UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____ to _____
Commission File Number: 001-34991
TARGA RESOURCES CORP.
(Exact name of registrant as specified in its charter)
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Delaware
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20-3701075
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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1000 Louisiana St, Suite 4300, Houston, Texas
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77002
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(Address of principal executive offices)
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(Zip Code)
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(713) 584-1000
(Registrant’s telephone number, including area code)
Securities registered pursuant to section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered
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Common Stock
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New York Stock Exchange
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Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £ No R
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No R
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No £
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. R
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer R
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Accelerated filer £
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Non-accelerated filer £
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Smaller reporting company £
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(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No R.
The aggregate market value of the common stock held by non-affiliates of the registrant was approximately $754.8 million on June 30, 2011, based on $33.46 per share, the closing price of the common stock as reported on the New York Stock Exchange (NYSE) on such date.
As of February 17, 2012, there were 42,441,543 shares of the registrant’s common stock, $0.001 par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Targa Resources Corp.’s (together with its subsidiaries, other than Targa Resources Partners LP, collectively “we,” “us,” “Targa,” “TRC,” or the “Company”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” of this Annual Report on Form 10-K (“Annual Report”) as well as the following risks and uncertainties:
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Targa Resources Partners LP’s (the “Partnership”) and our ability to access the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations;
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the amount of collateral required to be posted from time to time in the Partnership’s transactions;
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the Partnership’s success in risk management activities, including the use of derivative financial instruments to hedge commodity risks;
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the level of creditworthiness of counterparties to transactions;
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changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;
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the timing and extent of changes in natural gas, natural gas liquids (“NGL”) and other commodity prices, interest rates and demand for the Partnership’s services;
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weather and other natural phenomena;
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industry changes, including the impact of consolidations and changes in competition;
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the Partnership’s ability to obtain necessary licenses, permits and other approvals;
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the level and success of oil and natural gas drilling around the Partnership’s assets and its success in connecting natural gas supplies to its gathering and processing systems and NGL supplies to its logistics and marketing facilities;
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the Partnership’s and our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets;
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general economic, market and business conditions; and
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the risks described elsewhere in this Annual Report and our reports and registration statements filed from time to time with the Securities and Exchange Commission (“SEC”).
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Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Annual Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Item 1A. Risk Factors” in this Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
As generally used in the energy industry and in this Annual Report, the identified terms have the following meanings:
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Bbl
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Barrels (equal to 42 gallons)
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Btu
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British thermal units, a measure of heating value
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BBtu
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Billion British thermal units
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/d
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Per day
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/hr
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Per hour
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gal
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U.S. gallons
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| GPM | Gallons of recoverable hydrocarbons contained per million cubic feet of natural gas |
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LPG
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Liquefied petroleum gas
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MBbl
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Thousand barrels
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MMBbl
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Million barrels
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Mcf
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Thousand cubic feet
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MMBtu
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Million British thermal units
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MMcf
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Million cubic feet
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NGL(s)
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Natural gas liquid(s)
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NYMEX
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New York Mercantile Exchange
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Price Index
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Definitions
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IF-NGPL MC
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Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
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IF-PB
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Inside FERC Gas Market Report, Permian Basin
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IF-WAHA
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Inside FERC Gas Market Report, West Texas WAHA
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NY-WTI
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NYMEX, West Texas Intermediate Crude Oil
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OPIS-MB
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Oil Price Information Service, Mont Belvieu, Texas
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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, refined petroleum products and crude oil.
On December 10, 2010, we completed an initial public offering, or 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 stock holders. 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 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:
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noncontrolling interests 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.
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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 17, 2012, 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 89,170,989 outstanding common units of the Partnership, representing a 14.5% limited partnership interest.
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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.
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We are party to an Omnibus Agreement with the Partnership that governs the relationship regarding certain reimbursement and indemnification matters. So long as our only cash generating asset are 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 1,096 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 engaged in the business of gathering, compressing, treating, processing and selling natural gas and storing, fractionating, treating, transporting, terminaling and selling NGLs, NGL products, refined petroleum products and crude oil. The Partnership operates in two primary divisions: (i) Natural Gas 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 our 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 along with three offshore gathering systems 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 the “Permian Business;”
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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.
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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 has a record of successful third-party acquisitions. During 2011, the Partnership closed the following three acquisitions:
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On March 15, 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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On September 30, 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 consideration for both facilities was $127.5 million plus an additional $7.5 million for estimated working capital.
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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. The Partnership expects that acquisitions of third-party businesses and assets will continue to be a significant component of its growth strategy.
Organic Growth Projects.
In addition to acquiring businesses and assets from Targa 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 $530 million since 2007 and include the following major projects active in 2011:
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Cedar Bayou Fractionator expansion project: The Partnership completed construction of 78 MBbl/d of additional fractionation capacity at its 88%-owned Cedar Bayou Fractionator (“CBF”) in Mont Belvieu, Texas at a cost of approximately $64 million. The expansion went online in the second quarter of 2011, and is supported by 10-year fee-based contracts with ONEOK Hydrocarbons, LP, Questar Gas Management Company and Majestic Energy Services, LLC that have certain guaranteed volume commitments or provisions for deficiency payments.
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North Texas expansion program. During 2011, the Partnership invested approximately $40 million to expand gathering and processing capability in its North Texas assets, particularly in the oily part of the Barnett Shale. This project provided both expanded capacity in the gathering system via new pipelines and a new compressor station as well expanded residue take away from the Chico Plant. In addition, expanded CO2 treating was added due to the higher CO2 content in the gas from the oily part of the Barnett Shale.
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SAOU expansion project. During 2011 the Partnership invested approximately $30 million to expand gathering and processing capability in our west Texas assets, particularly in the Wolfberry play. This expansion program also included expenditures to restart the 25 MMcf/d Conger processing plant, which went online during the second quarter of 2011.
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The Partnership has the following major organic growth projects underway, which the Partnership estimates will require over $1 billion in growth capital expenditures through 2013:
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Cedar Bayou fractionation expansion. A 100,000 Bbl/d expansion of fractionation capacity is underway at CBF. Substantially all of this additional capacity is currently contracted with long-term “frac-or-pay” firm capacity fractionating agreements. The expansion will be fully integrated with the Partnership’s existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which includes an extensive network of connections to key petrochemical and industrial customers as well as the Partnership’s LPG export terminal at Galena Park, Texas on the Houston Ship Channel. The Partnership estimates that the total capital expenditures for the CBF expansion and related infrastructure enhancements at Mont Belvieu will be approximately $360 million and construction will be completed in the second quarter of 2013.
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International propane export project. In September 2011, the Partnership announced a $250 million expansion of its Mont Belvieu complex and its existing import/export marine terminal at Galena Park to provide export capability for 5,000 + Bbl/hr of fully refrigerated, low ethane propane. The expansion project, expected to be operational in the third quarter of 2013, will allow the Partnership to load three to four VLGC (very large gas carrier) class ships per month and is in addition to existing capabilities to handle multiple MGC (medium gas carrier) export cargos of HD-5 grade propane, imports/exports of LPGs and petrochemicals and other spot ship and barge business.
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North Texas Longhorn project. The Partnership has ordered a new 200 MMcf/d cryogenic processing plant for its North Texas System to meet increasing production, continued producer activity and expected volumes from significant new acreage dedications in the liquids-rich, oily areas of the Barnett Shale. The new processing plant, which will be located in Wise County, Texas, is expected to be operational in mid-2013, subject to regulatory approvals, and is expected to require a capital investment related to the plant and associated projects of approximately $150 million.
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Petroleum logistics terminal expansions. The Partnership currently estimates that it will invest approximately $60 million to expand the capacity and capability of the three refined petroleum products and crude oil terminals that it acquired in 2011.
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Benzene treating project. A new treater is under construction which will operate in conjunction with the Partnership’s existing LSNG facility at Mont Belvieu and is designed to reduce benzene content of natural gasoline to meet new, more stringent environmental standards. The treater has an estimated gross cost of approximately $40 million and an anticipated date of completion in the first quarter of 2012.
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SAOU/Permian expansion programs. During 2012, $45 million is projected to be spent at SAOU/Permian for additional compression and gathering and processing infrastructure, separate from the 2011 expansion project described above, to support the high level of drilling activity.
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North Texas expansion program. During 2012 $20 million is projected to be spent to expand the North Texas System gathering and processing capability. This spending is in addition to the North Texas Longhorn project.
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HD-5 Refrigeration Export project. The Partnership plans to invest approximately $13 million to enhance refrigeration capability used to export semi-refrigerated HD5 propane at our Galena Park facility. The project has an anticipated date of completion in the second quarter of 2012.
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Gulf Coast Fractionators expansion project. Gulf Coast Fractionators (“GCF”), a partnership with ConocoPhillips and Devon Energy Corporation in which the Partnership owns a 38.8% interest, is expanding the capacity of its NGL fractionation facility in Mont Belvieu by 43 MBbl/d for an estimated gross cost of $90 million (the Partnership’s net cost is estimated to be $35 million). ConocoPhillips, as the operator, will manage the expansion project. The expansion is expected to be operational during the second quarter of 2012.
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The Partnership’s assets are not easily duplicated and are located in active producing areas and near key NGL markets and logistics centers.
Growth Drivers
We believe our near-term growth will be driven by the Partnership's significant organic growth investments as well as strong supply and demand fundamentals for the Partnership's existing businesses. 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 strength of oil, condensate and NGL prices and of forecast prices for these energy commodities has 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 the Wolfberry Trend and Canyon Sands plays, which are accessible by SAOU, 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.
Producer activity in areas rich in oil, condensate and NGLs is 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. Until additional fractionation capacity comes on-line in 2013, there will be limited incremental supply of fractionation services in the area. These strong supply and demand fundamentals have resulted in long-term, “frac-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.
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 shale 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 / other geologic cross-section combinations) and the Bone Springs / Avalon 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.
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 Canyon Sands, Bone Springs, Wolfberry, and Barnett Shale plays 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 available to the Partnership’s gathering and processing systems.
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 mixed NGL 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 producers, including natural gas gathering, compression, treating, processing and selling natural gas and storing, fractionating, treating, transporting and selling NGLs, NGL products and refined petroleum products. These services are essential to gather, 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 natural gas sector on a scale similar to the Partnership’s 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 approximately $58.9 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 capital expenditures will be sufficient 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 (largely based on replacement cost economics), 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.
Financial flexibility.
The Partnership has historically maintained strong financial metrics relative to its peer group, with financial results consistently above the peer group median. The Partnership also reduces 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 appropriate leverage liquidity and distribution coverage levels and mitigating commodity price volatility allows the Partnership to be flexible in its growth strategy and enables 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 over 200 years 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 it to generate attractive cash flows. Geographic, business and customer diversity enhances the Partnership’s cash flow profile. The Partnership’s Natural Gas Gathering and Processing division has a favorable contract mix that is primarily percent-of-proceeds (the Field Gathering and Processing Segment) or hybrid or percent-of-liquids (the Coastal Gathering and Processing Segment) which, along with the Partnership’s long-term commodity hedging program and the nature of our contracts and assets, serves to mitigate the impact of commodity price movements on cash flow. In the Coastal Gathering and Processing Segment, we have increased volumes of higher GPM 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 and NGL equity volumes through 2013 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 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 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 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 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. Risk Factors.”
Targa has used the Partnership as a growth vehicle to pursue the acquisition and expansion of midstream natural gas, NGL and other complementary energy businesses and assets; however, Targa is not prohibited from competing with the Partnership and may evaluate acquisitions and dispositions that do not involve the Partnership. In addition, through the Partnership’s relationship with Targa, it has access to a significant pool of management talent, strong commercial relationships throughout the energy industry and access to Targa’s broad operational, commercial, technical, risk management and administrative infrastructure.
The Partnership’s Challenges
The Partnership faces a number of challenges in implementing its business strategy. For example:
|
·
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The Partnership has a substantial amount of indebtedness which may adversely affect its financial position.
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·
|
The Partnership’s cash flow is affected by supply and demand for oil, natural gas and NGL products and by natural gas, NGL, and condensate prices, and decreases in these prices could adversely affect its results of operations and financial condition.
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|
·
|
The Partnership’s long-term success depends on its ability to obtain new sources of supplies of natural gas and NGLs, which depends on certain factors beyond its control. Any decrease in supplies of natural gas or NGLs could adversely affect the Partnership’s business and operating results.
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|
·
|
If the Partnership does not make acquisitions or investments in new assets on economically acceptable terms or efficiently and effectively integrate new assets, its results of operations and financial condition could be adversely affected.
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·
|
The Partnership is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect its results of operations and financial condition.
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·
|
The Partnership’s growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair the Partnership’s ability to grow.
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·
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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.
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·
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The Partnership’s industry is highly competitive, and increased competitive pressure could adversely affect its business and operating results.
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For a further discussion of these and other challenges the Partnership faces, please read “Item 1A. Risk Factors.”
The Partnership’s Business Operations
The Partnership’s operations are reported in two divisions: (i) Natural Gas Gathering and Processing, consisting of two segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing, consisting of two segments—(a) Logistics Assets and (b) Marketing and Distribution.
Natural Gas Gathering and Processing Division
The Partnership’s Natural Gas Gathering and Processing Division consists of gathering, compressing, dehydrating, treating, conditioning, processing, transporting and marketing natural gas. The gathering of natural gas consists of aggregating natural gas produced from various wells through small diameter gathering lines to processing plants. Natural gas has a widely varying composition depending on the field, the formation and the reservoir from which it is produced. The processing of natural gas consists of the extraction of imbedded NGLs and the removal of water vapor and other contaminants to form (i) a stream of marketable natural gas, commonly referred to as residue gas, and (ii) a stream of mixed NGLs, commonly referred to as “Mixed NGLs” or “Y-grade.” Once processed, the residue gas is transported to markets through pipelines that are either owned by the gatherers or processors or third parties. End users of residue gas include large commercial and industrial customers, as well as natural gas and electric utilities serving individual consumers. The Partnership sells its residue gas either directly to such end users or to marketers into intrastate or interstate pipelines, which are typically located in close proximity or with ready access to the Partnership’s facilities.
