Item 1.
Business.
Overview
Targa Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. We do not directly own any operating assets; our main source of future revenue therefore is from general and limited partner interests, including incentive distribution rights (“IDRs”), in the Partnership, a publicly traded Delaware limited partnership (NYSE: NGLS) that is a leading provider of midstream natural gas and natural gas liquid services in the United States. The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas and storing, fractionating, treating, transporting, terminaling and selling NGLs, NGL products, and gathering, storing and terminaling crude oil and refined petroleum products.
On December 10, 2010, we completed an initial public offering (“IPO”) of common shares in the Company. In the IPO, the selling shareholders, including a member of our senior management, sold 18,831,250 common shares at a price of $22.00 per share. We did not receive any proceeds from the sale of shares by the selling shareholders. On completion of the IPO, there were 42,292,348 shares outstanding.
Financial Presentation
One of our indirect subsidiaries is the sole general partner of the Partnership. Because we control the general partner, under generally accepted accounting principles we must reflect our ownership interest in the Partnership on a consolidated basis. Accordingly, the Partnership’s financial results are included in our consolidated financial statements even though the distribution or transfer of Partnership assets are limited by the terms of the partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by us are reflected in our results of operations as net income attributable to noncontrolling interests. Throughout this Annual Report, we make a distinction where relevant between financial results and disclosures applicable to the Partnership versus those applicable to us as a standalone parent including our non-Partnership subsidiaries (“Non-Partnership”). In addition, we provide condensed Parent only financial statements as required by the SEC.
The Partnership files its own separate Annual Report. The financial results and dividends to our shareholders included in our consolidated financial statements will differ from the financial results and distributions of the Partnership primarily due to the financial effects of:
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noncontrolling interest in the Partnership;
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our separate debt obligations;
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certain general and administrative costs applicable to us as a public company;
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federal income taxes; and
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certain non-operating assets and liabilities that we retained.
Overview of the Business of Targa Resources Corp.
Our primary business objective is to increase our cash available for dividends to our stockholders by assisting the Partnership in executing its business strategy. We may facilitate the Partnership’s growth through various forms of financial support, including, but not limited to, modifying the Partnership’s IDRs, exercising the Partnership’s IDR reset provision contained in its partnership agreement, making loans, making capital contributions in exchange for yielding or non-yielding equity interests or providing other financial support to the Partnership, if needed, to support its ability to make distributions. In addition, we may acquire assets that could be candidates for acquisition by the Partnership, potentially after operational or commercial improvement or further development.
At February 15, 2013, our interests in the Partnership consist of the following:
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a 2% general partner interest, which we hold through our 100% ownership interest in the general partner;
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all of the outstanding IDRs; and
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12,945,659 of the 101,788,617 outstanding common units of the Partnership, representing a 12.7% limited partnership interest.
Our cash flows are generated from the cash distributions we receive from the Partnership. The Partnership is required to distribute all available cash at the end of each quarter after establishing reserves to provide for the proper conduct of its business or to provide for future distributions. Our ownership of the general partner interest entitles us to receive 2% of all cash distributed in a quarter.
Our ownership of the IDRs of the Partnership entitles us to receive:
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13% of all cash distributed in a quarter after $0.3881 has been distributed in respect of each common unit of the Partnership for that quarter;
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23% of all cash distributed in a quarter after $0.4219 has been distributed in respect of each common unit of the Partnership for that quarter; and
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48% of all cash distributed in a quarter after $0.50625 has been distributed in respect of each common unit of the Partnership for that quarter.
We are party to an Omnibus Agreement with the Partnership that governs the relationship regarding certain reimbursement and indemnification matters. The Partnership agreement will govern these matters after the Omnibus Agreement expires on April 30, 2013. So long as our only cash generating asset is our interests in the Partnership, we will continue to allocate to the Partnership substantially all of our general and administrative costs other than our direct costs of being a reporting company. See “Item 13. Certain Relationships and Related Transactions, and Director Independence-Omnibus Agreement.”
We employ 1,192 people. See “Employees.” The Partnership does not have any employees to carry out its operations.
Overview of the Business of the Partnership
We formed the Partnership in October 2006 to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. The Partnership is a leading provider of midstream natural gas, NGL, terminaling and crude oil gathering services in the United States. It is engaged in the business of:
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gathering, compressing, treating, processing and selling natural gas;
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storing, fractionating, treating, transporting and selling NGLs and NGL products;
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gathering, storage and terminaling crude oil, and
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storing, terminaling and selling refined petroleum products.
The Partnership operates in two primary divisions: (i) Gathering and Processing, consisting of two reportable segments-(a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing, consisting of two reportable segments-(a) Logistics Assets and (b) Marketing and Distribution.
Acquisitions from Targa
From 2007 through 2010, the Partnership acquired most of its operating businesses in a series of acquisitions from us with an aggregate purchase price of approximately $3.1 billion. The businesses include:
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In February 2007, the Partnership acquired certain natural gas gathering, processing and treating assets in the Fort Worth Basin / Bend Arch in North Texas and their operations collectively referred to as the “North Texas System;”
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In October 2007, the Partnership acquired certain natural gas gathering, processing and treating assets in West Texas and their operations collectively referred to as “SAOU;”
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In October 2007, the Partnership acquired certain natural gas gathering, processing and treating assets in Southwest Louisiana and their operations collectively referred to as “LOU;”
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In September 2009, the Partnership acquired our NGL business consisting of fractionation facilities, storage and terminaling facilities, low sulfur natural gasoline treating facilities, pipeline transportation and distribution assets, propane storage, truck terminals and NGL transport assets and their operations collectively referred to as the Logistics and Marketing division or the “Downstream Business;”
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In April 2010, the Partnership acquired certain natural gas gathering and processing assets which serve production from the Louisiana Gulf Coast and their operations collectively referred to as the “Coastal Straddles;”
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In April 2010, the Partnership acquired certain natural gas gathering and processing systems, processing plants and related assets in West Texas and their operations collectively referred to as “Sand Hills;”
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In August 2010, the Partnership acquired our 63% ownership interest in Versado Gas Processors, L.L.C. which conducts a natural gas gathering and processing business in New Mexico, collectively referred to as “Versado;” and
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In September 2010, the Partnership acquired our 77% ownership interest in Venice Energy Services Company, L.L.C., a joint venture that owns and operates a natural gas gathering and processing business in Louisiana consisting of a coastal straddle plant and their operations and a wholly-owned subsidiary that owns and operates an offshore gathering system and related assets (collectively, “VESCO”) that serve production from the Gulf of Mexico shelf and deepwater.
For a detailed description of these assets, please see “- The Partnership’s Business Operations.”
Acquisitions from Third Parties
While the Partnership’s growth through 2010 was primarily driven by the implementation of a dropdown strategy, it also had a record of successful third-party acquisitions. During 2011 and 2012, the Partnership closed the following acquisitions:
Badlands
On December 31, 2012, the Partnership acquired Saddle Butte Pipeline LLC’s crude oil gathering pipeline and terminal system and natural gas gathering and processing operations, collectively referred to as “Badlands” for cash consideration of $975.8 million subject to customary purchase price adjustments and a contingent payment of $50 million that is conditioned upon aggregate crude oil gathering volumes exceeding certain thresholds by mid-2014. The business is located in the Williston Basin in the McKenzie, Dunn and Mountrail counties of North Dakota and includes approximately 155 miles of crude oil gathering pipelines. The acquired business has combined crude oil operational storage capacity of 70,000 barrels with a combined estimated throughput of 32,000 barrels per day. It also includes approximately 95 miles of natural gas gathering pipelines and a 20 MMcf/d natural gas processing plant with an expansion underway to increase capacity to 40 MMcf/d. As of December 31, 2012, the system had approximately 260,000 acres dedicated for crude oil gathering and over 100,000 acres dedicated for natural gas gathering. We are actively pursuing gathering opportunities such that we expect additional acreage dedications from producers active in the Bakken Shale as we expand our operations. As this acquisition closed on December 31, 2012, it had no impact on the Partnership’s results of operations for 2012, other than transaction costs related to the acquisition. See Note 4 in our “Consolidated Financial Statements” for pro forma financial information related to the Partnership’s Badlands acquisition.
Other Acquisitions
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In March 2011, the Partnership acquired a refined petroleum products and crude oil storage and terminaling facility in Channelview, Texas on Carpenter's Bayou along the Houston Ship Channel (the "Channelview Terminal") for $29 million. The Channelview Terminal, with storage capacity of 544,000 barrels, can handle multiple grades of blend stocks, petroleum products and crude oil and has potential for expansion, as well as integration with the Partnership’s other logistics operations.
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In September 2011, the Partnership acquired refined petroleum products and crude oil storage and terminaling facilities in two separate transactions. The facility on the Hylebos Waterway in the Port of Tacoma, Washington (the “Sound Terminal”) has 758,000 barrels of capacity and handles refined petroleum products, crude oil, LPGs and biofuels, including ethanol and biodiesel. The facility on the Patapsco River in Baltimore, Maryland (the “Baltimore Terminal”) has approximately 505,000 barrels of storage capacity. Both terminals contain blending and heating capabilities, and have tanker truck and barge loading and unloading infrastructure. Total cash consideration including working capital for both facilities was $135 million.
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In July 2012, the Partnership acquired the Big Lake gas processing plant in Lake Charles, Louisiana, with a gross processing capacity of 200 MMcf/d.
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In December 2012, the Partnership acquired additional property on the Houston Ship Channel (“Targa Patriot Marine Terminal” or “Patriot Terminal”). The Partnership’s initial investment including the acquisition of the property and initial dock upgrades will be approximately $25 million. While not currently operational, the acquisition of the Patriot Terminal provides expansion potential for both our Petroleum Logistics business and propane/butane export capabilities.
The Partnership has funded all acquisitions from Targa and third parties using earnings from operations, proceeds of equity offerings, borrowings under its credit facilities and note issuances. We expect that acquisitions of third-party businesses and assets will continue to be a significant component of the Partnership’s growth strategy.
Organic Growth Projects
In addition to acquiring businesses and assets from us and third parties, the Partnership has successfully completed both large and small organic growth projects associated with its existing assets and expects to continue to do so in the future. These projects have involved growth capital expenditures of approximately $1 billion since 2007 and include the following projects completed in 2012:
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Benzene treating project. A new treater was constructed which operates in conjunction with the Partnership’s existing low sulfur natural gasoline (“LSNG”) facility at Mont Belvieu and is designed to reduce benzene content of natural gasoline to meet new, more stringent environmental standards. The gross cost was approximately $40 million and was completed in the first quarter of 2012.
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Gulf Coast Fractionators expansion. In the second quarter of 2012, Gulf Coast Fractionators (“GCF”), a partnership with Phillips 66 and Devon Energy Corporation, in which the Partnership owns a 38.8% interest, completed an expansion to increase the capacity of its NGL fractionation facility in Mont Belvieu. The gross cost was approximately $92 million (the Partnership’s net cost was approximately $35 million) for an estimated ultimate capacity of approximately 145 MBbl/d.
The Partnership has the following major organic growth projects either underway or announced, which it estimates will require approximately $1.3 billion in future growth capital expenditures through 2014:
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Cedar Bayou Fractionators expansion. The Partnership is currently constructing approximately 100 MBbl/d of additional fractionation capacity (“Train 4”) at its 88% owned Cedar Bayou Fractionator (“CBF”) in Mont Belvieu for an estimated gross cost of $385 million. The expected start-up of the Train 4 facilities is in the second quarter of 2013.
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North Texas Longhorn plant. The Partnership has commenced spending associated with a new 200 MMcf/d cryogenic processing plant for its North Texas System, with an expected completion in third quarter 2013, subject to regulatory approvals, and an estimated capital investment of approximately $150 million for the plant and associated projects.
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International export projects. Construction is underway to expand the Partnership’s propane and butane international export capacity. The Partnership expects to invest a total of approximately $480 million in connection with the expanded project to improve and expand its Mont Belvieu complex and existing import/export marine terminals at Galena Park. The anticipated completion date for the initial portion of the project is in the third quarter of 2013, and we expect to complete the expanded portion of the project in the third quarter of 2014.
As mentioned previously, in December 2012, the Partnership acquired the Targa Patriot Marine Terminal near its existing marine terminal in Galena Park. The Partnership’s investment, including acquisition of the property and initial dock upgrades, will be approximately $25 million. Plans are being developed to utilize the facility for petroleum products and/or propane/butane exports.
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Petroleum logistics terminal expansions. The Partnership has started projects to expand the capacity and capability of the three refined products terminals that it acquired in 2011. The Partnership expects to invest approximately $105 million on these projects.
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SAOU High Plains plant. The Partnership has commenced spending associated with a new 200 MMcf/d cryogenic processing plant and related gathering and compression facilities for SAOU to meet increasing production and continued producer activity on the eastern side of the Permian Basin, with an anticipated completion date in mid-2014. The Partnership expects to invest an estimated $225 million for the plant and associated projects.
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Badlands expansion. The Partnership has announced preliminary plans to invest over $250 million during 2013 to support additional infrastructure necessary to meet producer activity at its Badlands gathering systems and facilities in North Dakota.
Growth Drivers
The Partnership believes its near-term growth will be driven by its significant organic growth investments as well as strong supply and demand fundamentals for the Partnership's existing businesses. The Partnership’s believes that its assets are not easily duplicated and are located in active producing areas and near key NGL markets and logistics centers. Over the longer term, we expect the Partnership's growth will continue to be driven by shale plays and by the deployment of shale exploration and production technologies in both liquids-rich natural gas and crude oil resource plays.
Strong supply and demand fundamentals for the Partnership’s existing businesses
We believe that the current levels of oil, condensate and NGL prices and the forecast prices for these energy commodities have caused producers in and around our natural gas gathering and processing areas of operation to focus their drilling programs on regions rich in these forms of hydrocarbons. Liquids rich gas is prevalent from oil wells in the Wolfberry Trend, Cline and Canyon Sands plays, which are accessible by the SAOU processing business in the Permian Basin, from the oil wells in the Wolfberry and Bone Springs plays, which are accessible by the Sand Hills system, and from “oilier” portions of the Barnett Shale natural gas play, especially portions of Montague, Cooke, Clay and Wise counties, which are accessible by the North Texas System and from oil wells in the Bakken and Three Forks plays which are accessible by our Badlands business in North Dakota.
Producer activity and resulting NGL supplies from areas rich in oil, condensate and NGLs are currently generating high demand for the Partnership’s fractionation services at the Mont Belvieu market hub. As a result, fractionation volumes have recently increased to near existing capacity. Even as additional fractionation capacity comes on-line beginning in 2013, there has been limited incremental supply of fractionation services in the area. These strong supply and demand fundamentals have resulted in long-term, “take-or-pay” contracts for existing capacity and support the construction of new fractionation capacity, such as the Partnership’s CBF and GCF expansion projects. We are continuing to see rates for fractionation services increase. The higher volumes of fractionated NGLs should also result in increased demand for other related fee-based services provided by the Downstream Business.
As domestic producers have focused their drilling in liquids-rich areas, new gas processing facilities are being built to accommodate liquids rich gas which results in an increasing supply of NGLs. As drilling in these areas continues, NGLs requiring transportation and fractionation to market hubs is expected to continue. The domestic demand for NGL components such as propane and butane have remained relatively flat compared to growing demand in other parts of the world while certain key global production areas are realizing less LPG production. The excess supply and globally lower relative production cost in the U.S. has caused prices for these products to be favorably priced compared to other world markets, creating export opportunities to higher price markets. The Partnership’s integrated Mont Belvieu and Galena Park Terminal assets allow us to provide the raw product, fractionation, storage, interconnected terminalling, refrigeration, pumping and ship loading capabilities to support exports. The Partnership is currently loading small and medium sized export vessels and has expansions underway to be able to support larger vessels in addition to our current activity.
Active drilling and production activity from liquids-rich natural gas shale plays and similar crude oil resource plays
The Partnership is actively pursuing natural gas gathering and processing and NGL fractionation opportunities associated with liquids-rich natural gas from shale and other resource plays, such as portions of the Barnett Shale and the Eagle Ford Shale, and with even richer casinghead gas opportunities from active crude oil resource plays, such as the Wolfberry (and other named variants of Wolfcamp, Spraberry, Dean and other geologic cross-section combinations) and the Bone Springs, Avalon and Bakken Shale plays. We believe that the Partnership’s leadership position in the Downstream Business, which includes its fractionation services, provides it with a competitive advantage relative to other gathering and processing companies without these capabilities.
Bakken Shale / Three Forks opportunities
The Bakken Shale and Three Forks areas of the Williston Basin are projected to be among the fastest growing crude oil basins in the world. As producers have increased their knowledge of the basin, they have increased drilling efficiencies and unlocked more value from their acreage. Much of the current oil production is transported by truck from the wells to terminals to be loaded onto rail cars or injected into pipelines. The transportation costs from trucking are higher than from gathering pipelines, giving the producers an economic incentive to pay for gathering services. Similarly, much of the current gas production is being flared, giving producers an incentive to pay for gathering and processing services. The Partnership’s recently acquired assets in the heart of the Bakken play should allow it to participate in the infrastructure build out in return for fee-based revenue to gather crude oil, or gather and process gas, from the wellhead to various takeaway options. There is a significant amount of uncommitted acreage in proximity to the Partnership’s system which should provide further opportunities to enhance medium and long-term growth.
Potential third party acquisitions
While the Partnership’s growth through 2010 was primarily driven by the implementation of a focused drop down strategy, its management team also has a record of successful third party acquisitions. Since the Partnership’s formation, its strategy has included approximately $5.3 billion in acquisitions and growth capital expenditures of which $1.2 billion was third-parties. We expect that third-party acquisitions will continue to be a significant focus of the Partnership’s growth strategy.
Competitive Strengths and Strategies
We believe the Partnership is well positioned to execute its business strategies due to the following competitive strengths:
Strategically located gathering and processing asset base
The Partnership’s gathering and processing businesses are predominantly located in active and growth oriented oil and gas producing basins. Activity in the shale resource plays underlying our gathering assets is driven by oil, condensate and NGL production and currently favorable prices for those energy commodities. Increased drilling and production activities in these areas would likely increase the volumes of natural gas and crude oil available to the Partnership’s gathering and processing systems and from oil wells in the Bakken and Three Forks plays which are accessible by our Badlands business in North Dakota.
Leading fractionation position
The Partnership is one of the largest fractionators of NGLs in the Gulf Coast. Its primary fractionation assets are located in Mont Belvieu, Texas and Lake Charles, Louisiana, which are key market centers for NGLs and are located at the intersection of NGL infrastructure including a stream of mixed NGL (“Mixed NGLs” or “Y-grade”) supply pipelines, storage, takeaway pipelines and other transportation infrastructure. The Partnership’s assets are also located near and connected to key consumers of NGL products including the petrochemical and industrial markets. The location and interconnectivity of the assets are not easily replicated, and the Partnership has sufficient additional capability to expand its capacity. The management has extensive experience in operating these assets and in permitting and building new midstream assets.
Comprehensive package of midstream services
The Partnership provides a comprehensive package of services to natural gas and crude oil producers, including: natural gas gathering, compression, treating, processing and selling; storing, fractionating, treating, and selling NGLs, NGL products, refined petroleum products and crude; and transporting natural gas, NGLs and NGL products. These services are essential to gather crude and to process and treat wellhead gas to meet pipeline standards and to extract NGLs for sale into petrochemical, industrial and commercial markets. We believe that the Partnership’s ability to provide these integrated services provides an advantage in competing for new supplies of natural gas because it can provide substantially all of the services producers, marketers and others require for moving natural gas and NGLs from wellhead to market on a cost-effective basis. Additionally, due to the high cost of replicating assets in key strategic positions, the difficulty of permitting and constructing new midstream assets and the difficulty of developing the expertise necessary to operate them, the barriers to enter the midstream sector on a scale similar to ours are reasonably high.
High quality and efficient assets
The Partnership’s gathering and processing systems and logistics assets consist of high-quality, well-maintained facilities, resulting in low-cost, efficient operations. Advanced technologies have been implemented for processing plants (primarily cryogenic units utilizing centralized control systems), measurements (essentially all electronic and electronically linked to a central data base) and operations and maintenance to manage work orders and implement preventative maintenance schedules (computerized maintenance management systems). These applications have allowed proactive management of the Partnership’s operations resulting in lower costs and minimal downtime. The Partnership has established a reputation in the midstream industry as a reliable and cost-effective supplier of services to its customers and has a track record of safe and efficient operation of its facilities. The Partnership intends to continue to pursue new contracts, cost efficiencies and operating improvements of its assets. Such improvements in the past have included new production and acreage commitments, reducing fuel gas and flare volumes and improving facility capacity and NGL recoveries. The Partnership will also continue to optimize existing plant assets to improve and maximize capacity and throughput.
In addition to routine annual maintenance expenses, the Partnership’s maintenance capital expenditures have averaged $69.4 million per year over the last three years. We believe that the Partnership’s assets are well-maintained and anticipate that a similar level of maintenance capital expenditures will be sufficient for us to continue to operate these assets in a prudent and cost-effective manner.
Large, diverse business mix with favorable contracts and increasing fee-based business
The Partnership maintains gathering and processing positions in strategic oil and gas producing areas across multiple oil and gas basins and provides services under attractive contract terms to a diverse mix of customers across its areas of operations. Consequently, the Partnership is not dependent on any one oil and gas basin or customer. The gathering and processing contract portfolio has attractive rate and term characteristics. The Partnership’s NGL Logistics and Marketing assets are typically located near key market hubs and near important NGL customers. They also serve must-run portions of the natural gas value chain, are primarily fee-based and have a diverse mix of customers. The logistics contract portfolio, largely fee-based, has attractive rate and term characteristics. Given the higher rates for logistics assets contracts that are being renewed, the new projects underway, the long-term nature of many of the renewed and new contracts and continuing strong supply and demand fundamentals for this business, we expect an increasing percentage of the Partnership’s cash flows to be fee-based. The expected growth of the fee-based Badlands business in North Dakota would also contribute to increasing fee-based cash flow.
Financial flexibility
The Partnership has historically maintained a conservative leverage ratio and, ample liquidity and have funded its growth investments with a mix of equity and debt over time. The Partnership has also reduced the impact of commodity price volatility by hedging the commodity price risk associated with a portion of its expected natural gas, NGL and condensate equity volumes. Maintaining a disciplined approach regarding the Partnership’s leverage ratio and, liquidity and mitigating commodity price volatility allow it to be flexible in its long term growth strategy and enable it to pursue strategic acquisitions and large growth projects.
Experienced and long-term focused management team
The executive management team which formed Targa Resources Inc. in 2004 and continues to manage Targa and the Partnership today possesses breadth and depth of combined experience working in the midstream natural gas and energy business. Other officers and key operational, commercial and financial employees provide significant experience in the industry and with the Partnership’s assets and businesses.
Attractive cash flow characteristics
We believe the Partnership’s strategy, combined with its high-quality asset portfolio and strong industry fundamentals, allows the Partnership to generate attractive cash flows. Geographic, business and customer diversity enhances the Partnership’s cash flow profile. The Partnership’s Gathering and Processing division has a favorable contract mix that is primarily percent-of-proceeds, but also has increasing fee-based revenues from natural gas treating fees and crude oil gathering in its recently acquired Bakken Shale midstream assets in the Partnership’s Field Gathering and Processing segment, and hybrid or percent-of-liquids contracts in the Partnership’s Coastal Gathering and Processing segment. The Partnership’s favorable contract mix, along with its long-term commodity hedging program, serves to mitigate the impact of commodity price movements on cash flow. Furthermore, in the Coastal Gathering and Processing Segment, the Partnership can access additional processable gas supplies under keep-whole contracts, which benefit from an environment of low gas prices relative to NGLs and crude oil.
The Partnership has hedged the commodity price risk associated with a portion of its expected natural gas equity volumes through 2015 and its NGL and condensate equity volumes through 2014 by entering into financially settled derivative transactions including swaps and purchased puts (or floors). The primary purpose of the Partnership’s commodity risk management activities is to hedge its exposure to price risk and to mitigate the impact of fluctuations in commodity prices on cash flow. The Partnership has intentionally tailored its hedges to approximate specific NGL products and to approximate its actual NGL and residue natural gas delivery points. The Partnership intends to continue to manage its exposure to commodity prices by entering into similar hedge transactions as market conditions permit. The Partnership also monitors and manages its inventory levels with a view to mitigate losses related to downward price exposure.
Asset base well-positioned for organic growth
We believe that the Partnership’s asset platform and strategic locations allow it to maintain and potentially grow its volumes and related cash flows as its supply areas continue to benefit from exploration and development. At current and recent historical prices, technology advances have resulted in increased domestic oil and liquids rich gas drilling and production activity. The location of the Partnership’s assets provides it with access to stable natural gas and crude oil supplies and proximity to end-use markets and liquid market hubs while positioning it to capitalize on drilling and production activity in those areas. The Partnership’s existing infrastructure has the capacity to handle some incremental increases in volumes without significant investments as well as opportunities to leverage existing assets with meaningful expansions. We believe that as domestic supply and demand for natural gas, crude oil and NGLs, and services for each, grows over the long term, the Partnership’s infrastructure will increase in value as such infrastructure takes on increasing importance in meeting that growing supply and demand.
While we have set forth the Partnership’s strategies and competitive strengths above, its business involves numerous risks and uncertainties which may prevent it from executing its strategies or impact the amount of distributions to unitholders. These risks include the adverse impact of changes in natural gas, NGL and condensate/crude oil prices or in the supply of or demand for these commodities, and the Partnership’s inability to access sufficient additional production to replace natural declines in production. For a more complete description of the risks associated with an investment in the Partnership, see “Item 1A.
Item 1A.
Risk Factors.
The nature of our business activities subjects us to certain hazards and risks. You should consider carefully the following risk factors together with all of the other information contained in this report. If any of the following risks were actually to occur, then our business, financial condition, cash flows and results of operations could be materially adversely affected.
Risks Related to Our Business
Our cash flow is dependent upon the ability of the Partnership to make cash distributions to us.
Our cash flow consists of cash distributions from the Partnership. The amount of cash that the Partnership will be able to distribute to its partners, including us, each quarter principally depends upon the amount of cash it generates from its business. For a description of certain factors that can cause fluctuations in the amount of cash that the Partnership generates from its business, please read “-Risks Inherent in the Partnership’s Business” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Factors That Significantly Affect Our Results.” The Partnership may not have sufficient available cash each quarter to continue paying distributions at their current level or at all. If the Partnership reduces its per unit distribution, because of reduced operating cash flow, higher expenses, capital requirements or otherwise, we will have less cash available to pay dividends to our stockholders and would probably be required to reduce the dividend per share of common stock. The amount of cash the Partnership has available for distribution depends primarily upon the Partnership’s cash flow, including cash flow from the release of reserves as well as borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, the Partnership may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records profits.
Once we receive cash from the Partnership and the general partner, our ability to distribute the cash received to our stockholders is limited by a number of factors, including:
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Our obligation to satisfy tax obligations associated with previous sales of assets to the Partnership;
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interest expense and principal payments on any indebtedness we incur;
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restrictions on distributions contained in any existing or future debt agreements;
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our general and administrative expenses, including expenses we incur as a result of being a public company as well as other operating expenses;
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expenses of the general partner;
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income taxes;
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reserves we establish in order for us to maintain our 2% general partner interest in the Partnership upon the issuance of additional partnership securities by the Partnership; and
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reserves our board of directors establishes for the proper conduct of our business, to comply with applicable law or any agreement binding on us or our subsidiaries or to provide for future dividends by us.
The actual amount of cash that is available for dividends to our stockholders will depend on numerous factors, many of which are beyond our control.
A reduction in the Partnership’s distributions will disproportionately affect the amount of cash distributions to which we are entitled.
Our ownership of the IDRs in the Partnership entitles us to receive specified percentages of the amount of cash distributions made by the Partnership to its limited partners only in the event that the Partnership distributes more than $0.3881 per unit for such quarter. As a result, the holders of the Partnership’s common units have a priority over our IDRs to the extent of cash distributions by the Partnership up to and including $0.3881 per unit for any quarter.
Our IDRs entitle us to receive increasing percentages, up to 48%, of all cash distributed by the Partnership. Because the Partnership’s distribution rate is currently above the maximum target cash distribution level on the IDRs, future growth in distributions we receive from the Partnership will not result from an increase in the target cash distribution level associated with the IDRs. Furthermore, a decrease in the amount of distributions by the Partnership to less than $0.50625 per unit per quarter would reduce the general partner’s percentage of the incremental cash distributions above $0.3881 per common unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributions from the Partnership would have the effect of disproportionately reducing the distributions that we receive from the Partnership based on our IDRs as compared to distributions we receive from the Partnership with respect to our 2% general partner interest and our common units.
If the Partnership’s unitholders remove the general partner, we would lose our general partner interest and IDRs in the Partnership and the ability to manage the Partnership.
We currently manage our investment in the Partnership through our ownership interest in the general partner. The Partnership’s partnership agreement, however, gives unitholders of the Partnership the right to remove the general partner upon the affirmative vote of holders of 66⅔% of the Partnership’s outstanding units. If the general partner were removed as general partner of the Partnership, it would receive cash or common units in exchange for its 2% general partner interest and the IDRs and would also lose its ability to manage the Partnership. While the cash or common units the general partner would receive are intended under the terms of the Partnership’s partnership agreement to fully compensate us in the event such an exchange is required, the value of the investments we make with the cash or the common units may not over time be equivalent to the value of the general partner interest and the IDRs had the general partner retained them.
In addition, if the general partner is removed as general partner of the Partnership, we would face an increased risk of being deemed an investment company. Please read “- If in the future we cease to manage and control the Partnership, we may be deemed to be an investment company under the Investment Company Act of 1940.”
The Partnership, without our stockholders’ consent, may issue additional common units or other equity securities, which may increase the risk that the Partnership will not have sufficient available cash to maintain or increase its cash distribution level per common unit.
Because the Partnership distributes to its partners most of the cash generated by its operations, it relies primarily upon external financing sources, including debt and equity issuances, to fund its acquisitions and expansion capital expenditures. Accordingly, the Partnership has wide latitude to issue additional common units on the terms and conditions established by its general partner. We receive cash distributions from the Partnership on the general partner interest, IDRs and common units that we own. Because a significant portion of the cash we receive from the Partnership is attributable to our ownership of the IDRs, payment of distributions on additional Partnership common units may increase the risk that the Partnership will be unable to maintain or increase its quarterly cash distribution per unit, which in turn may reduce the amount of distributions we receive attributable to our common units, general partner interest and IDRs and the available cash that we have to pay as dividends to our stockholders.
The general partner, with our consent but without the consent of our stockholders, may limit or modify the incentive distributions we are entitled to receive, which may reduce cash dividends to you.
We own the general partner, which owns the IDRs in the Partnership that entitle us to receive increasing percentages, up to a maximum of 48% of any cash distributed by the Partnership as certain target distribution levels are reached in excess of $0.3881 per common unit in any quarter. A substantial portion of the cash flow we receive from the Partnership is provided by these IDRs. Because of the high percentage of the Partnership’s incremental cash flow that is distributed to the IDRs, certain potential acquisitions might not increase cash available for distribution per Partnership unit. In order to facilitate acquisitions by the Partnership or for other reasons, the board of directors of the general partner may elect to reduce the IDRs payable to us with our consent. These reductions may be permanent reductions in the IDRs or may be reductions with respect to cash flows from the potential acquisition. If distributions on the IDRs were reduced for the benefit of the Partnership units, the total amount of cash distributions we would receive from the Partnership, and therefore the amount of cash dividends we could pay to our stockholders, would be reduced.
In the future, we may not have sufficient cash to pay estimated dividends.
