MMBtu | IF-Waha | ||||||
Jan 2010 - Dec 2010 | Natural gas | 247 | MMBtu | 8.17 | per MMBtu | NY-HH | ||||||
Jan 2009 - Dec 2009 | NGL | 3,000 | Bbl | 1.18 | per gallon | OPIS-MB | ||||||
Jan 2009 - Dec 2009 | Condensate | 202 | Bbl | 70.60 | per barrel | NY-WTI | ||||||
Jan 2010 - Dec 2010 | Condensate | 181 | Bbl | 69.28 | per barrel | NY-WTI |
As of December 31, 2008 the fair value of these Partnership open positions was an asset of $32.0 million. For the years ended December 31, 2008, 2007 and 2006 the partnership paid to (received from) MLCI $9.1 million, $1.9 million and ($4.2) million in commodity derivative settlements.
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. For the years 2008, 2007 and 2006, we had product sales to MLCI, which are included in revenues of $97.0 million, $81.2 million and $78.1 million. For the same periods, we had natural gas and NGL product purchases of $5.1 million, $12.1 million and $15.2 million from MLCI.
Relationships with Noble Energy
Chris Tong, one of our directors, is a Senior Vice President and Chief Financial Officer of Noble Energy, Inc. (“Noble”) from whom we buy certain commodity products. We had net purchases of $3.8 million, $0.3 million and $1.9 million of natural gas and NGL products from Noble during 2008, 2007 and 2006. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.
Transactions with Unconsolidated Affiliates
For the years indicated, our natural gas and NGL sales and purchases with our unconsolidated affiliates were:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Included in Revenues | ||||||||||||
GCF | $ | 469 | $ | 4,514 | $ | 1,366 | ||||||
VESCO (1) | 690 | 4,771 | 2,628 | |||||||||
$ | 1,159 | $ | 9,285 | $ | 3,994 | |||||||
Included in Costs and Expenses | ||||||||||||
GCF | $ | 3,501 | $ | 3,316 | $ | 3,336 | ||||||
VESCO (1) | 178,098 | 145,806 | 132,798 | |||||||||
$ | 181,599 | $ | 149,122 | $ | 136,134 |
________
(1) For 2008, our commercial transactions with VESCO are reflected through July 31, 2008. As a result of acquiring an additional ownership in VESCO, they are no longer considered an unconsolidated affiliate and we have consolidated the operations of VESCO in our financial results with effect from August 1, 2008.
These transactions were at market prices consistent with similar transactions with nonaffiliated entities.
Note 17—Fair Value of Financial Instruments
The estimated fair values of our assets and liabilities classified as financial instruments 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 value of our and the Partnership’s credit facilities approximates their fair values, as the interest rates are 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.
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 the dates indicated:
As of December 31, | ||||||||||||||||
2008 | 2007 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
(In thousands) | ||||||||||||||||
Senior secured term loan facility | $ | 522,175 | $ | 331,581 | $ | 534,675 | $ | 521,308 | ||||||||
Senior unsecured notes, 8½% fixed rate | 250,000 | 134,375 | 250,000 | 241,250 | ||||||||||||
Senior unsecured notes of the Partnership, 8¼% fixed rate | 209,080 | 128,333 | - | - |
Note 18—Supplemental Cash Flow Information
Supplemental cash flow information was as follows for the periods indicated:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands) | ||||||||||||
Cash: | ||||||||||||
Interest paid | $ | 93,742 | $ | 144,868 | $ | 170,928 | ||||||
Income taxes paid | 1,608 | 3,573 | 59 | |||||||||
Business interruption insurance receipts | 15,903 | 11,706 | 14,926 | |||||||||
Non-cash: | ||||||||||||
Like-kind exchange of property, plant and equipment | 4,353 | - | - | |||||||||
Settlement of Partnership notes | 14,088 | - | - | |||||||||
Distribution of property to minority interest | 14,811 | - | - |
Note 19—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.