The Partnership continually seeks new supplies of natural gas, both to offset the natural decline in production from connected wells and to increase throughput volumes. The Partnership obtains additional natural gas supply in its operating areas by contracting for production from new wells or by capturing existing production currently gathered by others. Competition for new natural gas supplies is based primarily on location of assets, commercial terms, service levels and access to markets. The commercial terms of natural gas gathering and processing arrangements are driven, in part, by capital costs, which are impacted by the proximity of systems to the supply source and by operating costs, which are impacted by operational efficiencies, facility design and economies of scale.
We believe that the Partnership’s extensive asset base and scope of operations in the regions in which it operates provides it with significant opportunities to add both new and existing natural gas production to its systems. We believe that the Partnership’s size and scope gives it a strong competitive position by placing it in close proximity to a large number of existing and new natural gas producing wells in its areas of operations, allowing the Partnership to generate economies of scale and to provide its customers with access to its existing facilities and to multiple end-use markets and market hubs. Additionally, we believe that the Partnership’s ability to serve its customers’ needs across the natural gas and NGL value chain further augments its ability to attract new customers.
Field Gathering and Processing Segment
The Field Gathering and Processing segment gathers and processes natural gas from the Permian Basin in West Texas and Southeast New Mexico and the Fort Worth Basin, including the Barnett Shale, in North Texas. The natural gas processed in this segment is supplied through the Partnership’s gathering systems which, in aggregate, consist of approximately 10,400 miles of natural gas pipelines. The segment’s processing plants include nine owned and operated facilities. During 2011, the Partnership processed an average of approximately 612 MMcf/d of natural gas and produced an average of approximately 74 MBbl/d of NGLs.
We believe that the Partnership is well positioned as a gatherer and processor in the Permian and Fort Worth Basins. The Partnership has a broad geographic scope, covering portions of 44 counties and approximately 18,100 square miles across these basins. We believe that the Partnership’s proximity to production and development provides it with a competitive advantage in capturing new supplies of natural gas because of its competitive costs to connect new wells and to process additional natural gas in its existing processing plants. Additionally, because the Partnership operates all of its plants in these regions, it is often able to redirect natural gas among two or more of its processing plants, allowing it to optimize processing efficiency and further improve the profitability of its operations.
The Field Gathering and Processing segment’s operations consist of the Permian Business, Versado, SAOU and the North Texas System, each as described below.
Permian Business. The Permian Business consists of the Sand Hills gathering and processing system and the West Seminole and Puckett gathering systems in West Texas. These systems consist of approximately 1,400 miles of natural gas gathering pipelines. These gathering systems are low-pressure gathering systems with significant compression assets. The Sand Hills refrigerated cryogenic processing plant has a gross processing capacity of 150 MMcf/d and residue gas connections to pipelines owned by affiliates of Enterprise Products Partners L.P., ONEOK, Inc. and El Paso Corporation.
Versado. Versado consists of the Saunders, Eunice and Monument gas processing plants and related gathering systems in Southeastern New Mexico. Versado consists of approximately 3,200 miles of natural gas gathering pipelines. The Saunders, Eunice and Monument refrigerated cryogenic processing plants have aggregate processing capacity of 280 MMcf/d (176.4 MMcf/d, net to the Partnership’s ownership interest). These plants have residue gas connections to pipelines owned by affiliates of El Paso Corporation, MidAmerican Energy Company and Kinder Morgan Energy Partners, L.P. The Partnership’s ownership in Versado is held through Versado Gas Processors, L.L.C., a joint venture that is 63% owned by the Partnership and 37% owned by Chevron U.S.A. Inc.
SAOU. Covering portions of 10 counties and approximately 4,000 square miles in West Texas, SAOU includes approximately 1,667 miles of pipelines in the Permian Basin that gather natural gas to the Mertzon, Sterling, and Conger processing plants. SAOU is connected to thousands of producing wells and over 950 central delivery points. SAOU has approximately 1,138 miles of low pressure gathering pipelines and approximately 528 miles of high-pressure gathering pipelines to deliver the natural gas to our processing plants. SAOU has 31 compressor stations to inject low-pressure gas into the high-pressure pipelines. SAOU’s processing facilities include three currently operating refrigerated cryogenic processing plants—the Mertzon, Sterling, and Conger plants—which have an aggregate processing capacity of approximately 139 MMcf/d. These plants have residue gas connections to pipelines owned by affiliates of ONEOK Inc., El Paso Corporation, Enterprise Partners L.P., Atmos Energy Corporation, Kinder Morgan Energy Partners L.P. and Northern Natural Gas Company.
North Texas System. The North Texas System includes two interconnected gathering systems with approximately 4,200 miles of pipelines, covering portions of 15 counties and approximately 5,700 square miles, gathering wellhead natural gas for the Chico and Shackelford natural gas processing facilities. These plants have residue gas connections to pipelines owned by affiliates of Atmos Energy Corporation, Energy Transfer Fuel LP, and Natural Gas Pipeline Company of America LLC.
The Chico gathering system consists of approximately 2,100 miles of primarily low-pressure gathering pipelines. Wellhead natural gas is either gathered for the Chico plant located in Wise County, Texas, and then compressed for processing, or it is compressed in the field at numerous compressor stations and then moved via one of several high-pressure gathering pipelines to the Chico plant. The plant has an aggregated processing capacity of 265 MMcf/d and an integrated fractionation capacity of 15 MBbl/d. The Shackelford gathering system consists of approximately 2,100 miles of intermediate-pressure gathering pipelines. The pipelines gather wellhead natural gas largely for the Shackelford plant in Albany, Texas. Natural gas gathered from the northern and eastern portions of the Shackelford Gathering System is typically compressed in the field at numerous compressor stations and then transported to the Chico plant for processing. The Shackelford plant has an aggregate processing capacity of 13 MMcf/d.
The following table lists the Field Gathering and Processing segment’s natural gas processing plants and related volumes for the year ended December 31, 2011:
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Gross
|
Gross Plant
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|||||||||||
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|
|
Processing
|
Natural Gas
|
|
|
|
|||||||||||
|
|
|
|
Capacity
|
Inlet Throughput
|
Gross NGL
|
Process
|
Operated/
|
|||||||||||
|
Facility
|
% Owned
|
Location
|
(MMcf/d)
|
Volume (MMcf/d)
|
Production
|
Type (4)
|
Non-Operated
|
|||||||||||
|
Permian Business
|
|
|
|
|
|
|
|
|||||||||||
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Sand Hills
|
100 |
Crane, TX
|
150.0 | 122.5 | 15.2 |
Cryo
|
Operated
|
|||||||||||
|
Other Permian (1)
|
|
11.8 | 0.5 |
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|
|||||||||||||
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|
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|
|||||||||||||||
|
Versado System
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|
|
|
|||||||||||||||
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Saunders (2)
|
63 |
Lea, NM
|
70.0 |
Cryo
|
Operated
|
|||||||||||||
|
Eunice (2)
|
63 |
Lea, NM
|
120.0 |
Cryo
|
Operated
|
|||||||||||||
|
Monument (2)
|
63 |
Lea, NM
|
90.0 |
Cryo
|
Operated
|
|||||||||||||
|
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Area Total
|
280.0 | 162.8 | 18.1 |
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|
||||||||||||
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SAOU
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|
|
|
|||||||||||||||
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Mertzon
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100 |
Irion, TX
|
52.0 |
Cryo
|
Operated
|
|||||||||||||
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Sterling
|
100 |
Sterling, TX
|
62.0 |
Cryo
|
Operated
|
|||||||||||||
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Conger
|
100 |
Sterling, TX
|
25.0 |
Cryo
|
Operated
|
|||||||||||||
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|
Area Total
|
139.0 | 111.0 | 17.4 |
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|
||||||||||||
|
North Texas System
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|
|
|
|||||||||||||||
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Chico (3)
|
100 |
Wise, TX
|
265.0 |
Cryo
|
Operated
|
|||||||||||||
|
Shackelford
|
100 |
Shackelford, TX
|
13.0 |
Cryo
|
Operated
|
|||||||||||||
|
|
Area Total
|
278.0 | 203.5 | 22.9 |
|
|
||||||||||||
|
|
Segment System Total
|
847.0 | 611.6 | 74.1 |
|
|
||||||||||||
_________
|
(1)
|
Other Permian includes throughput other than plant inlet, primarily from compressor stations.
|
|
(2)
|
These plants are part of our Versado joint venture, of which we own 63%; capacity and volumes represent 100% of ownership interest.
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|
(3)
|
The Chico plant has fractionation capacity of approximately 15 MBbl/d.
|
|
(4)
|
Cryo - Cryogenic Processing.
|
Coastal Gathering and Processing Segment
The Partnership’s Coastal Gathering and Processing segment assets are located in the onshore region of the Louisiana Gulf Coast and the Gulf of Mexico. With the strategic location of its assets in Louisiana, the Partnership has access to the Henry Hub, the largest natural gas hub in the U.S., and to a substantial NGL distribution system with access to markets throughout Louisiana and the southeast U.S. The Coastal Gathering and Processing segment’s assets consist of the Coastal Straddles and LOU, each as described below. For the year ended December 31, 2011, the Partnership processed an average of approximately 1,551 MMcf/d of plant natural gas inlet and produced an average of approximately 50 MBbl/d of NGLs.
Coastal Straddles. Coastal Straddles consists of three wholly owned and operated gas processing plants and seven partially owned plants, some of which are operated by the Partnership. The plants, having an aggregated processing capacity of approximately 8,230 MMcf/d, are generally situated on mainline natural gas pipelines near the coastline and process volumes of natural gas collected from multiple offshore gathering systems and pipelines throughout the Gulf of Mexico. Coastal Straddles also has ownership in three offshore gathering systems that are operated by the Partnership. The Pelican and Seahawk pipeline systems are non-FERC regulated gathering systems that have a combined length of approximately 175 miles and a combined capacity of approximately 230 MMcf per day. These systems gather natural gas from the shallow waters of the central Gulf of Mexico and supply a portion of the natural gas delivered to the Barracuda and Lowry processing facilities. Additionally, through the Partnership’s 77% ownership interest in VESCO, the Partnership operates the Venice Gathering System (“VGS”), an offshore gathering system regulated as an interstate pipeline by the Federal Energy Regulatory Commission (“FERC”). VGS is approximately 150 miles in length and has a nominal capacity of 320 MMcf per day. VGS gathers natural gas from the shallow waters of eastern Gulf of Mexico and supplies a portion of the natural gas to the Venice gas plant.
Coastal Straddles process natural gas produced from shallow water central and western Gulf of Mexico natural gas wells and from deep shelf and deepwater Gulf of Mexico production via connections to third-party pipelines or through pipelines owned by the Partnership. Coastal Straddles has access to markets across the U.S. through the interstate natural gas pipelines to which they are interconnected.
LOU. LOU consists of approximately 875 miles of gathering system pipelines, covering approximately 3,800 square miles in Southwest Louisiana. The gathering system is connected to numerous producing wells and/or central delivery points in the area between Lafayette and Lake Charles, Louisiana. The gathering system is a high-pressure gathering system that delivers natural gas for processing to either the Acadia or Gillis plants via three main trunk lines. The processing facilities include the Gillis and Acadia processing plants, both of which are cryogenic plants. These processing plants have an aggregate processing capacity of approximately 260 MMcf/d. In addition, the Gillis plant has integrated fractionation with operating capacity of approximately 13 MBbl/d.
The following table lists the Coastal Gathering and Processing segment’s natural gas processing plants and related volumes for the year ended December 31, 2011:
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|
Gross
|
Gross Plant
|
|
|
|
|||||||||||
|
|
|
|
Processing
|
Natural Gas
|
|
|
|
|||||||||||
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|
|
|
Capacity
|
Inlet Throughput
|
Gross NGL
|
Process
|
Operated/
|
|||||||||||
|
Facility
|
% Owned
|
Location
|
(MMcf/d)
|
Volume (MMcf/d)
|
Production
|
Type (4)
|
Non-operated
|
|||||||||||
|
Coastal Straddles (1)
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|
|
|
|
|
|
|
|||||||||||
|
Barracuda
|
100 |
Cameron, LA
|
190 | 126.2 | 3.3 |
Cryo
|
Operated
|
|||||||||||
|
Lowry
|
100 |
Cameron, LA
|
265 | 125.5 | 2.8 |
Cryo
|
Operated
|
|||||||||||
|
Stingray
|
100 |
Cameron, LA
|
300 | 135.3 | 3.1 |
RA
|
Operated
|
|||||||||||
|
Calumet (5)
|
32.4 |
St. Mary, LA
|
1,650 | 99.7 | 2.6 |
RA
|
Non-operated
|
|||||||||||
|
Yscloskey (2)
|
25.3 |
St. Bernard, LA
|
1,850 | 276.4 | 1.8 |
RA
|
Operated
|
|||||||||||
|
Bluewater (2)
|
21.8 |
Acadia, LA
|
425 | * | * |
Cryo
|
Non-operated
|
|||||||||||
|
Terrebonne (2)
|
4.8 |
Terrebonne, LA
|
950 | 22.6 | 0.6 |
RA
|
Non-operated
|
|||||||||||
|
Toca (2)
|
10.7 |
St. Bernard, LA
|
1,150 | 51.5 | 1.2 |
Cryo/RA
|
Non-operated
|
|||||||||||
|
Sea Robin
|
0.8 |
Vermillion, LA
|
700 | 17.4 | 0.5 |
Cryo
|
Non-operated
|
|||||||||||
|
VESCO
|
76.8 |
Plaquemines, LA
|
750 | 498.5 | 25.8 |
Cryo
|
Operated
|
|||||||||||
|
Other (6)
|
|
21.7 | 0.8 |
|
|
|||||||||||||
|
|
Area Total
|
8,230 | 1,374.8 | 42.5 |
|
|
||||||||||||
|
LOU
|
|
|
|
|||||||||||||||
|
Gillis (3)
|
100 |
Calcasieu, LA
|
180 |
Cryo
|
Operated
|
|||||||||||||
|
Acadia
|
100 |
Acadia, LA
|
80 |
Cryo
|
Operated
|
|||||||||||||
|
|
Area Total
|
260 | 175.7 | 7.4 |
|
|
||||||||||||
|
|
Consolidated System Total
|
8,490 | 1,550.5 | 49.9 |
|
|
||||||||||||
|
* Not available.
|
|
|
|
|||||||||||||||
_________
|
(1)
|
Coastal Straddles also includes three offshore gathering systems which have a combined length of approximately 330 miles.
|
|
(2)
|
Our ownership is adjustable and subject to annual redetermination based on our proportionate share of owners’ production.
|
|
(3)
|
The Gillis plant has fractionation capacity of approximately 13 MBbl/d.
|
|
(4)
|
Cryo—Cryogenic Processing; RA—Refrigerated Absorption Processing.
|
|
(5)
|
Plant shut-down January 2012.
|
|
(6)
|
Other includes plants not owned by us or the Partnership.
|
Logistics and Marketing Division
The Partnership’s Logistics and Marketing Division is also referred to as the Downstream Business. It includes the activities necessary to convert mixed NGLs into NGL products and provide certain value added services such as the fractionation, storage, terminaling, transportation, distribution and marketing of NGLs, as well as certain natural gas supply and marketing activities in support of our other businesses. Through fractionation, mixed NGLs are separated into their component parts (ethane, propane, butanes and natural gasoline). These component parts are delivered to end-users through pipelines, barges, trucks and rail cars. End-users of NGL products include petrochemical and refining companies and propane markets for heating, cooking or crop drying applications. Retail distributors often sell to end-use propane customers.