Because our only source of operating cash flow consists of cash distributions from the Partnership, the amount of dividends we are able to pay to our stockholders may fluctuate based on the level of distributions the Partnership makes to its partners, including us. The Partnership may not continue to make quarterly distributions at the 2012 fourth quarter distribution level of $0.68 per common unit, or may not distribute any other amount, or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease dividends to our stockholders if the Partnership increases or decreases distributions to us, the timing and amount of such changes in distributions, if any, will not necessarily be comparable to the timing and amount of any changes in dividends made by us. Factors such as reserves established by our board of directors for our estimated general and administrative expenses as well as other operating expenses, reserves to satisfy our debt service requirements, if any, and reserves for future dividends by us may affect the dividends we make to our stockholders. The actual amount of cash that is available for dividends to our stockholders will depend on numerous factors, many of which are beyond our control.
Our cash dividend policy limits our ability to grow.
Because we plan on distributing a substantial amount of our cash flow, our growth may not be as fast as the growth of businesses that reinvest their available cash to expand ongoing operations. In fact, because currently our only cash-generating assets are direct and indirect partnership interests in the Partnership, our growth will be substantially dependent upon the Partnership. If we issue additional shares of common stock or we were to incur debt, the payment of dividends on those additional shares or interest on that debt could increase the risk that we will be unable to maintain or increase our cash dividend levels.
Our rate of growth may be reduced to the extent we purchase additional units from the Partnership, which will reduce the relative percentage of the cash we receive from the IDRs.
Our business strategy includes, where appropriate, supporting the growth of the Partnership by purchasing the Partnership’s units or lending funds or providing other forms of financial support to the Partnership to provide funding for the acquisition of a business or asset or for a growth project. To the extent we purchase common units or securities not entitled to a current distribution from the Partnership, the rate of our distribution growth may be reduced, at least in the short term, as less of our cash distributions will come from our ownership of IDRs, whose distributions increase at a faster rate than those of our other securities.
We have a credit facility that contains various restrictions on our ability to pay dividends to our stockholders, borrow additional funds or capitalize on business opportunities.
We have a credit facility that contains various operating and financial restrictions and covenants. Our ability to comply with these restrictions and covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If we are unable to comply with these restrictions and covenants, any future indebtedness under this credit facility may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.
Our credit facility limits our ability to pay dividends to our stockholders during an event of default or if an event of default would result from such dividend. In addition, any future borrowings may:
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adversely affect our ability to obtain additional financing for future operations or capital needs;
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limit our ability to pursue acquisitions and other business opportunities;
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make our results of operations more susceptible to adverse economic or operating conditions; or
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limit our ability to pay dividends.
Our payment of any principal and interest will reduce our cash available for dividends to our stockholders. In addition, we are able to incur substantial additional indebtedness in the future. If we incur additional debt, the risks associated with our leverage would increase. For more information regarding our credit facility, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
If dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’s payments in the future.
Dividends to our stockholders will not be cumulative. Consequently, if dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’s payments in the future.
The Partnership’s practice of distributing all of its available cash may limit its ability to grow, which could impact distributions to us and the available cash that we have to dividend to our stockholders.
Because currently our only cash-generating assets are common units and general partner interests in the Partnership, including the IDRs, our growth will be dependent upon the Partnership’s ability to increase its quarterly cash distributions. The Partnership has historically distributed to its partners most of the cash generated by its operations. As a result, it relies primarily upon external financing sources, including debt and equity issuances, to fund its acquisitions and expansion capital expenditures. Accordingly, to the extent the Partnership is unable to finance growth externally, its ability to grow will be impaired because it distributes substantially all of its available cash. Also, if the Partnership incurs additional indebtedness to finance its growth, the increased interest expense associated with such indebtedness may reduce the amount of available cash that the Partnership distributes to us, which in turn may reduce the amount of available cash that we can distribute to our stockholders. In addition, to the extent the Partnership issues additional common units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional common units may increase the risk that the Partnership will be unable to maintain or increase its per unit distribution level, which in turn may impact the cash available for dividends to our stockholders.
Restrictions in the Partnership’s Senior Secured Revolving Credit Facility (the “TRP Revolver”) and indentures could limit its ability to make distributions to us.
The TRP Revolver and indentures contain covenants limiting its ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions. The TRP Revolver also contains covenants requiring the Partnership to maintain certain financial ratios. The Partnership is prohibited from making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a covenant under the TRP Revolver or the indentures, which in turn may impact the cash available for dividends to our stockholders.
If in the future we cease to manage and control the Partnership, we may be deemed to be an investment company under the Investment Company Act of 1940.
If we cease to manage and control the Partnership and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contractual rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us and our affiliates, and adversely affect the price of our common stock.
Our historical financial information may not be representative of our future performance.
The historical financial information included in this annual report is derived from our historical financial statements including for periods prior to our initial public offering in December 2010. Our audited historical financial statements were prepared in accordance with GAAP. Accordingly, the historical financial information included in this annual report does not reflect what our results of operations and financial condition would have been had we been a public entity during the periods presented, or what our results of operations and financial condition will be in the future.
If we lose any of our named executive officers, our business may be adversely affected.
Our success is dependent upon the efforts of the named executive officers. Our named executive officers are responsible for executing our and the Partnership’s business strategies and, when appropriate to our primary business objective, facilitating the Partnership’s growth through various forms of financial support provided by us, including, but not limited to, modifying the Partnership’s IDRs, exercising the Partnership’s IDR reset provision contained in its partnership agreement, making loans, making capital contributions in exchange for yielding or non-yielding equity interests or providing other financial support to the Partnership. There is substantial competition for qualified personnel in the midstream natural gas industry. We may not be able to retain our existing named executive officers or fill new positions or vacancies created by expansion or turnover. We have not entered into employment agreements with any of our named executive officers. In addition, we do not maintain “key man” life insurance on the lives of any of our named executive officers. A loss of one or more of our named executive officers could harm our and the Partnership’s business and prevent us from implementing our and the Partnership’s business strategies.
If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition, potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.
Effective internal controls are necessary for us to provide timely and reliable financial reports and effectively prevent fraud. If we cannot provide timely and reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We continue to enhance our internal controls and financial reporting capabilities. These enhancements require a significant commitment of resources, personnel and the development and maintenance of formalized internal reporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective controls or difficulties encountered in the 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 or the Partnership 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, financial condition and ability to comply with our and the Partnership’s debt obligations.
An increase in interest rates may cause the market price of our common stock to decline.
Like all equity investments, an investment in our common stock is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments. Reduced demand for our common stock resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common stock to decline.
Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
We or our stockholders may sell shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. As of December 31, 2012, we have 42,294,502 outstanding shares of common stock. Certain of our existing stockholders, including our executive officers, certain of our directors and affiliates of Warburg Pincus LLC (“Warburg Pincus”) are party to a registration rights agreement with us which requires us to affect the registration of their shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement of our initial public offering.
We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.
Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third-party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third-party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
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a classified board of directors, so that only approximately one-third of our directors are elected each year;
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limitations on the removal of directors; and
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limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.
Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors. Please read “Description of Our Capital Stock-Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law.”
We have a significant stockholder, which will limit other stockholders’ ability to influence corporate matters and may give rise to conflicts of interest.
As of December 31, 2012, affiliates of Warburg Pincus beneficially owned approximately 11.1% of our outstanding common stock. See “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.” Accordingly, Warburg Pincus can exert significant influence over us and any action requiring the approval of the holders of our stock, including the election of directors and approval of significant corporate transactions. Warburg’s concentrated ownership makes it less likely that any other holder or group of holders of common stock will be able to affect the way we are managed or the direction of our business. These factors also may delay or prevent a change in our management or voting control.
Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Warburg Pincus and its affiliates, on the other hand, concerning, among other things, potential competitive business activities, business opportunities, the issuance of additional securities, the payment of dividends by us and other matters. Warburg Pincus is a private equity firm that has invested, among other things, in companies in the energy industry. As a result, Warburg Pincus’ existing and future portfolio companies which it controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.
In our amended and restated certificate of incorporation, we have renounced business opportunities that may be pursued by the Partnership or by affiliated stockholders that currently hold a significant amount of our common stock.
In our restated charter and in accordance with Delaware law, we have renounced any interest or expectancy we may have in, or being offered an opportunity to participate in, any business opportunities, including any opportunities within those classes of opportunity currently pursued by the Partnership, presented to Warburg Pincus or any private fund that it manages or advises, their affiliates (other than us and our subsidiaries), their officers, directors, partners, employees or other agents who serve as one of our directors, Merrill Lynch Ventures L.P. 2001, its affiliates (other than us and our subsidiaries) and any portfolio company in which such entities or persons has an equity investment (other than us and our subsidiaries) participates or desires or seeks to participate in and that involves any aspect of the energy business or industry.
The duties of our officers and directors may conflict with those owed to the Partnership and these officers and directors may face conflicts of interest in the allocation of administrative time among our business and the Partnership’s business.
Substantially all of our officers and certain members of our board of directors are officers and/or directors of the general partner and, as a result, have separate duties that govern their management of the Partnership’s business. These officers and directors may encounter situations in which their obligations to us, on the one hand, and the Partnership, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our stockholders.
In addition, our officers who also serve as officers of the general partner may face conflicts in allocating their time spent on our behalf and on behalf of the Partnership. These time allocations may adversely affect our or the Partnership’s results of operations, cash flows, and financial condition. For a discussion of our officers and directors that will serve in the same capacity for the general partner and the amount of time we expect them to devote to our business, please read “Management.”
Risks Inherent in the Partnership’s Business
Because we are directly dependent on the distributions we receive from the Partnership, risks to the Partnership’s operations are also risks to us. We have set forth below risks to the Partnership’s business and operations, the occurrence of which could negatively impact the Partnership’s financial performance and decrease the amount of cash it is able to distribute to us.
The Partnership has a substantial amount of indebtedness which may adversely affect its financial position.
The Partnership has a substantial amount of indebtedness. As of December 31, 2012, the Partnership had $620.0 million of borrowings outstanding under the TRP Revolver, $45.3 million of letters of credit outstanding and $534.7 million of additional borrowing capacity under the TRP Revolver. In addition, the Partnership had $1,806.3 million outstanding under its senior unsecured notes, excluding $33.0 million in unamortized discounts. The $1.2 billion TRP Revolver allows it to request increases in commitments up to an additional $300 million. For the years ended December 31, 2012, 2011 and 2010, the Partnership’s consolidated interest expense was $116.8 million, $107.7 million and $110.9 million.
This substantial level of indebtedness increases the possibility that the Partnership may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of indebtedness. This substantial indebtedness, combined with lease and other financial obligations and contractual commitments, could have other important consequences to the Partnership, including the following:
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its ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
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satisfying its obligations with respect to indebtedness may be more difficult and any failure to comply with the obligations of any debt instruments could result in an event of default under the agreements governing such indebtedness;
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the Partnership will need a portion of cash flow to make interest payments on debt, reducing the funds that would otherwise be available for operations and future business opportunities;
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the Partnership’s debt level will make it more vulnerable to competitive pressures or a downturn in its business or the economy generally; and
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the Partnership’s debt level may limit flexibility in planning for, or responding to, changing business and economic conditions.
The Partnership’s ability to service its debt will depend upon, among other things, its 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 its control. If the Partnership’s operating results are not sufficient to service its current or future indebtedness, it will be forced to take actions such as reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital and may adversely affect its ability to make cash distributions. The Partnership may not be able to affect any of these actions on satisfactory terms, or at all.
Increases in interest rates could adversely affect the Partnership’s business.
The Partnership has significant exposure to increases in interest rates. As of December 31, 2012, its total indebtedness was $2,426.3 million, excluding $33.0 million in unamortized discounts, of which $1,806.3 million was at fixed interest rates and $620.0 million was at variable interest rates. A one percentage point increase in the interest rate on the Partnership’s variable interest rate debt would have increased its consolidated annual interest expense by approximately $6.2 million. As a result of this significant amount of variable interest rate debt, the Partnership’s financial condition could be adversely affected by significant increases in interest rates.
Despite current indebtedness levels, the Partnership may still be able to incur substantially more debt. This could increase the risks associated with the Partnership’s substantial leverage.
The Partnership may be able to incur substantial additional indebtedness in the future. As of December 31, 2012, the Partnership had $620.0 million of borrowings outstanding under the TRP Revolver, $45.3 million of letters of credit outstanding and $534.7 million of additional borrowing capacity under the TRP Revolver. The Partnership may be able to incur an additional $300 million of debt under the TRP Revolver if the Partnership requests and is able to obtain commitments for the additional $300 million available under the TRP Revolver. Although the TRP Revolver contains restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial. If the Partnership incurs additional debt, the risks associated with its substantial leverage would increase.
The terms of the TRP Revolver and indentures may restrict its current and future operations, particularly its ability to respond to changes in business or to take certain actions.
The credit agreement governing the TRP Revolver, its accounts receivable securitization facility (the “Securitization Facility”) and the indentures governing its senior notes (other than its 11¼% Senior Notes due 2017 (the “11¼% Notes”)) contain, and any future indebtedness the Partnership incurs will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on its ability to engage in acts that may be in its best long-term interests. These agreements include covenants that, among other things, restrict the Partnership’s ability to:
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incur or guarantee additional indebtedness or issue preferred stock;
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pay distributions on its equity securities or redeem, repurchase or retire its equity securities or subordinated indebtedness;
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make investments;
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create restrictions on the payment of distributions to its equity holders;
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sell assets, including equity securities of its subsidiaries;
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engage in affiliate transactions,
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consolidate or merge;
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incur liens;
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prepay, redeem and repurchase certain debt, other than loans under the TRP Revolver;
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make certain acquisitions;
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transfer assets;
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enter into sale and lease back transactions;
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make capital expenditures;
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amend debt and other material agreements; and
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change business activities conducted by it.
In addition, the TRP Revolver requires it to satisfy and maintain specified financial ratios and other financial condition tests. The Partnership’s ability to meet those financial ratios and tests can be affected by events beyond its control, and we cannot assure you that the Partnership will meet those ratios and tests.
A breach of any of these covenants could result in an event of default under the TRP Revolver and indentures, as applicable. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If the Partnership is unable to repay the accelerated debt under the TRP Revolver, the lenders under the TRP Revolver could proceed against the collateral granted to them to secure that indebtedness. The Partnership has pledged substantially all of its assets as collateral under the TRP Revolver. If the Partnership’s indebtedness under the TRP Revolver or indentures is accelerated, we cannot assure you that the Partnership will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect the Partnership’s ability to finance future operations or capital needs or to engage in other business activities.
The Partnership’s cash flow is affected by supply and demand for natural gas and NGL products and by natural gas, NGL, crude oil and condensate prices, and decreases in these prices could adversely affect its results of operations and financial condition.
The Partnership’s operations can be affected by the level of natural gas and NGL prices and the relationship between these prices. The prices of oil, natural gas and NGLs have been volatile and we expect this volatility to continue. The Partnership’s future cash flow may be materially adversely affected if it experiences significant, prolonged pricing deterioration. The markets and prices for natural gas and NGLs depend upon factors beyond the Partnership’s control. These factors include demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:
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the impact of seasonality and weather;
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general economic conditions and economic conditions impacting the Partnership’s primary markets;
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the economic conditions of the Partnership’s customers;
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the level of domestic crude oil and natural gas production and consumption;
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the availability of imported natural gas, liquefied natural gas, NGLs and crude oil;
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actions taken by foreign oil and gas producing nations;
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the availability of local, intrastate and interstate transportation systems and storage for residue natural gas and NGLs;
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the availability and marketing of competitive fuels and/or feedstocks;
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the impact of energy conservation efforts; and
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the extent of governmental regulation and taxation.
The Partnership’s primary natural gas gathering and processing arrangements that expose it to commodity price risk are its percent-of-proceeds arrangements. For the years ended December 31, 2012 and 2011, the Partnership’s percent-of-proceeds arrangements accounted for approximately 43% and 40% of its gathered natural gas volume. Under these arrangements, the Partnership generally processes 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 the Partnership’s processing facilities. In some percent-of-proceeds arrangements, the Partnership remits 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, the Partnership’s revenues and cash flows increase or decrease, whichever is applicable, as the price of natural gas, NGLs and crude oil fluctuates. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Quantitative and Qualitative Disclosures about Market Risk.”
Because of the natural decline in production in the Partnership’s operating regions and in other regions from which it sources NGL supplies, its long-term success depends on its ability to obtain new sources of supplies of natural gas, NGLs and crude oil which depends on certain factors beyond its control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect the Partnership’s business and operating results.
The Partnership’s gathering systems are connected to oil and natural gas wells from which production will naturally decline over time, which means that the cash flows associated with these sources of natural gas and crude oil will likely also decline over time. The Partnership’s logistics assets are similarly impacted by declines in NGL supplies in the regions in which it operates as well as other regions from which it sources NGLs. To maintain or increase throughput levels on the Partnership’s gathering systems and the utilization rate at its processing plants and its treating and fractionation facilities, the Partnership must continually obtain new natural gas, NGL and crude oil supplies. A material decrease in natural gas production from producing areas on which the Partnership relies, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of natural gas or crude oil that it processes, NGL products delivered to its fractionation facilities or crude oil that the Partnership gathers. The Partnership’s ability to obtain additional sources of natural gas, NGLs and crude oil depends, in part, on the level of successful drilling and production activity near its gathering systems and, in part, on the level of successful drilling and production in other areas from which it sources NGL and crude oil supplies. The Partnership has no control over the level of such activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, the Partnership has 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, 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 historically volatile, and we expect this volatility to continue. Consequently, even if new natural gas or crude oil reserves are discovered in areas served by the Partnership’s assets, producers may choose not to develop those reserves. For example, current low prices for natural gas combined with relatively high levels of natural gas in storage could result in curtailment or shut-in of natural gas production. Reductions in exploration and production activity, competitor actions or shut-ins by producers in the areas in which the Partnership operates may prevent it from obtaining supplies of natural gas or crude oil to replace the natural decline in volumes from existing wells, which could result in reduced volumes through its facilities, and reduced utilization of its gathering, treating, processing and fractionation assets.
If the Partnership does not make acquisitions or develop growth projects for expanding existing assets or constructing new midstream assets on economically acceptable terms or fail to efficiently and effectively integrate acquired or developed assets with its asset base, its future growth will be limited. In addition, any acquisitions the Partnership completes, including the Badlands acquisition, are subject to substantial risks that could adversely affect its financial condition and results of operations and reduce its ability to make distributions to unitholders.
The Partnership’s ability to grow depends, in part, on its ability to make acquisitions or develop growth projects that result in an increase in cash generated from operations per unit. The Partnership is unable to acquire businesses from us in order to grow because our only assets are the interests in the Partnership that we own. As a result, the Partnership will need to focus on third-party acquisitions and organic growth. If the Partnership is unable to make accretive acquisitions or develop accretive growth projects because it is (1) unable to identify attractive acquisition candidates and negotiate acceptable acquisition agreements or develop growth projects economically, (2) unable to obtain financing for these acquisitions or projects on economically acceptable terms, or (3) unable to compete successfully for acquisitions or growth projects, then the Partnership’s future growth and ability to increase distributions will be limited.
In addition, the Partnership may not achieve the expected results of the Badlands acquisition, and any adverse conditions or developments related to the Badlands acquisition may have a negative impact on its operations and financial condition.
Saddle Butte Pipeline LLC (“Saddle Butte”), the entity whose crude oil pipeline and terminal system and natural gas gathering and processing operations the Partnership acquired in the Badlands acquisition, operates its business in geographic regions in which it did not operate prior to the acquisition, including in the Bakken Shale Play. In order to operate effectively in these new regions, the Partnership will need to understand the local market and regulatory environment and identify and retain certain employees from Saddle Butte who are familiar with these markets. If the Partnership is not successful in retaining these employees or operating in these new geographic areas, it may not be able to compete effectively in the new markets or fully realize the expected benefits of the Badlands acquisition.
Any acquisition, including the Badlands acquisition, or growth project involves potential risks, including, among other things:
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operating a significantly larger combined organization and adding new or expanded operations;
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difficulties in the assimilation of the assets and operations of the acquired businesses or growth projects, especially if the assets acquired are in a new business segment or geographic area;
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the risk that crude oil and natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;
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the failure to realize expected volumes, revenues, profitability or growth;
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the failure to realize any expected synergies and cost savings;
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coordinating geographically disparate organizations, systems and facilities;
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the assumption of unknown liabilities;
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limitations on rights to indemnity from the seller in an acquisition or contractors and suppliers in growth projects;
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inaccurate assumptions about the overall costs of equity or debt;
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the diversion of management’s and employees’ attention from other business concerns; and
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customer or key employee losses at the acquired businesses or to a competitor.
If these risks materialize, the acquired assets or growth project may inhibit the Partnership’s growth, fail to deliver expected benefits and add further unexpected costs. Challenges may arise whenever businesses with different operations or management are combined, and the Partnership may experience unanticipated delays in realizing the benefits of an acquisition or growth project. If the Partnership consummates any future acquisition or growth project, its capitalization and results of operations may change significantly and you may not have the opportunity to evaluate the economic, financial and other relevant information that the Partnership will consider in evaluating future acquisitions or growth projects.
The Partnership’s acquisition and growth strategy is based, in part, on its expectation of ongoing divestitures of energy assets by industry participants and new opportunities created by industry expansion. A material decrease in such divestitures or in opportunities for economic commercial expansion would limit the Partnership’s opportunities for future acquisitions or growth projects and could adversely affect its operations and cash flows available for distribution to its unit holders.
Acquisitions may significantly increase the Partnership’s size and diversify the geographic areas in which it operates and growth projects may increase its concentration in a line of business or geographic region. The Partnership may not achieve the desired affect from any future acquisitions or growth project.
The Partnership’s expansion or modification of existing assets or the construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect its results of operations and financial condition.
The construction of additions or modifications to the Partnership’s existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond its control and may require the expenditure of significant amounts of capital. If the Partnership undertakes these projects, they may not be completed on schedule or at the budgeted cost or at all. Moreover, the Partnership’s revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if the Partnership builds a new fractionation facility or gas processing plant, the construction may occur over an extended period of time and it will not receive any material increases in revenues until the project is completed. Moreover, the Partnership may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since the Partnership is not engaged in the exploration for and development of natural gas and oil reserves, it does not possess reserve expertise and it often does not have access to third-party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent the Partnership relies on estimates of future production in its decision to construct additions to its systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve the Partnership’s expected investment return, which could adversely affect its results of operations and financial condition. In addition, the construction of additions to the Partnership’s existing gathering and transportation assets may require it to obtain new rights-of-way prior to constructing new pipelines. The Partnership may be unable to obtain such rights-of-way to connect new natural gas supplies to its existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for the Partnership to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, the Partnership’s cash flows could be adversely affected.
The Partnership’s acquisition and growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair the Partnership’s ability to grow through acquisitions or growth projects.
The Partnership continuously considers and enters into discussions regarding potential acquisitions and growth projects. Any limitations on the Partnership’s access to capital will impair its ability to execute this strategy. If the cost of such capital becomes too expensive, the Partnership’s ability to develop or acquire strategic and accretive assets will be limited. The Partnership may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence the Partnership’s initial cost of equity include market conditions, fees it pays to underwriters and other offering costs, which include amounts it pays for legal and accounting services. The primary factors influencing the Partnership cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges it pays to lenders. These factors may impair the Partnership’s ability to execute its acquisition and growth strategy.
In addition, the Partnership is experiencing increased competition for the types of assets it contemplates purchasing or developing. Current economic conditions and competition for asset purchases and development opportunities could limit its ability to fully execute its acquisition and growth strategy.
Demand for propane is seasonal and requires increases in inventory to meet seasonal demand.
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 the Partnership operates can significantly decrease the total volume of propane it sells. Lack of consumer demand for propane may also adversely affect the retailers with which the Partnership transacts its wholesale propane marketing operations, exposing the Partnership to retailers’ inability to satisfy their contractual obligations to the Partnership.
If the Partnership fails to balance its purchases of natural gas and its sales of residue gas and NGLs, its exposure to commodity price risk will increase.
The Partnership may not be successful in balancing its purchases of natural gas and its sales of residue gas and NGLs. In addition, a producer could fail to deliver promised volumes to the Partnership 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 the Partnership’s purchases and sales. If the Partnership’s purchases and sales are not balanced, it will face increased exposure to commodity price risks and could have increased volatility in its operating income.
The Partnership’s hedging activities may not be effective in reducing the variability of its cash flows and may, in certain circumstances, increase the variability of its cash flows. Moreover, the Partnership’s hedges may not fully protect it against volatility in basis differentials. Finally, the percentage of the Partnership’s expected equity commodity volumes that are hedged decreases substantially over time.
The Partnership has entered into derivative transactions related to only a portion of its equity volumes. As a result, it will continue to have direct commodity price risk to the unhedged portion. The Partnership’s actual future volumes may be significantly higher or lower than it estimated at the time it entered into the derivative transactions for that period. If the actual amount is higher than the Partnership estimated, it will have greater commodity price risk than it intended. If the actual amount is lower than the amount that is subject to its derivative financial instruments, the Partnership might be forced to satisfy all or a portion of its derivative transactions without the benefit of the cash flow from its sale of the underlying physical commodity. The percentages of the Partnership’s expected equity volumes that are covered by its hedges decrease over time. To the extent the Partnership hedges its commodity price risk, it may forego the benefits it would otherwise experience if commodity prices were to change in its favor. The derivative instruments the Partnership utilizes 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 it realizes in its operations. These pricing differentials may be substantial and could materially impact the prices the Partnership ultimately realizes. In addition, market and economic conditions may adversely affect the Partnership’s hedge counterparties’ ability to meet their obligations. Given volatility in the financial and commodity markets, the Partnership may experience defaults by its hedge counterparties in the future. As a result of these and other factors, the Partnership’s hedging activities may not be as effective as it intended in reducing the variability of its cash flows, and in certain circumstances may actually increase the variability of its cash flows. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Quantitative and Qualitative Disclosures about Market Risk.”
If third-party pipelines and other facilities interconnected to the Partnership’s natural gas and crude oil gathering systems, terminals and processing facilities become partially or fully unavailable to transport natural gas and NGLs, its revenues could be adversely affected.
The Partnership depends upon third-party pipelines, storage and other facilities that provide delivery options to and from its gathering and processing facilities. Since the Partnership does not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within its 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 the Partnership’s ability to utilize them, its revenues could be adversely affected.
The Partnership’s industry is highly competitive, and increased competitive pressure could adversely affect its business and operating results.
The Partnership competes with similar enterprises in its respective areas of operation. Some of the Partnership’s competitors are large oil, natural gas and NGL companies that have greater financial resources and access to supplies of natural gas and NGLs than it does. Some of these competitors may expand or construct gathering, processing, storage, terminaling and transportation systems that would create additional competition for the services the Partnership provides to its customers. In addition, customers who are significant producers of natural gas may develop their own gathering, processing, storage, terminaling and transportation systems in lieu of using those operated by the Partnership. The Partnership’s ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of its competitors and its customers. All of these competitive pressures could have a material adverse effect on the Partnership’s business, results of operations, and financial condition.
The Partnership typically does not obtain independent evaluations of natural gas and crude oil reserves dedicated to its gathering pipeline systems; therefore, supply volumes on its systems in the future could be less than it anticipates.
The Partnership typically does not obtain independent evaluations of natural gas or crude oil reserves connected to its gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, the Partnership does not have independent estimates of total reserves dedicated to its gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to the Partnership’s gathering systems is less than it anticipates and it is unable to secure additional sources of supply, then the volumes of natural gas transported on its gathering systems in the future could be less than it anticipates. A decline in the volumes on the Partnership’s systems could have a material adverse effect on its 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, or a significant increase in NGL product supply relative to this demand, could materially adversely affect the Partnership’s business, results of operations and financial condition.
The NGL products the Partnership produces 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 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 the Partnership handles or reduce the fees it charges for its services. Also, increased supply of NGL products could reduce the value of NGLs handled by the Partnership and reduce the margins realized. The Partnership’s 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 the Partnership’s 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 petroleum product blending component, as a fuel gas either alone or in a mixture with propane, and in the production of ethylene and propylene. Changes in the composition of refined petroleum 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.
Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.
Natural Gasoline. Natural gasoline is used as a blending component for certain refined petroleum products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition of motor gasoline resulting from governmental regulation, and in demand for ethylene and propylene, could adversely affect demand for natural gasoline.
NGLs and products produced from NGLs also compete with products from global markets. Any reduced demand or increased supply for ethane, propane, normal butane, isobutane or natural gasoline in the markets the Partnership accesses for any of the reasons stated above could adversely affect demand for the services it provides as well as NGL prices, which would negatively impact its results of operations and financial condition.
The Partnership has significant relationships with CPC as a customer for its marketing and refinery services. In some cases, these agreements are subject to renegotiation and termination rights.
For the years ended December 31, 2012, and 2011, approximately 10% and 12% of the Partnership’s consolidated revenues were derived from transactions with CPC. Under many of the Partnership’s CPC contracts where it purchases or markets NGLs on CPC’s behalf, CPC may elect to terminate the contracts or renegotiate the price terms. To the extent CPC reduces the volumes of NGLs that it purchases from the Partnership or reduces the volumes of NGLs that the Partnership markets on its behalf or to the extent the economic terms of such contracts are changed, the Partnership’s 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 a material amount 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 an approximate 14.7% limited partner interest, a 2% general partner interest and the IDRs 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. A publicly traded partnership such as the Partnership may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on the Partnership’s current operations we believe that the Partnership satisfies the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause the Partnership to be treated as a corporation for federal income tax purposes or otherwise subject the Partnership to taxation as an entity. The Partnership has not requested and does not plan to request a ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes.
If the Partnership were 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. Distributions to the Partnership’s unitholders, including us, would generally be taxed again as corporate distributions and no income, gains, losses or deductions would flow through to the Partnership’s unitholders, including us. 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 Partnership’s unitholders, including us, and would likely cause a substantial reduction in the value of our investment in the Partnership.
In addition, 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 for state or local income tax purposes. The present U.S. federal income tax treatment of publicly traded partnerships, including the Partnership, or an investment in the Partnership’s common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which the Partnership relies for its treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of our investment in the Partnership’s common units. In addition, 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 similar tax on the Partnership by additional states would reduce the cash available for distribution to Partnership unitholders, including us.
The Partnership’s partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects it to taxation as a corporation or otherwise subjects it to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on the Partnership.
The Partnership does not own most of the land on which its pipelines and compression facilities are located, which could disrupt its operations.
The Partnership does not own most of the land on which its pipelines, terminals and compression facilities are located, and the Partnership is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. The Partnership sometimes obtains the rights to land owned by third parties and governmental agencies for a specific period of time. The Partnership’s loss of these rights, through its inability to renew right-of-way contracts, leases or otherwise, could cause it to cease operations on the affected land, increase costs related to continuing operations elsewhere and reduce its revenue.
The Partnership may be unable to cause its majority-owned joint ventures to take or not to take certain actions unless some or all of its joint venture participants agree.
The Partnership participates 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, the Partnership may be unable to cause any of its joint ventures to take or not take certain actions, even though taking or preventing those actions may be in the best interest of the Partnership 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 the Partnership partnering with different or additional parties.
Weather may limit the Partnership’s ability to operate its business and could adversely affect its operating results.
The weather in the areas in which the Partnership operates can cause disruptions and in some cases suspension of its operations. For example, unseasonably wet weather, extended periods of below freezing weather or hurricanes may cause disruptions or suspensions of the Partnership’s operations, which could adversely affect its operating results. Potential climate changes may have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events could have an adverse effect on the Partnership’s operations.
The Partnership’s 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 the Partnership fails to recover all anticipated insurance proceeds for significant accidents or events for which it is insured, or if the Partnership fails to rebuild facilities damaged by such accidents or events, its operations and financial results could be adversely affected.