Our reportable segment information is shown in the following tables:
Natural Gas Gathering and Processing | Logistics Assets | NGL Distribution and Marketing Services | Wholesale Marketing | Eliminations and Other | Total | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | $ | 1,835,266 | $ | 106,016 | $ | 4,613,423 | $ | 1,415,462 | $ | - | $ | 7,970,167 | ||||||||||||
Intersegment revenues | 1,605,053 | 131,995 | 571,296 | 44,587 | (2,352,931 | ) | - | |||||||||||||||||
Revenues | 3,440,319 | 238,011 | 5,184,719 | 1,460,049 | (2,352,931 | ) | 7,970,167 | |||||||||||||||||
Product purchases | 2,844,465 | (101 | ) | 3,445,263 | 900,186 | 7,189,811 | ||||||||||||||||||
Intersegment product purchases | 36,147 | 101 | 1,719,177 | 546,705 | (2,302,130 | ) | - | |||||||||||||||||
Product purchases | 2,880,612 | - | 5,164,440 | 1,446,890 | (2,302,131 | ) | 7,189,811 | |||||||||||||||||
Operating expenses | 134,959 | 138,439 | 1,746 | 58 | - | 275,202 | ||||||||||||||||||
Intersegment operating expenses | 812 | 49,989 | - | - | (50,801 | ) | - | |||||||||||||||||
Operating expenses | 135,771 | 188,428 | 1,746 | 58 | (50,801 | ) | 275,202 | |||||||||||||||||
Selling expense | - | - | - | - | - | - | ||||||||||||||||||
Operating margin | $ | 423,936 | $ | 49,583 | $ | 18,533 | $ | 13,102 | $ | - | $ | 505,154 | ||||||||||||
General and administrative | $ | 50,911 | $ | 20,186 | $ | 11,764 | $ | 14,333 | $ | (1,296 | ) | $ | 95,898 | |||||||||||
Equity in earnings of unconsolidated investments | $ | 10,162 | $ | 3,877 | $ | - | $ | - | $ | - | $ | 14,039 | ||||||||||||
Identifiable assets | $ | 2,403,893 | $ | 572,298 | $ | 148,449 | $ | 115,670 | $ | 408,267 | $ | 3,648,577 | ||||||||||||
Unconsolidated investments | - | 18,465 | - | - | - | 18,465 | ||||||||||||||||||
Capital expenditures | 99,003 | 41,460 | - | - | 5,086 | 145,549 |
Year Ended December 31, 2007 | ||||||||||||||||||||||||
Natural Gas Gathering and Processing | Logistics Assets | NGL Distribution and Marketing Services | Wholesale Marketing | Eliminations and Other | Total | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | $ | 1,494,905 | $ | 83,262 | $ | 4,419,636 | $ | 1,271,857 | $ | - | $ | 7,269,660 | ||||||||||||
Intersegment revenues | 1,423,012 | 111,968 | 476,178 | 30,795 | (2,041,953 | ) | - | |||||||||||||||||
Revenues | 2,917,917 | 195,230 | 4,895,814 | 1,302,652 | (2,041,953 | ) | 7,269,660 | |||||||||||||||||
Product purchases | 2,385,338 | - | 3,322,534 | 790,111 | - | 6,497,983 | ||||||||||||||||||
Intersegment product purchases | 2,571 | - | 1,516,288 | 489,707 | (2,008,566 | ) | - | |||||||||||||||||
Product purchases | 2,387,909 | - | 4,838,822 | 1,279,818 | (2,008,566 | ) | 6,497,983 | |||||||||||||||||
Operating expenses | 122,344 | 123,129 | 1,562 | 31 | - | 247,066 | ||||||||||||||||||
Intersegment operating expenses | 937 | 32,473 | (23 | ) | - | (33,387 | ) | - | ||||||||||||||||
Operating expenses | 123,281 | 155,602 | 1,539 | 31 | (33,387 | ) | 247,066 | |||||||||||||||||
Operating margin | $ | 406,727 | $ | 39,628 | $ | 55,453 | $ | 22,803 | $ | - | $ | 524,611 | ||||||||||||
General and administrative | $ | 48,170 | $ | 18,030 | $ | 9,818 | $ | 18,355 | $ | 1,680 | $ | 96,053 | ||||||||||||
Equity in earnings of unconsolidated investments | $ | 6,597 | $ | 3,511 | $ | - | $ | - | $ | - | $ | 10,108 | ||||||||||||
Identifiable assets | $ | 2,375,589 | $ | 554,801 | $ | 594,604 | $ | 239,734 | $ | 25,237 | $ | 3,789,965 | ||||||||||||
Unconsolidated investments | 28,767 | 19,238 | - | - | - | 48,005 | ||||||||||||||||||
Capital expenditures | 81,504 | 35,179 | - | - | 2,045 | 118,728 |
Year Ended December 31, 2006 | ||||||||||||||||||||||||
Natural Gas Gathering and Processing | Logistics Assets | NGL Distribution and Marketing Services | Wholesale Marketing | Eliminations and Other | Total | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | $ | 1,486,081 | $ | 63,813 | $ | 3,315,535 | $ | 1,267,452 | $ | - | $ | 6,132,881 | ||||||||||||
Intersegment revenues | 1,104,938 | 114,700 | 423,234 | 63,106 | (1,705,978 | ) | - | |||||||||||||||||
Revenues | 2,591,019 | 178,513 | 3,738,769 | 1,330,558 | (1,705,978 | ) | 6,132,881 | |||||||||||||||||
Product purchases | 2,064,436 | 3 | 2,496,448 | 879,945 | - | 5,440,832 | ||||||||||||||||||
Intersegment product purchases | 2,939 | (3 | ) | 1,229,673 | 440,646 | (1,673,255 | ) | - | ||||||||||||||||
Product purchases | 2,067,375 | - | 3,726,121 | 1,320,591 | (1,673,255 | ) | 5,440,832 | |||||||||||||||||
Operating expenses | 118,123 | 103,992 | 2,044 | 10 | - | 224,169 | ||||||||||||||||||
Intersegment operating expenses | 617 | 32,106 | - | - | (32,723 | ) | - | |||||||||||||||||
Operating expenses | 118,740 | 136,098 | 2,044 | 10 | (32,723 | ) | 224,169 | |||||||||||||||||
Operating margin | $ | 404,904 | $ | 42,415 | $ | 10,604 | $ | 9,957 | $ | - | $ | 467,880 | ||||||||||||