Logistics Assets Segment
This segment uses its platform of integrated assets to receive, fractionate, store, treat, transport and deliver NGLs typically under fee-based arrangements. For NGLs to be used by refineries, petrochemical manufacturers, propane distributors and other industrial end-users, they must be fractionated into their component products and delivered to various points throughout the U.S. The Partnership’s logistics assets are generally connected to and supplied in part by its Natural Gas Gathering and Processing assets and are primarily located at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana. This segment also contains refined petroleum product and crude oil storage and terminaling.
Fractionation. After being extracted in the field, mixed NGLs, sometimes referred to as “Y-grade” or “raw NGL mix,” are typically transported to a centralized facility for fractionation where the mixed NGLs are separated into discrete NGL products: ethane-propane mix, ethane, propane, normal butane, iso-butane and natural gasoline. Mixed NGLs delivered from the Partnership’s Field and Coastal Gathering and Processing segments represent the largest single source of volumes processed by the Partnership’s NGL fractionators.
The Partnership’s fractionation assets include ownership interests in three stand-alone fractionation facilities that are located on the Gulf Coast, two of which it operates, one at Mont Belvieu, Texas and the other at Lake Charles, Louisiana. The Partnership has an equity investment in the third fractionator, GCF, also located at Mont Belvieu. The Partnership is subject to a consent decree with the Federal Trade Commission, issued December 12, 1996, that, among other things, prevents it from participating in commercial decisions regarding rates paid by third parties for fractionation services at GCF. This restriction on the Partnership activity at GCF will terminate on December 12, 2016, twenty years after the date the consent order was issued. In addition to the three stand-alone facilities in the Logistics Assets segment, see the description of fractionation assets in the North Texas System and LOU in our Natural Gas Gathering and Processing division.
The majority of the Partnership’s NGL fractionation business is under fee-based arrangements. These fees are subject to adjustment for changes in certain fractionation expenses, including energy costs. The operating results of the Partnership’s NGL fractionation business are dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged.
We believe that sufficient volumes of mixed NGLs will be available for fractionation in commercially viable quantities for the foreseeable future due to increases in NGL production expected from shale plays and other shale-technology driven resource plays in areas of the U.S. that include North Texas, South Texas, Permian Basin, Oklahoma and the Rockies and certain other basins accessed by pipelines to Mont Belvieu, as well as from conventional production of NGLs in areas such as the Permian Basin, Mid-Continent, East Texas, South Louisiana and shelf and deepwater Gulf of Mexico. Hydrocarbon dew point specifications implemented by individual natural gas pipelines and the policy statement enacted by FERC should result in volumes of mixed NGLs being available for fractionation because natural gas requires processing or conditioning to meet pipeline quality specifications. These requirements establish a base volume of mixed NGLs during periods when it might be otherwise uneconomical to process certain sources of natural gas. Furthermore, significant volumes of mixed NGLs are contractually committed to the Partnership’s NGL fractionation facilities.
Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs and distribute NGL products is also an important competitive factor. This ability is a function of the existence of storage infrastructure and supply and market connectivity necessary to conduct such operations. We believe that the location, scope and capability of the Partnership’s logistics assets, including its transportation and distribution systems, give the Partnership access to both substantial sources of mixed NGLs and a large number of end-use markets.
The Partnership also has a natural gasoline hydrotreater at Mont Belvieu, Texas that removes sulfur from natural gasoline, allowing customers to meet new, more stringent environmental standards. The facility has a capacity of 30 MBbl/d and is supported by fee-based contracts with Marathon Petroleum Company LLC (“Marathon”) and Koch Supply and Trading LP that have certain guaranteed volume commitments or provisions for deficiency payments.
Modifications have been made to this process to also provide for benzene treating for Marathon’s account. This new process addition was started up in January 2012, which effectively reset Marathon’s term for five years beginning February 1, 2012. Similar to the hydrotreater, the benzene saturation process is supported by fee-based contracts that have certain guaranteed volume commitments or provisions for deficiency payments.
The following table details the Logistics Assets segment’s fractionation and treating facilities:
|
|
|
|
|
|
|
|
|
|
Facility
|
|
% Owned
|
|
Maximum Gross Capacity (MBbl/d)
|
|
Gross Throughput for 2011 (MBbl/d)
|
|
|
Operated Fractionation Facilities:
|
|
|
|
|
|
|
|
|
|
Lake Charles Fractionator (Lake Charles, LA)
|
|
100.0
|
|
55.0
|
|
34.8
|
|
|
Cedar Bayou Fractionator (Mont Belvieu, TX)
|
|
88.0
|
|
293.0
|
|
230.3
|
|
|
Targa LSNG Hydrotreater (Mont Belvieu, TX)
|
|
100.0
|
|
30.0
|
|
15.3
|
|
Non-operated Fractionation Facilities:
|
|
|
|
|
|
|
|
|
|
Gulf Coast Fractionator (Mont Belvieu, TX)
|
|
38.8
|
|
109.0
|
|
92.0
|
Storage, Terminaling and Petroleum Logistics. In general, the Partnership’s storage assets provide warehousing of mixed NGLs, NGL products and petrochemical products in underground wells, which allows for the injection and withdrawal of such products at various times in order to meet supply and demand cycles. Similarly, the Partnership’s terminaling operations provide the inbound/outbound logistics and warehousing of mixed NGLs, NGL products and petrochemical products in above-ground storage tanks. The Partnership’s underground storage and terminaling facilities serve single markets, such as propane, as well as multiple products and markets. For example, the Mont Belvieu and Galena Park facilities have extensive pipeline connections for mixed NGL supply and delivery of component NGLs. In addition, some of these facilities are connected to marine, rail and truck loading and unloading facilities that provide services and products to the Partnership’s customers. The Partnership provides long and short term storage and terminaling services and throughput capability to third-party customers for a fee.
The Partnership’s newly acquired Petroleum Logistics business, which consists of storage and terminaling facilities in Texas (the Channelview Terminal), Maryland (the Baltimore Terminal) and Washington (the Sound Terminal), each currently primarily for the refined petroleum products and crude oil market, but potentially also including crude oil, LPGs and biofuels.
Across the Logistics Assets segment, the Partnership owns or operates a total of 39 storage wells at its facilities with a net storage capacity of approximately 64 MMBbl, the usage of which may be limited by brine handling capacity, which is utilized to displace NGLs from storage.
The Partnership operates its storage and terminaling facilities based on the needs and requirements of its customers. The Partnership usually experiences an increase in demand for storage and terminaling of mixed NGLs during the summer months when gas plants typically reach peak NGL production, refineries have excess NGL products and LPG imports are often highest. Demand for storage and terminaling at the Partnership’s propane facilities typically peaks during fall, winter and early spring. The Partnership has experienced significant demand growth for NGL (primarily propane) exports and expects that trend to continue with its announced international grade propane exports project.
The Partnership’s fractionation, storage and terminaling business is supported by approximately 940 miles of company-owned pipelines to transport mixed NGLs and specification products.
The following table details the Logistics Assets NGL storage facilities at December 31, 2011:
|
|
|
NGL Storage Facilities
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||||||
|
|
|
|
|
|
|
Number of
|
|
Gross Storage
|
|
Facility
|
|
% Owned
|
|
County/Parish, State
|
|
Permitted Wells
|
|
Capacity (MMBbl)
|
|
Hackberry Storage (Lake Charles)
|
|
100
|
|
Cameron, LA
|
|
12
|
(1)
|
20.0
|
|
Mont Belvieu Storage
|
|
100
|
|
Chambers, TX
|
|
20
|
(2)
|
43.0
|
|
Easton Storage
|
|
100
|
|
Evangeline, LA
|
|
1
|
|
0.8
|
_______
|
(1)
|
Five of twelve owned wells leased to CITGO under long-term leases.
|
|
(2)
|
The Partnership owns 20 wells and operates 6 wells owned by Chevron Phillips Chemical Company LLC.
|
The following table details the Logistics Assets Terminal Facilities for the year ended December 31, 2011:
|
|
|
|
|
|
|
|
|
|
|
Usable Storage
|
|
|
|
|
|
|
|
|
|
Throughput for 2011
|
|
Capacity
|
|
Facility
|
|
% Owned
|
|
County/Parish, State
|
|
Description
|
|
(Million gallons)
|
|
(MMBbl)
|
|
Galena Park Terminal (1)
|
|
100
|
|
Harris, TX
|
|
NGL import/export terminal
|
|
1,022.3
|
|
0.7
|
|
Mont Belvieu Terminal
|
|
100
|
|
Chambers, TX
|
|
Transport and storage terminal
|
|
2,554.8
|
|
48.9
|
|
Hackberry Terminal
|
|
100
|
|
Cameron, LA
|
|
Storage terminal
|
|
390.9
|
|
17.8
|
|
Channelview Terminal (2)
|
|
100
|
|
Harris, TX
|
|
Transport and storage terminal
|
|
101.6
|
|
0.5
|
|
Baltimore Terminal
|
|
100
|
|
Baltimore, MD
|
|
Transport and storage terminal
|
|
-
|
|
0.5
|
|
Sound Terminal (3)
|
|
100
|
|
Pierce, WA
|
|
Transport and storage terminal
|
|
46.7
|
|
0.8
|
_________
|
(1)
|
Volumes reflect total import and export across the dock/terminal.
|
|
(2)
|
Represents throughput for the 10 ½ months following the Channelview terminal acquisition on March 15, 2011.
|
|
(3)
|
Represents throughput for the three months following the Sound Terminal acquisition on September 30, 2011.
|
Marketing and Distribution Segment
The Marketing and Distribution segment transports, distributes and markets NGLs via terminals and transportation assets across the U.S. The Partnership owns or commercially manages terminal facilities in a number of states, including Texas, Louisiana, Arizona, Nevada, California, Florida, Alabama, Mississippi, Tennessee, Kentucky, New Jersey and Washington. The geographic diversity of the Partnership’s assets provide direct access to many NGL customers as well as markets via trucks, barges, rail cars and open-access regulated NGL pipelines owned by third parties. The Marketing and Distribution segment consists of (i) NGL Distribution and Marketing, (ii) Wholesale Marketing, (iii) Refinery Services, (iv) Commercial Transportation, (v) Natural Gas Marketing, and (vi) Terminal Facilities, each as described below.
NGL Distribution and Marketing. The Partnership markets its own NGL production and also purchases component NGL products from other NGL producers and marketers for resale. During the year ended December 31, 2011, the Partnership’s distribution and marketing services business sold an average of approximately 273 MBbl/d of NGLs.
The Partnership generally purchases mixed NGLs from producers at a monthly pricing index less applicable fractionation, transportation and marketing fees and resells these products to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical settlement business in which the Partnership earns margins from purchasing and selling NGL products from producers under contract. The Partnership also earns margins by purchasing and reselling NGL products in the spot and forward physical markets. To effectively serve its Distribution and Marketing customers, the Partnership contracts for and uses many of the assets included in its Logistics Assets segment. The Partnership also markets natural gas available from its Gathering and Processing segments, and purchases and resells natural gas in selected United States markets.
Wholesale Marketing. The Partnership’s wholesale propane marketing operations primarily sell propane and related logistics services to major multi-state retailers, independent retailers and other end-users. The Partnership’s propane supply primarily originates from both its refinery/gas supply contracts and its other owned or managed logistics and marketing assets. The Partnership generally sells propane at a fixed or posted price at the time of delivery and, in some circumstances, the Partnership earns margin on a net-back basis.
The wholesale propane marketing business is significantly impacted by weather-driven demand, particularly in the winter, which can impact the price of propane in the markets it serves and impact the ability to deliver propane to satisfy peak demand.