The Partnership’s operations are subject to many hazards inherent in gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling of NGLs and NGL products; gathering, storing and terminaling crude oil; and storing and terminaling refined petroleum products and crude oil including:
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damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism;
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inadvertent damage from third parties, including from motor vehicles or construction, farm and utility equipment;
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damage that is the result of the Partnership’s negligence or any of its employees’ negligence;
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leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;
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spills or other unauthorized releases of natural gas, NGLs, crude oil, other hydrocarbons or waste materials that contaminate the environment, including soils, surface water and groundwater, and otherwise adversely impact natural resources; and
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other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in substantial losses due to personal injury, 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 the Partnership’s related operations. A natural disaster or other hazard affecting the areas in which the Partnership operates could have a material adverse effect on its operations. For example, in 2005 Hurricanes Katrina and Rita damaged gathering systems, processing facilities, NGL fractionators and pipelines along the Gulf Coast, including certain of the Partnership’s facilities, and 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. The Partnership is not fully insured against all risks inherent to its business. Additionally, while the Partnership is insured for pollution resulting from environmental accidents that occur on a sudden and accidental basis, it may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs that is not fully insured, if the Partnership fails to recover all anticipated insurance proceeds for significant accidents or events for which it is insured, or if the Partnership fails to rebuild facilities damaged by such accidents or events, its operations and financial condition could be adversely affected. In addition, the Partnership may not be able to maintain or obtain insurance of the type and amount it desires at reasonable rates. As a result of market conditions, premiums and deductibles for certain of the Partnership’s 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 could be obtained prior to such hurricanes. Insurance market conditions worsened as a result of the losses sustained from Hurricanes Gustav and Ike in September 2008. As a result, the Partnership experienced further increases in deductibles and premiums, and further reductions in coverage and limits, with some coverage unavailable at any cost.
The Partnership may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the DOT, through the PHMSA, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could do the most harm in “high consequence areas,” including high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators of covered pipelines to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
In addition, states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. The Partnership currently estimates an annual average cost of $2.1 million between 2013 and 2015 to implement pipeline integrity management program testing along certain segments of its natural gas and NGL pipelines. 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 Partnership’s ultimate cost of compliance with applicable pipeline integrity management regulations, 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. The Partnership will continue its pipeline integrity testing programs to assess and maintain the integrity of its pipelines. The results of these tests could cause the Partnership to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.
Moreover, changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on the Partnership and similarly situated midstream operators. The 2011 Pipeline Safety Act, among other things, directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. These safety enhancement requirements and other provisions of this act could require the Partnership to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in the Partnership incurring increased operating costs that could be significant and have a material adverse effect on its financial position or results of operations.
Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase the Partnership’s exposure to commodity price movements.
The Partnership sells processed natural gas to third parties at plant tailgates or at pipeline pooling points. Sales made to natural gas marketers and end-users may be interrupted by disruptions to volumes anywhere along the system. The Partnership attempts to balance sales with volumes supplied from processing operations, but unexpected volume variations due to production variability or to gathering, plant or pipeline system disruptions may expose it to volume imbalances which, in conjunction with movements in commodity prices, could materially impact its income from operations and cash flow.
The Partnership requires a significant amount of cash to service its indebtedness. The Partnership’s ability to generate cash depends on many factors beyond its control.
The Partnership’s ability to make payments on and to refinance its indebtedness and to fund planned capital expenditures depends on its 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 the Partnership’s control. We cannot assure you that the Partnership will generate sufficient cash flow from operations, that future borrowings will be available to it under its credit agreement, that it will be able to sell its accounts receivables and make borrowings under its Securitization Facility, or otherwise in an amount sufficient to enable it to pay its indebtedness or to fund its other liquidity needs. The Partnership may need to refinance all or a portion of its indebtedness at or before maturity. We cannot assure you that the Partnership will be able to refinance any of its indebtedness on commercially reasonable terms or at all.
Failure to comply with existing or new environmental laws or regulations or an accidental release of hazardous substances, hydrocarbons or wastes into the environment may cause the Partnership to incur significant costs and liabilities.
The Partnership’s operations are subject to stringent federal, state and local environmental laws and regulations governing the discharge of pollutants into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to the Partnership’s operations including acquisition of a permit before conducting regulated activities, restriction of types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmentally sensitive areas such as wetlands, urban areas, wilderness regions and other protected areas; requiring capital expenditures to comply with pollution control requirements and imposition of substantial liabilities for pollution resulting from its operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with these laws and regulations or any newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties or other sanctions, the imposition of remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or waste products have been disposed or otherwise released, even under circumstances where the substances, hydrocarbons or waste have been released by a predecessor operator. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by noise, odor or 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 the Partnership’s operations due to its handling of natural gas, NGLs, crude oil and other petroleum products, because of air emissions and product-related discharges arising out of its operations, and as a result of historical industry operations and waste disposal practices. For example, an accidental release from one of the Partnership’s facilities could subject it 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, stricter laws, regulations or enforcement policies could significantly increase the Partnership’s operational or compliance costs and the cost of any remediation that may become necessary. Additionally, environmental groups have, from time to time, advocated increased regulation on the issuance of drilling permits for new wells in areas where the Partnership operates, including the Barnett Shale area. The adoption of any laws, regulations or other legally enforceable mandates that result in more stringent air emission limitations or that restrict or prohibit the drilling of new natural gas wells for any extended period of time could increase the Partnership’s natural gas customers’ operating and compliance costs as well as reduce the rate of production of natural gas or crude oil operators with whom the Partnership has a business relationship, which could have a material adverse effect on its results of operations and cash flows.
Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact the Partnership’s revenues by decreasing the volumes of natural gas that it gathers, processes and fractionates.
Hydraulic fracturing is a process used by oil and gas exploration and production operators in the completion of certain oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate gas and, to a lesser extent, oil production. The process is typically regulated by state oil and gas commissions but the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel fuel under the SDWA Underground Injection Control Program and has issued draft guidance documents related to this asserted regulatory authority. In November 2011, the EPA announced its intent to develop and issue regulations under the federal Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. In addition, from time to time legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Moreover, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the constituents used in the hydraulic-fracturing process. Adoption of legislation or of any implementing regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of natural gas and, in turn, adversely affect the Partnership’s revenues and results of operations by decreasing the volumes of natural gas that it gathers, processes and fractionates.
In addition, several governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administrative-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Moreover, the EPA is developing effluent standards for the treatment and disposal of wastewater resulting from hydraulic fracturing activities and plans to propose those standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior have evaluated various other aspects of hydraulic fracturing. These studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms, which events could delay or curtail production of natural gas by exploration and production operators, some of which are the Partnership’s customers, and thus reduce demand for its midstream services.
A change in the jurisdictional characterization of some of the Partnership’s assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of the Partnership’s assets, which may cause its revenues to decline and operating expenses to increase.
VGS is engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the FERC under the NGA. VGS owns and operates a natural gas gathering system extending from South Timbalier Block 135 to an onshore interconnection to a natural gas processing plant owned by VESCO. With the exception of the Partnership’s interest in VGS, its operations are generally exempt from FERC regulation under the NGA, but FERC regulation still affects its non-FERC jurisdictional businesses and the markets for products derived from these businesses. 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 its 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 the Partnership’s 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 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 the Partnership’s gathering facilities and transportation pipelines may be subject to change based on future determinations by FERC, the courts or Congress.
While the Partnership’s natural gas gathering operations are generally exempt from FERC regulation under the NGA, its gas gathering operations may be subject to certain FERC reporting and posting requirements in a given year. FERC has issued a final rule (as amended by orders on rehearing and clarification), Order No. 704, requiring certain participants in the natural gas market, including 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. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting.
In addition, FERC has issued a final rule (as amended by orders on rehearing and clarification), Order No. 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/d and requiring interstate pipelines to post information regarding the provision of no-notice service. In October 2011, Order No. 720, as clarified, was vacated by the Court of Appeals for the Fifth Circuit with respect to its application to non-interstate pipelines. In December 2011, the Fifth Circuit confirmed that Order No. 720, as clarified, remained applicable to interstate pipelines with respect to posting information regarding the provision of no-notice service. We take the position that at this time the Partnership and its subsidiaries are exempt from this rule.
In addition, FERC recently issued an order extending certain of the open-access requirements including the prohibition on buy/sell arrangements and shipper-must-have-title provisions to include Hinshaw pipelines to the extent such pipelines provide interstate service. However, FERC issued a Notice of Inquiry on October 21, 2010, effectively suspending the recent ruling and requesting comments on whether and how holders of firm capacity on Section 311 and Hinshaw pipelines should be permitted to allow others to make use of their firm interstate capacity, including to what extent buy/sell transactions should be permitted. We have no way to predict with certainty whether and to what extent the Notice of Inquiry will result in a modification to the FERC’s previous ruling.
The crude oil pipeline system that is part of the Badlands assets has qualified for a temporary waiver of applicable FERC regulatory requirements under the ICA based on current circumstances. Such waivers are subject to revocation, however, should the pipeline’s circumstances change, FERC could, either at the request of other entities or on its own initiative, assert that some or all of the transportation on this pipeline system is within it jurisdiction. In the event FERC were to determine that this pipeline system no longer qualified for waiver, the Partnership would likely be required to file a tariff with FERC, provide a cost justification for the transportation charge and provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on this pipeline could adversely affect the Partnership’s results of operations.
Other FERC regulations may indirectly impact the Partnership’s businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of the Partnership’s 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. For more information regarding the regulation of the Partnership’s operations, see “Item 1. Business-Regulation of Operations.”
Should the Partnership fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines.
Under the EP Act of 2005, which is applicable to VGS, 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 the Partnership’s systems other than VGS have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of the Partnership’s 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 the Partnership to civil penalty liability. For more information regarding regulation of the Partnership’s operations, see “Item 1. Business-Regulation of Operations.”
The adoption of climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the products and services the Partnership provides.
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted rules under the Clean Air Act that requires a reduction in emissions of GHGs from motor vehicles and that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. The stationary source final rule addresses the permitting of GHG emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit programs, pursuant to which these permit programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Moreover, because the EPA assumed responsibility for issuing Clean Air Act PSD construction and Title V operating permits for GHG emissions in Texas in December 2010, those two permitting programs are now subject to dual sets of approvals at the state and federal levels. Operators in Texas with stationary sources emitting GHGs in excess of applicable regulatory thresholds must now obtain separate PSD and/or Title V permits from each of the EPA, with respect to GHG emissions, and the TCEQ with respect to all other regulated non-GHG emissions. Facilities required to obtain PSD permits for their GHG emissions will be required to reduce those emissions according to “best available control technology” standards for GHGs. In addition, the EPA adopted rules requiring the monitoring and reporting of GHG emissions from certain sources, including, among others, onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities on an annual basis, which includes certain of the Partnership’s operations.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Partnership to incur increased operating costs or comply with new regulatory or reporting requirements. The division of PSD construction and Title V operating permit authority in Texas between the EPA and TCEQ may cause the Partnership’s Texas operations to experience added delays in obtaining permit coverages, which delays may be significant. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the natural gas and NGLs the Partnership processes or fractionates, which could have an adverse effect on its business, financial condition and results of operations.
Pipeline safety legislation and regulations expanding integrity management programs or requiring the use of certain safety technologies could require the Partnership to use more comprehensive and stringent safety controls and subject it to increased capital and operating costs.
The 2011 Pipeline Safety Act requires increased safety measures for gas and hazardous liquids transportation pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, and leak detection system installation. The 2011 Pipeline Safety Act also directs owners and operators of interstate and intrastate gas transmission pipelines to verify their records confirming the maximum allowable pressure of pipelines in certain class locations and high consequence areas, requires promulgation of regulations for conducting tests to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas, and increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act could require the Partnership to install new or modified safety controls, pursue additional capital projects, decrease its pipeline operating pressures, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in the Partnership incurring increased operating costs that could be significant and have a material adverse effect on its results of operations or financial position.
The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Partnership’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.
The United States Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Partnership, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was signed into law by the President on July 21, 2010, and requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation. The financial reform legislation and subsequent rulemaking may require the Partnership to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although the application of those provisions to the Partnership is uncertain at this time. The financial reform legislation may also require counterparties to the Partnership’s derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect the Partnership’s available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Partnership encounters, reduce its ability to monetize or restructure its existing derivative contracts and increase its exposure to less creditworthy counterparties. If the Partnership reduces its use of derivatives as a result of the legislation and regulations, its results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect its ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Partnership’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Partnership, its financial condition and its results of operations.
The Partnership’s interstate common carrier liquids pipeline is regulated by the FERC.
Targa NGL has interstate NGL pipelines that are considered common carrier pipelines subject to regulation by FERC under the ICA. More specifically, Targa NGL owns a twelve inch diameter pipeline that runs between Lake Charles, Louisiana and Mont Belvieu, Texas. This pipeline can move mixed NGL and purity NGL products. Targa NGL also owns an eight inch diameter pipeline and a twenty inch diameter pipeline, each of which run between Mont Belvieu, Texas and Galena Park, Texas. The eight inch and the twenty inch 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 the Partnership maintain tariffs on file with FERC for each of these pipelines. Those tariffs set forth the rates the Partnership charges 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. All shippers on these pipelines are the Partnership’s subsidiaries.
Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to the Partnership’s business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact the Partnership’s 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 the Partnership’s industry in general and on the Partnership in particular is not known at this time. However, resulting regulatory requirements and/or related business decisions associated with security are likely to increase the Partnership’s costs.
Increased security measures taken by the Partnership as a precaution against possible terrorist attacks have resulted in increased costs to its business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect the Partnership’s operations in unpredictable ways, including disruptions of crude oil supplies and markets for its products, and the possibility that infrastructure facilities could be direct targets, 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 the Partnership to obtain. Moreover, the insurance that may be available to the Partnership may be significantly more expensive than its existing insurance coverage or coverage may be reduced or unavailable. Instability in the financial markets as a result of terrorism or war could also affect the Partnership’s ability to raise capital.
Item 1B.
Item 1B.
Unresolved Staff Comments.
None.
Item 2.
Item 2.
Properties.
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.
Item 3.
Item 3.
Legal Proceedings.
We are not a party to any legal proceedings other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. See “Item 1. Business - Regulation of Operations” and “Item 1. Business - Environmental, Health and Safety Matters.”
Item 4.
Item 4.
Mine Safety Disclosures.
Not applicable.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information
Our common stock has been listed on the New York Stock Exchange (“NYSE”) since December 7, 2010 under the symbol “TRGP.” The following table sets forth the high and low sales prices of the common stock at the end of each subsequent quarter, as reported by the NYSE through December 31, 2012 and the amount of cash dividends declared since our IPO.
(1)
Represents a prorated dividend for the portion of the fourth quarter of 2010 that the Company was public.
As of February 11, 2013, there were approximately 250 stockholders of record of our common stock. This number does not include stockholders whose shares are held in trust by other entities. The actual number of stockholders is greater than the number of holders of record.
Stock Performance Graph
The graph below compares the cumulative return to holders of Targa Resources Corp.'s common stock, the NYSE Composite index (the “NYSE Index") and the Alerian MLP Index ("the MLP Index"). The performance graph was prepared based on the following assumptions: (i) $100 was invested in our common stock at $24.70 per share (the closing market price at the end of our first trading day), in the NYSE Index, and the MLP Index on December 7, 2010 (our first day of trading) and (ii) dividends were reinvested on the relevant payment dates. The stock price performance included in this graph is historical and not necessarily indicative of future stock price performance.
Pursuant to Instruction 7 to Item 201(e) of Regulation S-K, the above stock performance graph and related information is being furnished and is not being filed with the SEC, and as such shall not be deemed to be incorporated by reference into any filing that incorporates this Annual Report by reference.
Our Dividend Policy
We intend to pay to our stockholders, on a quarterly basis, dividends equal to the cash we receive from our Partnership distributions, less reserves for expenses, future dividends and other uses of cash, including:
·
federal income taxes, which we are required to pay because we are taxed as a corporation;
·
the expenses of being a public company;
·
other general and administrative expenses;
·
general and administrative reimbursements to the Partnership;
·
capital contributions to the Partnership upon the issuance by it of additional partnership securities if we choose to maintain the general partner’s 2.0% interest;
·
reserves our board of directors believes prudent to maintain;
·
our obligation to satisfy tax obligations associated with previous sales of assets to the Partnership; and
·
interest expense or principal payments on any indebtedness we incur.
If the Partnership is successful in implementing its business strategy and increasing distributions to its partners, we would generally expect to increase dividends to our stockholders, although the timing and amount of any such increased dividends will not necessarily be comparable to the increased Partnership distributions. We cannot assure you that any dividends will be declared or paid in the future.
The determination of the amount of cash dividends, including the quarterly dividend referred to above, if any, to be declared and paid will depend upon our financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects and any other matters that our board of directors deems relevant. The Partnership’s debt agreements contain restrictions on the payment of distributions and prohibit the payment of distributions if the Partnership is in default. If the Partnership cannot make incentive distributions to the general partner or limited partner distributions to us, we will be unable to pay dividends on our common stock.
The Partnership’s Cash Distribution Policy
The term “available cash” for any quarter, means the sum of all cash and cash equivalents on hand at the end of that quarter, and all additional cash and cash equivalents on hand immediately prior to the date of the distribution of available cash resulting from borrowings for working capital purposes subsequent to the end of that quarter, less the amount of any cash reserves established by the general partner to:
·
provide for the proper conduct of the Partnership’s business including reserves for future capital expenditures and for anticipated future credit needs;
·
comply with applicable law or any loan agreements, security agreements, mortgages, debt instruments or other agreements binding on the Partnership and its subsidiaries; or
·
provide funds for distributions to the Partnership’s unitholders and to the general partner for any one or more of the next four quarters.
The determination of available cash takes into account the possibility of establishing cash reserves in some quarterly periods that the Partnership may use to pay cash distributions in other quarterly periods, thereby enabling it to maintain relatively consistent cash distribution levels even if the Partnership’s business experiences fluctuations in its cash from operations due to seasonal and cyclical factors. The general partner’s determination of available cash also allows the Partnership to maintain reserves to provide funding for its growth opportunities. The Partnership makes its quarterly distributions from cash generated from its operations, and those distributions have grown over time as its business has grown, primarily as a result of numerous acquisitions and organic expansion projects that have been funded through external financing sources and cash from operations.
The actual cash distributions paid by the Partnership to its partners occur within 45 days after the end of each quarter. Since the second quarter of 2007, the Partnership has increased its quarterly cash distribution fifteen times. During that time period, the Partnership has increased its quarterly distribution by 101% from $0.3375 per common unit, or $1.35 on an annualized basis, to $0.68 per common unit, or $2.72 on an annualized basis.
For a discussion of restrictions on our and our subsidiaries’ ability to pay dividends or make distributions, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Credit Facilities and Long-Term Debt” and Note 10 “Debt Obligations” to our consolidated financial statements beginning on page of this Form 10-K.
Recent Sales of Unregistered Stock
None.
Repurchase of Equity by Targa Resources Corp. or Affiliated Purchasers.
None.
Item 6.
Item 6.
Selected Financial Data.
The following table presents selected historical consolidated financial and operating data of Targa Resources Corp. for the periods ended, and as of, the dates indicated. We derived this information from our historical “Consolidated Financial Statements” and accompanying notes. This information should be read together with, and is qualified in its entirety, by reference to those financial statements and notes of this Annual Report.
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our historical financial statements and notes included in Part IV of this Annual Report. Also, the Partnership files a separate Annual Report on Form 10-K with the SEC.
Overview
Financial Presentation
An indirect subsidiary of ours is the general partner of the Partnership. Because we control the general partner, under GAAP we must reflect our ownership interest in the Partnership on a consolidated basis. Accordingly, the Partnership’s financial results are included in our consolidated financial statements even though the distribution or transfer of Partnership assets are limited by the terms of the partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by us are reflected in our results of operations as net income attributable to noncontrolling interests. Therefore, throughout this discussion, we make a distinction where relevant between financial results of the Partnership versus those of us as a standalone parent including our non-Partnership subsidiaries.
As a result of the conveyance of all of our remaining operating assets to the Partnership in September 2010, we have no separate, direct operating activities apart from those conducted by the Partnership. As such, our cash inflows will primarily consist of cash distributions from our interests in the Partnership. The Partnership is required to distribute all available cash at the end of each quarter after establishing reserves to provide for the proper conduct of its business or to provide for future distributions.
The Partnership files its own separate Annual Report. The results of operations included in our consolidated financial statements will differ from the results of operations of the Partnership primarily due to the financial effects of:
·
noncontrolling interests in the Partnership;
·
our separate debt obligations;
·
certain general and administrative costs applicable to us as a separate public company;
·
certain non-operating assets and liabilities that we retained; and
·
federal income taxes.
Our Operations
Currently, we have no separate, direct operating activities apart from those conducted by the Partnership. As such, our cash inflows will primarily consist of cash distributions from our interests in the Partnership. The Partnership is required to distribute all available cash at the end of each quarter after establishing reserves to provide for the proper conduct of its business or to provide for future distributions.
The Partnership’s Operations
The Partnership is a leading provider of midstream natural gas, NGLs, terminaling and crude oil gathering services in the United States. It is engaged in the business of:
·
gathering, compressing, treating, processing and selling natural gas;
·
storing, fractionating, treating, transporting and selling NGLs and NGL products;
·
gathering, storage and terminaling crude oil, and
·
storing, terminaling and selling refined petroleum products.
The Partnership reports its operations in two divisions: (i) Gathering and Processing, consisting of two reportable segments - (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing consisting of two reportable segments - (a) Logistics Assets and (b) Marketing and Distribution. The financial results of the Partnership’s hedging activities are reported in Other.
The Partnership’s Gathering and Processing division 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 NGLs and removing impurities. The Field Gathering and Processing segment’s assets are located in North Texas and the Permian Basin of West Texas and New Mexico. With the Badlands acquisition on December 31, 2012, the Field Gathering and Processing segment’s assets now include the Badlands crude oil and natural gas gathering, terminaling and processing assets in North Dakota as well. However, because the Badlands acquisition closed on December 31, 2012, the Badlands assets had no operational impact for 2012 other than transaction costs related to the acquisition. The Coastal Gathering and Processing segment’s assets are located in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
The Partnership’s Logistics and Marketing division is also referred to as the Downstream Business. The Downstream Business includes all the activities necessary to convert raw NGLs into NGL products and provides certain value added services such as storing, terminaling, transporting, distributing and marketing of NGLs, refined petroleum products and crude oil. It also includes certain natural gas supply and marketing activities in support of the Partnership’s other operations.
The Partnership’s Logistics Assets segment is involved in transporting, storing and fractionating mixed NGLs; storing, terminaling and transporting finished NGLs; and storing and terminaling refined petroleum products and crude oil. These assets are generally connected to, and supplied in part by, the Partnership’s Gathering and Processing segments and are predominantly located in Mont Belvieu, Texas and Southwestern Louisiana. This segment includes the activities associated with the Partnership’s 2011 acquisitions of refined petroleum products and crude oil storage and terminaling facilities.
The Partnership’s Marketing and Distribution segment covers activities required to distribute and market raw and finished NGLs and all natural gas marketing activities. It includes (1) marketing the Partnership’s own NGL production and purchasing NGL products in selected United States markets; (2) providing LPG balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users; and (4) marketing natural gas available to the Partnership from its Gathering and Processing division and the purchase and resale and other value added activities related to third-party natural gas in selected United States markets.
Other contains the results of the Partnership’s commodity hedging activities included in operating margin.
Factors That Significantly Affect Our Results
Our cash flow and resulting ability to pay dividends will be dependent upon the Partnership’s ability to make distributions to its partners, including us. The actual amount of cash that the Partnership will have available for distributions will depend primarily on the amount of cash that it generates from its operations.
As of February 15, 2013, our interests in the Partnership consist of the following:
·
a 2% general partner interest, which we hold through our 100% ownership interest in the general partner of the Partnership;
·
all of the outstanding IDRs; and
·
12,945,659 of the 101,788,617 outstanding common units of the Partnership, representing a 12.7% limited partnership interest.
Factors That Significantly Affect the Partnership’s Results
The Partnership’s results of operations are substantially impacted by the volumes that move through its gathering, processing and logistics assets, changes in commodity prices, contract terms, the impact of hedging activities and the cost to operate and support assets.
Volumes
In the Partnership’s gathering and processing operations, plant inlet volumes and capacity utilization rates generally are driven by wellhead production, its competitive and contractual position on a regional basis and more broadly by the impact of prices for oil, natural gas and NGLs on exploration and production activity in the areas of its operations. The factors that impact the gathering and processing volumes also impact the total volumes that flow to the Partnership’s Downstream Business. In addition, fractionation volumes are also affected by the location of the resulting mixed NGLs, available pipeline capacity to transport NGLs to the Partnership’s fractionators and the Partnership’s competitive and contractual position relative to other fractionators.
Commodity Prices
The following table presents selected annual and quarterly industry index prices for natural gas, selected NGL products and crude oil for the periods presented:
(1)
Natural gas prices are based on average quarterly and annual prices from Henry Hub I-FERC commercial index prices.
(2)
NGL prices are based on quarterly and annual averages of prices from Mont Belvieu Non-TET monthly commercial index prices. Illustrative Targa NGL contains 44% ethane, 30% propane, 11% natural gasoline, 5% isobutane and 10% normal butane.
(3)
Crude oil prices are based on quarterly and annual averages of daily prices from West Texas Intermediate commercial index prices as measured on the NYMEX.
Contract Terms, Contract Mix and the Impact of Commodity Prices
Because of the significant volatility of natural gas and NGL prices, the contract mix of the Partnership’s gathering and processing segment can also have a significant impact on its profitability, especially those contracts that create exposure to changes in energy prices (“equity volumes”). Set forth below is a table summarizing the mix of the Partnership’s gathering and processing contracts for 2012 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
43%
Decreases in natural gas and or NGL prices generate decreases in operating margins.
Fee-Based
3%
No direct impact from commodity price movements.
Wellhead Purchases/Keep-whole
21%
Increases in natural gas prices relative to NGL prices generate decreases in operating margin.
Hybrid
33%
In periods of favorable processing economics (1), similar to percent-of-liquids or to wellhead purchases/keep-whole in some circumstances, if economically advantageous to the processor. In periods of unfavorable processing economics, similar to fee-based.
(1)
Favorable processing economics typically occur when processed NGLs can be sold, after allowing for processing costs, at a higher value than natural gas on a Btu equivalent basis.
Negotiated contract terms are based upon a variety of factors, including natural gas quality, geographic location, competitive commodities and the pricing environment at the time the contract is executed, and customer requirements. The gathering and processing contract mix and, accordingly, the exposure to natural gas and NGL prices may change as a result of producer preferences, competition, changes in production as wells decline at different rates or are added, the Partnership’s expansion into regions where different types of contracts are more common and other market factors.
The contract terms and contract mix of the Downstream Business can also have a significant impact on its results of operations. During periods of low relative demand for available fractionation capacity, rates were low and frac-or-pay contracts were not readily available. Currently, demand for fractionation services is near existing industry capacity, rates have increased, contract lengths have increased and reservation fees are required. These fractionation contracts in the logistics assets segment are primarily fee-based arrangements while the marketing and distribution segment includes both fee-based and percent-of-proceeds contracts.
Impact of the Partnership’s Commodity Price Hedging Activities
In an effort to reduce the variability of its cash flows, the Partnership has hedged the commodity price associated with a portion of its expected natural gas equity volumes through 2015 and NGL and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). With these arrangements, the Partnership has attempted to mitigate its exposure to commodity price movements with respect to its forecasted volumes for these periods. The Partnership also actively manages the Downstream Business product inventory and other working capital levels to reduce exposure to changing NGL prices. For additional information regarding the Partnership’s hedging activities, see “Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
Our exposure to market risk is largely derivative of the Partnership’s exposure to market risk. The Partnership’s principal market risks are its exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by its customers. Neither we nor the Partnership use risk sensitive instruments for trading purposes.
Commodity Price Risk
A significant portion of the Partnership’s revenues are derived from percent-of-proceeds contracts under which it receives a portion of the natural gas and/or NGLs or equity volumes as payment for services. 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 the Partnership’s control. The Partnership monitors these risks and enters into hedging transactions designed to mitigate the impact of commodity price fluctuations on its business. 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 the commodity risk management activities is to hedge the exposure to commodity price risk and reduce fluctuations in the Partnership’s operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of the Partnership’s cash flows, as of December 31, 2012, the Partnership has hedged the commodity price associated with a portion of its expected (i) natural gas equity volumes in Field Gathering and Processing Operations and (ii) NGL and condensate equity volumes predominately in Field Gathering and Processing Operations as well as in the LOU portion of the Coastal Gathering and Processing Operations that result from its percent of proceeds processing arrangements by entering into derivative instruments, including swaps and purchased puts (or floors) and calls (or caps). The Partnership hedges a higher percentage of its expected equity volumes in the current year compared to future years, in which it hedges incrementally lower percentages of expected equity volumes. With swaps, the Partnership typically receives an agreed fixed price for a specified notional quantity of natural gas or NGL and it pays the hedge counterparty a floating price for that same quantity based upon published index prices. Since the Partnership receives from its 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 its actual equity volumes, the Partnership typically limits its use of swaps to hedge the prices of less than its expected natural gas and NGL equity volumes. The Partnership utilizes purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. The Partnership may buy calls in connection with swap positions to create a price floor with upside. The Partnership intends to continue to manage its exposure to commodity prices in the future by entering into similar derivative transactions using swaps, collars, purchased puts (or floors) or other derivative instruments as market conditions permit.
The Partnership has tailored its hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of its physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. The Partnership believes this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The natural gas and NGL hedges’ fair values are based on published index prices for delivery at various locations which closely approximate the actual natural gas and NGL delivery points. A portion of the Partnership’s condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.
These commodity price hedging transactions are typically documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. The Partnership’s 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 its senior secured indebtedness that ranks equal in right of payment with liens granted in favor of its senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Act, and as long as this first priority lien is in effect, the Partnership expects to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if a counterparty’s exposure to the Partnership’s credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in the Partnership’s creditworthiness. A purchased put (or floor) transaction does not expose the Partnership’s counterparties to credit risk, as the Partnership has no obligation to make future payments beyond the premium paid to enter into the transaction, however, the Partnership is exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.
For all periods presented, the Partnership has entered into hedging arrangements for a portion of its forecasted equity volumes. Floor volumes and floor pricing are based solely on purchased puts (or floors). During the years ended December 31, 2012, 2011 and 2010, our operating revenues were increased (decreased) by net hedge adjustments on commodity derivative contracts of $43.2 million, $(33.9) million and $4.7 million. The net hedge adjustments that impact our consolidated revenues (but do not affect the Partnership’s revenues) include amortization of OCI related to hedges terminated and re-assigned upon the Partnership’s acquisition of Versado in 2010, as well as OCI related to terminations of commodity derivatives in July 2008.
As of December 31, 2012, the Partnership had the following derivative instruments which will settle during the years ending December 31, 2013 through 2015:
These contracts may expose the Partnership to the risk of financial loss in certain circumstances. The Partnership’s hedging arrangements provide 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 they have been hedged, the Partnership will receive less revenue on the hedged volumes than it would receive in the absence of hedges (other than with respect to purchased calls).
The Partnership accounts for the fair value of its financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant 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. The Partnership values its derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. For the contracts that have inputs from quoted prices, the classification of these instruments is Level 2 within the fair value hierarchy. For those contracts which the Partnership is unable to obtain quoted prices for at least 90% of the full term of the commodity swap and options, the valuations are classified as Level 3 within the fair value hierarchy. See Note 15 to the “Consolidated Financial Statements” in this Annual Report for more information regarding classifications within the fair value hierarchy.
Interest Rate Risk
We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRC Revolver. The Partnership is exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under its TRP Revolver. As of December 31, 2012, neither we nor the Partnership have any interest rate hedges. However, we or the Partnership may in the future enter into interest rate hedges intended to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRC Revolver and the TRP Revolver will also increase. As of December 31, 2012, the Partnership had $620.0 million in variable rate borrowings under its TRP Revolver and we had variable rate borrowings of $82.0 million under our TRC Revolver. A hypothetical change of 100 basis points in the interest rate of variable rate debt would impact the Partnership’s annual interest expense by $6.2 million and the TRC Non-Partnership annual interest expense by $0.8 million.