General and administrative | $ | 40,602 | $ | 14,043 | $ | 9,504 | $ | 17,818 | $ | 215 | $ | 82,182 | ||||||||||||
Equity in earnings of unconsolidated investments | $ | 7,214 | $ | 2,754 | $ | - | $ | - | $ | - | $ | 9,968 | ||||||||||||
Identifiable assets | $ | 2,375,589 | $ | 542,718 | �� | $ | 352,900 | $ | 158,015 | $ | 28,803 | $ | 3,458,025 | |||||||||||
Unconsolidated investments | 20,610 | 19,602 | - | - | - | 40,212 | ||||||||||||||||||
Capital expenditures | 115,261 | 23,167 | - | - | 4,474 | 142,902 |
The following table is a reconciliation of operating margin to net income for each period presented:
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
Reconciliation of operating margin to net income: | (In thousands) | |||||||||||
Operating margin | $ | 505,154 | $ | 524,611 | $ | 467,880 | ||||||
Depreciation and amortization expense | (160,948 | ) | (148,101 | ) | (149,687 | ) | ||||||
Income tax expense | (26,329 | ) | (31,331 | ) | (16,209 | ) | ||||||
Other, net | (67,045 | ) | (37,922 | ) | (16,199 | ) | ||||||
Interest income, net | (102,030 | ) | (142,632 | ) | (180,189 | ) | ||||||
General and administrative expense | (95,898 | ) | (96,053 | ) | (82,182 | ) | ||||||
Net income | $ | 52,904 | $ | 68,572 | $ | 23,414 |
Note 20—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 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, and more recently Hurricanes Gustav and Ike, as well as the current economic environment, have 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 21—Consolidating Financial Statements
We are the issuer of the Notes discussed in Note 10. 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. |
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Balance Sheet | ||||||||||||||||||||
December 31, 2008 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Assets | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | - | $ | 219,620 | $ | 143,149 | $ | - | $ | 362,769 | ||||||||||
Trade receivables and other current assets | 298 | 328,517 | 165,564 | - | 494,379 | |||||||||||||||
Total current assets | 298 | 548,137 | 308,713 | - | 857,148 | |||||||||||||||
Property, plant, and equipment, at cost | - | 837,268 | 2,255,996 | - | 3,093,264 | |||||||||||||||
Accumulated depreciation | - | 58,095 | (533,990 | ) | - | (475,895 | ) | |||||||||||||
Property, plant, and equipment, net | - | 895,363 | 1,722,006 | - | 2,617,369 | |||||||||||||||
Unconsolidated investments | - | 18,465 | - | - | 18,465 | |||||||||||||||
Investment in subsidiaries | (193,993 | ) | 307,175 | - | (113,183 | ) | - | |||||||||||||
Advance to (from) subsidiaries | (177,700 | ) | 131,971 | 45,729 | - | - | ||||||||||||||
Other assets | 146,950 | (75,141 | ) | 83,786 | - | 155,595 | ||||||||||||||
Total assets | $ | (224,445 | ) | $ | 1,825,970 | $ | 2,160,234 | $ | (113,183 | ) | $ | 3,648,577 | ||||||||
Liabilities and stockholder's equity | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable and other liabilities | $ | 50,735 | $ | 239,929 | $ | 164,380 | $ | - | $ | 455,044 | ||||||||||
Current maturities of debt | 12,500 | - | - | - | 12,500 | |||||||||||||||
Total current liabilities | 63,235 | 239,929 | 164,380 | - | 467,544 | |||||||||||||||
Long-term liabilities: | ||||||||||||||||||||
Long-term debt, net of current maturities | (900,976 | ) | 1,756,571 | 696,845 | - | 1,552,440 | ||||||||||||||
Other long-term obligations | 33,655 | 23,463 | 42,226 | - | 99,344 | |||||||||||||||
Total long-term liabilities | (867,321 | ) | 1,780,034 | 739,071 | - | 1,651,784 | ||||||||||||||
Minority interest/Non-controlling interest | - | - | - | 949,608 | 949,608 | |||||||||||||||
Stockholder's equity: | ||||||||||||||||||||
Stockholder's equity | 547,707 | (249,161 | ) | 1,184,538 | (935,377 | ) | 547,707 | |||||||||||||
Accumulated other comprehensive income (loss) | 31,934 | 55,168 | 72,245 | (127,414 | ) | 31,934 | ||||||||||||||
Total stockholder's equity | 579,641 | (193,993 | ) | 1,256,783 | (1,062,791 | ) | 579,641 | |||||||||||||
Total liabilities and stockholder's equity | $ | (224,445 | ) | $ | 1,825,970 | $ | 2,160,234 | $ | (113,183 | ) | $ | 3,648,577 |
Condensed Consolidating Balance Sheet | ||||||||||||||||||||
December 31, 2007 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Assets | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | - | $ | 88,303 | $ | 89,646 | $ | - | $ | 177,949 | ||||||||||
Trade receivables and other current assets | 25,130 | 954,910 | 104,387 | - | 1,084,427 | |||||||||||||||
Total current assets | 25,130 | 1,043,213 | 194,033 | - | 1,262,376 | |||||||||||||||
Property, plant, and equipment, at cost | - | 743,652 | 2,020,578 | - | 2,764,230 | |||||||||||||||
Accumulated depreciation | - | 94,265 | (428,425 | ) | - | (334,160 | ) | |||||||||||||
Property, plant, and equipment, net | - | 837,917 | 1,592,153 | - | 2,430,070 | |||||||||||||||
Unconsolidated investments | - | 48,005 | - | - | 48,005 | |||||||||||||||