Refinery Services. In its refinery services business, the Partnership typically provides NGL balancing services via contractual arrangements with refiners to purchase and/or market propane and to supply butanes. The Partnership uses its commercial transportation assets (discussed below) and contracts for and uses the storage, transportation and distribution assets included in its Logistics Assets segment to assist refinery customers in managing their NGL product demand and production schedules. This includes both feedstocks consumed in refinery processes and the excess NGLs produced by those same refining processes. Under typical net-back purchase contracts, the Partnership generally retains a portion of the resale price of NGL sales or receives a fixed minimum fee per gallon on products sold. Under net-back sales contracts, fees are earned for locating and supplying NGL feedstocks to the refineries based on a percentage of the cost to obtain such supply or a minimum fee per gallon.
Key factors impacting the results of the Partnership’s refinery services business include production volumes, prices of propane and butanes, as well as its ability to perform receipt, delivery and transportation services in order to meet refinery demand.
Commercial Transportation. The Partnership’s NGL transportation and distribution infrastructure includes a wide range of assets supporting both third-party customers and the delivery requirements of its marketing and asset management business. The Partnership provides fee-based transportation services to refineries and petrochemical companies throughout the Gulf Coast area. The Partnership’s assets are also deployed to serve its wholesale distribution terminals, fractionation facilities, underground storage facilities and pipeline injection terminals. These distribution assets provide a variety of ways to transport products to and from its customers. The Partnership’s transportation assets, as of December 31, 2011, include:
|
•
|
approximately 565 railcars that the Partnership leases and manages;
|
|
•
|
approximately 74 owned and leased transport tractors and approximately 100 company-owned tank trailers; and
|
|
•
|
18 company-owned pressurized NGL barges.
|
Natural Gas Marketing. The Partnership also markets natural gas available to the Partnership from the Gathering and Processing segments, and purchases and resells natural gas in selected United States markets.
The following table details the Marketing and Distribution segment’s Terminal Facilities:
|
|
|
|
|
|
|
|
|
|
|
Usable Storage
|
|
|
|
|
|
|
|
|
|
Throughput for 2011
|
|
Capacity
|
|
Facility
|
|
% Owned
|
|
County/Parish, State
|
|
Description
|
|
(Million gallons) (1)
|
|
(Million gallons)
|
|
Calvert City Terminal
|
|
100
|
|
Marshall, KY
|
|
Propane terminal
|
|
24.0
|
|
0.1
|
|
Greenville Terminal
|
|
100
|
|
Washington, MS
|
|
Marine propane terminal
|
|
20.1
|
|
1.7
|
|
Port Everglades Terminal
|
|
100
|
|
Broward, FL
|
|
Marine propane terminal
|
|
12.0
|
|
1.7
|
|
Tyler Terminal
|
|
100
|
|
Smith, TX
|
|
Propane terminal
|
|
15.4
|
|
0.2
|
|
Abilene Transport (2)
|
|
100
|
|
Taylor, TX
|
|
Raw NGL transport terminal
|
|
13.2
|
|
Less than 0.1
|
|
Bridgeport Transport (2)
|
|
100
|
|
Jack, TX
|
|
Raw NGL transport terminal
|
|
37.2
|
|
0.1
|
|
Gladewater Transport (2)
|
|
100
|
|
Gregg, TX
|
|
Raw NGL transport terminal
|
|
25.7
|
|
0.2
|
|
Hammond Transport
|
|
100
|
|
Tangipahoa, LA
|
|
Transport terminal
|
|
31.0
|
|
No storage
|
|
Chattanooga Terminal
|
|
100
|
|
Hamilton, TN
|
|
Propane terminal
|
|
14.0
|
|
1.0
|
|
Sparta Terminal
|
|
100
|
|
Sparta, NJ
|
|
Propane terminal
|
|
10.7
|
|
0.2
|
|
Hattiesburg Terminal (3)
|
|
50
|
|
Forrest, MS
|
|
Propane terminal
|
|
138.4
|
|
269.6
|
|
Winona Terminal
|
|
100
|
|
Flagstaff, AZ
|
|
Propane terminal
|
|
7.2
|
|
0.3
|
|
Sound Terminal (4)
|
|
100
|
|
Pierce, WA
|
|
Propane terminal
|
|
Less than 0.1
|
|
0.2
|
_______
|
(1)
|
Throughputs include volumes related to exchange agreements and third-party storage agreements.
|
|
(2)
|
Volumes reflect total transport and injection volumes.
|
|
(3)
|
Throughput volume is based on total facility capacity.
|
|
(4)
|
Operated by Logistics Assets segment; throughput volume is for three months following the Sound Terminal acquisition on September 30, 2011
|
Operational Risks and Insurance
The Partnership is subject to all risks inherent in the midstream natural gas and petroleum logistics businesses. These risks include, but are not limited to, explosions, fires, mechanical failure, terrorist attacks, product spillage, weather, nature and inadequate maintenance of rights-of-way and could result in damage to or destruction of operating assets and other property, or could result in personal injury, loss of life or polluting the environment, as well as curtailment or suspension of operations at the affected facility. We maintain, on behalf of ourselves and our subsidiaries, including the Partnership, general public liability, property, boiler and machinery and business interruption insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles that we consider reasonable and not excessive given the current insurance market environment. The costs associated with this insurance coverage have increased significantly following Hurricanes Katrina and Rita in 2005 and then again following hurricanes Gustav and Ike and as a result of volatile conditions in the financial markets in 2008. Insurance premiums, deductibles and co-insurance requirements increased substantially, and terms were generally less favorable than terms that were obtained prior to these events.
The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect the Partnership’s operations and the Partnership’s and our financial condition. While we currently maintain levels and types of insurance that we believe to be prudent under current insurance industry market conditions, our inability to secure these levels and types of insurance in the future could negatively impact the Partnership business operations and the Partnership’s and our financial stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintain these levels of insurance in the future at rates considered commercially reasonable, particularly named windstorm coverage and contingent business interruption coverage for our onshore operations.
Significant Customer
The following table lists the percentage of the Partnership’s consolidated sales with the Partnership’s significant customer:
|
|
2011
|
2010
|
2009
|
|||||||||
|
% of consolidated revenues
|
|
|
|
|||||||||
|
Chevron Phillips Chemical Company LLC
|
12% | 10% | 15% | |||||||||
The Partnership has agreements with Chevron Phillips Chemical Company LLC (“CPC”), pursuant to which it supplies a significant portion of CPC’s NGL feedstock needs for petrochemical plants in the Texas Gulf Coast area and a related services agreement, pursuant to which the Partnership provides storage and logistical services to CPC for feedstocks and products produced from the petrochemical plants. The services contract was renegotiated in 2008 with key components having a 10 year term. In September 2009, CPC and the Partnership executed a new feedstock and storage agreement effective for a term of 5 years, which will renew annually following the end of the five year term unless terminated by either party. We believe that the Partnership is well positioned to retain CPC as a customer based on the Partnership’s long-standing history of customer service, the criticality of the service provided, the integrated nature of facilities and the difficulty and high cost associated with replicating the Partnership’s assets. In addition to these two agreements, The Partnership has fractionation agreements in place with CPC for Y-grade streams and butanes.
No other customer accounted for more than 10% of the Partnership’s consolidated revenues during these periods.
Competition
The Partnership faces strong competition in acquiring new natural gas supplies. Competition for natural gas supplies is primarily based on the location of gathering and processing facilities, pricing arrangements, reputation, efficiency, flexibility, reliability and access to end-use markets or liquid marketing hubs. Competitors to the Partnership’s gathering and processing operations include other natural gas gatherers and processors, such as major interstate and intrastate pipeline companies, master limited partnerships and oil and gas producers. The Partnership’s major competitors for natural gas supplies in its current operating regions include Atlas Gas Pipeline Company, Copano Energy, L.L.C. (“Copano”), WTG Gas Processing, L.P. (“WTG”), DCP Midstream Partners LP (“DCP”), Devon Energy Corp (“Devon”), Enbridge Inc., GulfSouth Pipeline Company, LP, Hanlon Gas Processing, Ltd., J W Operating Company, Louisiana Intrastate Gas and several other interstate pipeline companies. Many of its competitors have greater financial resources than the Partnership possesses.
The Partnership also competes for NGL products to market through its NGL Logistics and Marketing division. The Partnership’s competitors include major oil and gas producers who market NGL products for their own account and for others. Additionally, the Partnership competes with several other NGL marketing companies, including Enterprise Products Partners L.P., DCP, ONEOK and BP p.l.c.
Additionally, the Partnership faces competition for mixed NGLs supplies at its fractionation facilities. Its competitors include large oil, natural gas and petrochemical companies. The fractionators in which the Partnership owns an interest in the Mont Belvieu region compete for volumes of mixed NGLs with other fractionators also located at Mont Belvieu. Among the primary competitors are Enterprise Products Partners L.P. and ONEOK, Inc. In addition, certain producers fractionate mixed NGLs for their own account in captive facilities. The Mont Belvieu fractionators also compete on a more limited basis with fractionators in Conway, Kansas and a number of decentralized, smaller fractionation facilities in Texas, Louisiana and New Mexico. The Partnership’s other fractionation facilities compete for mixed NGLs with the fractionators at Mont Belvieu as well as other fractionation facilities located in Louisiana. The Partnership’s customers who are significant producers of mixed NGLs and NGL products or consumers of NGL products may develop their own fractionation facilities in lieu of using the Partnerships’ services.
Regulation of Operations
Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of the Partnership’s business and the market for its products and services.
Regulation of Interstate Natural Gas Pipelines
VGS is regulated by FERC under the Natural Gas Act of 1938 (“NGA”), and the Natural Gas Policy Act of 1978 (“NGPA”). VGS operates under a FERC approved, open-access tariff that establishes rates and terms and conditions under which the system provides services to its customers. Pursuant to FERC’s jurisdiction, existing pipeline rates and/or terms and conditions of service may be challenged by customer complaint or by FERC and proposed rate changes or changes in the terms and conditions of service may be challenged by protest. Generally, FERC’s authority extends to: transportation of natural gas; rates and charges for natural gas transportation; certification and construction of new facilities; extension or abandonment of services and facilities; maintenance of accounts and records; commercial relationships and communications between pipelines and certain affiliates; terms and conditions of service and service contracts with customers; depreciation and amortization policies; and acquisition and disposition of facilities.
VGS holds a certificate of public convenience and necessity issued by FERC permitting the construction, ownership, and operation of its interstate natural gas pipeline facilities and the provision of transportation services. This certificate authorization requires VGS to provide on a nondiscriminatory basis open-access services to all customers who qualify under its FERC gas tariff. FERC has the power to prescribe the accounting treatment of items for regulatory purposes. Thus, the books and records of VGS may be periodically audited by FERC.
The maximum recourse rates that may be charged by VGS for its services are established through FERC’s ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline’s investment. Key determinants in the ratemaking process are costs of providing service, allowed rate of return and volume throughput and contractual capacity commitment assumptions. VGS is permitted to discount its firm and interruptible rates without further FERC authorization down to the variable cost of performing service, provided they do not “unduly discriminate.” The applicable recourse rates and terms and conditions for service are set forth in each pipeline’s FERC approved tariff. Rate design and the allocation of costs also can impact a pipeline’s profitability.
Gathering Pipeline Regulation
The Partnership’s natural gas gathering operations are typically subject to ratable take and common purchaser statutes in the states in which the Partnership operates. The common purchaser statutes generally require gathering pipelines to purchase or take without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on the Partnership’s ability as an owner of gathering facilities to decide with whom it contracts to gather natural gas. The states in which the Partnership operates have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. The rates the Partnership charges for gathering are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against the Partnership in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.
Section 1(b) of the NGA exempts natural gas gathering facilities from regulation as a natural gas company by FERC under the NGA. We believe that the natural gas pipelines in the Partnership’s 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. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. The Partnership’s natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on the Partnership’s operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
In 2007, Texas enacted new laws regarding rates, competition and confidentiality for natural gas gathering and transmission pipelines (“Competition Statute”) and new informal complaint procedures for challenging determinations of lost and unaccounted for gas by gas gatherers, processors and transporters (“LUG Statute”). The Competition Statute gives the Railroad Commission of Texas (“RRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and transportation pipelines in formal rate proceedings. This statute also gives the RRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The Competition Bill also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale, transportation, or gathering of natural gas. The LUG Statute modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. Such statute also extends the types of information that can be requested and provides the RRC with the authority to make determinations and issue orders in specific situations. We cannot predict what effect, if any, these statutes might have on the Partnership’s future operations in Texas.
Intrastate Pipeline Regulation
Though the Partnership’s natural gas intrastate pipelines are not subject to regulation by FERC as natural gas companies under the NGA, the Partnership’s intrastate pipelines may be subject to certain FERC-imposed reporting requirements depending on the volume of natural gas purchased or sold in a given year. See “—Other Federal Laws and Regulation Affecting Our Industry—FERC Market Transparency Rules.”
The Partnership’s intrastate pipelines located in Texas are regulated by the RRC. The Partnership’s Texas intrastate pipeline, Targa Intrastate Pipeline LLC (“Targa Intrastate”), owns the intrastate pipeline that transports natural gas from the Partnership’s Shackelford processing plant to an interconnect with Atmos Pipeline-Texas that in turn delivers gas to the West Texas Utilities Company’s Paint Creek Power Station. Targa Intrastate also owns a 1.65 mile, 10 inch diameter intrastate pipeline that transports natural gas from a third-party gathering system into the Chico System in Denton County, Texas. Targa Intrastate is a gas utility subject to regulation by the RRC and has a tariff on file with such agency.
The Partnership’s Louisiana intrastate pipeline, Targa Louisiana Intrastate LLC (“TLI”) owns an approximately 60-mile intrastate pipeline system that receives all of the natural gas it transports within or at the boundary of the State of Louisiana. Because all such gas ultimately is consumed within Louisiana, and since the pipeline’s rates and terms of service are subject to regulation by the Office of Conservation of the Louisiana Department of Natural Resources (“DNR”), the pipeline qualifies as a Hinshaw pipeline under Section 1(c) of the NGA and thus is exempt from most FERC regulation.