Counterparty Credit Risk
The Partnership is subject to risk of losses resulting from nonpayment or nonperformance by its counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Should the creditworthiness of one or more of the counterparties decline, the Partnership’s ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, the Partnership may sustain a loss and its cash receipts could be negatively impacted.
As of December 31, 2012, affiliates of Wells Fargo Bank N.A. (“Wells Fargo”), Barclays PLC (“Barclays”), Securities Americas LLC (“Natixis”), Credit Suisse Group AG (“Credit Suisse”) and Bank of America Merrill Lynch (“BAML”) accounted for 31%, 16%, 15%, 11% and 10% of the Partnership’s counterparty credit exposure related to commodity derivative instruments. Wells Fargo, Barclays, Natixis, Credit Suisse and BAML are major financial institutions that possess investment grade credit ratings based upon minimum credit ratings assigned by Moody’s Investors Service, Inc. and Standard & Poor’s Corporation.
Customer Credit Risk
The Partnership extends credit to customers and other parties in the normal course of business. The Partnership has established various procedures to manage its credit exposure, including initial credit approvals, credit limits and terms, letters of credit and rights of offset. The Partnership also uses prepayments and guarantees to limit credit risk to ensure that its established credit criteria are met.
The Partnership has an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If an assessment of uncollectible accounts resulted in a 1% reduction of the Partnership’s third-party accounts receivable, annual operating income would decrease by $5.1 million in the year of the assessment.
Item 8.
Item 8.
Financial Statements and Supplementary Data.
Our “Consolidated Financial Statements,” together with the report of our independent registered public accounting firm, begin on page of this Annual Report.
Item 9.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A.
Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Annual Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2012 our disclosure controls and procedures were designed at the reasonable assurance level and, as of the end of the period covered in this Annual Report, our disclosure controls and procedures are effective at the reasonable assurance level to provide that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and (ii) accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow for timely decisions regarding required disclosure.
Internal Control Over Financial Reporting
(a) Management’s Report on Internal Control Over Financial Reporting
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). Management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of the 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, management concluded that the internal control over financial reporting was effective as of December 31, 2012, as stated in its report included in our “Consolidated Financial Statements” on page of this Annual Report, which is incorporated herein by reference.
The business of Saddle Butte Pipeline, LLC that the Partnership purchased on December 31, 2012 was excluded from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2012. This business constituted 20.1% of our total assets as of December 31, 2012.
(b) Changes in Internal Control Over Financial Reporting
During the three months ended December 31, 2012, there were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B.
Other Information.
None.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance.
Our executive officers listed below serve in the same capacity for the general partner and devote their time as needed to conduct the business and affairs of both the Company and the Partnership. Because our only cash-generating assets are direct and indirect partnership interests in the Partnership, we expect that our executive officers will devote a substantial majority of their time to the Partnership’s business. We expect the amount of time that our executive officers devote to our business as opposed to the Partnership’s business in future periods will not be substantial unless significant changes are made to the nature of our business.
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. Please read “Certain Relationships and Related Transactions-Stockholders’ Agreement” for a discussion of arrangements among our stockholders pursuant to which our directors were selected prior to our IPO. The following table sets forth certain information with respect to our directors, executive officers and other officers as of February 15, 2013.
Rene R. Joyce has served as Executive Chairman of the Board of TRC, the general partner and TRI since January 1, 2012 and as a director of the Company since its formation on October 27, 2005 and of the general partner since October 2006. Mr. Joyce previously served as Chief Executive Officer of the Company between October 27, 2005 and December 31, 2011, the general partner between October 2006 and December 31, 2011 and TRI between February 2004 and December 31, 2011. He also served as director of TRI between 2004 and December 31, 2011 and was a consultant for the TRI 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. As the founding Chief Executive Officer of TRI, Mr. Joyce brings deep experience in the midstream business, expansive knowledge of the oil and gas industry, as well as relationships with chief executives and other senior management at peer companies, customers and other oil and natural gas companies throughout the world. His experience and industry knowledge, complemented by an engineering and legal educational background, enable Mr. Joyce to provide the board with executive counsel on the full range of business, technical, and professional matters.
Joe Bob Perkins has served as Chief Executive Officer and director of the Company, the general partner and TRI since January 1, 2012. Mr. Perkins previously served as President of the Company between the date of its formation on October 27, 2005 and December 31, 2011, of the general partner between October 2006 and December 31, 2011 and of TRI between February 2004 and December 31, 2011. He was a consultant for the TRI predecessor company during 2003. Mr. Perkins was an independent consultant in the energy industry from 2002 through 2003 and was an active partner in an outdoor advertising firm during a portion of 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 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. Mr. Perkins’ intimate knowledge of all facets of the Company, derived from his service as President from its founding through 2011 and his current service as Chief Executive Officer and director, coupled with his broad experience in the oil and gas industry, and specifically in the midstream sector, his engineering and business educational background and his experience with the investment community enable Mr. Perkins to provide a valuable and unique perspective to the board on a range of business and management matters.
James W. Whalen has served as Advisor to Chairman and CEO of the Company, the general partner and TRI since January 1, 2012 and as a director of the Company since its formation on October 27, 2005, of the general partner since February 2007 and of TRI between 2004 and December 2010. Mr. Whalen previously served as Executive Chairman of the Board of the Company and TRI between October 25, 2010 and December 31, 2011 and of the general partner between December 15, 2010 and December 31, 2011. He also served as President-Finance and Administration of the Company and TRI between January 2006 and October 2010 and the general partner between October 2006 and December 2010 and for various Targa subsidiaries since November 2005. 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 brings a breadth and depth of experience as an executive, board member, and audit committee member across several different companies and in energy and other industry areas. His valuable management and financial expertise includes an understanding of the accounting and financial matters that the Partnership and industry address on a regular basis.
Michael A. Heim has served as President and Chief Operating Officer of the Company, the general partner and TRI since January 1, 2012. Mr. Heim previously served as Executive Vice President and Chief Operating Officer of the Company between the date of its formation on October 27, 2005 and December 2011, of the general partner between October 2006 and December 2011 and of TRI between April 2004 and December 2011 and was a consultant for the TRI 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 President - Finance and Administration of the Company and TRI since October 25, 2010 and of the general partner since December 15, 2010. He has also served as a director of TRI since December 16, 2010. Mr. McParland served as Executive Vice President and Chief Financial Officer of the Company between October 27, 2005 and October 25, 2010 and of TRI between April 2004 and October 25, 2010 and was a consultant for the TRI predecessor company during 2003. He served as Executive Vice President and Chief Financial Officer of the general partner between October 2006 and December 15, 2010 and served as a director of the general partner from October 2006 to February 2007. Mr. McParland served as Treasurer of the Company from October 27, 2005 until May 2007, of the general partner from October 2006 until May 2007 and of TRI from April 2004 until May 2007. Mr. McParland served as Secretary of TRI between February 2004 and May 2004, at which time he was elected as Assistant Secretary. Mr. McParland served as Senior Vice President, Finance of 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.
Roy E. Johnson has served as Executive Vice President of the Company since its formation on October 27, 2005, of the general partner since October 2006 and of TRI since April 2004 and was a consultant for the TRI 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.
Paul W. Chung has served as Executive Vice President, General Counsel and Secretary of the Company since its formation on October 27, 2005, of the general partner since October 2006 and of TRI since May 2004. 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.
Matthew J. Meloy has served as Senior Vice President, Chief Financial Officer and Treasurer of the Company and TRI since October 25, 2010 and of the general partner since December 15, 2010. Mr. Meloy served as Vice President - Finance and Treasurer of the Company and TRI between April 2008 and October 2010, and as Director, Corporate Development of the Company and TRI between March 2006 and March 2008 and of the general partner between March 2006 and March 2008. He has served as Vice President - Finance and Treasurer of the general partner between April 2008 and December 15, 2010. Mr. Meloy was with The Royal Bank of Scotland in the structured finance group, focusing on the energy sector from October 2003 to March 2006, most recently serving as Assistant Vice President.
John R. Sparger has served as Senior Vice President and Chief Accounting Officer of the Company and TRI since January 2006 and of the general partner since October 2006. Mr. Sparger served as Vice President, Internal Audit of the Company between October 2005 and January 2006 and of TRI between November 2004 and January 2006. Mr. Sparger served as a consultant in the energy industry from 2002 through September 2004, including TRI between February 2004 and September 2004, providing advice to various energy companies and entities regarding processes, systems, accounting and internal controls. Prior to 2002, he worked in various accounting and administrative positions with companies in the energy industry, audit and consulting positions in public accounting and consulting positions with a large international consulting firm.
Charles R. Crisp has served as a director of the Company since its formation on October 27, 2005 and of TRI between February 2004 and December 2010. 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. Mr. Crisp brings extensive energy experience, a vast understanding of many aspects of our industry and experience serving on the boards of other public companies in the energy industry. His leadership and business experience and deep knowledge of various sectors of the energy industry bring a crucial insight to the board of directors.
In Seon Hwang has served as a director of the Company since May 2006, of TRI between May 2006 and December 2010 and the general partner since February 2011. 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, and became a partner of Warburg Pincus & Co. in 2009. 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 Competitive Power Ventures, Gulf Coast Energy Resources, LLC, Omega Energia Renovavel S.A. and Venari LLC and serves on the investment committee of Sheridan Production Partners LLC. Mr. Hwang was appointed as a director because certain investment funds managed by Warburg Pincus LLC, for whom Mr. Hwang is a managing director and member, previously controlled us through their ownership of securities in Targa Resources Corp. Mr. Hwang has significant experience with energy companies and investments and broad familiarity with the industry and related transactions and capital markets activity, which enhance his contributions to the board of directors.
Peter R. Kagan has served as a director of the Company since its formation on October 27, 2005, of the general partner since February 2007 and of TRI between February 2004 and December 2010. 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 and became a partner of Warburg Pincus & Co. in 2002. He is also a member of Warburg Pincus’ Executive Management Group. He is also a director of Antero Resources Corporation, Asian Amercian Gas, Inc., Canbriam Energy, Fairfield Energy Limited, Hawkwood Energy LLC, Laredo Petroleum, MEG Energy Corp. and Venari Resources LLC. Mr. Kagan was appointed as a director because certain investment funds managed by Warburg Pincus LLC, for whom Mr. Kagan is a managing director and member, previously controlled us through their ownership of securities in Targa Resources Corp. Mr. Kagan has significant experience with energy companies and investments and broad familiarity with the industry and related transactions and capital markets activity, which enhance his contributions to the board of directors.
Chris Tong has served as a director of the Company since January 2006 and of TRI between January 2006 and December 2010. Mr. Tong is a director of Kosmos Energy Ltd. He also served as a director of Cloud Peak Energy Inc. from October 2009 until May 2012. He served as Senior Vice President and Chief Financial Officer of Noble Energy, Inc. from January 2005 until August 2009. He also 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. Mr. Tong brings a breadth and depth of experience as a chief financial officer in the energy industry, a financial executive, a director of other public companies and a member of other audit committees. He brings significant financial, capital markets and energy industry experience to the board and in his position as the chairman of our Audit Committee.
Ershel C. Redd Jr. has served as a director of the Company since February 2011. Mr. Redd has served as a consultant in the energy industry since 2008 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. Mr. Redd was President and Chief Executive Officer of El Paso Electric Company, a public utility company, from May 2007 until March 2008. Prior to this, Mr. Redd served in various positions with NRG Energy, Inc., a wholesale energy company, including as Executive Vice President - Commercial Operations from October 2002 through July 2006, as President - Western Region from February 2004 through July 2006, and as a director between May 2003 and December 2003. On May 14, 2003, NRG filed for protection under Chapter 11 of the Federal Bankruptcy Code. On November 24, 2003, NRG's Chapter 11 Plan of Reorganization was confirmed. Mr. Redd served as Vice President of Business Development for Xcel Energy Markets, a unit of Xcel Energy Inc., from 2000 through 2002, and as President and Chief Operating Officer for New Century Energy’s (predecessor to Xcel Energy Inc.) subsidiary, Texas Ohio Gas Company, from 1997 through 2000. Mr. Redd brings to the Company extensive energy industry experience, a vast understanding of varied aspects of the energy industry and experience in corporate performance, marketing and trading of natural gas and natural gas liquids, risk management, finance, acquisitions and divestitures, business development, regulatory relations and strategic planning. His leadership and business experience and deep knowledge of various sectors of the energy industry bring a crucial insight to the board of directors.
Board of Directors
Our board of directors consists of eight members. The board reviewed the independence of our directors using the independence standards of the NYSE and, based on this review, determined that Messrs. Crisp, Hwang, Kagan, Redd and Tong are independent within the meaning of the NYSE listing standards currently in effect.
Our directors are divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2014, 2015 and 2013, respectively. The Class I directors are Messrs. Crisp and Whalen, the Class II directors are Messrs. Redd, Perkins and Hwang and the Class III directors are Messrs. Kagan, Tong and Joyce. At each annual meeting of stockholders, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.
Committees of the Board of Directors
Our board of directors has four standing committees - an Audit Committee, a Compensation Committee, a Nominating and Governance Committee and a Conflicts Committee - and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors has the composition and responsibilities described below.
Audit Committee
The members of our Audit Committee are Messrs. Tong, Redd and Crisp. Mr. Tong is the Chairman of this committee. Our board of directors has affirmatively determined that Messrs. Crisp, Redd, and Tong are independent as described in the rules of the NYSE and the Exchange Act. Our board of directors has also determined that, based upon relevant experience, Mr. Tong is an “audit committee financial expert” as defined in Item 407 of Regulation S-K of the Exchange Act.
This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the Audit Committee oversees our compliance programs relating to legal and regulatory requirements. We have adopted an Audit Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.
Compensation Committee
The members of our Compensation Committee are Messrs. Kagan, Crisp and Hwang. Mr. Crisp is the Chairman of this committee. This committee establishes salaries, incentives and other forms of compensation for officers and other employees. Our Compensation Committee also administers our incentive compensation and benefit plans. We have adopted a Compensation Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.
Nominating and Governance Committee
The members of our Nominating and Governance Committee are Messrs. Kagan, Redd and Tong. Mr. Kagan is the Chairman of this committee. This committee identifies, evaluates and recommends qualified nominees to serve on our board of directors, develops and oversees our internal corporate governance processes and maintains a management succession plan. We have adopted a Nominating and Governance Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.
In evaluating director candidates, the Nominating and Governance Committee assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board’s ability to manage and direct the affairs and business of the Company, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.
Conflicts Committee
The members of our Conflicts Committee are Messrs. Crisp, Redd and Tong. Mr. Tong is the Chairman of this committee. This Committee reviews matters of potential conflicts of interest, as directed by our board of directors. We adopted a Conflicts Committee charter defining the committee’s primary duties.
Corporate Governance
Code of Business Conduct and Ethics
Our board of directors has adopted a Code of Ethics For 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 of our other senior financial and accounting officers, and our Code of Conduct (the “Code of Conduct”), which applies to our and our subsidiaries’ officers, directors and employees. 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 or Code of Conduct under Item 5.05 of a current report on Form 8-K.
Available Information
We make available, free of charge within the “Corporate Governance” section of our website at www.targaresources.com and in print to any stockholder who so requests, our Corporate Governance Guidelines, Code of Ethics, Code of Conduct, Audit Committee Charter, Compensation Committee charter and Nominating and Governance Committee charter. Requests for print copies may be directed to: Investor Relations, Targa Resources Corp., 1000 Louisiana, Suite 4300, Houston, Texas 77002 or made by telephone by calling (713) 584-1000. The information contained on or connected to, our internet website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.
Corporate Governance Guidelines
Our board of directors has adopted corporate governance guidelines in accordance with the corporate governance rules of the NYSE.
Executive Sessions of Non-Management Directors
Our non-management directors meet in executive session without management participation at regularly scheduled executive sessions. These meetings are chaired by Mr. Peter Kagan.
Interested parties may communicate directly with our non-management directors by writing to: Non-Management Directors, Targa Resources Corp., 1000 Louisiana, Suite 4300, Houston, Texas 77002.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our directors, executive officers and 10% stockholders to file with the SEC reports of ownership and changes in ownership of our equity securities. Based solely upon a review of the copies of the Form 3, 4 and 5 reports furnished to us and certifications from our directors and executive officers, we believe that during 2012, all of our directors, executive officers and beneficial owners of more than 10% of our common units complied with Section 16(a) filing requirements applicable to them.
Item 11.
Item 11.
Executive Compensation.
Compensation Discussion and Analysis
The following Compensation Discussion and Analysis (“CD&A”) contains statements regarding our compensation programs and our executive officers’ business priorities related to our compensation programs and target payouts under the programs. These business priorities 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
Compensatory arrangements with our executive officers identified in the Summary Compensation Table (“named executive officers”) are approved by the Compensation Committee of our Board of Directors (the “Compensation Committee”). For 2012, our named executive officers were:
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Rene R. Joyce - Executive Chairman of the Board;
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Joe Bob Perkins - Chief Executive Officer;
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James W. Whalen -Advisor to Chairman and CEO;
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Michael A. Heim - President and Chief Operating Officer; and
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Matthew J. Meloy - Senior Vice President, Chief Financial Officer and Treasurer.
Our named executive officers also serve as executive officers of the general partner. We own a 14.5% interest in the Partnership, including the 2% general partner interest, and are the indirect parent of the general partner. The compensation information described in this Compensation Discussion and Analysis and contained in the tables that follow reflects all compensation received by our named executive officers for the services they provide to us and for the services they provide to the general partner and the Partnership for the years covered.
All decisions regarding this compensation are made by the Compensation Committee, except that long-term equity incentive awards recommended by the Compensation Committee under the Targa Resources Partners Long-Term Incentive Plan are approved by the board of directors of the general partner who oversees that plan. The named executive officers devote their time as needed to the conduct of our business and affairs and the conduct of the Partnership’s business and affairs. During 2012, the Partnership reimbursed us and our affiliates for the compensation of our named executive officers pursuant to the Partnership Agreement and the terms, and subject to the limitations, of the Omnibus Agreement, which will expire in April 2013. See “Item 13. Certain Relationships and Related Transactions, and Director Independence-Omnibus Agreement” for additional information regarding the Partnership’s reimbursement obligations for 2012 and for 2013 following the expiration of the Omnibus Agreement.
The Compensation Committee believes that the actions it has taken to govern compensation in a responsible way as described in this CD&A and the Company’s performance over its relative brief trading history will demonstrate that our compensation programs are structured to pay reasonable amounts for performance based on our understanding of the markets and that our shareholders have realized substantial returns since our public offering.
At our 2011 Annual Meeting, more than 99% of the votes cast by our shareholders approved the compensation paid to our named executive officers as described in the CD&A and the other related compensation tables and disclosures contained in our Proxy Statement filed with the SEC on April 4, 2011. The Board of Directors and the Compensation Committee reviewed the results of this vote and concluded that with this level of support, no changes to our compensation design and philosophy needed to be considered as a result of the vote. In accordance with the preference expressed by our shareholders to conduct an advisory vote on executive compensation every three years, the next advisory vote will occur at our 2014 Annual Meeting.
Summary of 2012 Compensation Decisions
While the compensation arrangements for our named executive officers during fiscal 2012 remained substantially similar to those in place during fiscal 2011, specific compensatory changes in 2012 included the following:
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Base salary raises were approved for our named executive officers, ranging from 2.4% to 17.0%. The larger adjustments approved for Mr. Heim and Mr. Meloy were implemented to reflect the increased responsibilities of these named executive officers in connection with organizational restructurings of executive roles and duties.
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Mr. Meloy’s target bonus amount under our annual incentive plan was increased to 50% of his base salary from 40% of his base salary in 2011, in order to reflect his promotion to Chief Financial Officer. The target bonus amounts for all other named executive officers did not change from 2011.
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On January 12, 2012, we adopted the Executive Change in Control Program, which provides “double trigger” benefits, including cash payments, to our named executive officers following a qualifying termination in connection with a change in control event. Under a “double trigger” plan, both a change in control and a qualifying termination must occur in order for an executive to be entitled to the change in control benefits. We believe these post-termination change in control benefits are appropriately aligned with shareholder interests are important in attracting and retaining qualified executives and are in line with similar benefits provided by our Peer Group and other companies with which we compete for executive talent.
Summary of Key Strategic Results
Our main source of cash flow is from our general and limited partner interests and our incentive distribution rights in the Partnership, which is a leading provider of midstream natural gas and natural gas liquid services in the United States. As described in “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” in our Annual Report on Form 10-K, our 2012 financial results and the 2012 financial results of the Partnership as well as the 2012 strategic and operational accomplishments were both significant improvements relative to 2011 results. In summary, some of our more significant financial, operational and strategic highlights in 2012 included:
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On balance, excellent execution across our businesses offset by weaker commodity prices, with the Partnership’s EBITDA nonetheless at the low end of public guidance;
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Excellent execution on announced expansion projects;
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Launch of additional expansion projects;
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Continued development of our potential future expansion project portfolio;
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Successful negotiation of the agreement for and closing of the acquisition of a Bakken shale midstream business;
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A strong track record and performance regarding safety and compliance with all aspects of our business, including environmental and regulatory compliance.
See “Components of Executive Compensation Program for Fiscal 2012-Annual Cash Incentive Bonus” for further detail regarding the above summary highlights.
Consistent with, and in recognition of, these achievements, in January 2013 we awarded 2012 annual cash incentive bonuses to our named executive officers at 165% of the target level. We also approved base salary raises to bring our named executive officers more closely in line with salaries provided to executives at companies within our Peer Group, adjusted for company size. The 2013 annual incentive bonus target was increased for Mr. Perkins to be more in line with those of chief executive officers at our Peer Group companies and the long-term equity incentive award opportunity for 2013 for Messrs. Perkins and Heim was increased to be more in line with those provided to executives at companies within our Peer Group, in all cases adjusted for company size. See “Role of Peer Group and Benchmarking” for a description of our Peer Group companies for 2012, including the regression methodology used by BDO USA, LLC, the compensation consultant engaged by the Compensation Committee (the “Compensation Consultant”), to adjust for company size, and see “Changes for 2013” for additional information regarding base salary and incentive bonus opportunity increases effected for fiscal 2013.
Discussion and Analysis of Executive Compensation
Compensation Philosophy
The Compensation Committee believes that total compensation for our executives should be competitive with the market in which we compete for executive talent, which encompasses not only midstream natural gas companies but also other energy industry companies as described in “Role of Peer Group and Benchmarking” below. The following compensation objectives guide the Compensation Committee in its deliberations about executive compensation matters:
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Competition Among Peers. The Compensation Committee believes our executive compensation program should provide a competitive total compensation program that enables us to attract and retain key executives.
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Accountability for Performance. The Compensation Committee believes our executive compensation program should ensure an alignment between our strategic and financial performance and the total compensation received by our named executive officers. This includes providing compensation for performance that reflects individual and company performance both in absolute terms and relative to our Peer Group.
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Alignment with Shareholder Interests. The Compensation Committee believes our executive compensation program should 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.
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Supportive of Business Goals. The Compensation Committee believes that our total compensation program should support our business objectives and priorities.
Consistent with this philosophy and the compensation objectives, our executive compensation program is comprised of the following elements of compensation:
Fiscal 2012 Total Direct Compensation
We review the mix of base salary, annual cash incentive bonuses and long-term equity incentive awards (i.e., total direct compensation) each year for the Company and for our Peer Group. We view the various components of total direct compensation as related but distinct and emphasize pay for performance, with a significant portion of total direct compensation reflecting a risk aspect tied to long- and short-term financial and strategic goals. Although we typically target annual long-term equity incentive awards as a percentage of base salary, we have historically not operated under any formal policies or guidelines for allocating compensation between long-term and currently paid out compensation, between cash and non-cash compensation, or among different forms of non-cash compensation. However, we believe that our compensation packages are representative of an appropriate mix of compensation components, and we anticipate that we will continue to utilize a similar, though not identical, mix of compensation in future years.
The approximate allocation of total direct compensation for our named executive officers in fiscal 2012 is presented below. This reflects (i) the salary rates in effect as of December 31, 2012, (ii) target annual cash incentive bonuses for services performed in fiscal 2012, and (iii) the grant date fair value of long-term equity incentive awards granted during fiscal 2012.
Fiscal 2012 Total Direct Compensation
In the two full calendar years since our December 2010 public offering, the target total direct compensation (salary plus target bonus plus grant value of annual equity awards) available to our Chief Executive Officer has been set by the Compensation Committee at a level that is approximately 70% of the market total compensation level that our Peer Group company-based regression models predict for a company of our size as measured by market capitalization and total assets. The following chart illustrates the relationship between the target total direct compensation available to our Chief Executive Officer and the market level developed by our Compensation Consultant for the last three years. The decrease in the Chief Executive Officer target from 2010 to 2011 corresponds to Mr. Perkin’s appointment to that position for 2011.
Because incentive compensation comprises 72% of our Chief Executive Officer’s total compensation opportunity, the amount of compensation he may realize may be more or less than the target amount as determined in particular by our Compensation Committee’s evaluation of our performance, the total unitholder return on the Partnership’s common units and the total return of our common stock relative to peer companies.
In the two full calendar years since our December 2010 public offering, we have delivered annual total return to our shareholders of 55.2% and 33.6%, respectively.
Methodology and Process
Role of Peer Group and Benchmarking
When evaluating compensation levels for each named executive officer, the Compensation Committee, with the assistance of the Compensation Consultant, reviews publicly available compensation data for executives in our Peer Group and compensation surveys and uses that information to set compensation levels for the named executive officers in the context of their roles and levels of responsibility, accountability and decision-making authority and in the context of company size relative to the Peer Group. While compensation data from other companies is considered, the Compensation Committee and senior management do not attempt to set compensation components to meet specific benchmarks.
The Peer Group company data that is reviewed by senior management and the Compensation Committee is simply one factor out of many that is used in connection with the establishment of the compensation for our officers. The other factors considered include, but are not limited to, (i) available compensation data, rankings and comparisons, (ii) effort and accomplishment on a group and individual basis, (iii) challenges faced and challenges overcome, (iv) unique skills, (v) contribution to the management team and (vi) the perception of both the Board of Directors and the Compensation Committee of our performance relative to expectations and actual market/business conditions. All of these factors, including Peer Group company data and analysis, are utilized in a subjective assessment of each year’s decisions relating to base salary, annual cash incentive bonus, and long-term equity incentive award decisions.
The Peer Group considered by the Compensation Committee in consultation with senior management for compensation comparison purposes includes midstream master limited partnerships (“MLPs”) and other energy utilities and exploration and production companies to reflect the market in which we compete for executive talent. Our analysis places greater weight on the compensation data reported by other publicly-traded midstream partnerships that are comparable to us in size as measured by market capitalization and total assets. Utilities and exploration and production companies selected for the Peer Group, in the Compensation Committee’s opinion, provide relevant reference points because they have similar or related operations, compete in the same or similar markets, face similar regulatory challenges and require similar skills, knowledge and experience of their executive officers as we require of our executive officers.
Because many companies in the Peer Group are larger than us as measured by market capitalization and total assets, with the assistance of the Compensation Consultant, compensation data for the Peer Group companies is analyzed using multiple regression analysis to develop a prediction of the total compensation that Peer Group companies of comparable size to us would offer similarly-situated executives. The regressed data is analyzed separately for each peer group and is then weighted as follows to develop a reference point for assessing our total executive pay opportunity relative to market practice: MLPs (given a 70% weighting), exploration and production companies (“E&Ps”) (given a 15% weighting) and utility companies (given a 15% weighting). For 2012, the “Peer Group” companies were:
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MLP peer companies: Atlas Pipeline Partners, L.P., Copano Energy, L.L.C., Crosstex Energy, LP, DCP Midstream Partners, LP, Enbridge Energy Partners LP, Energy Transfer Partners, LP, Enterprise Products Partners LP, Magellan Midstream Partners, LP, MarkWest Energy Partners, LP, NuStar Energy LP, ONEOK Partners, LP, Regency Energy Partners LP and Williams Partners LP.
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E&P peer companies: Apache Corporation, Anadarko Petroleum Corporation, Cabot Oil & Gas Corp., Cimarex Energy Co., Denbury Resources Inc., Devon Energy Corporation, EOG Resources Inc., Murphy Oil Corp., Newfield Exploration Co., Noble Energy Inc., Penn Virginia Corp., Petrohawk Energy Corp., Pioneer Natural Resources Co., Southwestern Energy Co. and Ultra Petroleum Corp.
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Utility peer companies: Centerpoint Energy Inc., Dominion Resources Inc., Enbridge Inc., EQT Corp., National Fuel Gas Co., NiSource Inc., ONEOK Inc., Questar Corp., Sempra Energy, Spectra Energy Co., Southern Union Co., TransCanada Corporation and Williams Companies Inc.
Senior management and the Compensation Committee review our compensation-setting practices and Peer Group companies on at least an annual basis.
Role of Senior Management in Establishing Compensation for Named Executive Officers
Typically, under the direction of the Compensation Committee, senior management consults with the Compensation Consultant, and reviews market data and evaluates relevant compensation levels and compensation program elements towards the end of each fiscal year. Based on these consultations and assessments of performance relative to key business priorities, senior management submits emerging conclusions and, subsequently, a proposal to the Chairman of the Compensation Committee. The proposal includes a recommendation of base salary, target annual cash incentive bonus opportunity and long-term equity incentive awards to be paid or awarded to executive officers for the next fiscal year. In addition, the proposal includes a recommendation regarding the annual cash incentive bonus amount to be paid for the current fiscal year.
The Chairman of the Compensation Committee reviews and discusses the proposal with senior management and the Compensation Consultant and may discuss it with the other members of the Compensation Committee, other members of the Board of Directors, the full Board of Directors and/or the full board of directors of the general partner. The Chairman of the Compensation Committee may request that senior management provide him with additional information or reconsider or revise the proposal. The resulting recommendation is then submitted to the full Compensation Committee for consideration, which typically invites other members of the Board of Directors and the directors of the general partner, and also meets separately with the Compensation Consultant. The final compensation decisions are reported to the Board of Directors.
Our senior management has no other role in determining compensation for our named executive officers, although the Compensation Committee may delegate the approval of award grants and other transactions and responsibilities regarding the administration of compensatory programs to the Executive Chairman of the Board or the Chief Executive Officer, provided that such administration and approval of awards does not apply for our Section 16 officers. Our executive officers are delegated the authority and responsibility to determine the compensation for all other employees.
Components of Executive Compensation Program for Fiscal 2012
Base Salary
The base salaries for our named executive officers are set and reviewed annually by the Compensation Committee. Base salaries for our named executive officers have been established based on Peer Group analysis and historical salary levels for these officers, as well as the relationship of their salaries to those of our other executive officers, taking into consideration the value of the total direct compensation opportunities available to our executive officers, including the long-term equity incentive award component of our compensation program.
For 2012, the Compensation Committee authorized increases in base salary for our named executive officers, effective March 1, 2012, as set forth in the following table. Salaries for all named executive officers were increased to recognize outstanding performance and to better align their salaries with data generated in our Compensation Consultant’s Peer Group analysis regarding expected compensation for companies of our size. The increases for Messrs. Heim and Meloy were more significant to reflect their increased responsibilities within the organization.
Annual Cash Incentive Bonus
For 2012, our named executive officers were eligible to receive annual cash incentive bonuses under the 2012 Annual Incentive Plan (the “2012 Bonus Plan”), which was approved by the Compensation Committee in January 2012. The funding of the cash bonus pool and the payment of individual cash bonuses to executive management, including our named executive officers, are subject to the sole discretion of the Compensation Committee and will generally be determined near or following the end of the year to which the bonus relates.
The target amount of the cash bonus pool for all employees is equal to the sum of the target bonus amounts for all participants in the 2012 Bonus Plan. Each participant’s target bonus amount is equal to the product of the participant’s base salary and the participant’s target bonus percentage, which may generally range from 6.0% to 100%. For purposes of the 2012 Bonus Plan, the percentage of base salary that was set as the “target” amount for each named executive officer’s bonus was as follows:
Mr. Meloy’s target bonus percentage was increased from 40% to 50%, effective January 12, 2012, to recognize his increased responsibilities as our Chief Financial Officer.