Investment in subsidiaries | (258,084 | ) | 186,773 | - | 71,311 | - | ||||||||||||||
Advances to (from) subsidiaries | 66,953 | (172,735 | ) | 105,782 | - | - | ||||||||||||||
Other assets | 134,215 | (97,599 | ) | 12,898 | - | 49,514 | ||||||||||||||
Total assets | $ | (31,786 | ) | $ | 1,845,574 | $ | 1,904,866 | $ | 71,311 | $ | 3,789,965 | |||||||||
Liabilities and stockholders' equity | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Accounts payable and other liabilities | $ | 11,043 | $ | 657,736 | $ | 256,894 | $ | - | $ | 925,673 | ||||||||||
Current maturities of debt | 12,500 | - | - | - | 12,500 | |||||||||||||||
Total current liabilities | 23,543 | 657,736 | 256,894 | - | 938,173 | |||||||||||||||
Long-term liabilities: | ||||||||||||||||||||
Long-term debt, net of current maturities | (573,231 | ) | 1,345,406 | 626,300 | - | 1,398,475 | ||||||||||||||
Other long-term obligations | 25,498 | 100,516 | 19,773 | - | 145,787 | |||||||||||||||
Total long-term liabilities | (547,733 | ) | 1,445,922 | 646,073 | - | 1,544,262 | ||||||||||||||
Minority interest | - | - | - | 100,826 | 100,826 | |||||||||||||||
Noncontrolling interest in TRP LP | - | - | - | 714,300 | 714,300 | |||||||||||||||
Stockholders' equity: | - | - | - | - | ||||||||||||||||
Stockholders' equity | 548,520 | (185,979 | ) | 1,075,149 | (889,170 | ) | 548,520 | |||||||||||||
Accumulated other comprehensive income (loss) | (56,116 | ) | (72,105 | ) | (73,250 | ) | 145,355 | (56,116 | ) | |||||||||||
Total stockholder's equity | 492,404 | (258,084 | ) | 1,001,899 | (743,815 | ) | 492,404 | |||||||||||||
Total liabilities and stockholders' equity | $ | (31,786 | ) | $ | 1,845,574 | $ | 1,904,866 | $ | 71,311 | $ | 3,789,965 | |||||||||
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Statement of Operations | ||||||||||||||||||||
Year Ended December 31, 2008 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Revenues | $ | - | $ | 7,162,547 | $ | 2,810,479 | $ | (2,002,859 | ) | $ | 7,970,167 | |||||||||
Operating costs and expenses: | ||||||||||||||||||||
Product purchases | - | 6,860,201 | 2,272,592 | (1,942,982 | ) | 7,189,811 | ||||||||||||||
Operating expenses | - | 146,260 | 188,819 | (59,877 | ) | 275,202 | ||||||||||||||
Depreciation and amortization expense | - | 51,313 | 109,635 | - | 160,948 | |||||||||||||||
General and administrative and other | (1,297 | ) | 37,947 | 72,622 | - | 109,272 | ||||||||||||||
(1,297 | ) | 7,095,721 | 2,643,668 | (2,002,859 | ) | 7,735,233 | ||||||||||||||
Income from operations | 1,297 | 66,826 | 166,811 | - | 234,934 | |||||||||||||||
Other income (expense): | ||||||||||||||||||||
Interest expense, net | 87,816 | (152,197 | ) | (37,649 | ) | - | (102,030 | ) | ||||||||||||
Equity in earnings of unconsolidated investments | - | 14,039 | - | - | 14,039 | |||||||||||||||
Equity in earnings of subsidiaries | (27,047 | ) | 44,578 | - | (17,531 | ) | - | |||||||||||||
Minority interest/non-controlling interest | - | - | - | (98,026 | ) | (98,026 | ) | |||||||||||||
Other income (expense) | 17,167 | (293 | ) | 13,442 | - | 30,316 | ||||||||||||||
Income before income tax | 79,233 | (27,047 | ) | 142,604 | (115,557 | ) | 79,233 | |||||||||||||
Income tax (expense) benefit | (26,329 | ) | - | (1,400 | ) | 1,400 | (26,329 | ) | ||||||||||||
Net income (loss) | $ | 52,904 | $ | (27,047 | ) | $ | 141,204 | $ | (114,157 | ) | $ | 52,904 | ||||||||
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Statement of Operations | ||||||||||||||||||||
Year Ended December 31, 2007 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Revenues: | $ | - | $ | 6,647,004 | $ | 2,258,305 | $ | (1,635,649 | ) | $ | 7,269,660 | |||||||||
Operating costs and expenses: | ||||||||||||||||||||
Product purchases | - | 6,294,234 | 1,796,416 | (1,592,667 | ) | 6,497,983 | ||||||||||||||
Operating expenses | - | 135,823 | 154,225 | (42,982 | ) | 247,066 | ||||||||||||||
Depreciation and amortization expense | - | 49,183 | 98,918 | - | 148,101 | |||||||||||||||
General and administrative and other | 925 | 75,071 | 19,958 | - | 95,954 | |||||||||||||||
925 | 6,554,311 | 2,069,517 | (1,635,649 | ) | 6,989,104 | |||||||||||||||
Income (loss) from operations | (925 | ) | 92,693 | 188,788 | - | 280,556 | ||||||||||||||
Other income (expense): | ||||||||||||||||||||
Interest income (expense), net | (1,914 | ) | (110,010 | ) | (30,708 | ) | - | (142,632 | ) | |||||||||||
Equity in earnings of unconsolidated investments | - | 10,108 | - | - | 10,108 | |||||||||||||||
Equity in earnings of subsidiaries | 102,300 | 109,411 | - | (211,711 | ) | - | ||||||||||||||
Minority interest/non-controlling interest | - | - | - | (48,129 | ) | (48,129 | ) | |||||||||||||
Income before income taxes | 99,461 | 102,202 | 158,080 | (259,840 | ) | 99,903 | ||||||||||||||
Income tax (expense) benefit | (30,889 | ) | 98 | (1,479 | ) | 939 | (31,331 | ) | ||||||||||||