Texas and Louisiana have adopted complaint-based regulation of intrastate natural gas transportation activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to pipeline access and rate discrimination. The rates the Partnership charges for intrastate transportation are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against the Partnership in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.
Regulation of NGL intrastate pipelines
The Partnership’s intrastate NGL pipelines in Louisiana gather mixed NGLs streams that the Partnership owns from processing plants in Louisiana and deliver such streams to the Gillis fractionators in Lake Charles, Louisiana, where the mixed NGLs streams are fractionated into various products. The Partnership delivers such refined petroleum products (ethane, propane, butanes and natural gasoline) out of its fractionator to and from Targa-owned storage, to other third-party facilities and to various third-party pipelines in Louisiana. These pipelines are not subject to FERC regulation or rate regulation by the DNR, but are regulated by United States Department of Transportation (“DOT”) safety regulations.
Natural Gas Processing
The Partnership’s natural gas gathering and processing operations are not presently subject to FERC regulation. However, starting in May 2009 the Partnership was required to report to FERC information regarding natural gas sale and purchase transactions for some of its operations depending on the volume of natural gas transacted during the prior calendar year. See “—Other Federal Laws and Regulation Affecting Our Industry—FERC Market Transparency Rules.” There can be no assurance that the Partnership’s processing operations will continue to be exempt from other FERC regulation in the future.
Availability, Terms and Cost of Pipeline Transportation
The Partnership’s processing facilities and marketing of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. The price and terms of access to pipeline transportation can be subject to extensive federal and, if a complaint is filed, state regulation. FERC is continually proposing and implementing new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of NGLs. These initiatives also may indirectly affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of these regulatory changes to the Partnership’s processing operations and its natural gas and NGL marketing operations. We do not believe that the Partnership would be affected by any such FERC action materially differently than other natural gas processors and natural gas and NGL marketers with whom it competes. The ability of the Partnership’s processing facilities and pipelines to deliver natural gas into third-party natural gas pipeline facilities is directly impacted by the gas quality specifications required by those pipelines. In 2006, FERC issued a policy statement on provisions governing gas quality and interchangeability in the tariffs of interstate gas pipeline companies and a separate order declining to set generic prescriptive national standards. FERC strongly encouraged all natural gas pipelines subject to its jurisdiction to adopt, as needed, gas quality and interchangeability standards in their FERC gas tariffs modeled on the interim guidelines issued by a group of industry representatives, headed by the Natural Gas Council (“NGC+ Work Group”), or to explain how and why their tariff provisions differ. We do not believe that the adoption of the NGC+ Work Group’s gas quality interim guidelines by a pipeline that either directly or indirectly interconnects with the Partnership’s facilities would materially affect its operations. We have no way to predict, however, whether FERC will approve of gas quality specifications that materially differ from the NGC+ Work Group’s interim guidelines for such an interconnecting pipeline.
Sales of Natural Gas and NGLs
The price at which the Partnership buys and sells natural gas and NGLs is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to the Partnership’s physical purchases and sales of these energy commodities and any related hedging activities that the Partnership undertakes, it is required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodities Futures Trading Commission (“CFTC”). See “—Other Federal Laws and Regulation Affecting Our Industry—Energy Policy Act of 2005.” Starting May 1, 2009, the Partnership was required to report to FERC information regarding natural gas sale and purchase transactions for some of its operations depending on the volume of natural gas transacted during the prior calendar year. See “—Other Federal Laws and Regulation Affecting Our Industry—FERC Market Transparency Rules.” Should the Partnership violate the anti-market manipulation laws and regulations, it could also be subject to related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.
Other State and Local Regulation of Operations
The Partnership’s business activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters. For additional information regarding the potential impact of federal, state or local regulatory measures on our, see “Risk Factors—Risks Related to Our Business.”
Interstate common carrier liquids pipeline regulation
The Partnership acquired Targa NGL Pipeline Company LLC (“Targa NGL”), which has interstate NGL pipelines that are considered regulated 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 NGLs and purity NGL products. Targa NGL also owns an eight inch diameter pipeline and a 20 inch diameter pipeline, each of which run between Mont Belvieu, Texas and Galena Park, Texas. The eight inch and the 20 inch pipelines are also regulated and 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 non-discriminatory. All shippers on this pipeline are our subsidiaries.
Other Federal Laws and Regulation Affecting Our Industry
Energy Policy Act of 2005 (“EPA Act of 2005”)
The EPA Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPA Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EPA Act of 2005 provides FERC with the power to assess civil penalties of up to $1 million per day for violations of the NGA and $1 million per violation per day for violations of the NGPA. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce, including VGS. In 2006, FERC issued Order 670 to implement the anti-market manipulation provision of EPA Act of 2005. Order 670 makes it unlawful: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit any statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. Order 670 does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (Order 704), and the quarterly reporting requirement under Order 735. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.
FERC Standards of Conduct for Transmission Providers
On October 16, 2008, FERC issued new standards of conduct for transmission providers (Order 717) to regulate the manner in which interstate natural gas pipelines may interact with their marketing affiliates based on an employee separation approach. A “Transmission Provider” includes an interstate natural gas pipeline that provides open access transportation pursuant to FERC’s regulations. Under these rules, a Transmission Provider’s transmission function employees (including the transmission function employees of any of its affiliates) must function independently from the Transmission Provider’s marketing function employees (including the marketing function employees of any of its affiliates). FERC clarified on October 15, 2009 in a rehearing order, Order 717-A, however, that if a Hinshaw pipeline affiliated with a Transmission Provider engages in off-system sales of gas that has been transported on the Transmission Provider’s affiliated pipeline, then the Transmission Provider and the Hinshaw pipeline (which is engaging in marketing functions) will be required to observe the Standards of Conduct by, among other things, having the marketing function employees function independently from the transmission function employees. The Partnership’s only Hinshaw pipeline, TLI, does not engage in any off-system sales of gas that have been transported on an affiliated Transmission Provider, and we do not believe that the Partnership’s operations will be affected by the new standards of conduct. FERC further clarified Order 717-A in a rehearing order, Order 717-B, on November 16, 2009, in Order 717-C, on April 16, 2010, and in Order 717-D, on April 8, 2011. However, Orders 717-B, 717-C, and 717-D did not substantively alter the rules promulgated under Orders 717 and 717-A. The Partnership’s only Transmission Provider, VGS, does not engage in any transactions with marketing affiliates, and we do not believe that the Partnership’s operations will be affected by the new standards of conduct.
FERC Market Transparency Rules
In 2007, FERC issued Order 704, whereby wholesale buyers and sellers of more than 2.2 BBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers, are now required to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704 as clarified in orders on clarification and rehearing.
On November 20, 2008, FERC issued a final rule on daily scheduled flows and capacity posting requirements (Order 720). Under Order 720, as clarified in orders on clarification and rehearing 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, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu/d and interstate pipelines are required to post information regarding the provision of no-notice service. In October 2011, Order 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 720, as clarified, remained applicable to interstate pipelines with respect to posting information regarding the provision of no-notice service. The Partnership takes the position that, at this time, all of its entities are exempt from this rule as currently written.
On May 20, 2010, the FERC issued Order No. 735, which requires intrastate pipelines providing transportation services under Section 311 of the NGPA and “Hinshaw” pipelines operating under Section 1(c) of the NGA to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information must be supplied through a new electronic reporting system and will be posted on FERC’s website, and that such quarterly reports may not contain information redacted as privileged. The FERC promulgated this Rule after determining that such transactional information would help shippers make more informed purchasing decisions and would improve the ability of both shippers and the FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends the Commission’s periodic review of the rates charged by the subject pipelines from three years to five years. Order No. 735 became effective on April 1, 2011. On December 16, 2010, the Commission issued Order No. 735-A. In Order No. 735-A, the Commission generally reaffirmed Order No. 735 requiring section 311 and Hinshaw pipelines to report on a quarterly basis storage and transportation transactions containing specific information for each transaction, aggregated by contract. Order No. 735-A did grant rehearing of three requests, including removing the requirement that the quarterly reports include the contract end-date for interruptible transactions, eliminating the increased per-customer revenue reporting requirements, and extending the deadline for submitting the quarterly reports from 30 days to 60 days following the quarter end date. As currently written, this rule does not apply to the Partnership’s Hinshaw pipelines.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to the Partnership’s natural gas operations. We do not believe that the Partnership would be affected by any such FERC action materially differently than other midstream natural gas companies with whom it competes.
Environmental and Operational Health and Safety Matters
General
The Partnership’s operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases the Partnership’s overall cost of business, including its capital costs to construct, maintain and upgrade equipment and facilities. These laws and regulations may, among other things, require the acquisition of various permits to conduct regulated activities, require the installation of pollution control equipment or otherwise restrict the way the Partnership can handle or dispose of its wastes; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection, require investigatory and remedial action to mitigate pollution conditions caused by the Partnership’s operations or attributable to former operations; and enjoin some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. Failure to comply with these laws and regulations may result in assessment of administrative, civil and criminal penalties, the imposition of removal or remedial obligations and the issuance of injunctions limiting or prohibiting the Partnership’s activities.
The Partnership has implemented programs and policies designed to keep its pipelines, plants and other facilities in compliance with existing environmental laws and regulations. The clear trend in environmental regulation, however, is to place more restrictions and limitations on activities that may affect the environment and thus, any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on the Partnership’s operations and financial position. The Partnership may be unable to pass on such increased compliance costs to its customers. Moreover, accidental releases or spills may occur in the course of the Partnership’s operations and we cannot assure you that the Partnership will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe that the Partnership is in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on it, there is no assurance that the current conditions will continue in the future.
The following is a summary of the more significant existing environmental, health and safety laws and regulations to which the Partnership’s business operations are subject and for which compliance may have a material adverse impact on the Partnership’s capital expenditures, results of operations or financial position.
Hazardous Substances and Waste
The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the Environmental Protection Agency (“EPA”) and, in some instances, third-parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. The Partnership generates materials in the course of its operations that are regulated as “hazardous substances” under CERCLA or similar state statutes and, as a result, may be jointly and severally liable under CERCLA or such statutes for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
The Partnership also generates solid wastes, including hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of the Partnership’s operations, it generates petroleum product wastes and ordinary industrial wastes such as paint wastes, waste solvents and waste compressor oils that are regulated as hazardous wastes. Certain materials generated in the exploration, development or production of crude oil and natural gas are excluded from RCRA’s hazardous waste regulations. However, it is possible that future changes in law or regulation could result in these wastes, including wastes currently generated during the Partnership operations, being designated as “hazardous wastes” and therefore subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on the Partnership’s capital expenditures and operating expenses as well as those of the oil and gas industry in general.
The Partnership currently owns or leases and has in the past owned or leased properties that for many years have been used for midstream natural gas and NGL activities and refined petroleum product and crude oil storage and terminaling activities. Although the Partnership has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third-parties whose treatment and disposal or release of hydrocarbons or wastes was not under the Partnership’s control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, the Partnership could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact the Partnership’s results of operations or financial condition.
Air Emissions
The federal Clean Air Act, as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources, including processing plants and compressor stations and also impose various monitoring and reporting requirements. These laws and regulations may require the Partnership to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The Partnership is currently reviewing the air emissions monitoring systems at certain of its facilities. The Partnership may be required to incur capital expenditures in the next few years to implement various air emissions leak detection and monitoring programs as well as to install air pollution control equipment or non-ambient storage tanks as a result of the Partnership’s review or in connection with maintaining, amending or obtaining operating permits and approvals for air emissions. We currently believe, however, that such requirements will not have a material adverse affect on the Partnership’s operations. In addition, in July 2011, the EPA proposed a range of new regulations that would establish new air emission controls for oil and natural gas production and natural gas processing, including, among other things, a new source performance standard for volatile organic compounds that would apply to hydraulically fractured wells, compressors, pneumatic controllers, condensate and crude oil storage tanks, and natural gas processing plants. The EPA is under a court order to finalize these proposed regulations by April 3, 2012.
Climate Change
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“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 adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act, including one that regulates emissions of GHGs from motor vehicles and another that requires certain construction and operating permit reviews for emissions of GHGs from certain large stationary sources of emissions. 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 in the United States on an annual basis. The EPA also assumed responsibility for issuing certain Clean Air Act permits for construction and Title V operating permits for GHG emissions in Texas in December 2010. As a result, those two permitting programs are now subject to dual sets of approvals at the state and federal levels. Effective January 2, 2011, operators in Texas with stationary sources emitting GHGs in excess of applicable regulatory thresholds must obtain separate Clean Air Act permits and/or Title V permits from each of the EPA, with respect to GHG emissions, and the Texas Commission on Environmental Quality (“TCEQ”) with respect to all other regulated non-GHG emissions. The Partnership is monitoring its GHG emissions from its operations in accordance with the GHG emissions reporting rule and the Partnership believes that its monitoring activities are in substantial compliance with applicable reporting obligations.
Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states already have 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 any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from the Partnership’s equipment and operations could require it to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the natural gas and natural gas liquids it gathers and processes or fractionates. Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate change that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse effect on the Partnership’s operations.
Water Discharges
The Federal Water Pollution Control Act, as amended (“Clean Water Act” or “CWA”), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the U.S. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require the Partnership to monitor and sample the storm water runoff. The CWA and analogous state laws can impose substantial civil and criminal penalties for non-compliance including spills and other nonauthorized discharges.
The Oil Pollution Act of 1990, as amended (“OPA”), which amends the CWA, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under OPA includes owners and operators of onshore facilities, such as the Partnership’s plants, and its pipelines. Under OPA, owners and operators of facilities that handle, store, or transport oil are required to develop and implement oil spill response plans, and establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties could be statutorily responsible. We believe that the Partnership is in substantial compliance with the CWA, OPA and analogous state laws.