The Chief Executive Officer and the Compensation Committee relied on the Compensation Consultant and market data from Peer Group companies and broader industry compensation practices to establish the target bonus percentages for the named executive officers and the applicable threshold, target and maximum percentage levels for funding the cash bonus pool, which are generally consistent with both Peer Group company and broader energy compensation practices.
The Compensation Committee, after consultation with the Chief Executive Officer, established the following overall threshold, target and maximum levels for the 2012 Bonus Plan: (i) 50% of the target amount of the cash bonus pool would be funded in the event that the Compensation Committee determined that our business priorities had been met for the year at a threshold level; (ii) 100% of the target amount of the cash bonus pool would be funded in the event that the Compensation Committee determined that our business priorities had been met for the year at a target level; and (iii) 200% of the target amount of the cash bonus pool would be funded in the event that the Compensation Committee determined that our business priorities had been met for the year at a maximum level. While the established threshold, target and maximum levels provide general guidelines in determining the funding level of the cash bonus pool each year, senior management recommends a funding level to the Compensation Committee based on our achievement of specified business priorities for the year, and the Compensation Committee ultimately determines the total amount to be allocated to the cash bonus pool in its sole discretion based on its assessment of the business priorities and our overall performance for the year.
For purposes of determining the actual funding level of the cash bonus pool and the amount of individual bonus awards under the 2012 Bonus Plan, the Compensation Committee focused on the business priorities listed in the table below. These priorities are not objective in nature-they are subjective and performance in regard to these priorities is ultimately evaluated by the Compensation Committee in its sole discretion. As such, success does not depend on achieving a particular target; rather, success is evaluated based on past norms, expectations and unanticipated obstacles or opportunities that arise. For example, hurricanes and deteriorating or changing market conditions may alter the priorities initially established by the Compensation Committee such that certain performance that would otherwise be deemed a negative may, in context, be a positive result. This subjectivity allows the Compensation Committee to account for the full industry and economic context of our actual performance and that of our personnel. The Compensation Committee considers all strategic priorities and reviews performance against the priorities and context but does not apply a formula or assign specific weightings to the strategic priorities in advance.
After reviewing the 2012 Business Priorities, Results and Overall Assessment as summarized above, in January, 2013, the Compensation Committee, in its sole discretion, approved a cash bonus pool equal to 165% of the target level under the 2012 Bonus Plan. The Compensation Committee determined to pay these above target level bonuses because it considered overall performance, including organizational performance, to have substantially exceeded expectations in 2012 based on its assessment of the key business priorities it established for 2012 despite deterioration in commodity prices.
This subjective assessment that performance substantially exceeded expectations was based on a qualitative evaluation rather than a mechanical, quantitative determination of results across each of the key business priorities. This subjective evaluation that performance had substantially exceeded expectations occurred with the background and ongoing context of (i) refinements of the 2012 business priorities by the Board of Directors and the Compensation Committee both before the beginning of and during the year, (ii) continued discussion and active dialogue between the Board of Directors and the Compensation Committee and management about priorities and performance, including routine reports sent to the Board of Directors and the Compensation Committee, (iii) detailed monthly performance communications to the Board of Directors, (iv) presentations and discussions in subsequent Board of Directors and Compensation Committee meetings, and (v) further discussion among the Board of Directors and Compensation Committee of our performance relative to expectations near the end and following the end of 2012. The extensive business and board of director experience of the members of the Compensation Committee and of our Board of Directors provides the perspective to make this subjective assessment in a qualitative manner and to evaluate management performance overall and the performance of individual executive officers.
In connection with determining the funding level of the cash bonus pool, the Compensation Committee also determined the amount of the annual cash incentive bonus payments to be made to each named executive officer under the 2012 Bonus Plan based on an evaluation of the executive group and each officer’s individual performance for the year. Because the funding level of the cash bonus pool was set at 165% of the target amount, each named executive officer was awarded a bonus amount equal to 165% of his respective target bonus amount, multiplied by a designated multiple determined by the Compensation Committee for each named executive officer based on his individual performance. The Compensation Committee determined that a performance multiplier of 1.25x should be applied to Mr. Meloy’s bonus amount for the year, based on his individual performance including his role in leading the Partnership’s execution of multiple capital markets transactions during 2012 and leading in our and the Partnership’s overall financial strategies. All other named executive officers received a 1.0x multiplier. The dollar amounts of the annual cash incentive bonus awards received by the named executive officers under the 2012 Bonus Plan to be paid by February 28, 2013 are as follows:
Long-Term Equity Incentive Awards
In connection with our initial public offering in December 2010 (the “IPO”), we adopted the 2010 Stock Incentive Plan (the “Stock Incentive Plan”) under which we may grant to the named executive officers, other key employees, consultants and directors certain equity-based awards, including restricted stock, bonus stock and performance-based awards. In addition, the general partner sponsors and maintains the Targa Resources Partners Long-Term Incentive Plan (the “Long-Term Incentive Plan”), under which the general partner may grant equity-based awards related to the Partnership’s common units to individuals, including the named executive officers, who provide services to the Partnership.
The Compensation Committee determines the amount of long-term equity incentive awards under the Stock Incentive Plan and recommends to the board of directors of the general partner an amount of long-term equity incentive awards under the Partnership’s Long-Term Incentive Plan that it believes is appropriate as a component of total compensation for each named executive officer for a given year based on its decisions regarding each named executive officer’s total compensation targets. The Long-Term Incentive Plan awards are ultimately determined and approved by the general partner’s board of directors. Long-term incentive awards to our named executive officers under the Stock Incentive Plan and the Long-Term Incentive Plan are made at the beginning of each year.
For 2012, the value of the long-term equity incentive component of our named executive officers’ compensation was allocated approximately (i) twenty-five (25%) to restricted stock awards under the Stock Incentive Plan and (ii) seventy-five (75%) to equity-settled performance unit awards under the Partnership’s Long-Term Incentive Plan. This allocation is based on the dollar value of the awards on the date of grant. The total dollar value of long-term equity incentive awards for each named executive officer for a given year is typically equal to a specified percentage of the officer’s base salary; however, the Compensation Committee may, in its discretion, award additional long-term equity incentive awards if deemed appropriate. The number of shares or units subject to each award is determined by dividing the total dollar value allocated to the award by the ten day average closing price of the shares or units for the period ending five business days prior to the date of grant.
The Compensation Committee believes that the combination of equity awards consisting of restricted stock (25% of award value) and equity-settled performance units (75% of award value) granted to our named executive officers provides a balance of performance-based long-term incentives and of parent and subsidiary MLP equity. The restricted stock awards are time-based awards that capture absolute total return performance of our common stock, and the equity-settled performance unit awards reflect both the absolute total return of the Partnership’s common units with variable performance based on the total return of the Partnership’s units in relation to the LTIP Peer Group (defined below). Also, this mix effectively aligns the named executive officer’s interests with both the interests of our stockholders and the interests of the Partnership’s unitholders. The Compensation Committee allocates a larger portion of each named executive officer’s long-term equity incentive compensation to equity-settled performance unit awards because these awards link executive compensation not only to the value of Partnership equity over time, but also to the relative performance of the Partnership compared to other midstream partnerships with which the Partnership competes.
Restricted Stock Awards. On January 12, 2012, our named executive officers were awarded restricted shares of our common stock under the Stock Incentive Plan in the following amounts: (i) 6,565 restricted shares to Mr. Joyce, (ii) 5,035 restricted shares to Mr. Perkins, (iii) 4,235 restricted shares to Mr. Whalen, (iv) 4,399 restricted shares to Mr. Heim, and (v) 1,866 restricted shares to Mr. Meloy. These restricted stock awards vest in full on the third anniversary of the grant date, subject to the officer’s continued service. Accelerated vesting provisions applicable to these awards in the event of certain terminations of employment and/or a change in control are described in detail below under “-Potential Payments Upon Termination or Change in Control-Stock Incentive Plan.” During the period the restricted shares are outstanding and unvested, we accrue any dividends paid by us in an amount equal to the dividends paid with respect to a share of common stock times the number of restricted shares awarded. At the time the restricted shares vest, the named executive officers will receive a cash payment equal to the amount of dividends accrued with respect to such named executive officer’s vested shares.
Equity-Settled Performance Unit Awards. Our named executive officers also receive awards of equity-settled performance unit awards under the Partnership’s Long-Term Incentive Plan. The vesting of these awards is dependent on the Partnership’s performance relative to the performance of a specified comparator group of publicly-traded partnerships (the “LTIP Peer Group”). These awards, which are settled in Partnership common units, are designed to align the interests of the named executive officers and other key employees with those of the Partnership’s equity holders.
On January 12, 2012, our named executive officers were awarded equity-settled performance units under the Partnership’s Long-Term Incentive Plan in the following amounts: (i) 21,240 performance units to Mr. Joyce, (ii) 16,290 performance units to Mr. Perkins, (iii) 13,702 performance units to Mr. Whalen, (iv) 14,233 performance units to Mr. Heim, and (v) 6,039 performance units to Mr. Meloy.
The performance period for the 2012 performance unit awards began on June 30, 2012 and ends on June 30, 2015. Provided a named executive officer remains continuously employed throughout the performance period, his 2012 performance units will vest on June 30, 2015 and will be settled as soon as practicable following the vesting date by the issuance of a number of Partnership common units equal to the number of performance units awarded multiplied by the “performance vesting percentage,” which may range from 0% to 150%, dependent upon the relative total return performance of the Partnership’s common units compared to the LTIP Peer Group.
For performance results that fall between the 25th percentile and the 50th percentile of the LTIP Peer Group, the performance vesting percentage will be interpolated between 25% and 100% and, for performance results that fall between the 50th percentile and 75th percentile, the performance vesting percentage will be interpolated between 100% and 150%. If the Partnership’s performance is above the 75th percentile of the LTIP Peer Group, the performance vesting percentage will be 150% of the award. If the Partnership’s performance is below the 25th percentile of the LTIP Peer Group, the performance vesting percentage will be 0%.
For the 2012 performance unit awards, the LTIP Peer Group is composed of the Partnership and the following other companies:
Copano Energy, L.L.C.
MarkWest Energy Partners, LP
Crosstex Energy, LP
Martin Midstream Partners LP
DCP Midstream Partners, LP
ONEOK Partners, LP
Enbridge Energy Partners LP
Plains All American Pipeline L.P.
Energy Transfer Partners, LP
Regency Energy Partners LP
Magellan Midstream Partners, LP
Williams Partners LP
The LTIP Peer Group is not composed of the same companies as the peer group companies employed for developing market reference points for executive pay because the companies in those groups are those with which we compete for executive talent. Companies in the LTIP Peer Group are principally those companies with which the Partnership competes to varying extents in the midstream sector.
The board of directors of the general partner has the ability to modify the LTIP Peer Group in the event a company listed above ceases to be publicly traded or another significant event occurs and a company is determined to no longer be one of the Partnership’s peers.
For purposes of the performance unit awards, the Partnership’s performance is determined based on the comparison of “total return” of a Partnership common unit for the performance period to the “total return” of a common share/unit of each member of the LTIP Peer Group for the performance period. “Total return” is measured by (i) subtracting the average closing price per share/unit for the first ten trading days of the performance period (the “Beginning Price”) from the sum of (a) the average closing price per share/unit for the last ten trading days ending on the date that is 15 days prior to the end of the performance period, plus (b) the aggregate amount of dividends/distributions paid with respect to a share/unit during such period (such result is referred to as the “Value Increase”), and (ii) dividing the Value Increase by the Beginning Price. During the period the performance unit awards are outstanding, the Partnership accrues any cash distributions paid by the Partnership in an amount equal to the cash distributions paid with respect to a common unit times the number of performance units awarded. At the time the performance unit awards are settled, the named executive officers will also receive a cash payment equal to the amount of cash distributions accrued with respect to a common unit times the number of such named executive officer’s vested units.
The following charts illustrate the total return for the Partnership’s common units compared to the total return of each other company in the LTIP Peer Group measured over the period beginning in June 30 of each year in which the long-term incentive awards were made, using the Beginning Price described above, and continuing through January 10, 2013.
Severance and Change in Control Benefits. On January 12, 2012, the Compensation Committee adopted the Executive Officer Change in Control Program (the “Change in Control Program”), in which each of our named executive officers is eligible to participate. Prior to 2012, none of our named executive officers (other than Mr. Meloy) was eligible to participate in any arrangement providing cash payments upon a change in control or specified termination of employment events. The Change in Control Program provides for post-termination payments following a qualifying termination in connection with a change in control event, or what is commonly referred to as a “double trigger” benefit. The vesting of certain of our long-term equity incentive compensation awards accelerates upon a change in control irrespective of whether the officer is terminated, and/or upon certain termination of employment events, such as death, disability or a termination by us without cause. Please see “-Potential Payments Upon Termination or Change in Control” below for further information.
We believe that the Change in Control Program and the accelerated vesting provisions in our long-term equity incentive awards create important retention tools for us and are consistent with the practices of most of our industry peers. Accelerated vesting of long-term equity incentive awards upon a change in control enables our named executive officers to realize value from these awards consistent with value created for investors upon the closing of a transaction. In addition, we believe that post termination benefits may, in part, mitigate some of the potential uncertainty created by a potential or actual change in control transaction, including the future employment of the named executive officers, thus allowing management to focus on the business transaction at hand.
Retirement, Health and Welfare, and Other Benefits. We offer eligible employees participation in a section 401(k) tax-qualified, defined contribution plan (the “401(k) 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 eligible compensation on a pre-tax basis (or on a post-tax basis via a Roth contribution) and have it contributed to the 401(k) Plan, subject to certain limitations under the Internal Revenue Code of 1986, as amended (the “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, and (ii) an amount equal to the employee’s contributions to the 401(k) Plan up to 5% of the employee’s eligible compensation. In addition, we may also make discretionary contributions to the 401(k) Plan for the benefit of employees depending on our performance. Company contributions to the 401(k) Plan may be subject to certain limitations under the Code for certain employees. We do not maintain a defined benefit pension plan or a nonqualified deferred compensation plan for our named executive officers or other employees.
All full-time employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, life insurance, dental coverage and disability insurance. It is the Compensation Committee’s policy not to pay for perquisites for any of our named executive officers, other than minimal parking subsidies.
Changes for 2013
Base Salary
The Compensation Committee authorized, and executive management will implement, the following increased base salaries for our named executive officers effective March 1, 2013.
Mr. Joyce and Mr. Whalen did not receive base salary increases for 2013 at their request. The Compensation Committee authorized base salary increases for the other named executive officers in order to more closely align the total direct compensation of these individuals with the total direct compensation provided to similarly situated executives at companies within our Peer Group, adjusted for company size and to reflect professional growth and the assumption of additional responsibilities. The analysis provided to the Compensation Committee by the Compensation Consultant indicates that the 2013 total target direct compensation of our Chief Executive Officer remains more than 25% below the competitive amount suggested by the market trend line that was developed through regression analysis of Peer Group pay programs.
Annual Cash Incentive Bonus
In preparing our business plan for 2013, senior management developed and proposed a set of business priorities to the Compensation Committee. The Compensation Committee adopted the business priorities proposed by senior management, with certain modifications requested by the Compensation Committee, for purposes of the 2013 Annual Incentive Plan (the “2013 Bonus Plan”). The 2013 business priorities are similar to those in effect for 2012 and have been revised to reflect a focus on EBITDA and distribution/dividend growth, our recent Bakken shale midstream acquisition and retaining qualified talent, and specifically include the following:
·
execute on all business dimensions, including 2013 guidance for EBITDA and distribution/dividend growth as furnished from time to time,
·
successfully integrate and commercialize the Bakken shale midstream acquisition including contribution to 2013 guidance,
·
continue priority emphasis and strong performance relative to a safe workplace,
·
reinforce business philosophy and mindset that promotes compliance in all aspects of our business including environmental and regulatory compliance,
·
continue to attract and retain the operational and professional talent needed in our businesses,
·
continue to control all costs-operating, capital and G&A,
·
continue to manage tightly credit, inventory, interest rate and commodity price exposures,
·
execute on major capital and development projects-finalizing negotiations, completing projects on time and on budget, and optimizing economics and capital funding,
·
pursue selected growth opportunities including G&P build outs, fee-based capex projects, and potential purchases of strategic assets, and
·
pursue commercial and financial approaches to achieve maximum value and manage risks.
The overall threshold, target and maximum funding percentages for the 2013 Bonus Plan remain the same as for the 2012 Bonus Plan. In addition, the target bonus percentage (as a percentage of base salary) for each named executive officer (other than Mr. Perkins) remains the same for 2013. Mr. Perkins’ target bonus percentage for 2013 has been increased from 80% of base salary to 100% of base salary in order to more closely align his total direct compensation with the total direct compensation provided to similarly situated chief executive officers at companies within our Peer Group, adjusted for company size. As with the 2012 Bonus Plan, funding of the cash bonus pool and the payment of individual cash bonuses to executive management, including our named executive officers, are subject to the sole discretion of the Compensation Committee.
Long-Term Incentive Awards
Restricted Stock Awards. On January 15, 2013, our named executive officers were awarded restricted shares of our common stock under the Stock Incentive Plan in the following amounts: (i) 4,960 restricted shares to Mr. Joyce, (ii) 4,895 restricted shares to Mr. Perkins, (iii) 3,200 restricted shares to Mr. Whalen, (iv) 4,296 restricted shares to Mr. Heim, and (v) 1,742 restricted shares to Mr. Meloy. These restricted stock awards vest in full on the third anniversary of the grant date, subject to the officer’s continued service.
Equity-Settled Performance Unit Awards. On January 15, 2013, our named executive officers were awarded equity-settled performance units under the Partnership’s Long-Term Incentive Plan in the following amounts: (i) 21,251 performance units to Mr. Joyce, (ii) 20,971 performance units to Mr. Perkins, (iii) 13,709performance units to Mr. Whalen, (iv) 18,405 performance units to Mr. Heim, and (v) 7,465 performance units to Mr. Meloy. The vesting and settlement value of these performance unit awards will be determined using the formula adopted for the performance unit awards granted on January 12, 2012, except that the performance period for the 2013 awards will begin on June 30, 2013 and end on June 30, 2016. Please see “Components of Executive Compensation Program for Fiscal 2012- Long-Term Equity Incentive Awards-Equity-Settled Performance Unit Awards.”
Other Compensation Matters
Accounting Considerations. We account for the equity compensation expense for our employees, including our named executive officers, under the rules of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 718, which requires us to estimate and record an expense for each award of long-term equity incentive compensation over the vesting period of the award. Accounting rules also require us to record cash compensation as an expense at the time the obligation is accrued.
Clawback Policy. To date, we have not adopted a formal clawback policy to recoup incentive based compensation upon the occurrence of a financial restatement, misconduct, or other specified events. However, restricted stock agreements covering grants made to our named executive officers and other employees in 2011 and later years do include language providing that any compensation, payments or benefits provided under such an award (including profits realized from the sale of earned shares) are subject to clawback to the extent required by applicable law.
Securities Trading Policy. All of our officers, employees and directors are subject to our Insider Trading Policy, which, among other things, prohibits officers, employees and directors from engaging in certain short-term or speculative transactions involving our securities. Specifically, the policy provides that officers, employees and directors may not engage in the following transactions: (i) purchasing our common stock on margin, (ii) short sales of our common stock, or (iii) the purchase or sale of options of any kind, whether puts or calls, or other derivative securities, relating to our common stock.
Compensation Risk Assessment
The Compensation Committee has reviewed the relationship between our risk management policies and compensation policies and practices and has concluded that we do not have any compensation policies or practices that expose us to excessive or unnecessary risks that are reasonably likely to have a material adverse effect on us. Because our Compensation Committee retains the sole discretion for determining the actual amount paid to executives pursuant to our annual cash incentive bonus program, our Compensation Committee is able to assess the actual behavior of our executives as it relates to risk-taking in awarding bonus amounts. Further, our use of long-term equity incentive compensation serves our executive compensation program’s goal of aligning the interests of executives and shareholders, thereby reducing the incentives to unnecessary risk-taking.
Compensation Committee Report
Messrs. Crisp, Hwang and Kagan are the current members of our Compensation Committee. In fulfilling its oversight responsibilities, the Compensation Committee has reviewed and discussed with management the Compensation Discussion and Analysis contained in our Annual Report on Form 10-K for the year ended December 31, 2012 and in this proxy statement. Based on these reviews and discussions, the Compensation Committee recommended to our Board of Directors that the Compensation Discussion and Analysis be included in our Annual Report on Form 10-K for the year ended December 31, 2012 and in this proxy statement 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 we specifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended, or the Exchange Act.
The Compensation Committee
Charles R. Crisp, Chairman
Peter R. Kagan
In Seon Hwang
Executive Compensation Tables
Summary Compensation Table for 2012
The following Summary Compensation Table sets forth the compensation of our named executive officers for 2012, 2011 and 2010. Additional details regarding the applicable elements of compensation in the Summary Compensation Table are provided in the footnotes following the table.
(1)
For 2012, represents payments pursuant to our 2012 Bonus Plan. Please see “-Components of Executive Compensation Program for Fiscal 2012-Annual Cash Incentive Bonus.” Note that, in prior filings, the payments reported under this column for 2010 were reported in the “Non-Equity Incentive Plan Compensation” column. As discussed above, payments pursuant to our Bonus Plan are discretionary and not based on objective performance measures.
(2)
Amounts reported in the “Stock Awards” column represent the aggregate grant date fair value of restricted stock awards under our Stock Incentive Plan and of equity-settled performance unit awards under the Partnership’s Long-Term Incentive Plan, in each case, granted in 2012 and computed in accordance with FASB ASC Topic 718. Assumptions used in the calculation of these amounts are included in Note 22 to our “Consolidated Financial Statements.” beginning on page of our Annual Report on Form 10-K for fiscal year 2012. Detailed information about the amount recognized for specific awards is reported in the table under “-Grants of Plan-Based Awards for 2012” below. The grant date fair value of each restricted share subject to the restricted stock awards granted on January 12, 2012, assuming vesting will occur, is $38.72. The grant date fair value of each performance unit subject to the equity-settled performance unit awards granted on January 12, 2012 is $41.54, computed in accordance with FASB ASC Topic 718. Assuming, instead, a payout percentage for these performance unit awards of 150%, which is the maximum payout percentage under the awards, the aggregate grant date fair value of the equity-settled performance unit awards granted on January 12, 2012 for each named executive officer is as follows: Mr. Joyce - $1,323,464; Mr. Meloy - $376,311; Mr. Perkins - $1,015,030; Mr. Whalen - $853,772; and Mr. Heim - $886,879.
(3)
For 2012 “All Other Compensation” includes (i) the aggregate value of all employer-provided contributions to our 401(k) plan and (ii) the dollar value of life insurance coverage provided by the Company.
Grants of Plan Based Awards for 2012
The following table and the footnotes thereto provide information regarding grants of plan-based equity awards made to the named executive officers during 2012:
(1)
The grants on January 12, 2012 are restricted stock awards granted under our Stock Incentive Plan and equity-settled performance units granted under the Partnership’s Long-Term Incentive Plan. For a detailed description of how performance achievements will be determined for the equity-settled performance units, see “-Components of Executive Compensation Program for Fiscal 2012-Long-Term Equity Incentive Awards-Equity-Settled Performance Unit Awards.”
(2)
The dollar amounts shown for the restricted stock awards granted on January 12, 2012 are determined by multiplying the shares reported in the table by $38.72, which is the grant date fair value of awards computed in accordance with FASB ASC Topic 718. The dollar amounts shown for the equity-settled performance units granted on January 12, 2012 are determined by multiplying the number of units equal to approximately 87% of the number of units reported in the table under the “Target” column by $41.54, which is the grant date fair value of awards computed in accordance with FASB ASC Topic 718 and is consistent with the estimate of aggregate compensation cost to be recognized over the service period of the awards, excluding the effect of estimated forfeitures.
Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards Table
A discussion of 2012 salaries, bonuses, incentive plans and awards is set forth in “-Compensation Discussion and Analysis,” including a discussion of the material terms and conditions of the 2012 restricted stock awards under our Stock Incentive Plan and the 2012 equity-settled performance unit awards under the Partnership’s Long-Term Incentive Plan, such as the vesting schedule of such awards, any applicable performance-based conditions, and the extent to which dividends and distributions are paid with respect to such awards.
Outstanding Equity Awards at 2012 Fiscal Year-End
The following table and the footnotes related thereto provide information regarding equity-based awards outstanding as of December 31, 2012 for each of our named executive officers.
·
Represents the following shares of restricted stock under our Stock Incentive Plan held by our named executive officers:
(a)
The restricted shares subject to the December 10, 2010 awards are subject to the following vesting schedule: 60% of the restricted shares vested on December 10, 2012 and the remaining 40% of the restricted shares will vest on December 10, 2013.
(b)
The restricted shares subject to the February 14, 2011 awards are subject to the following vesting schedule: 100% of the restricted shares vest on February 14, 2014.
(c)
The restricted shares subject to the January 12, 2012 awards are subject to the following vesting schedule: 100% of the restricted shares vest on January 12, 2015.
(2)
The dollar amounts shown are determined by multiplying the number of shares of restricted stock reported in the table by the closing price of a share of our common stock on December 31, 2012 ($52.84). The amounts do not include the related distribution equivalent rights for the award.
(3)
Represents the following performance units linked to the performance of the Partnership’s common units held by our named executive officers:
(a)
Reflects the target number of performance units granted to the named executive officers on December 3, 2009. Vesting of these awards is contingent upon continuous active employment at the end of the performance period, which ends June 30, 2013, and the Partnership’s performance over the applicable performance period measured against a peer group of companies.
(b)
Reflects the target number of performance units granted to the named executive officer on August 2, 2010 . Vesting of this award is contingent upon continuous active employment at the end of the performance period, which ends June 30, 2013, and the Partnership’s performance over the applicable performance period measured against a peer group of companies.
(c)
Reflects the target number of performance units granted to the named executive officers on February 17, 2011 multiplied by a performance percentage of 142.9%. Vesting of these awards is contingent upon continuous active employment at the end of the performance period, which ends June 30, 2014, and the Partnership’s performance over the applicable performance period measured against a peer group of companies.
(d)
Reflects the target number of performance units granted to the named executive officers on January 12, 2012 multiplied by a performance percentage of 100%. Vesting of these awards is contingent upon continuous active employment at the end of the performance period, which ends June 30, 2015, and the Partnership’s performance over the applicable performance period measured against a peer group of companies.
(4)
The dollar amounts shown are determined by multiplying the number of performance units reported in the table by the closing price of a common unit of the Partnership on December 31, 2012 ($37.38). The amounts do not include the related distribution equivalent rights for the award.
Option Exercises and Stock Vested in 2012
The following table provides the amount realized during 2012 by each named executive officer upon the vesting of restricted stock and performance unit awards. None of our named executive officers exercised any option awards during the 2012 year and, currently, there are no options outstanding under any of our plans.
(1)
Shares of restricted stock granted under our Stock Incentive Plan on December 10, 2010, which vested on December 10, 2012 (60% of the total number of restricted shares subject to each grant).
(2)
Computed with respect to the restricted stock awards granted under our Stock Incentive Plan, by multiplying the number of shares of stock vesting by the closing price of a share of common stock on the December 10, 2012 vesting date ($47.88) and does not include associated dividends accrued during the vesting period.
(3)
Performance units linked to the performance of the Partnership’s common units granted under the Partnership’s Long-Term Incentive Plan in January 2009 (in August 2009 with respect to Mr. Meloy), which vested on June 30, 2012, at the 100% payout level.
(4)
Computed as the number of performance units vested multiplied by the closing price of a Partnership common unit on June 29, 2012 ($35.65), since the June 30, 2012 vesting date was not a trading day, and does not include associated distributions accrued during the vesting period
Pension Benefits
Other than our 401(k) Plan, we do not have any plan that provides for payments or other benefits at, following, or in connection with, retirement.
Non-Qualified Deferred Compensation
We do not have any plan that provides for the deferral of compensation on a basis that is not tax qualified.
Potential Payments Upon Termination or Change in Control
Aggregate Payments
The table below reflects the aggregate amount of payments and benefits that we believe our named executive officers would have received under our Executive Officer Change in Control Severance Program (the “Change in Control Program”), our Stock Incentive Plan and the Partnership’s Long-Term Incentive Plan upon certain specified termination of employment events and/or a change in control, in each case, that occurred on December 31, 2012. Details regarding individual plans and arrangements follow the table. The amounts below constitute estimates of the amounts that would be paid to our named executive officers upon each designated event, and do not include any amounts accrued through fiscal 2012 year-end that would be paid in the normal course of continued employment, such as accrued but unpaid salary and benefits generally available to all salaried employees. The actual amounts to be paid are dependent on various factors, which may or may not exist at the time a named executive officer is actually terminated and/or a change in control actually occurs. Therefore, such amounts and disclosures should be considered “forward-looking statements.”
Executive Officer Change in Control Severance Program
We adopted the Change in Control Program on and effective as of January 12, 2012. Each of our named executive officers became eligible to participate in the Change in Control Program during the 2012 calendar year.
The Change in Control Program is administered by our Vice President - Human Resources. The Change in Control Program provides that if, in connection with or within 18 months after a “Change in Control,” a participant suffers a “Qualifying Termination,” then the individual will receive a severance payment, paid in a single lump sum cash payment within 60 days following the date of termination, equal to three times (i) the participant’s annual salary as of the date of the Change in Control or the date or termination, whichever is greater, and (ii) the amount of the participant’s annual salary multiplied by the participant’s most recent “target” bonus percentage specified by the Compensation Committee prior to the Change in Control. In addition, the participant (and his eligible dependents, as applicable) will receive the continuation of their medical and dental benefits until the earlier to occur of (a) three years from the date of termination, or (b) the date the participant becomes eligible for coverage under another employer’s plan.
For purposes of the Change in Control Program, the following terms will generally have the meanings set forth below:
·
Cause means discharge of the participant by us on the following grounds: (i) the participant’s gross negligence or willful misconduct in the performance of his duties, (ii) the participant’s conviction of a felony or other crime involving moral turpitude, (iii) the participant’s willful refusal, after 15 days’ written notice, to perform his material lawful duties or responsibilities, (iv) the participant’s willful and material breach of any corporate policy or code of conduct, or (v) the participant’s willfully engaging in conduct that is known or should be known to be materially injurious to us or our subsidiaries.
·
Change in Control means any of the following events: (i) any person (other than the Partnership) becomes the beneficial owner of more than 20% of the voting interest in us or in the general partner, (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Company or the general partner (other than to the Partnership or its affiliates), (iii) a transaction resulting in a person other than Targa Resources GP LLC or an affiliate being the general partner of the Partnership, (iv) the consummation of any merger, consolidation or reorganization involving us or the general partner in which less than 51% of the total voting power of outstanding stock of the surviving or resulting entity is beneficially owned by the stockholders of the Company or the general partner, immediately prior to the consummation of the transaction, or (v) a majority of the members of the Board of Directors or the Board of Directors of the general partner is replaced during any 12 month period by directors whose appointment or election is not endorsed by a majority of the members of the applicable Board of Directors before the date of the appointment or election.
·
Good Reason means: (i) a material reduction in the participant’s authority, duties or responsibilities, (ii) a material reduction in the participant’s base compensation, or (iii) a material change in the geographical location at which the participant must perform services. The individual must provide notice to us of the alleged Good Reason event within 90 days of its occurrence and we have the opportunity to remedy the alleged Good Reason event within 30 days from receipt of the notice of such allegation.
·
Qualifying Termination means (i) an involuntary termination of the individual’s employment by us without Cause or (ii) a voluntary resignation of the individual’s employment for Good Reason.