Net income | $ | 68,572 | $ | 102,300 | $ | 156,601 | $ | (258,901 | ) | $ | 68,572 | |||||||||
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Statement of Operations | ||||||||||||||||||||
Year Ended December 31, 2006 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Revenues: | $ | - | $ | 5,343,654 | $ | 2,293,765 | $ | (1,504,538 | ) | $ | 6,132,881 | |||||||||
Operating costs and expenses: | ||||||||||||||||||||
Product purchases | - | 5,041,129 | 1,863,201 | (1,463,498 | ) | 5,440,832 | ||||||||||||||
Operating expenses | - | 116,085 | 149,124 | (41,040 | ) | 224,169 | ||||||||||||||
Depreciation and amortization expense | - | 52,185 | 97,502 | - | 149,687 | |||||||||||||||
General and administrative and other | 161 | 65,820 | 16,370 | - | 82,351 | |||||||||||||||
161 | 5,275,219 | 2,126,197 | (1,504,538 | ) | 5,897,039 | |||||||||||||||
Income (loss) from operations | (161 | ) | 68,435 | 167,568 | - | 235,842 | ||||||||||||||
Other income (expense): | ||||||||||||||||||||
Interest income (expense), net | - | (181,417 | ) | 1,228 | - | (180,189 | ) | |||||||||||||
Equity in earnings of unconsolidated investments | - | 9,968 | - | - | 9,968 | |||||||||||||||
Equity in earnings of subsidiaries | 39,784 | 139,872 | - | (179,656 | ) | - | ||||||||||||||
Minority interest | - | - | - | (25,998 | ) | (25,998 | ) | |||||||||||||
Income before income taxes | 39,623 | 36,858 | 168,796 | (205,654 | ) | 39,623 | ||||||||||||||
Income tax (expense) benefit | (16,209 | ) | 2,926 | (2,926 | ) | - | (16,209 | ) | ||||||||||||
Net income | $ | 23,414 | $ | 39,784 | $ | 165,870 | $ | (205,654 | ) | $ | 23,414 |
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Statement of Cash Flows | ||||||||||||||||||||
Year Ended December 31, 2008 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities | ||||||||||||||||||||
Net income (loss) | $ | 52,904 | $ | (27,047 | ) | $ | 141,204 | $ | (114,157 | ) | $ | 52,904 | ||||||||
Adjustments to reconcile net income (loss) to net cash | ||||||||||||||||||||
provided by (used in)operating activities: | ||||||||||||||||||||
Depreciation, amortization and accretion | 6,473 | 52,058 | 113,229 | - | 171,760 | |||||||||||||||
Deferred income taxes | 25,084 | - | 1,400 | (1,400 | ) | 25,084 | ||||||||||||||
Earnings (loss) from unconsolidated investments | - | (14,039 | ) | - | - | (14,039 | ) | |||||||||||||
Equity in earnings of subsidiaries | 27,047 | (44,578 | ) | - | 17,531 | - | ||||||||||||||
Other | (18,566 | ) | (36,640 | ) | (135,649 | ) | 98,026 | (92,829 | ) | |||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||||||
Accounts receivable and other assets | 9,553 | 531,331 | 60,768 | - | 601,652 | |||||||||||||||
Inventory | - | 72,339 | 487 | - | 72,826 | |||||||||||||||
Accounts payable and other liabilities | (5,451 | ) | (443,276 | ) | (67,969 | ) | - | (516,696 | ) | |||||||||||
Net cash provided by (used in) operating activities | 97,044 | 90,148 | 113,470 | - | 300,662 | |||||||||||||||
Cash flows from investing activities | ||||||||||||||||||||
Purchases of property and equipment | - | (53,498 | ) | (78,791 | ) | - | (132,289 | ) | ||||||||||||
Other | (16,400 | ) | 22,048 | (96,491 | ) | - | (90,843 | ) | ||||||||||||
Net cash used in investing activities | (16,400 | ) | (31,450 | ) | (175,282 | ) | - | (223,132 | ) | |||||||||||
Cash flows from financing activities | ||||||||||||||||||||
Borrowings | 95,920 | - | 435,265 | - | 531,185 | |||||||||||||||
Repayments and repurchases | (12,500 | ) | - | (350,632 | ) | - | (363,132 | ) | ||||||||||||
Other | (123 | ) | 300 | (7,079 | ) | - | (6,902 | ) | ||||||||||||
Receipts from (payments to) subsidiaries | (163,941 | ) | 72,319 | 37,761 | - | (53,861 | ) | |||||||||||||
Net cash provided by (used in) financing activities | (80,644 | ) | 72,619 | 115,315 | - | 107,290 | ||||||||||||||
Net increase (decrease) in cash and cash equivalents | - | 131,317 | 53,503 | - | 184,820 | |||||||||||||||
Cash and cash equivalents, beginning of period | - | 88,303 | 89,646 | - | 177,949 | |||||||||||||||
Cash and cash equivalents, end of period | $ | - | $ | 219,620 | $ | 143,149 | $ | - | $ | 362,769 | ||||||||||
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Statement of Cash Flows | ||||||||||||||||||||
Year Ended December 31, 2007 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities | ||||||||||||||||||||
Net income (loss) | $ | 68,572 | $ | 102,300 | $ | 156,601 | $ | (258,901 | ) | $ | 68,572 | |||||||||
Adjustments to reconcile net income (loss) to net cash | ||||||||||||||||||||
provided by (used in)operating activities: | ||||||||||||||||||||
Depreciation, amortization and accretion | 11,969 | 49,628 | 100,363 | - | 161,960 | |||||||||||||||
Deferred income taxes | 30,616 | - | 1,479 | (939 | ) | 31,156 | ||||||||||||||
Earnings (loss) from unconsolidated investments | - | (10,108 | ) | - | - | (10,108 | ) | |||||||||||||