Hydraulic Fracturing
It is customary to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. The process is typically regulated by state oil and gas commissions but the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel under the Safe Drinking Water Act. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act, as amended, and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the Partnership’s oil and natural gas exploration and production customers’ operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development, or production activities, which could reduce demand for the Partnership’s gathering, processing and fractionation services. In addition, several governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing activities. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms, which events could delay or curtail production of natural gas by exploration and production operators, some of which may be the Partnership’s customers, and thus reduce demand for its midstream services.
Endangered Species Act
The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered or threatened species or their habitats. While some of the Partnership’s facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that the Partnership is in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where the Partnership wishes to conduct development activities, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA over the next six years, through the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where the Partnership’s or its oil and natural gas exploration and production customers operate could cause us or the Partnership’s customers to incur increased costs arising from species protection measures and could result in delays or limitations in the Partnership’s customers’ performance of operations, which could reduce demand for the Partnership’s midstream services.
Pipeline Safety
The pipelines used by the Partnership to transport natural gas and transport NGLs are subject to regulation by the DOT under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas and NGL pipeline facilities. Pursuant to these acts, the DOT has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Where applicable, the NGPSA and HLPSA require any entity that owns or operates pipeline facilities to comply with the regulations under these acts, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that the Partnership’s pipeline operations are in substantial compliance with applicable NGPSA and HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA and HLPSA could result in increased costs.
The Partnership’s pipelines are also subject to regulation by the DOT under the Pipeline Safety Improvement Act of 2002, which was amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES Act”). The DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a series of rules, which require pipeline operators to develop and implement integrity management programs for gas transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility and areas where people gather that are located along the route of a pipeline. Similar rules are also in place for operators of hazardous liquid pipelines including lines transporting NGLs and condensates.
In addition, states have adopted regulations, similar to existing DOT regulations, for intrastate gathering and transmission lines. Texas, Louisiana and New Mexico have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines transporting natural gas and NGLs. The Partnership currently estimates an annual average cost of $2.7 million for years 2012 through 2014 to perform necessary integrity management program testing on its pipelines required by existing DOT and state regulations. This estimate does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. However, we do not expect that any such costs would be material to the Partnership’s financial condition or results of operations.
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. On January 3, 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), which 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 $1 million to $2 million. Also, in August 2011, PHMSA published an advance notice of proposed rulemaking in which the agency is seeking public comment on a number of changes to regulations governing the safety of gas transmission pipelines and gathering lines, including, for example, (i) revising the definitions of “high consequence areas” and “gathering lines”; (ii) strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed; (iii) strengthening requirements on the types of gas transmission pipeline integrity assessment methods that may be selected for use by operators; (iv) imposing gas transmission integrity management requirements on onshore gas gathering lines; (v) requiring the submission of annual, incident and safety-related conditions reports by operators of all gathering lines; and (vi) enhancing the current requirements for internal corrosion control of gathering lines. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any adoption of the proposed PHMSA regulations applying more comprehensive or stringent pipeline safety standards 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 results of operations or financial position.
Employee Health and Safety
We and the Partnership are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in the Partnership’s operations and that this information be provided to employees, state and local government authorities and citizens. The Partnership and the entities in which it owns an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. The Partnership has an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. The Partnership believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.
Title to Properties and Rights-of-Way
The Partnership’s real property falls into two categories: (1) parcels that it owns in fee and (2) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for its operations. Portions of the land on which the Partnership’s plants and other major facilities are located are owned by it in fee title and we believe that the Partnership has satisfactory title to these lands. The remainder of the land on which the Partnership’s plant sites and major facilities are located is held by the Partnership pursuant to ground leases between it, as lessee, and the fee owner of the lands, as lessors. The Partnership and its predecessors have leased these lands for many years without any material challenge known to the Partnership relating to the title to the land upon which the assets are located, and we believe that the Partnership has satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit, lease or license; and we believe that the Partnership has satisfactory title to all of its material leases, easements, rights-of-way, permits, and licenses.
We may continue to hold record title to portions of certain assets until we make the appropriate filings in the jurisdictions in which such assets are located and obtain any consents and approvals that are not obtained prior to transfer. Such consents and approvals would include those required by federal and state agencies or political subdivisions. In some cases, we may, where required consents or approvals have not been obtained, temporarily hold record title to property as nominee for our benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, cause us to retain title, as nominee for our benefit, until a future date. We anticipate that there will be no material change in the tax treatment of our common units resulting from the holding by us of title to any part of such assets subject to future conveyance or as our nominee.
Employees
Through a wholly-owned subsidiary of ours, we employ 1,096 people who primarily support the Partnership’s operations. None of these employees are covered by collective bargaining agreements. We consider our employee relations to be good.
Financial Information by Reportable Segment
See “Segment Information” included under Note 23 to our “Consolidated Financial Statements” beginning on page F-1 of this Annual Report for a presentation of financial results by reportable segment and see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations of the Partnership – By Segment” for a discussion of our financial results by segment.
Available Information
We make certain filings with the SEC, including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports. We make such filings available free of charge through our website, http://www.targaresources.com, as soon as reasonably practicable after they are filed with the SEC. The filings are also available through the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. Our press releases and recent analyst presentations are also available on our website.
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 (i) satisfy tax obligations associated with previous sales of assets to the Partnership and (ii) reimburse the Partnership for certain capital expenditures related to Versado all as described in more detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources;”
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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.
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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 2011 fourth quarter distribution level of $0.6025 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.
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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 “Revolver”) and indentures could limit its ability to make distributions to us.
The Partnership’s Revolver and indentures contain covenants limiting its ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions. The Partnership’s 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 its 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, 2011 we have 42,398,148 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.
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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. We have opted out of this provision of Delaware law until such time as Warburg Pincus and certain transferees do not beneficially own at least 15% of our common stock. 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.
Affiliates of Warburg Pincus beneficially own approximately 23.1% 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, 2011, the Partnership had approximately $498.0 million of borrowings outstanding under its Revolver, approximately $92.5 million of letters of credit outstanding and approximately $509.5 million of additional borrowing capacity under its Revolver. In addition, as of December 31, 2011, the Partnership had $979.7 million outstanding under its senior unsecured notes. The partnership’s $1.1 billion Revolver allows us to request increases in commitments up to an additional $300 million. For the years ended December 31, 2011, 2010 and 2009, the Partnership’s consolidated interest expense was $107.7 million, $110.8 million and $159.8 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 the Partnership’s lease and other financial obligations and contractual commitments, could have other important consequences to us, including the following:
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the Partnership’s 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 the Partnership’s 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.
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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 the Partnership’s 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, 2011, its total indebtedness was $1,477.7 million, of which $979.7 million was at fixed interest rates and $498.0 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 $5.0 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 its substantial leverage.
The Partnership may be able to incur substantial additional indebtedness in the future. As of December 31, 2011, the Partnership had approximately $498.0 million of borrowings outstanding under its Revolver, approximately $92.5 million of letters of credit outstanding and approximately $509.5 million of additional borrowing capacity under its Revolver. The Partnership may be able to incur an additional $300 million of debt under its Revolver if it requests and is able to obtain commitments for the additional $300 million available under its Revolver. Although the Partnership’s 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 Partnership’s 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 Partnership’s Revolver and the indentures governing the Partnership’s senior notes (other than its 11¼% senior notes due 2017) 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 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.
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In addition, the Partnership’s 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 Partnership’s 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 its Revolver, the lenders under the 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 its Revolver. If the Partnership indebtedness under its 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 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.
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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, 2011 and 2010, its percent-of-proceeds arrangements accounted for approximately 40% and 38% of its gathered natural gas volume. Under these arrangements, the Partnership generally processes natural gas from producers and remits 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 its 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 its 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, the Partnership’s long-term success depends on its ability to obtain new sources of supplies of natural gas and NGLs, which depends on certain factors beyond its control. Any decrease in supplies of natural gas or NGLs 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 its cash flows associated with these sources of natural gas will likely also decline over time. The Partnership’s logistics assets are similarly impacted by declines in NGL supplies in the regions in which the Partnership operates as well as other regions from which it sources NGLs. To maintain or increase throughput levels on its gathering systems and the utilization rate at its processing plants and its treating and fractionation facilities, the Partnership must continually obtain new natural gas and NGL 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 that it processes and NGL products delivered to its fractionation facilities. The Partnership’s ability to obtain additional sources of natural gas and NGLs 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 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 the Partnership expects this volatility to continue. Consequently, even if new natural gas 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 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 fails to efficiently and effectively integrate acquired or developed assets with its asset base, its future growth will be limited.
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, it 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 the Partnership 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 its future growth and ability to increase distributions will be limited.
Any 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 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.
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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 its 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 the Partnership’s 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 the Partnership’s 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, it 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 its 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 its access to capital will impair its ability to execute this strategy. If the cost of such capital becomes too expensive, its 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’s 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 the Partnership’s 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 the Partnership sells. Lack of consumer demand for propane may also adversely affect the retailers the Partnership transacts with their wholesale propane marketing operations, exposing the Partnership to the wholesaler’s 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 it 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, it 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 intends 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 pipelines, terminals and processing facilities become partially or fully unavailable to transport natural gas and NGLs, the Partnership’s revenues could be adversely affected.
The Partnership depends upon third-party pipelines, storage and other facilities that provide delivery options to and from its pipelines and processing facilities. Since it does not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within the Partnership’s 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 the Partnership’s business and operating results.
The Partnership competes with similar enterprises in its respective areas of operation. Some of its competitors are large oil, natural gas and natural gas liquid companies that have greater financial resources and access to supplies of natural gas and NGLs than 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, its customers who are significant producers of natural gas may develop their own gathering, processing, storage, terminaling and transportation systems in lieu of using the Partnership’s. 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 reserves dedicated to its gathering pipeline systems; therefore, volumes of natural gas on the Partnership’s systems in the future could be less than it anticipates.
The Partnership typically does not obtain independent evaluations of natural gas 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 its gathering systems is less than it anticipates and the Partnership is unable to secure additional sources of natural gas, 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 of natural gas 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’s 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 the Partnership’s results of operations and financial condition.
The Partnership has significant relationships with Chevron Phillips Chemical Company LLC 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, 2011, and 2010, approximately 12% and 10% 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 14.5% 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 United States federal income tax purposes unless 90 percent or more of its gross income for every taxable year is “qualifying income” under section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”). 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.
Despite the fact that the Partnership is a limited partnership under Delaware law, it is possible, under certain circumstances, for an entity such as the Partnership to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon the Partnership’s current operations, that it will be so treated, a change in the Partnership’s business could cause it to be treated as a corporation for federal income tax purposes or otherwise subject it to federal income taxation as an entity.
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. For example, members of Congress have recently considered legislative changes that would affect the tax treatment of certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of 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.
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 it 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, fractionation, treating, transportation and selling of NGLs and NGL products; 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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leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;
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spills or other unauthorized releases of natural gas, NGLs, 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.
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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. While we are insured for pollution resulting from environmental accidents that occur on a sudden and accidental basis, we 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 it 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.
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In addition, states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. The Partnership currently estimates that it will incur an aggregate cost of approximately $8.2 million between 2012 and 2014 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, the Partnership cannot predict the 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 us and similarly situated midstream operators. On January 3, 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which, 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 us 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 our incurring increased operating costs that could be significant and have a material adverse effect on our 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 the Partnership to volume imbalances which, in conjunction with movements in commodity prices, could materially impact the Partnership’s 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 its control. We cannot assure you that the Partnership will generate sufficient cash flow from operations or that future borrowings will be available to it under its credit agreement 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, wilderness regions and other protected areas; requiring capital expenditures to comply with pollution control requirements, and imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (‘‘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. 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 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 natural gas wells in areas where we operate, 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 operating and compliance costs as well as reduce the rate of production of natural gas operators with whom the Partnership has a business relationship, which could have a material adverse effect on the Partnership’s 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 the Partnership 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 under the Safe Drinking Water Act’s (“SDWA”) Underground Injection Control Program and has begun the process of drafting guidance documents related to this asserted regulatory authority. In addition, 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 restrict hydraulic fracturing in certain circumstances. 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, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results 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, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act 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 the Partnership’s 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.
Venice Gathering System, L.L.C. (“VGS”) is a wholly owned subsidiary of VESCO engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of 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 our interest in VGS, our operations are generally exempt from FERC regulation under the NGA, but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived from these businesses. The NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. The Partnership believes 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 Partnerships’ 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 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 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 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 720, as clarified, remained applicable to interstate pipelines with respect to posting information regarding the provision of no-notice service. The Partnership takes the position that at this time it 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. The Partnership has 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.
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 its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity. For more information regarding the regulation of Targa’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 Domenici-Barton Energy Policy Act of 2005 (“EP Act 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 its 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 Targa’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 greenhouse gases (“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 adopted two sets of rules regulating GHG emissions under existing provisions of the Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another 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. Effective January 2, 2011, operators in Texas with stationary sources emitting GHGs in excess of applicable regulatory thresholds must obtain separate PSD and/or Title V permits from each of the EPA, with respect to GHG emissions, and the Texas Commission on Environmental Quality (“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 our 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 the Partnership’s business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Partnership’s financial condition and results of operations.
Recently proposed rules regulating air emissions from oil and natural gas operations could cause the Partnership as well as natural gas exploration and production operators to incur increased capital expenditures and operating costs as well as cause the Partnership to experience reduced demand for its gathering, processing or fractionation services.
On July 28, 2011, the U.S. Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”), and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules combined with other federal and state rules that regulate air emissions that impact natural gas gathering and processing operations would establish new operating requirements for the Partnership’s business. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to the Partnership’s customer’s as well as the Partnership’s operations including the installation of new equipment. Compliance with such rules could result in significant costs as well as delays in well completions by the Partnership’s customers, including increased capital expenditures and operating costs, which may adversely impact the Partnership’s business. Moreover, the incurrence of such expenditures and costs by the Partnership’s exploration and production customers’ could result in reduced production by those customers and thus translate into reduced demand for the Partnership’s gathering, processing or fractionation services.