All payments due under the Change in Control Program will be conditioned on the execution and nonrevocation of a release for our benefit and the benefit of our related entities and agents. The Change in Control Program will supersede any other severance program for eligible participants in the event of a Change in Control, but will not affect accelerated vesting of any equity awards under the terms of the plans governing such awards.
If amounts payable to a named executive officer under the Change in Control Program (together with any other amounts that are payable by us as a result of a Change in Control (collectively, the “Payments”) exceed the amount allowed under section 280G of the Code for such individual, thereby subjecting the individual to an excise tax under section 4999 of the Code, then, depending on which method produces the largest net after-tax benefit for the recipient, the Payments shall either be: (i) reduced to the level at which no excise tax applies or (ii) paid in full, which would subject the individual to the excise tax.
The following table reflects payments that would have been made to each of the named executive officers under the Change in Control Program in the event there was a Change in Control and the officer incurred a Qualifying Termination, in each case, as of December 31, 2012.
(1)
Includes 3 years’ worth of continued participation in our medical and dental plans, calculated based on the monthly employer-paid portion of the premiums for our medical and dental plans as of December 31, 2012 for each named executive officer and his eligible dependents in the following amounts: (a) Mr. Perkins - $47,290, (b) Mr. Meloy - $47,290, (c) Mr. Joyce - $35,556, (d) Mr. Whalen - $35,556, and (e) Mr. Heim - $47,290.
Stock Incentive Plan
Each of our named executive officers held outstanding restricted stock awards under our form of restricted stock agreement (the “Stock Agreement”) and the Stock Incentive Plan as of December 31, 2012. If a “Change in Control” occurs and the named executive officer has remained continuously employed by us from the date of grant to the date upon which such Change in Control occurs, then the restricted stock granted to him under the Stock Agreements, and related dividends then credited to him, will fully vest on the date upon which such Change in Control occurs.
Restricted stock granted to a named executive officer under the Stock Agreements, and related dividends then credited to him, will also fully vest if the named executive officer’s employment is terminated by reason of death or a “Disability.” If a named executive officer’s employment with us is terminated for any reason other than death or Disability, then his unvested restricted stock is forfeited to us for no consideration.
The following terms generally have the following meanings for purposes of the Stock Incentive Plan and Stock Agreements:
1.
Affiliate means an entity or organization which, directly or indirectly, controls, is controlled by, or is under common control with, us.
2.
Change in Control means the occurrence of one of the following events: (i) any person or group acquires or gains ownership or control (including, without limitation, the power to vote), by way of merger, consolidation, recapitalization, reorganization or otherwise, of more than 50% of the outstanding shares of the our voting stock or more than 50% of the combined voting power of the equity interests in the Partnership or the general partner; (ii) the liquidation or dissolution of us or the approval by the limited partners of the Partnership of a plan of complete liquidation of the Partnership; (iii) the sale or other disposition by us of all or substantially all of our assets in one or more transactions to any person other than Warburg Pincus LLC or any other Affiliate; (iv) the sale or disposition by either the Partnership or the general partner of all or substantially all of its assets in one or more transactions to any person other than to Warburg Pincus LLC, the general partner, or any other Affiliate; (v) a transaction resulting in a person other than Targa Resources GP LLC or an Affiliate being the general partner of the Partnership; or (vi) as a result of or in connection with a contested election of directors, the persons who were our directors before such election shall cease to constitute a majority of our Board of Directors.
3.
Disability means a disability that entitles the named executive officer to disability benefits under our long-term disability plan.
The following table reflects amounts that would have been received by each of the named executive officers under the Stock Incentive Plan and related Stock Agreements in the event there was a Change in Control or their employment was terminated due to death or Disability, each as of December 31, 2012. The amounts reported below assume that the price per share of our common stock was $52.84, which was the closing price per share of our common stock on December 31, 2012.
(1)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column: (a) $1,436,825 and $66,596, respectively, relate to the restricted shares and related dividend rights granted on December 10, 2010, which are scheduled to vest December 10, 2013; (b) $224,570 and $8,989, respectively, relate to the restricted shares and related dividend rights granted on February 14, 2011, which are scheduled to vest February 14, 2014; and (c) $266,049 and $4,110, respectively, relate to the restricted shares and related dividend rights granted on January 12, 2012, which are scheduled to vest on January 12, 2015.
(2)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column: (a) $473,975 and $21,968, respectively, relate to the restricted shares and related dividend rights granted on December 10, 2010, which are scheduled to vest December 10, 2013; (b) $66,578 and $2,665, respectively, relate to the restricted shares and related dividend rights granted on February 14, 2011, which are scheduled to vest February 14, 2014; and (c) $98,599 and $1,523, respectively, relate to the restricted shares and related dividend rights granted on January 12, 2012, which are scheduled to vest on January 12, 2015.
(3)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column: (a) $2,560,098 and $118,659, respectively, relate to the restricted shares and related dividend rights granted on December 10, 2010, which are scheduled to vest December 10, 2013; (b) $406,340 and $16,264, respectively, relate to the restricted shares and related dividend rights granted on February 14, 2011, which are scheduled to vest February 14, 2014; and (c) $346,895 and $5,359, respectively, relate to the restricted shares and related dividend rights granted on January 12, 2012, which are scheduled to vest on January 12, 2015.
(4)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column: (a) $1,436,825 and $66,596, respectively, relate to the restricted shares and related dividend rights granted on December 10, 2010, which are scheduled to vest December 10, 2013; (b) $224,570 and $8,989, respectively, relate to the restricted shares and related dividend rights granted on February 14, 2011, which are scheduled to vest February 14, 2014; and (c) $223,777 and $3,457, respectively, relate to the restricted shares and related dividend rights granted on January 12, 2012, which are scheduled to vest on January 12, 2015.
(5)
Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column: (a) $1,286,865 and $59,645, respectively, relate to the restricted shares and related dividend rights granted on December 10, 2010, which are scheduled to vest December 10, 2013; (b) $199,207 and $7,974, respectively, relate to the restricted shares and related dividend rights granted on February 14, 2011, which are scheduled to vest February 14, 2014; and (c) $232,443 and $3,591, respectively, relate to the restricted shares and related dividend rights granted on January 12, 2012, which are scheduled to vest on January 12, 2015.
Partnership’s Long-Term Incentive Plan
Each of our named executive officers held outstanding performance unit awards under the Partnership’s form of performance unit grant agreement (the “Performance Unit Agreement”) and the Partnership’s Long-Term Incentive Plan as of December 31, 2012. If a “Change in Control” occurs during the performance period established for the performance units and related distribution equivalent rights granted to a named executive officer under the Performance Unit Agreements prior to 2011, 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 in cash equal to the sum of (i) the product of (a) the fair market value of a common unit of the Partnership multiplied by (b) the target 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. If a Change in Control occurs during the performance period established for the performance units and related distribution rights granted to a named executive officer under the Performance Unit Agreements in 2011 and later years, the performance units will be settled upon the occurrence of the Change in Control by providing the named executive officer with a number of common units of the Partnership equal to the target number of performance units granted to the named executive officer plus a cash payment in the amount of distribution equivalent rights then credited to the named executive officer, if any. The general partner may elect to settle the performance unit awards in cash instead of in common units.
Generally, 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 the named executive officer’s employment with us and our affiliates. However, if a named executive officer’s employment is terminated by reason of his death or “Disability” or is terminated by us other than for “Cause,” he will become vested in the 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 as if the named executive officer had remained continuously employed through the end of the performance period.
The following terms generally have the meanings specified below for purposes of the Partnership’s Long-Term Incentive Plan:
·
Change in Control means (i) any person or group, other than an affiliate, becomes 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 the general partner, (ii) the limited partners of the Partnership approve a plan of complete liquidation of the Partnership, (iii) the sale or other disposition by either the Partnership or the general partner of all or substantially all of its assets in one or more transactions to any person other than the general partner or one of the general partner’s affiliates, or (iv) a transaction resulting in a person other than Targa Resources GP LLC or one of its affiliates being the general partner of the Partnership.
·
Cause means (i) failure to perform assigned duties and responsibilities, (ii) engaging in conduct which is injurious (monetarily or otherwise) to us or our affiliates, (iii) breach of any corporate policy or code of conduct established by us or our affiliates, or breach of any agreement between the named executive officer and us or our 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 us or our 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.
·
Disability means a disability that entitles the named executive officer to disability benefits under our long-term disability plan.
The following table reflects amounts that would have been received by each of the named executive officers under the Partnership’s Long-Term Incentive Plan and related Performance Unit Agreements in the event there was a Change in Control or their employment was terminated due to death or Disability or by us without Cause, each as of December 31, 2012. The amounts reported below assume that the price per Partnership common unit was $37.38, which was the closing price per common unit on December 31, 2012. In addition, the amounts reported below in the “Termination for Death or Disability or Without Cause” column assume that the applicable performance period for each award ended December 31, 2012 and are based on achieving the next higher performance level for the award (if any) that exceeds performance for the 2012 fiscal year.
(1)
Of the amount reported under the “Change in Control” column; (a) $518,087 and $81,116, respectively, relate to the performance units and related distribution equivalent rights granted on December 3, 2009; (b) $436,972 and $43,048, respectively, relate to the performance units and related distribution equivalent rights granted on February 17, 2011; and (c) $608,920 and $21,258, respectively, relate to the performance units and related distribution equivalent rights granted on January 12, 2012. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: (a) $518,087 and $99,840, respectively, relate to the performance units and related distribution equivalent rights granted on December 3, 2009; (b) $624,433 and $127,919, respectively, relate to the performance units and related distribution equivalent rights granted on February 17, 2011; and (c) $608,920 and $129,180, respectively, relate to the performance units and related distribution equivalent rights granted on January 12, 2012.
(2)
Of the amount reported under the “Change in Control” column: (a) $149,520 and $23,410, respectively, relate to the performance units and related distribution equivalent rights granted on August 2, 2010; (b) $129,709 and $12,778, respectively, relate to the performance units and related distribution equivalent rights granted on February 17, 2011; and (c) $225,738 and $7,881, respectively, relate to the performance units and related distribution equivalent rights granted on January 12, 2012. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: (a) $149,520 and $28,710, respectively, relate to the performance units and related distribution equivalent rights granted on December 3, 2009; (b) $185,367 and $37,974, respectively, relate to the performance units and related distribution equivalent rights granted on February 17, 2011; and (c) $225,738 and $47,889, respectively, relate to the performance units and related distribution equivalent rights granted on January 12, 2012.
(3)
Of the amount reported under the “Change in Control” column: (a) $673,775 and $105,491, respectively, relate to the performance units and related distribution equivalent rights granted on December 3, 2009; (b) $789,092 and $77,738, respectively, relate to the performance units and related distribution equivalent rights granted on February 17, 2011; and (c) $793,951 and $27,718, respectively, relate to the performance units and related distribution equivalent rights granted on January 12, 2012. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: (a) $673,775 and $129,374, respectively, relate to the performance units and related distribution equivalent rights granted on December 3, 2009; (b) $1,127,605 and $230,996, respectively, relate to the performance units and related distribution equivalent rights granted on February 17, 2011; and (c) $793,951 and $168,433, respectively, relate to the performance units and related distribution equivalent rights granted on January 12, 2012.
(4)
Of the amount reported under the “Change in Control” column: (a) $503,284 and $78,798, respectively, relate to the performance units and related distribution equivalent rights granted on December 3, 2009; (b) $436,972 and $43,048, respectively, relate to the performance units and related distribution equivalent rights granted on February 17, 2011; and (c) $512,181 and $17,881, respectively, relate to the performance units and related distribution equivalent rights granted on January 12, 2012. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: (a) $503,284 and $96,638, respectively, relate to the performance units and related distribution equivalent rights granted on December 3, 2009; (b) $624,433 and $127,919, respectively, relate to the performance units and related distribution equivalent rights granted on February 17, 2011; and (c) $512,181 and $108,657, respectively, relate to the performance units and related distribution equivalent rights granted on January 12, 2012.
(5)
Of the amount reported under the “Change in Control” column: (a) $369,838 and $57,905, respectively, relate to the performance units and related distribution equivalent rights granted on December 3, 2009; (b) $387,257 and $38,151, respectively, relate to the performance units and related distribution equivalent rights granted on February 17, 2011; and (c) $532,030 and $18,574, respectively, relate to the performance units and related distribution equivalent rights granted on January 12, 2012. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: (a) $369,838 and $71,014, respectively, relate to the performance units and related distribution equivalent rights granted on December 3, 2009; (b) $553,374 and $113,362, respectively, relate to the performance units and related distribution equivalent rights granted on February 17, 2011; and (c) $532,030 and $112,868, respectively, relate to the performance units and related distribution equivalent rights granted on January 12, 2012.
Director Compensation
The following table sets forth the compensation earned by our non-employee directors for 2012:
(1)
Each of Messrs. Kagan and Hwang earned $63,550 and $65,000, respectively, in fees for service on the Board of Directors of the general partner in 2012. Mr. Kagan’s compensation included $63,500 in cash fees, $77,285 in common unit awards and $82,562 in all other compensation. Mr. Hwang’s compensation included $65,500 in cash fees, $77,285 in common unit awards and $0 in all other compensation. Please see “Director Compensation” in the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012 for additional information.
(2)
As of December 31, 2012, Messrs. Crisp, Tong, and Kagan each held 750 unvested common units of the Partnership.
(3)
Amounts reported in the “Stock Awards” column represent the aggregate grant date fair value of fully vested shares of our common stock awarded to the non-employee directors under our Stock Incentive Plan, computed in accordance with FASB ASC Topic 718. For a discussion of the assumptions and methodologies used to value the awards reported in this column, see the discussion contained in the Notes to Consolidated Financial Statements at Note 22 included in our Annual Report on Form 10-K for the year ended December 31, 2012. On January 12, 2012, each director received 1,851 fully vested shares of our common stock in connection with their 2012 service on our Board of Directors, and the grant date fair value of each share of common stock computed in accordance with FASB ASC Topic 718 was $38.72. As of December 31, 2012, none of our non-employee directors held any outstanding stock options or any outstanding, unvested shares of our common stock.
Narrative to Director Compensation Table
For 2012, all non-employee directors received an annual cash retainer of $50,000. The Chairman of the Audit Committee received an additional annual retainer of $20,000, the Chairman of the Compensation Committee received an additional annual retainer of $15,000 and the Chairman of the Governing and Nominating Committee received an additional retainer of $10,000. All of our non-employee directors receive $1,500 for each Board of Directors, Audit Committee, Compensation Committee, Governance and Nominating Committee, and Conflicts Committee meeting attended. Payment of non-employee director fees is generally made twice annually, at the second regularly scheduled meeting of the Board of Directors and at the final regularly scheduled meeting of the Board of Directors for the fiscal year. All non-employee directors are reimbursed for out-of-pocket expenses incurred in attending Board of Director 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, Perkins and Whalen for services performed for us and our affiliates.
Director Long-term Equity Incentives
We granted equity awards in January 2012 to our non-employee directors under the Stock Incentive Plan. Each of these directors received an award of 1,851 fully vested shares of our common stock, which reflected our intent to provide them with a target value of approximately $75,000 in annual long-term incentive awards. The awards are intended to align the long-term interests of our directors with those of our stockholders.
Changes for 2013
In January 2013, the Board of Directors approved changes to our non-employee director compensation for the 2013 fiscal year by increasing the annual cash retainer for service on our Board of Directors to $56,000 per year.
Director Long-term Equity Incentives. In January 2013, each of our non-employee directors received an award of 1,492 fully vested shares of our common stock under the Stock Incentive Plan, which reflects our desire to increase the target value of those awards from approximately $75,000 to $80,000 per year.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The following table sets forth information regarding the beneficial ownership of our common stock and the beneficial ownership of the Partnership’s common units as of February 15, 2013 held by:
•
each person who beneficially owns 5% or more of our the then outstanding shares of common stock;
•
each of our named executive officers;
•
each of our directors; and
•
all of our executive officers and directors as a group.
Beneficial ownership is determined under the rules of the Securities and Exchange Commission. In general, these rules attribute beneficial ownership of securities to persons who possess sole or shared voting power and/or investment power with respect to those securities and include, among other things, securities that an individual has the right to acquire within 60 days. Unless otherwise indicated, the stockholders and unitholders identified in the table below have sole voting and investment power with respect to all securities shown as beneficially owned by them. Percentage ownership calculations for any security holder listed in the table below are based on 42,331,085 shares of our common stock and 101,788,617 common units of the Partnership outstanding on February 15, 2013.
* Less than 1%.
(1)
Unless otherwise indicated, the address for all beneficial owners in this table is 1000 Louisiana, Suite 4300, Houston, Texas 77002.
(2)
Warburg Pincus Private Equity VIII, L.P., a Delaware limited partnership, and two affiliated partnerships, Warburg Pincus Netherlands Private Equity VIII C.V.I., a company organized under the laws of the Netherlands, and WP-WP VIII Investors, L.P., a Delaware limited partnership (together “WP VIII”), and Warburg Pincus Private Equity IX, L.P., a Delaware limited partnership (“WP IX”), in the aggregate own, on a fully diluted basis, approximately 11% of our equity interests. 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 450 Lexington Avenue, New York, New York 10017. Messrs. Hwang and Kagan 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. Hwang, Kagan, Kaye and Landy disclaim beneficial ownership of all shares held by the Warburg Pincus entities.
(3)
The business address for Prudential Financial, Inc. is 751 Broad Street, Newark, New Jersey 07102-3777. Prudential Financial, Inc. through its indirect ownership of The Prudential Insurance Company of America ("PICOA") may be deemed to presently hold 17,100 shares of our common stock for the benefit of PICOA's general account. Prudential Financial, Inc. may be deemed the beneficial owner of securities beneficially owned by PICOA, Jennison Associates LLC, Prudential Investment Management, Inc. and Quantitative Management Associates LLC and may have direct or indirect voting and/or investment discretion over 4,422,765 shares which are held for its own benefit or for the benefit of its clients by its separate accounts, externally managed accounts, registered investment companies, subsidiaries and/or other affiliates. Of the 4,439,865 common shares reported as beneficially held by Prudential Financial, Inc., Prudential Financial, Inc. has reported that it has shared voting power with respect to 133,991 of these common shares and shared dispositive power with respect to 4,305,874 of the common shares.
(4)
Shares of common stock beneficially owned by Mr. Joyce include: (i) 234,959 shares issued to The Rene Joyce 2010 Grantor Retained Annuity Trust, of which Mr. Joyce and his wife are co-trustees and have shared voting and investment power; and (ii) 561,292 shares issued to The Kay Joyce 2010 Family Trust, of which Mr. Joyce’s wife is trustee and has sole voting and investment power.
(5)
Shares of common stock beneficially owned by Mr. Perkins include 407,370 shares issued to the Perkins Blue House Investments Limited Partnership.
(6)
Shares of common stock beneficially owned by Mr. Heim include: (i) 187,378 shares issued to The Michael Heim 2009 Family Trust, of which Mr. Heim and his son are co-trustees and have shared voting and investment power; (ii) 116,672 shares issued to The Patricia Heim 2009 Grantor Retained Annuity Trust, of which Mr. Heim and his wife are co-trustees and have shared voting and investment power; (iii) 63,973 shares issued to the Pat Heim 2012 Family Trust, of which Mr. Heim’s wife and son serve as co-trustees and have shared voting and investment power; (iv) 42,000 shares issued to the Heim 2012 Children’s Trust, of which Mr. Heim serves as trustee; and (v) 21,972 shares held by Mr. Heim’s wife of which Mr. Heim and his wife have shared voting and investment power.
(7)
Shares of common stock beneficially owned by Mr. Whalen include 459,249 shares issued to the Whalen Family Investments Limited Partnership.
(8)
All shares indicated as owned by Messrs. Hwang and Kagan other than 11,662 shares issued to Mr. Hwang and 21,474 shares issued to Mr. Kagan in their capacity as directors are included because of their affiliation with the Warburg Pincus entities.
(9)
The common units of the Partnership presented as being beneficially owned by our directors and officers do not include the common units held indirectly by us that may be attributable to such directors and officers based on their ownership of equity interests in us.
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forth certain information as of December 31, 2012 regarding our long-term incentive plans, under which our common stock is authorized for issuance to employees, consultants and directors of us, our general partner and its affiliates. Our sole equity compensation plan, under which we will make equity grants in the future, is our long-term incentive plan, which was approved by our stockholders prior to our initial public offering.
(1)
Generally, awards of restricted stock to our officers and employees under the 2010 Incentive Plan are subject to vesting over time as determined by the Compensation Committee and, prior to vesting, are subject to forfeiture. Stock incentive plan awards may vest in other circumstances, as approved by the Compensation Committee and reflected in an award agreement. Restricted stock is issued, subject to vesting, on the date of grant. The Compensation Committee may provide that dividends on restricted stock are subject to vesting and forfeiture provisions, in which cash such dividends would be held, without interest, until they vest or are forfeited.
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
Our Relationship with Targa Resources Partners LP and its General Partner
Our only cash generating assets consist of our interests in the Partnership, which as of February 15, 2013 consists of the following:
•
a 2.0% general partner interest in the Partnership, which we hold through our 100% ownership interests in the general partner;
•
all of the outstanding IDRs of the Partnership; and
•
12,945,659 of the 101,788,617 outstanding common units of the Partnership, representing a 12.7% limited partnership interest.
Omnibus Agreement
Our Omnibus Agreement with the Partnership addresses the reimbursement to us for costs we incur on the Partnership’s behalf, competition and 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 as the Partnership’s general partner without cause and units held by us and our affiliates have not voted in favor of that removal. The Omnibus Agreement will also terminate in the event of a Change of Control (as defined in the Omnibus Agreement) of the Partnership or its general partner. The Omnibus Agreement expires according to its terms on April 30, 2013, and the Omnibus Agreement will not be extended. At such time, reimbursement matters will be governed by our partnership agreement, which provides that our general partner will be reimbursed for all direct and indirect expenses, as well as expenses otherwise allocable to us in connection with the operation of our business, incurred on our behalf.
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 and direct expenses, including compensation and benefits of operating personnel, and for the provision of various general and administrative services for the Partnership’s benefit. 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 the Partnership’s behalf, such as compensation of operational personnel performing services for the Partnership’s benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits. The general partner determines the amount of general and administrative expenses to be allocated to the Partnership in accordance with the partnership agreement. Other than our direct costs of being a reporting company, so long as our only cash-generating asset consists of our interests in the Partnership, substantially all of our general and administrative costs have been, so long as our only cash-generating assets consist of our interest in the Partnership, and will continue to be allocated to the Partnership. The Omnibus Agreement expires according to its terms on April 30, 2013, and the term of the Omnibus Agreement will not be extended. At such time, reimbursement matters will be governed by the Partnership Agreement, which provides that we will be reimbursed for all direct and indirect expenses, as well as expenses otherwise allocable to the Partnership in connection with the operation of the Partnership’s business, incurred on the Partnership’s behalf.
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.
Registration Rights Agreement
Agreement with Series B Preferred Stock Investors
On October 31, 2005, we entered into an amended and restated registration rights agreement with the holders of our then outstanding Series B preferred stock that received or purchased 6,453,406 shares of preferred stock pursuant to a stock purchase agreement dated October 31, 2005. Pursuant to the registration rights agreement, we agreed to register the sale of shares of our common stock that holders of such preferred stock received upon conversion of the preferred stock, under certain circumstances. These holders include (directly or indirectly through subsidiaries or affiliates), among others, Warburg Pincus.
Demand Registration Rights
At any time, the qualified holders have the right to require us by written notice to register a specified number of shares of common stock in accordance with the Securities Act and the registration rights agreement. The qualified holders have the right to request up to an aggregate of five registrations; provided that such qualified holders are not limited in the number of demand registrations that constitute “shelf” registrations pursuant to Rule 415 under the Securities Act. In no event shall more than one demand registration occur during any six-month period or within 120 days after the effective date of a registration statement we file, provided that no demand registration may be prohibited for that 120-day period more than once in any 12-month period.
Piggy-back Registration Rights
If, at any time, we propose to file a registration statement under the Securities Act with respect to an offering of common stock (subject to certain exceptions), for our own account, then we must give at least 15 days’ notice prior to the anticipated filing date to all holders of registrable securities to allow them to include a specified number of their shares in that registration statement. We will be required to maintain the effectiveness of that registration statement until the earlier of 180 days after the effective date and the consummation of the distribution by the participating holders.
Conditions and Limitations; Expenses
These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective.
Contracts with Affiliates
Indemnification Agreements with Directors and Officers
In February 2007, the Partnership and the general partner entered into indemnification agreements with each independent director of the general partner. Each indemnification agreement provides that each of the Partnership and the general partner will indemnify and hold harmless each indemnitee against Expenses (as defined in the indemnification agreement) to the fullest extent permitted or authorized by law, including the Delaware Revised Uniform Limited Partnership Act and the Delaware Limited Liability Company Act in effect on the date of the agreement or as such laws may be amended to provide more advantageous rights to the indemnitee. If such indemnification is unavailable as a result of a court decision and if the Partnership or the general partner is jointly liable in the proceeding with the indemnitee, the Partnership and the general partner will contribute funds to the indemnitee for his Expenses (as defined in the in the Indemnification Agreement) in proportion to relative benefit and fault of the Partnership or the general partner on the one hand and indemnitee on the other in the transaction giving rise to the proceeding.
Each indemnification agreement also provides that the Partnership and the general partner will indemnify and hold harmless the indemnitee against Expenses incurred for actions taken as a director or officer of the Partnership or the general partner or for serving at the request of the Partnership or the general partner as a director or officer or another position at another corporation or enterprise, as the case may be, but only if no final and non-appealable judgment has been entered by a court determining that, in respect of the matter for which the indemnitee is seeking indemnification, the indemnitee acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal proceeding, the indemnitee acted with knowledge that the indemnitee’s conduct was unlawful. The indemnification agreement also provides that the Partnership and the general partner must advance payment of certain Expenses to the indemnitee, including fees of counsel, subject to receipt of an undertaking from the indemnitee to return such advance if it is it is ultimately determined that the Indemnitee is not entitled to indemnification.
We have entered into parent indemnification agreements with each of our directors and officers, including Messrs. Joyce, Perkins, Whalen, Kagan, Meloy and Hwang who serve or served as directors and/or officers of the general partner. Each parent indemnification agreement provides that we will indemnify and hold harmless each indemnitee for Expenses (as defined in the parent indemnification agreement) to the fullest extent permitted or authorized by law, including the Delaware General Corporation Law, in effect on the date of the agreement or as it may be amended to provide more advantageous rights to the indemnitee. If such indemnification is unavailable as a result of a court decision and if we and the indemnitee are jointly liable in the proceeding, we will contribute funds to the indemnitee for his Expenses in proportion to relative benefit and fault of us and indemnitee in the transaction giving rise to the proceeding.
Each parent indemnification agreement also provides that we will indemnify the indemnitee for monetary damages for actions taken as our director or officer or for serving at our request as a director or officer or another position at another corporation or enterprise, as the case may be but only if (i) the indemnitee acted in good faith and, in the case of conduct in his official capacity, in a manner he reasonably believed to be in our best interests and, in all other cases, not opposed to our best interests and (ii) in the case of a criminal proceeding, the indemnitee must have had no reasonable cause to believe that his conduct was unlawful. The parent indemnification agreement also provides that we must advance payment of certain Expenses to the indemnitee, including fees of counsel, subject to receipt of an undertaking from the indemnitee to return such advance if it is it is ultimately determined that the indemnitee is not entitled to indemnification.
Indemnification Agreements with the Partnership
Under the Omnibus Agreement, the Partnership agreed to indemnify us against environmental liabilities related to the North Texas System arising or occurring after February 14, 2007.
Additionally, we have agreed to indemnify the Partnership for losses relating to income tax liabilities attributable to pre-IPO operations that are not reserved on the books of the Predecessor Business of the North Texas System as of February 14, 2007. We do not have any obligation under this indemnification until the Partnership’s aggregate losses exceed $250,000. Our obligation under this indemnification will terminate upon the expiration of any applicable statute of limitations. The Partnership will indemnify us for all losses attributable to the post-IPO operations of the North Texas System.
Transactions with Related Persons
Relationship with Sajet Resources LLC
Former holders of our Class B Common units, including Warburg Pincus and certain of our executive managers and directors, own a controlling interest in Sajet Resources LLC (“Sajet”), which was spun-off in December 2010 prior to the IPO. We provide general and administrative services to Sajet and are reimbursed for these amounts at our actual cost. During 2012, we were reimbursed $1.3 million for such services provided. Additionally, on December 1, 2012, Targa Midstream Services LLC purchased six 90,000 gallon propane storage tanks from Sajet for $1.2 million. This transaction was at a market price consistent with similar transactions with other nonaffiliated entities.
Relationship with Tesla Resources LLC
In September 2012, Tesla Resources LLC (“Tesla”) was spun-off from Sajet. Tesla owns certain technology rights, real property and ownership interests in Floridian Natural Gas Storage Company LLC. We will provide general and administrative services to Tesla and will be reimbursed for these amounts at our actual cost. During 2012, there were no services rendered.
Relationship with Warburg Pincus LLC
Affiliates of Warburg Pincus beneficially own approximately 11.1% of our outstanding common stock. Accordingly, Warburg Pincus can exert significant influence over us and any action requiring the approval of the holders of our stock, including the election of directors and approval of significant corporate transactions. Warburg’s concentrated ownership makes it less likely that any other holder or group of holders of common stock will be able to affect the way we are managed or the direction of our business.
Peter Kagan, one of our directors, is a Managing Director of Warburg Pincus LLC and is also a director of Laredo Petroleum Holdings Inc. (“Laredo”) from whom the Partnership buys natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Laredo. Purchases from Laredo during 2012 totaled $88.1 million. These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.
Relationship with Total Safety US Inc.
Joe Bob Perkins, our Chief Executive Officer, is also a member of the Board of Managers of W3 Holdings, LLC, parent company of Total Safety US Inc. (“Total Safety”) which provides the Partnership safety services and equipment, including detection and monitoring systems. Affiliates of Warburg Pincus own a controlling interest in Total Safety. During 2012, we made payments of $242,980 to Total Safety. These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.
Relationships with Sequent Energy Management, LP, EOG Resources Inc. and IntercontinentalExchange, Inc.
Charles R. Crisp, one of our directors, is a director of AGL Resources, Inc., parent company of Sequent Energy Management, LP (“Sequent”) and Northern Illinois Gas Company d/b/a NICOR Energy (“NICOR”). The Partnership purchases and sells natural gas and NGL products from and to Sequent and sells natural gas products to NICOR. Mr. Crisp also serves as a director of EOG Resources Inc. (“EOG”) from whom the Partnership purchases natural gas and NGL products. Mr. Crisp is also a director of IntercontinentalExchange Inc., parent company of ICE US OTC Commodity Markets LLC (“ICE”) from whom the Partnership purchases brokerage services. The following table shows the Partnership’s transactions with each of these entities during 2012.
These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.
Relationships with Martin Gas Sales and Southwest Energy LP
Erschel C. Redd, one of our directors, has an immediate family member who is an officer of Martin Gas Sales, which is a subsidiary of Martin Midstream Partners LP (“Martin”) and an immediate family member who is an officer and part owner of Southwest Energy LP (“Southwest Energy”) from and to whom the Partnership purchases and sells natural gas and NGL products. The following table shows the Partnership’s transactions with each of these entities during 2012.
These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between the general partner and its affiliates (including us), on the one hand, and the Partnership and its other limited partners, on the other hand. The directors and officers of the general partner have fiduciary duties to manage the general partner and us, if applicable, in a manner beneficial to our owners. At the same time, the general partner has a fiduciary duty to manage the Partnership in a manner beneficial to it and its unitholders. Please see “-Review, Approval or Ratification of Transactions with Related Persons” below for additional detail of how these conflicts of interest will be resolved.