Equity in earnings (losses) of subsidiaries | (102,300 | ) | (109,411 | ) | - | 211,711 | - | |||||||||||||
Minority interest/Non-controlling interest | - | - | - | 48,129 | 48,129 | |||||||||||||||
Other | 2,040 | (35,482 | ) | (48,417 | ) | - | (81,859 | ) | ||||||||||||
Changes in operating assets and liabilities: | - | - | - | - | - | |||||||||||||||
Accounts receivable and other assets | (286,342 | ) | (38,041 | ) | (11,371 | ) | - | (335,754 | ) | |||||||||||
Inventory | - | (26,068 | ) | (161 | ) | - | (26,229 | ) | ||||||||||||
Accounts payable and other liabilities | (131,453 | ) | 386,450 | 49,738 | - | 286,735 | ||||||||||||||
Net cash provided by (used in) operating activities | (406,898 | ) | 301,268 | 248,232 | - | 142,602 | ||||||||||||||
Cash flows from investing activities | ||||||||||||||||||||
Purchases of property and equipment | - | (51,999 | ) | (66,422 | ) | - | (118,421 | ) | ||||||||||||
Other | - | 22,180 | 352 | - | 22,532 | |||||||||||||||
Net cash used in investing activities | - | (29,819 | ) | (66,070 | ) | - | (95,889 | ) | ||||||||||||
Cash flows from financing activities | ||||||||||||||||||||
Senior secured credit facility: | ||||||||||||||||||||
Borrowings | - | - | 721,300 | - | 721,300 | |||||||||||||||
Repayments | (1,399,700 | ) | - | (95,000 | ) | - | (1,494,700 | ) | ||||||||||||
Non-controlling investment in Targa Resources Partners LP | - | - | 771,834 | - | 771,834 | |||||||||||||||
Other | (991 | ) | - | (8,946 | ) | - | (9,937 | ) | ||||||||||||
Receipts from (payments to) subsidiaries | 1,807,589 | (300,807 | ) | (1,506,782 | ) | - | - | |||||||||||||
Net cash provided by (used in) financing activities | 406,898 | (300,807 | ) | (117,594 | ) | - | (11,503 | ) | ||||||||||||
- | ||||||||||||||||||||
Net increase in cash and cash equivalents | - | (29,358 | ) | 64,568 | - | 35,210 | ||||||||||||||
Cash and cash equivalents, beginning of year | - | 117,661 | 25,078 | - | 142,739 | |||||||||||||||
Cash and cash equivalents, end of year | $ | - | $ | 88,303 | $ | 89,646 | $ | - | $ | 177,949 | ||||||||||
Targa Resources, Inc. | ||||||||||||||||||||
Condensed Consolidating Statement of Cash Flows | ||||||||||||||||||||
Year Ended December 31, 2006 | ||||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Intercompany Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities | ||||||||||||||||||||
Net income (loss) | $ | 23,414 | $ | 39,784 | $ | 165,870 | $ | (205,654 | ) | $ | 23,414 | |||||||||
Adjustments to reconcile net income (loss) to net cash | ||||||||||||||||||||
provided by (used in)operating activities: | ||||||||||||||||||||
Depreciation, amortization and accretion | - | 85,717 | 77,859 | - | 163,576 | |||||||||||||||
Deferred income taxes | 16,141 | (2,892 | ) | 2,926 | - | 16,175 | ||||||||||||||
Earnings (loss) from unconsolidated investments | - | (9,968 | ) | - | - | (9,968 | ) | |||||||||||||
Equity in earnings (losses) of subsidiaries | (39,784 | ) | (139,872 | ) | - | 179,656 | - | |||||||||||||
Minority interest/Non-controlling interest | - | (25,998 | ) | - | (25,998 | ) | ||||||||||||||
Other | - | (38,252 | ) | 7,700 | 25,998 | (4,554 | ) | |||||||||||||
Changes in operating assets and liabilities: | - | - | - | - | - | |||||||||||||||
Accounts receivable and other assets | 347 | (79,104 | ) | 75,845 | - | (2,912 | ) | |||||||||||||
Inventory | - | 34,328 | 2,182 | - | 36,510 | |||||||||||||||
Accounts payable and other liabilities | (18,243 | ) | 106,188 | (50,902 | ) | - | 37,043 | |||||||||||||
Net cash provided by (used in) operating activities | (18,125 | ) | (4,071 | ) | 255,482 | - | 233,286 | |||||||||||||
Cash flows from investing activities | ||||||||||||||||||||
Purchases of property and equipment | - | (95,557 | ) | (41,108 | ) | - | (136,665 | ) | ||||||||||||
Proceeds from property insurance | - | 27,221 | - | - | 27,221 | |||||||||||||||
Investment in unconsolidated affiliate | - | (9,102 | ) | - | - | (9,102 | ) | |||||||||||||
Other | - | 1,008 | (274 | ) | - | 734 | ||||||||||||||
Net cash used in investing activities | - | (76,430 | ) | (41,382 | ) | - | (117,812 | ) | ||||||||||||
Cash flows from financing activities | ||||||||||||||||||||
Senior secured credit facility: | ||||||||||||||||||||
Borrowings | - | - | - | - | - | |||||||||||||||
Repayments | (12,500 | ) | - | - | - | (12,500 | ) | |||||||||||||
Proceeds from issuance of long-term debt | - | - | - | - | - | |||||||||||||||
Repayment of long-term debt | - | - | - | - | - | |||||||||||||||
Parent contributions (distributions) | - | 173,364 | (174,333 | ) | - | (969 | ) | |||||||||||||
Receipts from (payments to) subsidiaries | 31,318 | 15,174 | (46,492 | ) | - | - | ||||||||||||||
Costs incurred in connection with financing arrangements | (693 | ) | - | - | - | (693 | ) | |||||||||||||
Net cash provided by financing activities | 18,125 | 188,538 | (220,825 | ) | - | (14,162 | ) | |||||||||||||