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 the Partnership to increased capital and operating costs.
Congress is currently considering adopting legislation that would establish more stringent pipeline safety requirements. The proposed legislation, if adopted, could impose strengthened pipeline integrity management system requirements, including expanding those requirements to pipelines outside high consequence areas, as well as more stringent non-integrity pipeline measures such as the use of automatic or remote-controlled shut-off valves on pipeline facilities. In addition, on May 5, 2011, the federal Pipeline and Hazardous Materials Safety Administration, or “PHMSA” published a final rule expanding pipeline safety requirements including added reporting obligations and integrity management standards to certain rural low-stress hazardous liquid pipelines that were not previously regulated in such manner. Also, on August 25, 2011, PHMSA published an advance notice of proposed rulemaking in which the agency is seeking public comment on a number of changes to regulations governing the safety of gas transmission pipelines, gathering lines and related facilities including, among other things, whether PHMSA should: (i) re-define the term “gathering line,” (ii) require the submission of annual, incident and safety-related conditions reports by operators of all gathering lines, (iii) establish a new, risk-based regime of safety requirements for large-diameter, high pressure gas gathering lines in rural locations, (iv) enhance the requirements for internal corrosion control of gathering lines, and (v) apply its gas integrity management requirements to onshore gas gathering lines. The adoption of legislation or regulations that apply more comprehensive or stringent safety standards to gathering lines could require the Partnership to install new or modified safety controls, pursue added capital projects, or conduct maintenance programs on an accelerated basis, all of which could require the Partnership to incur increased operational costs that could be significant and have a material adverse effect on the Partnership’s financial position or results of operations.
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 “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. In its rulemaking under the Act, the CFTC issued regulations which set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents; provided, however certain bona fide hedging transactions or positions are exempt from these position limits. 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 the Partnership’s ability to monetize or restructure its existing derivative contracts, and increase the Partnership’s 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 us and the Partnership, the Partnership’s financial condition, and the Partnership’s results of operations.
The Partnership’s interstate common carrier liquids pipeline is regulated by the Federal Energy Regulatory Commission.
Targa NGL Pipeline Company LLC (“Targa NGL”), one of the Partnership’s subsidiaries, 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 20 inch diameter pipeline each of which run between Mont Belvieu, Texas and Galena Park, Texas. The eight inch and the 20 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 Interstate Commerce Act (“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 it 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. Unresolved Staff Comments.
None.
A description of our properties is contained in “Item 1. Business” of this Annual Report.
Our principal executive offices are located at 1000 Louisiana Street, Suite 4300, Houston, Texas 77002 and our telephone number is 713-584-1000.
Item 3. Legal Proceedings.
We are not a party to 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. Mine Safety Disclosures.
Not applicable.
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 since December 7, 2010 under the symbol “TRGP.” The following table sets forth the high and low sales prices of the common stock, as reported by The New York Stock Exchange (“NYSE”) through December 31, 2011 and the amount of cash dividends declared since our IPO.
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Stock Prices
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Dividends
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Quarter Ended
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High
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Low
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Declared
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December 31, 2011
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$ | 41.12 | $ | 26.76 | $ | 0.3363 | ||||||
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September 30, 2011
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34.91 | 26.01 | 0.3075 | |||||||||
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June 30, 2011
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36.73 | 29.44 | 0.2900 | |||||||||
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March 31, 2011
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36.70 | 26.51 | 0.2725 | |||||||||
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December 31, 2010
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28.40 | 23.50 | 0.0616 | (1) | ||||||||
________
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(1)
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Represents a prorated dividend for the portion of the fourth quarter of 2010 that the Company was public.
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As of February 17, 2012, there were approximately 214 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.
Overview of Dividends
During 2011 and 2010, our stockholders have received dividends from us on a pro rata basis. Prior to our IPO in 2010, holders of our previously outstanding preferred stock received their pro rata share of (i) an $18 million dividend paid on November 22, 2010; (ii) a $220 million extraordinary dividend paid in April 2010; and (iii) a $200 million extraordinary dividend paid on the common stock (treating the preferred stock on a common stock equivalent basis) in April 2010. Subsequent to our IPO, holders of our common stock have been paid in accordance with our dividend policy.
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:
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·
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Federal income taxes, which we are required to pay because we are taxed as a corporation;
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·
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the expenses of being a public company;
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·
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other general and administrative expenses;
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·
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general and administrative reimbursements to the Partnership;
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·
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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;
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reserves our board of directors believes prudent to maintain;
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·
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our obligation to (i) satisfy tax obligations associated with previous sales of assets to the Partnership, (ii) reimburse the Partnership for certain capital expenditures related to Versado (completed in 2011) and (iii) provide the Partnership with limited quarterly distribution support through 2011 (completed in 2011, with no support provided), all as described in more detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources;” and
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·
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interest expense or principal payments on any indebtedness we incur.
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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
Under the Partnership’s partnership agreement, available cash is defined to generally mean, for each fiscal quarter, all cash on hand at the date of determination of available cash for that quarter less the amount of cash reserves established by the general partner to provide for the proper conduct of the Partnership’s business, to comply with applicable law or any agreement binding on the Partnership and its subsidiaries and to provide for future distributions to the Partnership’s unitholders for any one or more of the upcoming 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 second quarter 2007, the Partnership has increased its quarterly cash distribution 11 times. During that time period, the Partnership has increased its quarterly distribution by 79% from $0.3375 per common unit, or $1.35 on an annualized basis, to $0.6025 per common unit, or $2.41 on an annualized basis.
For a discussion of restrictions on our and our subsidiaries’ ability to pay dividends or make distributions, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Credit Facilities and Long-Term Debt” and Note 8 “Debt Obligations” to our consolidated financial statements beginning on page F-1 of this Form 10-K.
Equity Compensation Plans
For information on our equity compensation plans, please see Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters – Securities Authorized for Issuance Under Equity Compensation Plans” and Note 22 “Stock and Other Compensation Plans” to our consolidated financial statements beginning on page F-1 of this Form 10-K.
Recent Sales of Unregistered Stock
None
Repurchase of Equity by Targa Resources Corp or Affiliated Purchasers.
None
Item 6. Selected Financial Data.
The following table presents selected historical consolidated financial and operating data of Targa Resources Corp. for the periods and as of the dates indicated. We derived this information from our historical consolidated financial statements and accompanying notes. This information should be read together with, and is qualified in its entirety, by reference to those financial statements and notes, which for the years 2011, 2010 and 2009 begins on page F-1 of this Form 10-K.
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2011
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2010
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2009
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2008
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2007
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(In millions, except per share amounts)
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Statement of operations data:
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Revenues
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$ | 6,994.5 | $ | 5,476.1 | $ | 4,542.3 | $ | 7,998.9 | $ | 7,297.2 | ||||||||||
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Income from operations
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351.1 | 196.1 | 217.2 | 234.5 | 280.3 | |||||||||||||||
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Net income
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215.4 | 63.3 | 79.1 | 134.4 | 104.2 | |||||||||||||||
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Net income (loss) attributable to Targa Resources Corp.
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30.7 | (15.0 | ) | 29.3 | 37.3 | 56.1 | ||||||||||||||
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Dividends on Series B preferred stock
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- | (9.5 | ) | (17.8 | ) | (16.8 | ) | (31.6 | ) | |||||||||||
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Net income (loss) available to common shareholders
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30.7 | (202.3 | ) | - | - | - | ||||||||||||||
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Net loss per common share - basic
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0.75 | (30.94 | ) | - | - | - | ||||||||||||||
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Net loss per common share - diluted
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0.74 | (30.94 | ) | - | - | - | ||||||||||||||
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Balance sheet data (at end of period):
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Total assets
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$ | 3,831.0 | $ | 3,393.8 | $ | 3,367.5 | $ | 3,641.8 | $ | 3,795.1 | ||||||||||
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Long-term debt
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1,567.0 | 1,534.7 | 1,593.5 | 1,976.5 | 1,867.8 | |||||||||||||||
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Convertible cumulative participating series B preferred stock
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- | - | 308.4 | 290.6 | 273.8 | |||||||||||||||
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Total owners' equity
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1,330.7 | 1,036.1 | 754.9 | 822.0 | 574.1 | |||||||||||||||
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Other:
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Dividends declared per share
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$ | 1.2063 | $ | 0.0616 | N/A | N/A | N/A | |||||||||||||
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Dividends paid on series B preferred shares
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$ | - | $ | 238.0 | $ | - | $ | - | $ | 445.1 | ||||||||||
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 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. 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. See “Condensed Parent Only Financial Statements” included under Note 25 to our “Consolidated Financial Statements” beginning on page F-1 in this Annual Report.
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:
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·
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noncontrolling interests 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 separate public company;
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federal income taxes; and
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certain non-operating assets and liabilities that we retained.
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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 engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; and storing and terminaling refined petroleum products and crude oil.
The Partnership reports its operations in two divisions: (i) Natural Gas 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 Natural Gas 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. 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 Natural Gas 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. See “2011 Developments”.
The Partnership’s Marketing and Distribution segment covers activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes: (1) marketing the Partnership’s NGL production and purchasing NGL products in selected United States markets; (2) providing liquefied petroleum gas 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 the Partnership’s Natural Gas Gathering and Processing division and the purchase and resale of natural gas in selected United States markets.
Other contains the results of the Partnership’s commodity hedging activities.
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 17, 2012, 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 of the Partnership;
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all IDRs; and
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12,945,659 of the 89,170,989 outstanding common units of the Partnership, representing a 14.5% limited partnership interest.
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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 and for the periods presented:
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Average Quarterly & Annual Prices
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Natural Gas
$/MMBtu (1)
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Illustrative Targa NGL $/gallon (2)
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Crude Oil $/Bbl (3)
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2011
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4th Quarter
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$ | 3.54 | $ | 1.37 | $ | 91.88 | ||||
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3rd Quarter
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4.20 | 1.37 | 89.54 | |||||||
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2nd Quarter
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4.32 | 1.36 | 102.34 | |||||||
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1st Quarter
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4.11 | 1.23 | 94.60 | |||||||
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2011 Average
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$ | 4.04 | $ | 1.33 | $ | 94.59 | ||||
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2010
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4th Quarter
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$ | 3.80 | $ | 1.13 | $ | 85.26 | ||||
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3rd Quarter
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4.38 | 0.94 | 76.21 | |||||||
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2nd Quarter
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4.09 | 1.00 | 78.05 | |||||||
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1st Quarter
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5.30 | 1.13 | 78.88 | |||||||
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2010 Average
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$ | 4.39 | $ | 1.05 | $ | 79.60 | ||||
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2009
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4th Quarter
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$ | 4.16 | $ | 1.02 | $ | 76.13 | ||||
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3rd Quarter
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3.39 | 0.80 | 68.24 | |||||||
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2nd Quarter
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3.51 | 0.70 | 59.79 | |||||||
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1st Quarter
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4.91 | 0.61 | 43.31 | |||||||
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2009 Average
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$ | 3.99 | $ | 0.78 | $ | 61.87 | ||||
________
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(1)
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Natural gas prices are based on average quarterly and annual prices from Henry Hub I-FERC commercial index prices.
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(2)
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NGL prices are based on quarterly and annual averages of prices from Mont Belvieu Non-TET monthly commercial index prices. Illustrative Targa NGL contains 43% ethane, 30% propane, 11% natural gasoline, 6% isobutane and 10% normal butane.
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(3)
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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.
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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 natural gas gathering and processing segment can also have a significant impact on its profitability, especially those that create exposure to changes in energy prices (“equity volumes”). Set forth below is a table summarizing the mix of the Partnership’s natural gas gathering and processing contracts for 2011 and the potential impacts of commodity prices on operating margins:
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Percent of
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Contract Type
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Throughput
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Impact of Commodity Prices
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Percent-of-Proceeds/Percent-of-Liquids
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40%
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Decreases in natural gas and or NGL prices generate decreases in operating margins.
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Fee-Based
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3%
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No direct impact from commodity price movements.
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Wellhead Purchases/Keep-whole
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21%
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Increases in natural gas prices relative to NGL prices generate decreases in operating margin.
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Hybrid
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36%
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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.
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___________
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(1)
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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.
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Negotiated contract terms are based upon a variety of factors, including natural gas quality, geographic location, the competitive commodity and pricing environment at the time the contract is executed, and customer requirements. 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, and 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 as well as 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 and NGL equity volumes through 2013 and condensate equity volumes through 2014 by entering into derivative 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 gas plant volumes for these periods. The Partnership also actively manages product inventory and other working capital levels to reduce its Downstream exposure to changing NGL prices. For additional information regarding the Partnership’s hedging activities, see “Quantitative and Qualitative Disclosures About Market Risk— Commodity Price Risk.”
Operating Expenses. Variable costs such as fuel, utilities, power, service and repairs can impact the Partnership’s results as volumes fluctuate through its systems. Continued expansion of existing assets will also give rise to additional operating expenses, which will affect the Partnership’s results.
General and Administrative Expenses. Under the Omnibus Agreement we have with the Partnership, which runs through April 2013, we provide general and administrative and other services associated with (1) the Partnership’s existing assets and any future conveyances by us and (2) subject to mutual agreement, future acquisitions from third parties. Since October 1, 2010, substantially all of our general and administrative costs have been and, so long as our only cash generating assets are ownership interests in the Partnership, will continue to be allocated to the Partnership, other than our direct costs of being a public reporting company.