Review, Approval or Ratification of Transactions with Related Persons
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 reflected in the general operation of our board of directors, consistent with past practice. Prior to our IPO, an agreement among our stockholders prohibited 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 without the prior written consent of the holders of at least a majority of our outstanding shares. 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. If a conflict or potential conflict of interest arises between us and our affiliates (excluding the Partnership) on the one hand and the Partnership and its limited partners (other than us and our affiliates), on the other hand, the resolution of any such conflict or potential conflict is addressed as described under “-Conflicts of Interest.” Pursuant to our Code of Conduct, our officers and directors are required to abandon or forfeit any activity or interest that creates a conflict of interest between them and us or any of our subsidiaries, unless the conflict is pre-approved by our board of directors.
Whenever a conflict arises between the general partner or its affiliates, on the one hand, and the Partnership or any other partner, on the other hand, the general partner will resolve that conflict. The Partnership’s partnership agreement contains provisions that modify and limit the general partner’s fiduciary duties to the Partnership’s unitholders. The partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.
The general partner will not be in breach of its obligations under the partnership agreement or its duties to the Partnership or its unitholders if the resolution of the conflict is:
• approved by the general partner’s conflicts committee, although the general partner is not obligated to seek such approval;
• approved by the vote of a majority of the Partnership’s outstanding common units, excluding any common units owned by the general partner or any of its affiliates;
• on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties; or
• fair and reasonable to the Partnership, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to the Partnership.
The general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. If the general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith and in any proceeding brought by or on behalf of any limited partner of the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in the partnership agreement, the general partner or its conflicts committee may consider any factors they determines in good faith to consider when resolving a conflict. When the partnership agreement provides that someone act in good faith, it requires that person to believe he is acting in the best interests of the Partnership.
Director Independence
Messrs. Crisp, Hwang, Kagan, Redd and Tong are our independent directors under the NYSE’s listing standards. Please see “Item 10. Directors, Executive Officers and Corporate Governance.” Our board of directors examined the commercial relationships between us and companies for whom our independent directors serve as directors or with whom family members of our independent directors have an employment relationship. The commercial relationships reviewed consisted of product and services purchases and product sales at market prices consistent with similar arrangements with unrelated entities.
Item 14.
Item 14.
Principal Accounting Fees and Services.
We have engaged PricewaterhouseCoopers LLP as our principal accountant. The following table summarizes fees we were billed by PricewaterhouseCoopers LLP for independent auditing, tax and related services for each of the last two fiscal years:
(1)
Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the integrated audit of our annual financial statements and internal control over financial reporting, (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.
(2)
Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews of our financial statements and are not reported under audit fees.
(3)
Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice and tax planning.
(4)
All other fees represent amounts we were billed in each of the years presented for services not classifiable under the other categories listed in the table above. No such services were rendered by PricewaterhouseCoopers LLP during the last two years.
The Audit Committee has approved the use of PricewaterhouseCoopers LLP as our independent principal accountant. All services provided by our independent auditor are subject to pre-approval by the Audit Committee. The Audit Committee is informed of each engagement of the independent auditor to provide services to us.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a)(1) Financial Statements
Our Consolidated Financial Statements are included under Part II, Item 8 of the Annual Report. For a listing of these statements and accompanying footnotes, see “Index to Financial Statements” Page of this Annual Report.
(a)(2) Financial Statement Schedules
All other 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
Number
Description
* Filed herewith
** Furnished herewith
*** Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omitted exhibit or Schedule to the SEC upon request.
+ Management contract or compensatory plan or arrangement
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on February 19, 2013.
Signature
Title (Position with Targa Resources Corp.)
/s/ Joe Bob Perkins
Chief Executive Officer and Director
Joe Bob Perkins
(Principal Executive Officer)
/s/ Matthew J. Meloy
Senior Vice President, Chief Financial Officer and Treasurer
Mathew J. Meloy
(Principal Financial Officer)
/s/ John R. Sparger
Senior Vice President and Chief Accounting Officer
John R. Sparger
(Principal Accounting Officer)
/s/ Rene R. Joyce
Executive Chairman of the Board
Rene R. Joyce
/s/ James W. Whalen
Advisor to Chairman and CEO and Director
James W. Whalen
/s/ Charles R. Crisp
Director
Charles R. Crisp
/s/ In Seon Hwang
Director
In Seon Hwang
/s/ Peter R. Kagan
Director
Peter R. Kagan
/s/ Ershel C. Redd Jr.
Director
Ershel C. Redd Jr.
/s/ Chris Tong
Director
Chris Tong
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
TARGA RESOURCES CORP. AUDITED CONSOLIDATED FINANCIAL STATEMENTS
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
Management has used the framework set forth in the report entitled “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of the internal control over financial reporting. Based on that evaluation, management has concluded that the internal control over financial reporting was effective as of December 31, 2012.
The business of Saddle Butte Pipeline, LLC that the Partnership purchased on December 31, 2012 was excluded from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2012. This business constituted 20.1% of our total assets as of December 31, 2012.
The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page.
/s/ Joe Bob Perkins
Joe Bob Perkins
Chief Executive Officer
(Principal Executive Officer)
/s/ Matthew J. Meloy
Matthew J. Meloy
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Targa Resources Corp.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of changes in owners' equity and of cash flows present fairly, in all material respects, the financial position of Targa Resources Corp. and its subsidiaries (the "Company") at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As described in Management's Report on Internal Control Over Financial Reporting, management has excluded from its assessment of internal control over financial reporting as of December 31, 2012 the business of Saddle Butte Pipeline, LLC acquired in a purchase business combination as of December 31, 2012. We have also excluded the acquired business from our audit of internal control over financial reporting. The total assets of the acquired business represent 20.1% of the related consolidated financial statement amounts as of December 31, 2012.
/s/PricewaterhouseCoopers LLP
Houston, Texas
February 19, 2013
TARGA RESOURCES CORP.
CONSOLIDATED BALANCE SHEETS
See notes to consolidated financial statements.
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
See notes to consolidated financial statements.
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
See notes to consolidated financial statements.
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY
See notes to consolidated financial statements.
TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
See notes to consolidated financial statements.
TARGA RESOURCES CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.
Note 1 - Organization
Targa Resources Corp. (“TRC”) is a Delaware corporation formed in October 2005. Our common stock is listed on the New York Stock Exchange under the symbol “TRGP.” In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa” are intended to mean our consolidated business and operations, including our wholly-owned subsidiary TRI Resources Inc. (“TRI”).
Note 2 - Basis of Presentation
These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2012 and 2011, and the results of operations, comprehensive income, cash flows, and changes in owners’ equity for the years ended December 31, 2012, 2011 and 2010.
We have prepared our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany balances and transactions have been eliminated. Certain amounts in prior periods have been reclassified to conform to the current year presentation.
One of our indirect subsidiaries is the sole general partner of Targa Resources Partners LP (“the Partnership”). Because we control the general partner of the Partnership, under generally accepted accounting principles, we must reflect our ownership interests in the Partnership on a consolidated basis. Accordingly, the Partnership’s financial results are included in our consolidated financial statements even though the distribution or transfer of Partnership assets is limited by the terms of the partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by controlling affiliates of us are reflected in our results of operations as net income attributable to noncontrolling interests and in our balance sheet equity section as noncontrolling interests in subsidiaries. Throughout these footnotes, we make a distinction where relevant between financial results of the Partnership versus those of a standalone parent and its non-partnership subsidiaries.
As of December 31, 2012, our interests in the Partnership consist of the following:
·
a 2% general partner interest, which we hold through our 100% ownership interest in the general partner of the Partnership;
·
all Incentive Distribution Rights (“IDR”); and
·
12,945,659 common units of the Partnership, representing a 12.7% limited partnership interest.
The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling natural gas liquids (“NGL”) and NGL products; and storing and terminaling refined petroleum products and crude oil. See Note 23 for an analysis of our and the Partnership’s operations by segment.
Note 3 - Significant Accounting Policies
Consolidation Policy
Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests.
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.
Cash and Cash Equivalents
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
Comprehensive Income
Comprehensive income includes net income and other comprehensive income (“OCI”), which includes unrealized gains and losses on derivative instruments that are designated as hedges.
Allowance for Doubtful Accounts
Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, 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.
Inventories
The Partnership’s inventories consist primarily of NGL product inventories. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of the Partnership’s customers. NGL product inventories are valued at the lower of cost or market using the average cost method. Inventories also include materials and supplies required for the Partnership’s Badlands expansion activities in North Dakota, which are valued at lower cost or market using the specific identification method.
Product Exchanges
Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange 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 accrued liabilities.
Gas Processing Imbalances
Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or market; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.
Derivative Instruments
We employ derivative instruments to manage the volatility of cash flows due to fluctuating energy prices and interest rates. All derivative instruments not qualifying for the normal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend on whether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales which, under GAAP, are not accounted for as derivatives.
If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the unrealized gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ 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. As such, we include the cash flows from commodity derivative instruments in revenues and from interest rate derivative instruments in interest expense.
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. The ultimate gain or loss on the derivative transaction upon settlement is also recognized as a component of other income and expense.
We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This documentation includes the 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.
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. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the unrealized gain or loss to earnings in the current period.
We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI 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.
For balance sheet classification purposes, we analyze the fair values of the derivative contracts on a deal by deal basis.
Property, Plant and Equipment
Property, plant and equipment are stated at acquisition value less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.
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 or major asset component. We also capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs.
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.
We 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 recorded 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. Asset recoverability is measured 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. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations.
Asset Retirement Obligations (“AROs”)
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 the straight-line 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. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows shall be recognized as an increase or a decrease in the carrying amount of the liability for an asset retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. 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. See Note 7.
Debt Issue Costs
Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issue costs.
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. See Note 17.
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 establish a valuation allowance. 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. 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.
Noncontrolling Interests
Third-party ownership in the net assets of our consolidated subsidiaries is shown as noncontrolling interests within the equity section of the balance sheet. In the statements of operations, noncontrolling interests reflects the allocation of earnings to third-party investors, which for the Partnership gives effect to the incentive distribution rights declared for each period. We account for the difference between the carrying amount of our investment in the Partnership and the underlying book value arising from issuance of common units by the Partnership, where we maintain control, as an equity transaction. If the Partnership issues common units at a price different than our carrying value per unit, we account for the premium or deficiency as an adjustment to paid-in capital.
Revenue Recognition
Our operating revenues are primarily derived from the following activities:
•
sales of natural gas, NGLs, condensate, crude oil and petroleum products;
•
services related to compressing, gathering, treating, and processing of natural gas; and
•
services related to NGL fractionation, terminaling and storage, transportation and treating.
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 natural gas processing activities, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. 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 retain the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. A significant portion of our Straddle plant processing contracts are hybrid contracts under which settlements are made on a percent-of-liquids basis or a fee basis, depending on market conditions. 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.
We generally report sales revenues gross in our consolidated statements of operations as we typically 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. However, buy-sell transactions with the same counterparty are reported on a net basis.
Share-Based Compensation
We award share-based compensation to employees, directors and non-management directors in the form of restricted stock, stock options and performance unit awards. Compensation expense on restricted common units and performance unit awards that qualify as equity arrangements are measured by the fair value of the award as determined by the market at the date of grant. Compensation expense on performance unit awards that qualify as liability arrangements is initially measured by the fair value of the award at the date of grant, and re-measured 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 22.
Earnings per Share
We account for earnings per share (EPS) in accordance with ASC 260 - Earnings per Share. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock so long as it does not have an anti-dilutive effect on EPS. The dilutive effect is determined through the application of the treasury method. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit. Prior to the conversion of the Series B Preferred Stock on December 10, 2010, we used the two-class method of allocating earnings between our common and preferred class of stock outstanding for the purposes of presenting net income per share.
Use of Estimates
When preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. 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, product purchases 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, therefore, could differ materially from estimated amounts.
Recent Accounting Pronouncements
In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. The amendment, required to be applied for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods, requires an entity to disclose information about offsetting assets and liabilities and related netting arrangements. In January 2013, the FASB also issued Accounting Standards Update No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies that ASU 2011-11 applies to financial instruments or derivative transactions accounted for under ASC 815. The amendments require disclosures to present both gross and net amounts of derivative assets and liabilities that are subject to master netting arrangements with counterparties. We currently present our derivative assets and liabilities gross on our statement of financial position. We will provide additional disclosures regarding the gross and net amounts of derivative assets and liabilities beginning with reporting periods in 2013 in accordance with these amendments.
Accounting Standards Update No. 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, was implemented in 2012. Note 13 includes additional disclosures regarding the fair value and fair value hierarchy classification of financial instruments reported at carrying value in our Consolidated Balance Sheets. Additionally, we have provided information regarding the unobservable inputs used in the fair value measurement of derivative contracts classified within Level 3 of the fair value hierarchy. Transfers among levels of the fair value hierarchy are deemed to occur at the end of the reporting period.
Accounting Standards Update No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income was retroactively adopted during 2012. We now display in the Consolidated Statements of Comprehensive Income (Loss) the tax effect, if any, of each component of other comprehensive income.
In February 2013, the FASB issued Accounting Standards Update No. 2013-2, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. The amendment, required to be applied prospectively for reporting periods beginning after December 15, 2012, requires entities to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line item of net income. Early adoption is permitted. Our financial statement presentation complies with this standards update.
Note 4 -Business Acquisitions
2011 Acquisitions
In March 2011, the Partnership acquired a refined petroleum products and crude oil storage and terminaling facility in Channelview, Texas on Carpenter's Bayou along the Houston Ship Channel (the "Channelview Terminal") for $29.0 million. The Channelview Terminal, with storage capacity of 544,000 barrels, can handle multiple grades of blend stocks, petroleum products and crude oil and has potential for expansion, as well as integration with the Partnership’s other logistics operations.
In September 2011, the Partnership acquired two refined petroleum products and crude oil storage and terminaling facilities. The facility on the Hylebos Waterway in the Port of Tacoma, Washington has 758,000 barrels of capacity and handles refined petroleum products, crude oil, LPGs and biofuels, including ethanol and biodiesel. The facility on the Patapsco River in Baltimore, Maryland has approximately 505,000 barrels of storage capacity. Both terminals contain blending and heating capabilities, and have tanker truck and barge loading and unloading infrastructure. Total cash consideration including working capital for both facilities was $135 million.
2012 Acquisition
Badlands
On December 31, 2012, the Partnership completed the acquisition of Saddle Butte Pipeline, LLC’s ownership of its Williston Basin crude oil pipeline and terminal system and its natural gas gathering and processing operations (collectively “Badlands”), for cash consideration of $975.8 million, subject to customary purchase price adjustments and a contingent payment.
The acquired business is located in the Williston Basin of the Bakken Shale Play in the McKenzie, Dunn and Mountrail counties of North Dakota and includes approximately 155 miles of crude oil pipelines. The business has combined crude oil operational storage capacity of 70,000 barrels, including the Johnsons Corner Terminal with 20,000 barrels of storage capacity (expanding to 40,000 barrels) and the Alexander Terminal with storage capacity of 30,000 barrels, with a combined estimated throughput of 32,000 barrels per day. It also includes approximately 95 miles of natural gas gathering pipelines and a 20 MMcf/d natural gas processing plant with an expansion underway to increase capacity to 40 MMcf/d. The operations are backed by producer dedications under long-term contracts that include approximately 260,000 acres of crude oil production and over 100,000 acres of natural gas production. The Badlands acquisition expands the Partnership’s portfolio of midstream assets, extends its footprint to the Bakken Shale / Three Forks play and diversifies its business with the addition of crude oil gathering. The Badlands financial results will be included in the Partnership’s Field Gathering and Processing business segment.
Pursuant to the Membership Interest Purchase and Sale Agreement, the acquisition is subject to a contingent payment of $50 million (the “contingent consideration”) if aggregate crude oil gathering volumes exceed certain stipulated monthly thresholds during the period from January 2013 through June 2014. If the threshold is not attained during the contingency period, no payment is owed. Accounting standards require that the contingent consideration be recorded at fair value at the date of acquisition and revalued at subsequent reporting dates under the acquisition method of accounting. At December 31, 2012, the Partnership recorded a $15.3 million accrued liability representing the fair value of this contingent consideration, determined by a probability based model measuring the likelihood of meeting certain volumetric measures identified in the Membership Interest Purchase and Sale Agreement. Future changes in the fair value of this accrued liability must be included in earnings.
The following table summarizes the consideration paid for the Badlands acquisition and the preliminary determination of the assets and liabilities acquired at the December 31, 2012 acquisition date.
Intangible assets consist of customer contracts and relationships acquired in the Badlands acquisition. Using relevant information and assumptions, the fair value of acquired identifiable intangible assets at the date of acquisition, was determined. Fair value is generally calculated as the present value of estimated future cash flows. Key assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate. During 2013, the Partnership will determine the amortization methods and estimate useful lives for the Badlands intangible assets.
Pro Forma Results
As the Badlands acquisition was completed on December 31, 2012, there were no results of operations attributable to this acquisition for 2012. The Partnership incurred $6.1 million of acquisition-related costs associated with the Badlands acquisition (included in Other expense in the consolidated statement of operations). The following unaudited pro forma consolidated results of operations for the years ended 2012 and 2011 are presented as if the Badlands acquisition had been completed on January 1, 2011.
The pro forma consolidated results of operations include adjustments to include the reported results of acquired company for 2012 and 2011, as adjusted to:
·
exclude the financial results of assets retained by the seller;
·
report revenues from the purchase and sale of crude oil inventory with the same counterparty on a net basis to conform to our accounting policy;
·
include the incremental depreciation and amortization expenses associated with the fair value adjustments to property, plant and equipment and definite-lived intangibles as a result of applying the acquisition method of accounting (assumed straight-line method over useful lives of 30 years for plant, property and equipment and 30 years for intangible assets);
·
include the financing costs associated with the Partnership’s debt offering and borrowings under the Partnership’s Senior Secured Credit Facility used to fund a portion of the acquisition;
·
adjust the attribution of net income to noncontrolling interests to give effect to the pro forma adjustments on the Partnership’s net income;
·
include the income tax effect for us; and
·
excludes $6.1 million of acquisition costs incurred in 2012 that were directly related to the transaction.
The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.
Note 5 - Inventory
The components of inventory consisted of the following:
Note 6 - Property, Plant and Equipment
(1)
The useful lives of the Badlands assets acquired on December 31, 2012 will be determined in 2013 in conjunction with our finalization of the preliminary fair value acquisition accounting.
Capitalized interest was $13.6 million, $3.4 million and $1.3 million in 2012, 2011 and 2010.
Note 7 - Asset Retirement Obligations
Our asset retirement obligations primarily relate to certain of the Partnership’s gas gathering pipelines and processing facilities and are included in our consolidated balance sheets as a component of other long-term liabilities. The changes in our aggregate asset retirement obligations are as follows:
Note 8 - Investment in Unconsolidated Affiliate
At December 31, 2012, 2011 and 2010, the Partnership’s unconsolidated investment consisted of a 38.8% ownership interest in Gulf Coast Fractionators LP (“GCF”).
The following table shows the activity related to our investment in an unconsolidated affiliate for the years indicated:
(1)
Pursuant to the Purchase and Sale Agreement for the conveyance of the Downstream Business to the Partnership, we were entitled to receive GCF distributions of $2.3 million in 2010.
Note 9 - Accounts Payable and Accrued Liabilities
The components of accounts payable and accrued liabilities consisted of the following:
Note 10 - Debt Obligations
(1)
As of December 31, 2012, $68.0 million of TRC’s $150.0 million credit facility was available.
(2)
While we consolidate the debt of the Partnership in our financial statements, 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, 2012, availability under the Partnership’s $1.2 billion senior secured revolving credit facility was $534.7 million.
The following table shows contractually scheduled maturities of our and the Partnership’s debt obligations outstanding at December 31, 2012 for the next five years, and in total thereafter:
The following table shows the range of interest rates and weighted average interest rate incurred on our and the Partnership’s variable-rate debt obligations during the year ended December 31, 2012:
Compliance with Debt Covenants
As of December 31, 2012, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.
TRC Credit Agreement
In January 2010 TRI entered into a Senior Secured Credit Agreement providing senior secured financing of $600 million, consisting of a $500 million Senior Secured Term Loan due October 2012 (the “term loan”) and a $100 million Senior Secured Revolving Credit Facility due July 2014 (the “credit facility”). Concurrent with the execution of the credit agreement, TRI borrowed $500 million on the term loan facility net of a $5 million discount. There was no initial funding on the revolving credit line. The proceeds from the term loan were used to:
·
complete the cash tender offer and consent solicitation for all $250 million of TRI’s outstanding 8½ senior notes due 2013;
·
repay the outstanding balance of $62.2 million on TRI’s existing term loan;
·
purchase $164.2 million in face value of the Holdco Notes for $131.4 million; and
·
fund working capital and pay fees and expenses under the credit agreement.
In 2010, TRI incurred a loss on debt repurchases of $17.4 million comprising $10.9 million of premiums paid and $6.5 million from the write-off of the debt issue costs related to the repurchase of TRI’s 8½ senior notes, discussed above. The premiums paid were included as a cash outflow from a financing activity in the Statement of Cash Flows.
In 2010, our term loan facility was paid in full and the available capacity of the credit facility was reduced to $75.0 million. The entire amount of our credit facility was available for letters of credit and includes a limited capacity for borrowings on same-day notice referred to as swing line loans. We wrote-off $21.5 million deferred debt issue costs associated with the term loan facility when the term loan was paid in full.
In October 2012, we entered into a Credit Agreement that replaced our existing variable rate Senior Secured Revolving Credit Facility due July 2014 with a new variable rate Senior Secured Credit Facility due October 3, 2017 (the “TRC Revolver”). The TRC Revolver increases available commitments to $150.0 million from $75.0 million, allows us to request up to an additional $100.0 million in commitment increases and includes a $30.0 million swing line sub-facility. Outstanding letters of credit and related outstanding reimbursement obligations may not exceed $50.0 million in the aggregate.
We incurred a charge of $0.2 million related to a partial write-off of debt issue costs associated with the previous credit facility as a result of a change in syndicate members under the new TRC Revolver. The remaining deferred debt issue costs along with the issue costs associated with the October 2012 amendment are amortized on a straight-line basis over the life of the TRC Revolver.
The TRC Revolver bears interest, at our option, at either (a) a base rate equal to the highest of the prime rate of Deutsche Bank Trust Company Americas, the administrative agent, the federal funds rate plus 0.5% and the one-month LIBOR rate plus 1.0%, plus an applicable margin ranging from 1.75% to 2.5% (dependent upon the Company’s consolidated leverage ratio), or (b) LIBOR plus an applicable margin ranging from 2.75% to 3.5% (dependent upon the Company’s consolidated leverage ratio).
We are required to pay a commitment fee ranging from 0.375% to 0.5% (dependent upon the Company’s consolidated leverage ratio) on the daily average unused portion of the TRC Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable rate from 2.75% to 3.5% (dependent upon the Company’s consolidated leverage ratio).
The TRC Revolver is secured by substantially all of the Company’s assets. The TRC Revolver requires us to maintain a consolidated leverage ratio (the ratio of consolidated funded indebtedness to consolidated adjusted EBITDA) of no more than 4.00 to 1.00. The TRC Revolver restricts our ability to make dividends to shareholders if, on a pro forma basis after giving effect to such dividend, (a) any default or event of default has occurred and is continuing or (b) our consolidated leverage ratio exceeds 4.00 to 1.00. In addition, the TRC Revolver includes various covenants that may limit, among other things, our ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates.
TRC Holdco Loan Facility
In August 2007, we borrowed $450 million under the TRC Holdco loan facility (“Holdco debt”).
The following subsidiary repurchases of Holdco debt have been recognized in the accompanying consolidated financial statements as extinguishments of debt:
·
In 2010, TRI and another wholly-owned subsidiary paid $269.3 million to extinguish $306.1 million of outstanding borrowings (including accrued interest of $23.1 million), resulting in a pretax gain of $36.8 million. In addition, we wrote-off $2.0 million of associated unamortized deferred debt issue costs.
·
In 2012, using proceeds from our TRC Revolver, we paid $88.8 million to extinguish the remaining $89.3 million outstanding borrowings of Holdco debt, resulting in a pretax gain of $0.5 million. In addition, we wrote-off $0.3 million of associated unamortized deferred debt issue costs.
The Partnership’s Revolving Credit Agreement
In July 2010, the Partnership entered into an Amended and Restated Credit Agreement that replaced the Partnership’s existing variable rate Senior Secured Credit Facility due February 2012 with a new variable rate Revolver due July 2015. The Amended and Restated Credit Agreement increased available commitments to $1.1 billion from $958.5 million and allowed the Partnership to request increases in commitments up to an additional $300 million.
The Partnership incurred a charge of $0.8 million related to a partial write-off of debt issue costs associated with this Amended and Restated Credit Agreement related to a change in syndicate members. The remaining balance in debt issue costs of $4.7 million was amortized over the life of the Amended and Restated Credit Agreement.
In October 2012, the Partnership entered into a Second Amended and Restated Credit Agreement that amends and replaces the Partnership’s existing variable rate Senior Secured Credit Facility due July 2015 (the “Previous Revolver”) to provide a variable rate Senior Secured Credit Facility due October 3, 2017 (the “TRP Revolver”). The TRP Revolver increases available commitments to $1.2 billion from $1.1 billion and allows the Partnership to request up to an additional $300.0 million in commitment increases.
The Partnership incurred a $1.7 million loss related to a partial write-off of debt issue costs associated with the Previous Revolver as a result of a change in syndicate members under the new TRP Revolver. The remaining deferred debt issue costs along with the issue costs associated with the October 2012 amendment are amortized on a straight-line basis over the life of the TRP Revolver.
The TRP Revolver bears interest, at the Partnership’s option, either at the base rate or the Eurodollar rate. The base rate is equal to the highest of: (i) Bank of America’s prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate plus 1.0%, plus an applicable margin ranging from 0.75% to 1.75%. The Eurodollar rate is equal to LIBOR plus an applicable margin ranging from 1.75% to 2.75%.
The Partnership is required to pay a commitment fee equal to an applicable rate ranging from 0.3% to 0.5% times the actual daily average unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable rate from 1.75% to 2.75%.
The TRP Revolver is collateralized by a majority of the Partnership’s assets. Borrowings are guaranteed by the Partnership’s restricted subsidiaries.
The TRP Revolver restricts the Partnership’s ability to make distributions of available cash to unitholders if a default or an event of default (as defined in the TRP Revolver) exists or would result from such distribution. The TRP Revolver requires the Partnership to maintain a ratio of consolidated funded indebtedness to consolidated adjusted EBITDA of no more than 5.50 to 1.00. The TRP Revolver also requires the Partnership to maintain a ratio of consolidated EBITDA to consolidated interest expense of no less than 2.25 to 1.00. In addition, the TRP Revolver contains various covenants that may limit, among other things, the Partnership’s ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates (in each case, subject to the Partnership’s right to incur indebtedness or grant liens in connection with, and convey accounts receivable as part of, a permitted receivables financing).
The Partnership’s Senior Unsecured Notes
In February 2011, the Partnership exchanged $158.6 million principal amount of its 6⅞% Notes plus payments of $28.6 million, including $0.9 million of accrued interest, for $158.6 million aggregate principal amount of its 11¼% Notes. The holders of the exchanged Notes are subject to the provisions of the 6⅞% Notes described below. The debt covenants related to the remaining $72.7 million of face value of the 11¼% Notes were removed. This exchange was accounted for as a debt modification whereby the financial effects of the exchange will be recognized over the term of the new debt issue.
In January 2012, the Partnership privately placed $400.0 million in aggregate principal amount of its 6⅜% Notes, resulting in approximately $395.5 million of net proceeds.
In October 2012, $400.0 million in aggregate principal of 5¼% Notes were issued by the Partnership at 99.5% of the face amount, resulting in gross proceeds of $398.0 million. An additional $200.0 million in aggregate principal of 5¼% Notes were issued in December 2012 at 101.0% of the face amount, resulting in gross proceeds of $202.0 million. Both issuances are treated as a single class of debt securities and have identical terms.
In November 2012, the Partnership redeemed all of the outstanding 8¼% Notes at a redemption price of 104.125% plus accrued interest through the redemption date. The redemption resulted in a premium paid on the redemption of $8.6 million, which is included as a cash outflow from financing activity in the Statement of Cash Flows, and a write off of $2.5 million of unamortized debt issue costs.
The terms of the senior unsecured notes outstanding as of December 31, 2012 were as follows:
All issues of unsecured senior notes are obligations that rank pari passu in right of payment with existing and future senior indebtedness, including indebtedness under the Partnership’s credit facility. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by the Partnership. These notes are effectively subordinated to all secured indebtedness under the Partnership’s credit agreement, which is secured by substantially all of the Partnership’s assets and the Partnership’s Securitization Facility, which is secured by accounts receivable pledged under the facility, to the extent of the value of the collateral securing that indebtedness. Interest on all issues of senior unsecured notes is payable semi-annually in arrears.
The Partnership’s senior unsecured notes and associated indenture agreements (other than the indenture for the 11¼ Notes) restrict the Partnership’s ability to make distributions to unitholders in the event of default (as defined in the indentures). The indentures also restrict the Partnership’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase, equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and the Partnership and its subsidiaries will cease to be subject to such covenants.
The Partnership may redeem up to 35% of the aggregate principal amount at the redemption dates and prices set forth below (expressed as percentages of principal amounts) plus accrued and unpaid interest and liquidation damages, if any, with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 90 days (180 days for the 6⅜% Notes and 5¼% Notes) of the date of the closing of such equity offering.
Prior to July 15, 2013, the Partnership may redeem some or all of the 11¼% Notes at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date.
The Partnership may also redeem all or part of each of the series of notes on or after the redemption dates set forth below at the price for each respective year (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidation damages, if any, on the notes redeemed.
Subsequent Event - Accounts Receivable Securitization Facility
In January 2013, the Partnership entered into an accounts receivable securitization facility (the “Securitization Facility”), that provides up to $200 million of borrowing capacity at favorable commercial paper rates through January 2014. Under this Securitization Facility, one of the Partnership’s consolidated subsidiaries (Targa Liquids Marketing and Trade LLC or “TLMT”) sells or contributes receivables to another of the Partnership’s consolidated subsidiaries (Targa Receivables LLC or “TRLLC”), a special purpose consolidated subsidiary created for the sole purpose of this Securitization Facility. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables, without recourse, to a third-party financial institution. Receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of us or TLMT. Any excess receivables are eligible to satisfy the claims of creditors of us or TLMT. Total funding under this Securitization Facility in January 2013 was $171.4 million.
Debt Re-acquisitions Summary
The debt re-acquisitions described above were reported as follows in our Consolidated Statements of Operations:
Note 11 - Partnership Units and Related Matters
Dropdown Transactions
In April 2010, we completed the sale of our interests to the Partnership in the Sand Hills and Straddle Systems for $420.0 million, effective April 1, 2010. This sale triggered a mandatory prepayment on TRI’s Senior Secured Credit Agreement of $152.5 million, which was paid on April 27, 2010. As part of the closing of the sale of our Sand Hills and Straddle Systems, we amended our Omnibus Agreement with the Partnership, to continue to provide general and administrative and other services to the Partnership through April 2013.
In August 2010, we completed the sale to the Partnership of our 63% equity interest in the Versado System, effective August 1, 2010, for $247.2 million in the form of $244.7 million in cash and $2.5 million in partnership interests represented by 89,813 common units and 1,833 general partner units. The sale triggered a mandatory prepayment of $91.3 million under TRI’s Senior Secured Credit Facility. In accordance with the terms of the Versado Purchase and Sale Agreement, we reimbursed the Partnership for maintenance capital expenditures required pursuant to our New Mexico Environmental Department settlement agreement. Expenditures were substantially completed by December 31, 2011, and our total share was $27.8 million.
In September 2010, we completed the sale to the Partnership of our Venice Operations, which includes Targa’s 76.8% interest in Venice Energy Services Company, L.L.C. (“VESCO”), for aggregate consideration of $175.6 million, effective September 1, 2010. The sale triggered a mandatory prepayment of $73.5 million under TRI’s Senior Secured Credit Facility.