Net increase in cash and cash equivalents | - | 108,037 | (6,725 | ) | - | 101,312 | ||||||||||||||
Cash and cash equivalents, beginning of year | - | 9,624 | 31,803 | - | 41,427 | |||||||||||||||
Cash and cash equivalents, end of year | $ | - | $ | 117,661 | $ | 25,078 | $ | - | $ | 142,739 |
Index to Exhibits
3.1 | Amended and Restated Certificate of Incorporation of Targa Resources, Inc. (incorporated by reference to Exhibit 3.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.2 | Amended and Restated Bylaws of Targa Resources, Inc. (incorporated by reference to Exhibit 3.2 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.3 | Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.3 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.4 | Certificate of Amendment of the Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.4 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
3.5 | Bylaws of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.5 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
4.1 | Indenture dated October 31, 2005 among Targa Resources, Inc., Targa Resources Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.3 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
4.2 | Supplemental Indenture dated October 31, 2008, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. (incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Quarterly Report on Form 10-Q filed November 12. 2008 (File No. 333-147066)). |
4.3* | Supplemental Indenture dated February 14, 2007, among Targa Resources GP LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. |
4.4* | Supplemental Indenture dated March 15, 2006, among Targa LSNG GP LLC and Targa LSNG LP, subsidiaries of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. |
4.5* | Supplemental Indenture dated December 22, 2005, among Targa GP Inc., Targa LP Inc., Targa North Texas GP LLC, Targa Versado GP LLC, Targa Straddle GP LLC, Targa Permian GP LLC, Targa Downstream GP LLC, Targa North Texas LP, Targa Versado LP, Targa Straddle LP, Targa Permian LP, and Targa Downstream LP, subsidiaries of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. |
4.6* | Supplemental Indenture dated December 14, 2005, among Targa Gas Marketing LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association. |
4.7 | Registration Rights Agreement, dated as of October 31, 2005, among Targa Resources, Inc., Targa Resources Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.4 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
4.8 | Indenture dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Form 10-Q filed August 11, 2008 (File No. 333-147066)). |
4.9 | Registration Rights Agreement dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporations, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources, Inc.’s Quarterly Report on Form 10-Q filed August 11, 2008 (File No. 333-147066)). |
10.1 | Credit Agreement dated October 31, 2005 between Targa Resources Inc., the Lenders named therein and Credit Suisse, as Administrative Agent, Swing Line Lender, Revolving L/C Issuer and Synthetic L/C Issuer (incorporated by reference to Exhibit 10.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)). |
10.2 | Targa Resources Investments Inc. Amended and Restated Stockholders’ Agreement dated as of October 31, 2005 (incorporated by reference to Exhibit 10.2 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.3 | First Amendment to Amended and Restated Stockholders’ Agreement, dated January 26, 2006 (incorporated by reference to Exhibit 10.3 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.4 | Second Amendment to Amended and Restated Stockholders’ Agreement dated March 30, 2007 (incorporated by reference to Exhibit 10.4 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.5 | Third Amendment to Amended and Restated Stockholders’ Agreement dated May 1, 2007 (incorporated by reference to Exhibit 10.5 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.6 | Fourth Amendment to Amended and Restated Stockholders’ Agreement dated December 7, 2007 (incorporated by reference to Exhibit 10.6 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.7+ | Targa Resources, Inc. 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.7 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.8+ | Amendment to and Assumption of Targa Resources, Inc. 2004 Stock Incentive Plan (incorporated by reference to Exhibit 10.8 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.9+ | Amendment to Targa Resources, Inc. 2004 Stock Incentive Plan (as Assumed and Amended) (incorporated by reference to Exhibit 10.9 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.10+ | Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.10 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.11+ | First Amendment to Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.11 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.12+ | Second Amendment to Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.12 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.13+ | Form of Targa Resources Investments Inc. Nonstatutory Stock Option Agreement (Non-Employee Director) (incorporated by reference to Exhibit 10.13 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.14+ | Form of Targa Resources Investments Inc. Nonstatutory Stock Option Agreement (Non-Director Management and Other Employees) (incorporated by reference to Exhibit 10.14 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.15+ | Form of Targa Resources Investments Inc. Incentive Stock Option Agreement (incorporated by reference to Exhibit 10.15 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.16+ | Form of Targa Resources Investments Inc. Restricted Stock Agreement (incorporated by reference to Exhibit 10.16 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.17+ | Form of Targa Resources Investments Inc. Restricted Stock Agreement (relating to preferred stock option exchange for directors) (incorporated by reference to Exhibit 10.17 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.18+ | Form of Targa Resources Investments Inc. Restricted Stock Agreement (relating to preferred stock option exchange for employees) (incorporated by reference to Exhibit 10.18 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.19+ | Targa Resources, Inc. Bonus Plan (incorporated by reference to Exhibit 10.19 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.20+ | Form of Targa Resources, Inc. Bonus Agreement (for directors) (incorporated by reference to Exhibit 10.20 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.21+ | Form of Targa Resources, Inc. Bonus Agreement (for executives) (incorporated by reference to Exhibit 10.21 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.22+ | Targa Resources Investments Inc. Change of Control Executive Officer Severance Program (incorporated by reference to Exhibit 10.22 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.23+ | Targa Resources, Inc. 2008 Annual Incentive Plan (incorporated by reference to Exhibit 10.25 to Targa Resources, Inc.’s Annual Report on Form 10-K filed March 31, 2008 (File No. 333-147006)). |
10.24+* | Targa Resources, Inc. 2009 Annual Incentive Plan |
10.25+ | Targa Resources Partners LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.25 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.26+* | Amendment to Targa Resources Partners LP Long-Term Incentive Plan dated December 18, 2008. |
10.27+ | Form of Restricted Unit Grant Agreement (incorporated by reference to Exhibit 10.26 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.28+ | Targa Resources Investments Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.27 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.29+ | Form of Performance Unit Grant Agreement (incorporated by reference to Exhibit 10.2 .to Targa Resources, Inc.’s Current Report on Form 8-K filed January 28, 2009 (File No. 333-147066)). |
10.30 | Credit Agreement, dated February 14, 2007, by and among Targa Resources Partners LP, as Borrower, Bank of America, N.A., as Administrative Agent, Wachovia Bank, N.A., as Syndication Agent, Merrill Lynch Capital, Royal Bank of Canada and The Royal Bank of Scotland PLC, as Co-Documentation Agents, and the other lenders part thereto (incorporated by reference to Exhibit 10.29 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.31 | First Amendment to Credit Agreement dated October 24, 2007 by and among Targa Resources Partners LP, as Borrower, Bank of America, N.A., as Administrative Agent, Collateral Agent, Swing Line Lender and L/C Issuer and the other lenders party thereto (incorporated by reference to Exhibit 10.30 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.32 | Commitment Increase Supplement made as of October 24, 2007 by and among Targa Resources Partners LP, Bank of America, N.A., as Administrative Agent, Collateral Agent, Swing Line Lender and L/C Issuer and the other parties thereto (incorporated by reference to Exhibit 10.31 to Targa Resources, Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). |
10.33 | Commitment Increase Supplement, dated June 18, 2008, by and among Targa Resources Partners LP, Bank of America, N.A. and other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources, Inc.’s Quarterly Report on Form 10-Q filed August 11, 2008 (File No. 333-147066)). |
10.34* | Amended and Restated Omnibus Agreement, dated October 24, 2007, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC. |
21.1* | Subsidiaries of Targa Resources, Inc. |
31.1* | Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934. |
31.2* | Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934. |
32.1* | Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.2* | Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
____
+ Management contract or compensation plan or arrangement. |
* Filed herewith. |