The net impact of our sale of assets to the Partnership resulted in an increase to additional paid-in capital of $258.9 million and a corresponding reduction of the noncontrolling interest in these assets.
Public Offerings of Common Units
In January 2010, the Partnership completed a public offering of 6,325,000 common units (including underwriters’ overallotment option) at a price of $23.14 per common unit, providing net proceeds of $140.2 million. We contributed $3.0 million to maintain our 2% general partner interest. The Partnership used the net proceeds from the offering for general partnership purposes, which included reducing borrowings under its Revolver.
In April 2010, Targa LP Inc., a wholly-owned subsidiary of ours, closed on a secondary public offering of 8,500,000 common units of the Partnership at $27.50 per common unit. Proceeds from this offering, after underwriting discounts and commission were $224.4 million before expenses associated with the offering. This offering also triggered a mandatory prepayment on our Senior Secured Credit Agreement of $3.2 million related to TRI’s Senior Secured Revolving Credit Facility and $105.6 million on TRI’s Senior Secured Term Loan Facility.
In 2010, the Partnership filed with the SEC a universal shelf registration statement (the “2010 Shelf”), which provides the Partnership with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and the Partnership’s capital needs. The 2010 Shelf expires in April 2013. The following transactions were completed under the 2010 Shelf:
·
August 2010 - 7,475,000 common units (including underwriters’ overallotment option) at a price of $24.80 per common unit, providing net proceeds of $177.8 million. We contributed $3.8 million to maintain our 2% general partner interest. The Partnership used the net proceeds from this offering to reduce borrowings under its Revolver.
·
January 2011 - 9,200,000 common units (including underwriters’ overallotment option) at a price of $33.67 per common unit, providing net proceeds of $298.0 million. We contributed $6.3 million to maintain our 2% general partner interest. The Partnership used the net proceeds from the offering for general partnership purposes, which included reducing borrowings under its Revolver.
·
January 2012 - 4,405,000 common units (including underwriters’ overallotment option) at a price of $38.30 per common unit, providing net proceeds of $164.8 million. As part of this offering, we purchased 1,300,000 common units with an aggregate value of $49.8 million. We contributed $3.5 million to maintain our 2% general partner interest. The Partnership used the net proceeds from this offering for general partnership purposes, including the repayment of indebtedness.
·
November 2012 - 10,925,000 common units (including underwriters’ overallotment option) at a price of $36.00 per common unit, providing net proceeds of $378.2 million. We contributed $8.0 million to maintain our 2% general partner interest. The Partnership used the net proceeds from this offering to fund a portion of the $975 million purchase price of the Badlands acquisition.
In 2012, the Partnership filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows the Partnership to issue up to an aggregate of $300 million of debt or equity securities (the “2012 Shelf”). In August 2012, the Partnership entered into an Equity Distribution Agreement (“EDA”) with Citibank pursuant to which the Partnership may sell, at its option, up to an aggregate of $100 million of its common units through Citibank, as sales agent, under the 2012 Shelf. Settlement for sales of common units will occur on the third business day following the date on which any sales were made in return for payment of the net proceeds to the Partnership. During 2012, there were no sales of common units pursuant to this program. The 2012 Shelf expires in August 2015.
Subsequent Event
In 2013, the Partnership issued 1,679,848 common units and received proceeds of $64.1 million, net of 2% commission fees, pursuant to the EDA. In addition, we contributed $1.3 million to maintain our 2% general partner interest.
Distributions
The following table details the distributions declared and/or paid during the years ended December 31, 2012, 2011 and 2010:
Note 12 - Common Stock and Related Matters
Public Offerings
On December 10, 2010, certain of our stockholders sold, in an initial public offering (“IPO”) 18,831,250 common shares at a price of $22.00 per share. We did not receive any proceeds from the sale of shares by the selling stockholders.
On April 26, 2011, certain of our stockholders sold, in a secondary public offering, 6,497,500 common shares at a price of $31.73 per share. We did not receive any proceeds from the sale of shares by the selling stockholders.
Dividends
The following table details the dividends declared and/or paid since our IPO through December 31, 2012:
(1)
Represents accrued dividends on the restricted shares that are payable upon vesting.
(2)
Represents a prorated dividend for the portion of the fourth quarter of 2010 that the Company was public.
Note 13 - Earnings Per Common Share
Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using weighted average shares outstanding during the period, incorporated with the dilutive effect of restricted stock awards and stock options. The dilutive effect was determined through the application of the treasury method.
Prior to the conversion of the Series B Preferred Stock to common stock on December 10, 2010, net income after the impact of preferred dividends was allocated according to the preferred stock agreement. The terms of the preferred stock agreement stipulated that common shareholders are not entitled to any dividends, unless approved with written consent of a majority of the outstanding preferred stockholders, until the preferred holders recapture the carrying value of their preferred securities which includes accreted dividends. For 2010, there was no allocation to preferred shareholders as the Company was in a loss position and the preferred shareholders do not participate in losses under the terms of the preferred stock agreement.
For each of the periods presented below, all of the potentially dilutive securities were excluded from the calculation of diluted EPS as they were anti-dilutive.
(1)
In connection with the IPO in December 2010, the Company issued 1,350,000 shares of restricted stock under the 2010 Stock Incentive Plan to employees. At December 31, 2010, all of these shares were unvested. Starting from 2011, these shares are included in the computation of diluted EPS. In 2012, 60% of the shares were vested and these vested shares were included in basic EPS calculation.
(2)
Amounts represent the weighted average number of unvested shares outstanding until 2011. Upon vesting, these shares were included in basic EPS calculation.
(3)
Amounts represent the weighted average number of unexercised stock options outstanding. Prior to the closing of the IPO in December 2010, all outstanding options were either exercised or cashed out. As of December 31, 2010, there are no outstanding stock options.
(4)
During 2010, in connection with the closing of the IPO, 6,409,697 shares of Series B Convertible Participating Preferred Stock, plus accreted value, were converted into 35,356,698 shares of common stock. Beginning on December 10, 2010, these shares are included in the calculation of weighted average shares outstanding - basic and diluted. The amount included in the table above for 2010 represents the weighted average shares for the period from January 1, 2010 through December 9, 2010 (based on the actual number of shares converted on December 10, 2010).
In 2012 and 2011, we included all the potentially dilutive securities in the calculation of diluted EPS.
The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per common share:
Note 14 - Derivative Instruments and Hedging Activities
Partnership Commodity Hedges
The primary purpose of the Partnership’s commodity risk management activities is to hedge the exposure to commodity price risk and reduce fluctuations in the Partnership’s operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of cash flows, the Partnership has hedged the commodity price associated with a portion of its expected (i) natural gas equity volumes in Field Gathering and Processing Operations through 2015 and (ii) NGL and condensate equity volumes predominately in Field Gathering and Processing Operations as well as in the LOU portion of the Coastal Gathering and Processing Operations through 2014 that result from its percent of proceeds processing arrangements by entering into derivative instruments including swaps and purchased puts (floors) and calls (caps). The Partnership has designated these derivative contracts as cash flow hedges.
The hedges generally match the NGL product composition and the NGL and natural gas delivery points to those of the Partnership’s physical equity volumes. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon the Partnership’s expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The Partnership’s natural gas and NGL hedges are settled using published index prices for delivery at various locations which closely approximate the Partnership’s actual natural gas and NGL delivery points.
The Partnership hedges a portion of its condensate sales using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This necessarily exposes the Partnership to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of its underlying West Texas condensate equity volumes.
At December 31, 2012, the notional volumes of the Partnership’s commodity hedges for equity volumes were:
The Partnership also enters into derivative instruments to help manage other short-term commodity-related business risks. The Partnership has not designated these derivatives as hedges and records changes in fair value and cash settlements to revenues.
The following schedules reflect the fair values of the Partnership’s derivative instruments:
The fair value of the Partnership’s 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.
The estimated fair value of the Partnership’s derivative instruments was a net asset of $22.2 million as of December 31, 2012, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities by year as indicated by market quotes for the counterparties’ credit default swap rates. These default probabilities have been applied to the unadjusted fair values of the derivative instruments to arrive at the credit risk adjustment, which was immaterial for all periods presented.
The Partnership’s payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in natural gas, NGL and crude oil prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing its senior secured indebtedness that ranks equal in right of payment with liens granted in favor of its senior secured lenders.
The following tables reflect amounts recorded in other comprehensive income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated:
Hedge ineffectiveness was immaterial for all periods presented.
Our consolidated earnings are also affected by the Partnership’s use of the mark-to-market method of accounting for derivative 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 settles. 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. The Partnership recorded the following mark-to-market gains (losses) for the periods indicated:
The following table shows the deferred gains (losses) included in accumulated OCI that will be reclassified into earnings through the end of 2015:
As of December 31, 2012, deferred net gains of $22.8 million on commodity hedges and deferred net losses of $6.1 million on terminated interest rate swaps recorded in OCI are expected to be reclassified to revenue and interest expense during the next twelve months.
See Note 15 for additional disclosures related to derivative instruments and hedging activities.
Note 15 - Fair Value Measurements
Under generally accepted accounting principles, our consolidated balance sheet reflects a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments are reported at fair value in our consolidated balance sheet. Other financial instruments are reported at historical cost or amortized cost in our consolidated balance sheet, with fair value measurements for these instruments provided as supplemental information.
Following is additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.
Fair Value of Derivative Financial Instruments
The Partnership’s derivative instruments consist of financially settled commodity swap and option contracts and fixed price commodity contracts with certain counterparties. The Partnership determines the fair value of its derivative contracts using a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. The Partnership has consistently applied these valuation techniques in all periods presented and believe the Partnership has obtained the most accurate information available for the types of derivative contracts the Partnership holds.
The fair values of the Partnership’s derivative instruments, which aggregate to a net asset position of $22.2 million as of December 31, 2012, are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. This asset position reflects the present value, adjusted for counterparty credit risk, of the amount the Partnership expects to receive in the future on its derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $1.8 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $46.2 million, ignoring an adjustment for counterparty credit risk.
Fair Value of Other Financial Instruments
Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. As such, long-term debt is primarily the other financial instrument for which our carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:
•
Holdco facility is based on repurchases we made in December 2010;
•
senior secured revolving credit facilities are based on carrying value which approximates fair value as its interest rate is based on prevailing market rates;
•
senior unsecured notes are based on quoted market prices derived from trades of the debt.
Fair Value Hierarchy
We categorize the inputs to the fair value measurements using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:
•
Level 1 - observable inputs such as quoted prices in active markets;
•
Level 2 - inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and
•
Level 3 - unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.
The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our consolidated balance sheet at fair value and (2) supplemental fair value disclosures for other financial instruments:
Additional Information Regarding Level 3 Fair Value Measurements
As of December 31, 2012, we reported certain of the Partnership’s natural gas basis swaps at fair value using Level 3 inputs due to such derivatives not having observable market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.
The fair value of these natural gas basis swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve which is based on observable or public data sources and extrapolated when observable prices are not available.
As of December 31, 2012, the Partnership has two natural gas basis swaps categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are the forward natural gas basis curve beginning in year 2015, and the forward natural gas basis curve for the South Texas Natural Gas Pipeline beginning in January 2013. Because a significant portion of the derivative’s term is in 2015 and beyond, for the former, and in calendar year 2013, for the latter, both valuations are categorized as Level 3. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial.
As of December 31, 2012, the Partnership has a $15.3 million liability which represents the fair value of contingent consideration included in the preliminary valuation of the Badlands acquisition (see Note 4). The preliminary fair value was determined by a probability based model measuring the likelihood of meeting certain volumetric measures identified in the Membership Interest Purchase and Sale Agreement. Consequently, as these probability based inputs are not observable, the entire valuation of the contingent consideration is categorized in Level 3.
The following table sets forth a reconciliation of the changes in the fair value of our and the Partnership’s financial instruments classified as Level 3 in the fair value hierarchy:
During 2011, we transferred $7.9 million in Partnership derivative assets out of Level 3 and into Level 2. This transfer related to long term OTC swaps executed in 2010 for NGL products with calendar year 2013 deliveries for which pricing was extrapolated (Level 3) for some periods. As of December 31, 2011, all products had actively traded contracts through December 2013 with open interest and settlement prices. Accordingly, we were no longer required to extrapolate to value the Partnership’s derivative contracts and reclassified these instruments as Level 2.
There were no transfers of assets or liabilities among the three levels of the fair value hierarchy during 2010 or 2012.
The amount of gains for the period included in earnings is attributable to the change in unrealized gains related to assets or liabilities held at the reporting date.
Note 16 - Related Party Transactions
Transactions with Unconsolidated Affiliate
For the years 2012, 2011 and 2010, transactions with GCF included in revenues were $0.1 million, $0.8 million and $0.3 million. For the same periods, transactions with GCF included in costs and expenses were $1.9 million, $0.4 million and $1.1 million. These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.
Relationship with SAJET Resources LLC
Former holders of our Class A Common units, including Warburg Pincus and certain of our executive managers and directors, own a controlling interest in SAJET Resources LLC (“SAJET”), which was spun-off in December 2010 prior to the IPO. We provide general and administrative services to SAJET and are reimbursed for these amounts. During 2012, we were reimbursed $1.3 million for such services provided. Additionally, on December 1, 2012, Targa Midstream Services LLC purchased six 90,000 gallon propane storage tanks from SAJET for $1.2 million. This transaction was at a market price consistent with similar transactions with other nonaffiliated entities.
Relationship with Warburg Pincus LLC
Affiliates of Warburg Pincus beneficially own approximately 11.1% of our outstanding common stock. Accordingly, Warburg Pincus can exert significant influence over us and any action requiring the approval of the holders of our stock, including the election of directors and approval of significant corporate transactions. Warburg’s concentrated ownership makes it less likely that any other holder or group of holders of common stock will be able to affect the way we are managed or the direction of our business.
Peter Kagan and In Sean Hwang, two of our directors, are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad Oak”), from whom the Partnership buys natural gas and NGL products. Mr. Kagan is also a director of Laredo Petroleum Holdings Inc. (“Laredo”) from whom the Partnership buys natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak and Laredo.
The following table shows the transactions with each of these related parties.
These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.
Note 17 - Commitments and Contingencies
Future non-cancelable commitments related to certain contractual obligations are presented below in aggregate and for each of the next five fiscal years. The below amounts represent those that were fixed and determinable as of December 31, 2012.
(1)
Includes minimum payments on lease obligation for corporate office space.
(2)
Includes minimum payments on lease obligations for office space, railcars and tractors, and service contracts.
(3)
Consists of pipeline capacity payments for firm transportation contracts and throughput and deficiency agreements.
(4)
Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by the Partnership. These agreements expire at various dates through 2099.
Total actual expenses related to the above non-cancelable commitments were:
Environmental
For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Environmental reserves do not reflect management’s assessment of any insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success.
The Partnership’s environmental liabilities were not significant as of December 31, 2012.
We have reimbursed the Partnership for maintenance capital expenditures totaling $16.8 million as of December 31, 2012, which are required to be made in connection with a settlement agreement with the New Mexico Environment Department relating to air emissions at three gas processing plants operated by the Versado Gas Processors, LLC joint venture, with $1.1 million reimbursed during the year ended December 31, 2012. These capital projects are substantially complete.
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 that 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.
Note 18 - Significant Risks and Uncertainties
Our primary business objective is to increase our available cash for dividends to our stockholders by assisting the Partnership in executing its business strategy. We may facilitate the Partnership’s growth through various forms of financial support, including, but not limited to, modifying the Partnership’s IDRs, exercising the Partnership’s IDR reset provision contained in its partnership agreement, making loans, making capital contributions in exchange for yielding or non-yielding equity interests or providing other financial support to the Partnership, if needed, to support its ability to make distributions. In addition, we may acquire assets that could be candidates for acquisition by the Partnership, potentially after operational or commercial improvement or further development.
Nature of the Partnership’s Operations in Midstream Energy Industry
The Partnership operates in the midstream energy industry. Its business activities include gathering, processing, fractionating and storage of natural gas, NGLs and crude oil. The Partnership’s results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products and changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate 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.
The Partnership’s 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 condensate production or condensate 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 the Partnership’s results of operations, cash flows and financial position.
The principal market risks are exposure to changes in commodity prices, as well as changes in interest rates.
Commodity Price Risk
A majority of the revenues from the gathering and processing business are derived from percent-of-proceeds contracts under which the Partnership receives a portion of the natural gas and/or NGLs or equity volumes as payment for services. The prices of natural gas and NGLs are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond the Partnership’s control.
In an effort to reduce the variability of our cash flows, the Partnership has hedged the commodity price associated with a significant portion of its expected natural gas equity volumes through 2015 and its NGL and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). The Partnership hedges a higher percentage of its expected equity volumes in the current year as compared to future years where the volume forecasting risk is greater. With swaps, the Partnership typically receives an agreed upon fixed price for a specified notional quantity of natural gas or NGL and pays the hedge counterparty a floating price for that same quantity based upon published index prices. Since the Partnership receives from its 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 actual equity volumes, the Partnership typically limits its use of swaps to hedge the prices of less than its expected natural gas and NGL equity volumes. The Partnership utilizes purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. The Partnership’s commodity hedges may expose it to the risk of financial loss in certain circumstances.
The fair value of commodity 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. See Note 14.
Interest Rate Risk
We and the Partnership are exposed to changes in interest rates, primarily as a result of variable rate borrowings under our and the Partnership’s credit facilities.
Counterparty Risk - Credit and Concentration
Derivative Counterparty Risk
Where the Partnership is exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties.
The Partnership has master netting provisions in the International Swap Dealers Association agreements with all of its derivative counterparties. These netting provisions allow the Partnership to net settle asset and liability positions with the same counterparties, and would reduce its maximum loss due to counterparty credit risk by $8.9 million as of December 31, 2012. The range of losses attributable to the Partnership’s individual counterparties would be between $0.8 and $5.6 million, depending on the counterparty in default.
The credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value, representing expected future receipts, at the reporting date. At such times, these outstanding instruments expose the Partnership to losses in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of the counterparties decline, the ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, the Partnership may sustain a loss and its cash receipts could be negatively impacted.
As of December 31, 2012, affiliates of Wells Fargo Bank N.A. (“Wells Fargo”), Barclays PLC (“Barclays”), Securities Americas LLC (“Natixis”), Credit Suisse Group AG (“Credit Suisse”) and Bank of America Merrill Lynch (“BAML”) accounted for 31%, 16%, 15%, 11% and 10% of the Partnership’s counterparty credit exposure related to commodity derivative instruments. Wells Fargo, Barclays, Natixis, Credit Suisse and BAML are major financial institutions that possess investment grade credit ratings based upon minimum credit ratings assigned by Moody’s Investors Service, Inc. and Standard & Poor’s Corporation.
Customer Credit Risk
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. The following table summarizes the activity affecting our allowance for bad debts:
Significant Commercial Relationships
The following customer accounted for more than 10% of our consolidated revenues for the periods indicated:
All transactions in the above table were associated with the Marketing and Distribution segment.
Casualty or Other Risks
We maintain coverage in various insurance programs, which provides us and the Partnership with property damage, business interruption and other coverages which are customary for the nature and scope of our operations.
Management believes that we have 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 or the Partnership 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 us or the Partnership, or which causes us or the Partnership to make significant expenditures not covered by insurance, could reduce our or the Partnership’s ability to meet our financial obligations.
Note 19 - Other Operating Income
(1)
Reflects a $15.4 million loss due to a write-off of the Partnership’s investment in the Yscloskey joint interest processing plant in Southeastern Louisiana. Following hurricane Isaac, the joint venture owners elected not to restart the plant.
Note 20-Income Taxes
Our provisions for income taxes for the periods indicated are as follows:
Our deferred income tax assets and liabilities at December 31, 2012 and 2011 consist of differences related to the timing of recognition of certain types of costs as follows:
(1)
Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of the assets and liabilities of our equity method investments.
As a result of dropdown transactions in 2010 and 2009, differences related to the date of income recognition for book and tax occurred. While these are timing differences, the reversal of these differences will not be recognized until we sell the units of the Partnership. Therefore, the tax effect of these differences is recorded as a valuation allowance of $3.5 million in deferred taxes, as a component of other long term assets for 2010.
As of December 31, 2010, for federal income tax purposes, both regular tax net operating losses (“NOLs”) and alternative minimum tax NOLs were fully utilized.
Set forth below is the reconciliation between our income tax provision (benefit) computed at the United States statutory rate on income before income taxes and the income tax provision in the accompanying consolidated statements of operations for the periods indicated:
(1)
For 2010, primarily consists of the write-off of an $11.9 million Texas margin tax credit.
We have not identified any uncertain tax positions. 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.
In April 2010, we closed on a secondary public offering of 8,500,000 common units of the Partnership. The direct tax effect of the change in ownership interest in the Partnership as a result of the secondary public offering was recorded as a reduction in shareholders’ equity of $79.1 million, an increase in current tax liability of $41.9 million and an increase in deferred tax liability of $37.2 million. A 2010 return to provision adjustment resulted in an increase in current tax liability of $0.8 million and a decrease in deferred tax liability of $0.8 million. There was no tax impact on consolidated net income as a result of the secondary public offering.
In April 2010, we sold our interests in the Sand Hills and Straddle Systems to the Partnership. On September 28, 2010, we sold our interests in the Venice Operations to the Partnership. Under applicable accounting principles, the tax consequences of transactions with common control entities are not to be reflected in pre-tax income. Consequently, there was no tax impact on consolidated pre-tax net income as a result of the sale of the Sand Hills and Straddle Systems and the Venice Operations. The tax effect of these sales was recorded as an increase in other long term assets of $64.7 million, to be amortized over the remaining life of the underlying assets, an increase in current tax liability of $94.9 million, a decrease in deferred tax liability of $27.5 million and an increase in current tax expense of $2.7 million. A 2010 return to provision adjustment resulted in an increase in current tax liability of $0.7 million and a decrease in deferred tax liability of $0.7 million.
Note 21 - Supplemental Cash Flow Information
Supplemental cash flow information was as follows for the periods indicated:
Note 22 - Stock and Other Compensation Plans
2005 TRC Incentive Compensation Plan
Under Our 2005 Incentive Compensation Plan (“2005 Plan”), we provided restricted stock and stock options to our employees, directors and consultants.
Concurrent with our IPO in December 2010, unexercised in-the-money stock options were cashed out, resulting in $1.2 million of additional compensation expense in 2010. Unexercised out-of-the-money stock options were rescinded. As such, we had no outstanding 2005 Plan stock options at December 31, 2010. Further, all vested restricted common shares awarded under the 2005 Plan were converted to unrestricted common stock concurrent with the IPO.
2010 TRC Stock Incentive Plan
In December 2010, we adopted the Targa Resources Corp. 2010 Stock Incentive Plan (“TRC Plan”) for employees, consultants and non-employee directors of the Company. The TRC Plan allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do not qualify as incentive options (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights (“SARs”) granted in conjunction with Options or Phantom Stock Awards, (iv) restricted stock awards (“Restricted Stock Awards”), (v) phantom stock awards (“Phantom Stock Awards”), (vi) bonus stock awards, (vii) performance unit awards, or (viii) any combination of such awards (collectively referred to a “Awards”).
Restricted Stock - Total shares authorized under this plan are 5,000,000. The following table summarizes the restricted stock awards in shares and in dollars for the years indicated:
(1)
These awards were issued in conjunction with the Targa IPO and vest over a three year period at 60% in 2012 and the remaining 40% in 2013.
(2)
These awards will cliff vest at the end of three years.
(3)
Awards vested in 2012 were 60% of the awards issued in conjunction with our IPO, net of forfeitures. The remaining 40% of awards will be vested in 2013. We repurchased 197,731 from employees at $47.88 per share to satisfy the employees’ minimum statutory tax withholdings on the vested awards. The repurchased shares are recorded in treasury stock at cost.
The compensation expense of the restricted stocks was calculated based on the fair value of the stock at the grant date.
Bonus Stock
On December 6, 2010, we granted 556,514 bonus stock awards to our executive management team which vested upon the closing of our IPO on December 10, 2010.
Director grants
On February 17, 2011, the compensation committee (the “Committee”) awarded 24,250 shares of our stock to our outside directors. The awards vested at the grant date.
Subsequent Events
On January 15, 2013, the Committee made restricted stock awards of 29,123 to executive management under the TRC Plan for the 2013 compensation cycle that will cliff vest in three years from the grant date. On the same day, the Committee also awarded 7,460 shares of our stock to our outside directors (1,492 shares of common stock to each non-management director). The awards vested at the grant date.
Long-Term Incentive Plans
Performance Units
In 2007 both we and the Partnership adopted Long-Term Incentive Plans (“LTIP”) for employees, consultants, directors and non-employee directors of us and our affiliates who perform services for us or our affiliates. The performance units granted under these plans are linked to the performance of the Partnership’s common units. These plans provide for, among other things, the grant of both cash-settled and equity-settled performance units. Performance unit awards may also include distribution equivalent rights (“DERs”). The LTIPs are administered by the compensation committee of the Targa Board of Directors. Total units authorized under the LTIPs are 1,680,000.
Each performance unit will entitle the grantee to the value of a Partnership common unit on the vesting date multiplied by the vesting percentage determined from the Partnership’s ranking in a defined peer group. Currently, the performance period of the awards is three years. The grantee will receive the vested unit value in cash or common units depending on the terms of the grant. The grantee may also be entitled to the value of any DERs based on the notional distributions accumulated during the vesting period times the vesting percentage. DERs are cash settled for both paid in cash and equity-settled performance units.
Compensation cost for equity-settled performance units is recognized as an expense over the performance period based on fair value at the grant date. Fair value is calculated using a simulated unit price that incorporates peer ranking. DERs associated with equity-settled performance units are accrued over the performance period as a reduction of owners’ equity.
Compensation expense for cash-settled performance units and any related DERs will ultimately be equal to the cash paid to the grantee upon vesting. However, throughout the performance period we must record an accrued expense based on an estimate of that future pay-out. We have used a Monte Carlo simulation model to estimate accruals throughout the vesting period. In 2012, we changed the volatility assumption in the Monte Carlo simulation model from implied volatility to historical volatility. We consider historical volatility to be more appropriate than the implied volatility because it provides a more reliable indication of future volatility.
TRC LTIP -- Cash-settled Performance Units
The following table summarizes the cash-settled performance units for the year ended 2012 awarded under the Targa LTIP.
The remaining weighted average recognition period for the unrecognized compensation cost is approximately 1.7 years.
Partnership LTIP - Equity-Settled Performance Units
The Partnership started issuing equity-settled performance units in 2011. The following table summarized activities of our equity-settled performance units for the years ended December 31, 2012 and 2011.
Subsequent Event. On January 15, 2013, the Committee made awards to the executive management for the 2013 compensation cycle of 124,778 equity-settled performance units under the Partnership LITP that will vest in June 2016.
Partnership Director Grants
In 2012 and 2011, the common units granted to the Partnership’s non-management directors were vested immediately at the grant date. The awards granted before 2011 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. The Partnership estimates that the remaining fair value of an immaterial amount will be recognized in expense during the next year.
The following table summarizes activity of the common unit-based awards granted to the Partnership and our Directors for the years ended December 31, 2012, 2011 and 2010 (in units and dollars):
Subsequent Event
On January 15, 2013, the Committee made awards of 10,650 of our common units (2,130 units to each of our non-management directors). On February 7, 2013, 2,130 common units were awarded to a new non-management director. The awards vested immediately at the grant date.
The following table summarizes the compensation expenses under the various compensation plans recognized for the years indicated.
(1)
The compensation expenses are recognized by us and allocated to the Partnership under the provisions of the Omnibus Agreement.
The table below summarizes the unrecognized compensation expenses and the approximate remaining weighed average vesting periods related to our various compensation plans as of December 31, 2012.
The total fair values of share-based awards on the dates they vested are as follows.
(1)
We recognized $1.3 million tax benefit associated with the vesting of 60% of the restricted stock related to our IPO.
401(k) Plan
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 $8.7 million, $7.8 million, and $7.2 million during 2012, 2011, and 2010.
Note 23 - Segment Information
The Partnership reports its operations in two divisions: (i) Gathering and Processing, consisting of two reportable segments - (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing consisting of two reportable segments - (a) Logistics Assets and (b) Marketing and Distribution. The financial results of the Partnership’s hedging activities are reported in Other.
The Partnership’s Gathering and Processing division 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 NGLs and removing impurities. The Field Gathering and Processing segment’s assets are located in North Texas and the Permian Basin of West Texas and New Mexico. With the Badlands acquisition on December 31, 2012, this segment’s assets now includes the Badlands crude oil and natural gas gathering, terminaling and processing assets in North Dakota. Because the acquisition closed on December 31, 2012, Badlands had no operational impact for 2012. The Coastal Gathering and Processing segment’s assets are located in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
The Partnership’s Logistics and Marketing division is also referred to as the Downstream Business. The Downstream Business includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, refined petroleum products and crude oil. It also includes certain natural gas supply and marketing activities in support of the Partnership’s other operations, as well as transporting natural gas and NGLs.
The Partnership’s Logistics Assets segment is involved in transporting, storing and fractionating mixed NGLs; storing, terminaling and transporting finished NGLs; and storing and terminaling refined petroleum products and crude oil. These assets are generally connected to, and supplied in part by, the Partnership’s Gathering and Processing segments and are predominantly located in Mont Belvieu, Texas and Southwestern Louisiana. This segment includes the activities associated with the Partnership’s 2011 acquisitions of refined petroleum products and crude oil storage and terminaling facilities.
The Partnership’s Marketing and Distribution segment covers activities required to distribute and market raw and finished NGLs and all natural gas marketing activities. It includes (1) marketing the Partnership’s own NGL production and purchasing NGL products in selected United States markets; (2) providing LPG balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users; and (4) marketing natural gas available to the Partnership from its Gathering and Processing division and the purchase and resale and other value added activities related to third-party natural gas in selected United States markets.
Other contains the results of the Partnership’s commodity hedging activities included in operating margin. Eliminations of inter-segment transactions are reflected in the corporate and eliminations column.
Segment information is shown in the following tables. We have segregated the following segment information between Partnership and non-Partnership activities. Partnership activities have been presented on a common control accounting basis which reflects the dropdown transactions between us and the Partnership as if they occurred in prior periods similar to a pooling of interests. The non-Partnership results include activities related to certain assets and liabilities contractually excluded from the dropdown transactions and certain historical hedge activities that could not be reflected under GAAP in the Partnership common control results.
(1)
The Partnership recorded a $15.4 million loss in Other Operating (Income) Expense due to a write-off of its investment in the Yscloskey joint venture interest processing plant in Southern Louisiana included in the Coastal Gathering and Processing segment. Following Hurricane Isaac, the joint venture owners elected not to restart the plant.
The following table shows our consolidated revenues by product and service for the periods presented:
The following table shows a reconciliation of operating margin to net income for the periods presented:
Note 24-Selected Quarterly Financial Data (Unaudited)
Our results of operations by quarter for the years ended December 31, 2012 and 2011 were as follows:
Note 25- Condensed Parent Only Financial Statements
The condensed financial statements represent the financial information required by Rule 5-04 of the Securities and Exchange Commission Regulation S-X for Targa Resources Corp.
In the condensed financial statements, Targa’s investments in consolidated subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the consolidated subsidiaries are recorded in the balance sheets. Intercompany debt holdings related to the Holdco debt extinguishment transactions (See Note 10) have been eliminated. The income (loss) from operations of the consolidated subsidiaries is reported as equity in income (loss) of consolidated subsidiaries.
A substantial amount of Targa’s operating, investing and financing activities are conducted by its affiliates. The condensed financial statements should be read in conjunction with Targa’s consolidated financial statements, which begin on page of this Annual Report.
TARGA RESOURCES CORP.
PARENT ONLY
CONDENSED BALANCE SHEET
TARGA RESOURCES CORP.
PARENT ONLY
CONDENSED STATEMENT OF OPERATIONS
TARGA RESOURCES CORP.
PARENT ONLY
CONDENSED STATEMENT OF CASH FLOWS