General Trends and Outlook
We expect the midstream energy business environment to continue to be affected by the following key trends: demand for our services, commodity prices, volatile capital markets and increased regulation. These expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
Demand for the Partnership’s Services. Fluctuations in energy prices can affect production rates and investments by third parties in the development of oil and natural gas reserves. Generally, drilling and production activity will increase as energy prices increase. We believe that the current strength of oil, condensate and NGL prices as compared to natural gas prices has caused producers in and around the Partnership’s natural gas gathering and processing areas of operation to focus their drilling programs on regions rich in liquid forms of hydrocarbons. This focus is reflected in increased drilling permits and higher rig counts in these areas, and we expect these activities to lead to higher inlet volumes in the Field Gathering and Processing segment over the next several years. While we expect demand for the Partnership’s NGL products to remain strong, a reduction in demand for NGL products or a significant increase in NGL product supply relative to this demand, could impact the Partnership’s business. Increases in demand for international grade propane, along with expansion in the petrochemical industry, which relies on ethane as a feedstock, point towards sustained demand for the Partnership’s terminaling and storage services in the Downstream Business. Producer activity in areas rich in oil, condensate and NGLs is currently generating increased demand for the Partnership’s fractionation services and for related fee-based services provided by the Downstream Business. While we expect development activity to remain robust with respect to oil and liquids rich gas development and production, currently depressed natural gas prices have resulted in reduced activity levels surrounding comparatively dry natural gas reserves, whether conventional or unconventional.
Commodity Prices. Current forward commodity prices as of December 31, 2011 show natural gas prices strengthening while NGL and crude oil prices weaken on an absolute price basis. Various industry commodity price forecasts based on fundamental analysis may differ significantly from forward market prices. Both are subject to change due to multiple factors. There has been and we believe there will continue to be significant volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. In addition, the volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producers and ultimately supply to the Partnership’s systems.
The Partnership’s operating income generally improves in an environment of higher natural gas, NGL and condensate prices, primarily as a result of its percent-of-proceeds contracts. The Partnership’s processing profitability is largely dependent upon pricing, the supply of and market demand for natural gas, NGLs and condensate, which are beyond its control and have been volatile. Recent weak economic conditions have negatively affected the pricing and market demand for natural gas which caused a reduction in profitability of the Partnership’s processing operations. In a declining commodity price environment, without taking into account the Partnership’s hedges, it will realize a reduction in cash flows under its percent-of-proceeds contracts proportionate to average price declines. The Partnership has attempted to mitigate its exposure to commodity price movements by entering into hedging arrangements. For additional information regarding hedging activities, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”
Volatile Capital Markets. We and the Partnership are dependent on our abilities to access equity and debt capital markets in order to fund acquisitions and expansion expenditures. Global financial markets have been, and are expected to continue to be, volatile and disrupted and weak economic conditions may cause a significant decline in commodity prices. As a result, we and the Partnership may be unable to raise equity or debt capital on satisfactory terms, or at all, which may negatively impact the timing and extent to which we and the Partnership execute growth plans. Prolonged periods of low commodity prices or volatile capital markets may impact our and the Partnership’s ability or willingness to enter into new hedges, fund organic growth, connect to new supplies of natural gas, execute acquisitions or implement expansion capital expenditures.
Increased Regulation. Additional regulation in various areas has the potential to materially impact the Partnership’s operations and financial condition. For example, increased regulation of hydraulic fracturing used by producers may cause reductions in supplies of natural gas and of NGLs from producers. Please read “Risk Factors—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.” Similarly, the forthcoming rules and regulations of the CFTC may limit the Partnership’s ability or increase the cost to use derivatives, which could create more volatility and less predictability in its results of operations. Please read “Risk Factors—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.”
How We Evaluate Our Operations
Our consolidated operations include the operations of the Partnership due to our ownership and control of the general partner. We currently have no separate, direct operating activities from those conducted by the Partnership. Our financial results differ from the Partnership’s due to the financial effects of: noncontrolling interests in the Partnership, our separate debt obligations, certain non-operating costs associated with assets and liabilities that we retained and were not included in asset conveyances to the Partnership, and certain general and administrative costs applicable to us as a separate public company. Management’s primary measure of analyzing our performance is the non-GAAP measure distributable cash flow.
Distributable Cash Flow. We define distributable cash flow as distributions due to us from the Partnership, less our specific general and administrative costs as a separate public reporting entity, the interest carry costs associated with our debt and taxes attributable to our earnings. Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts, and others to compare basic cash flows generated by us to the cash dividends we expect to pay our shareholders. Using this metric, management and external users of our financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash dividends. Distributable cash flow is also an important financial measure for our shareholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly dividend rates. Distributable cash flow is also a quantitative standard used throughout the investment community because the share value is generally determined by the share’s yield (which in turn is based on the amount of cash dividends the entity pays to a shareholder).
The economic substance behind our use of distributable cash flow is to measure the ability of our assets to generate cash flow sufficient to pay dividends to our investors.
The GAAP measure most directly comparable to distributable cash flow is net income. Distributable cash flow should not be considered as an alternative to GAAP net income. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of distributable cash flow may not be compatible to similarly titled measures of other companies, thereby diminishing its utility.
Management compensates for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision making process. On January 12, 2012, the Partnership announced that the board of directors of its general partner declared a quarterly distribution for the three months ended December 31, 2011 of $0.6025 per common unit, or an annual rate of $2.41 per common unit. Based on these distribution rates, we will receive quarterly distributions of $7.8 million, or $31.2 million on an annualized basis, in respect of our common units in the Partnership, and based on these distribution rates, we will receive quarterly distributions of $11.0 million and $1.3 million, or $44.0 million and $5.3 million on an annualized basis, based on our IDRs and 2% general partner interests. See Note 9 – Partnership Units and Related Matters.
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2011
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Targa Resources Corp. Distributable Cash Flow
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(In millions)
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Distributions declared by Targa Resources
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Partners LP associated with:
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General Partner Interests
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$ | 4.8 | ||
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Incentive Distribution Rights
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34.4 | |||
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Common Units
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27.7 | |||
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Total distributions declared by Targa Resources Partners LP
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66.9 | |||
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Income (expenses) of TRC Non-Partnership
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General and administrative expenses
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(8.3 | ) | ||
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Interest expense, net
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(4.0 | ) | ||
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Current cash tax expense (1)
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(7.4 | ) | ||
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Taxes funded with cash on hand (2)
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10.1 | |||
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Other income (expense)
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2.9 | |||
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Distributable cash flow
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$ | 60.2 | ||
________
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(1)
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Excludes $4.7 million of non-cash current tax expense arising from amortization of deferred long-term tax assets from drop down gains realized for tax purposes and paid in 2010 for the year ended December 31, 2011.
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(2)
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Current period portion of amount established at our IPO to fund taxes on deferred gains related to drop down transactions that were treated as sales for income tax purposes.
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2011
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Reconciliation of net income attributable to
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(In millions)
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Targa Resources Corp. to Distributable Cash Flow
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Net income of Targa Resources Corp.
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$ | 215.4 | ||
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Less: Net income of Targa Resources Partners LP
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(245.5 | ) | ||
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Net loss for TRC Non-Partnership
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(30.1 | ) | ||
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Plus: TRC Non-Partnership income tax expense
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22.3 | |||
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Plus: Distributions declared by the Partnership
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66.9 | |||
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Plus: Non-cash loss (gain) on hedges
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(4.4 | ) | ||
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Plus: Depreciation - Non-Partnership assets
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2.8 | |||
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Less: Current cash tax expense (1)
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(7.4 | ) | ||
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Plus: Taxes funded with cash on hand (2)
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10.1 | |||
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Distributable cash flow
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$ | 60.2 | ||
________
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(1)
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Excludes $4.7 million of non-cash current tax expense arising from amortization of deferred long-term tax assets from drop down gains realized for tax purposes and paid in 2010 for the year ended December 31, 2011.
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(2)
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Current period portion of amount established at our IPO to fund taxes on deferred gains related to drop down transactions that were treated as sales for income tax purposes.
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How We Evaluate the Partnership’s Operations
The Partnership’s profitability is a function of the difference between: (i) the revenues the Partnership receives from its operations, including fee-based revenues from services and revenues from the natural gas, NGLs and condensate the Partnership sells, and (ii) the costs associated with conducting the Partnership’s operations, including the costs of wellhead natural gas and mixed NGLs that the Partnership purchases as well as operating and general and administrative costs and the impact of commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in the Partnership’s revenues alone are not necessarily indicative of increases or decreases in its profitability. The Partnership’s contract portfolio, the prevailing pricing environment for natural gas and NGLs, and the volumes of natural gas and NGL throughput on its systems are important factors in determining its profitability. The Partnership’s profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for its products and services and changes in its customer mix.
Aside from commodity-based revenues, the Partnership’s profitability is also impacted by fee-based revenues. The Partnership’s growth strategy, largely based on third-party acquisitions of businesses and assets as well as expansion of existing facilities, emphasizes assets that generate fee-based revenues. Fixed fees for services such as storage and terminaling are more attractive to the Partnership’s investors because these revenues are not susceptible to changes in market prices for commodities or to changes in the efficiency of the Partnership’s operational environments.
Management uses a variety of financial measures and operational measurements to analyze the Partnership’s performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses and (3) the following non-GAAP measures—gross margin, operating margin, adjusted EBITDA and distributable cash flow.
Throughput Volumes, Facility Efficiencies and Fuel Consumption. The Partnership’s profitability is impacted by its ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to its gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing natural gas supplies currently gathered by third parties. Similarly, the Partnership’s profitability is impacted by its ability to add new sources of mixed NGL supply, typically connected by third-party transportation, to its Downstream Business’ fractionation facilities. The Partnership fractionates NGLs generated by its gathering and processing plants, as well as by contracting for mixed NGL supply from third-party gathering, fractionation and export facilities.
In addition, the Partnership seeks to increase operating margin by limiting volume losses and reducing fuel consumption by increasing compression efficiency. With its gathering systems’ extensive use of remote monitoring capabilities, the Partnership monitors the volumes of natural gas received at the wellhead or central delivery points along its gathering systems, the volume of natural gas received at its processing plant inlets and the volumes of NGLs and residue natural gas recovered by its processing plants. The Partnership also monitors the volumes of NGLs received, stored, fractionated and delivered across its logistics assets. This information is tracked through its processing plants and Downstream Business facilities to determine customer settlements for sales and volume-related fees for service and help the Partnership increase efficiency and reduce fuel consumption.
As part of monitoring the efficiency of its operations, the Partnership measures the difference between the volume of natural gas received at the wellhead or central delivery points on its gathering systems and the volume received at the inlet of its processing plants as an indicator of fuel consumption and line loss. The Partnership also tracks the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of the facilities. Similar tracking is performed for its logistics assets. These volume, recovery and fuel consumption measurements are an important part of the Partnership’s operational efficiency analysis.
Operating Expenses. Operating expenses are costs associated with the operation of a specific asset. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of the Partnership’s operating expenses. These expenses, other than fuel and power, generally remain relatively stable and independent of the volumes through its systems but fluctuate depending on the scope of the activities performed during a specific period.
Gross Margin. We define gross margin as revenues less purchases. It is impacted by volumes and commodity prices as well as the Partnership’s contract mix and hedging program. We define Natural Gas Gathering and Processing gross margin as total operating revenues from the sales of natural gas and NGLs plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases. Logistics Assets gross margin consists primarily of service fee revenue. Gross margin for Marketing and Distribution equals total revenue from service fees and NGL sales, less cost of sales, which consists primarily of NGL purchases, transportation costs and changes in inventory valuation. The gross margin impacts of cash flow hedge settlements are reported in Other.
Operating Margin. Operating margin is an important performance measure of the core profitability of the Partnership’s operations. We define operating margin as gross margin less operating expenses. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges.
Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of the Partnership’s results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
Our management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by us and by external users of our financial statements, including investors and commercial banks, to assess:
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the financial performance of the Partnership’s assets without regard to financing methods, capital structure or historical cost basis;
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the Partnership’s operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and
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the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
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Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.
Adjusted EBITDA. The Partnership defines Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and non-cash risk management activities related to derivative instruments. Adjusted EBITDA is used as a supplemental financial measure by the Partnership and by external users of our financial statements such as investors, commercial banks and others.
The economic substance behind the Partnership’s use of Adjusted EBITDA is to measure the ability of its assets to generate cash sufficient to pay interest costs, support its indebtedness and make distributions to its investors.
The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities or GAAP net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
The Partnership compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.
Distributable Cash Flow. The Partnership defines distributable cash flow as net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash losses (gains) on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures (net of any reimbursements of project costs). The impact of noncontrolling interests is included in this measure.
Distributable cash flow is a significant performance metric used by the Partnership and by external users of the Partnership’s financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by the Partnership (prior to the establishment of any retained cash reserves by the board of directors of its general partner) to the cash distributions the Partnership expects to pay the Partnership’s unitholders. Using this metric, the Partnership’s management and external users of its financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important financial measure for the Partnership’s unitholders since it serves as an indicator of the Partnership’s success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Partnership is generating cash flow at a level that can sustain or support an increase in the Partnership’s quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder).
The GAAP measure most directly comparable to distributable cash flow is net income attributable to Targa Resources Partners LP. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Partners LP. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in the Partnership’s industry, our definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
The Partnership compensates for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision making processes.
Non-GAAP Financial Measures
The following tables reconcile the non-GAAP financial measures of the Partnership used by management to their most directly comparable GAAP measures for the periods indicated:
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2011
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2010
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2009
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|||||||||
|
Reconciliation of Targa Resources Partners LP
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(In millions)
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|||||||||||
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gross margin and operating margin to net income:
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Gross margin
|
$ | 948.1 | $ | 771.3 | $ | 710.9 | ||||||
|
Operating expenses
|
(287.0 | ) | (258.6 | ) | (234.4 | ) | ||||||
|
Operating margin
|
661.1 | 512.7 | 476.5 | |||||||||
|
Depreciation and amortization expenses
|
(178.2 | ) | (176.2 | ) | (166.7 | ) | ||||||
|
General and administrative expenses
|
(127.8 | ) | (122.4 | ) | (118.5 | ) | ||||||
|
Other operating income (loss)
|
- | 3.3 | 3.6 | |||||||||
|
Interest expense, net
|
(107.7 | ) | (110.8 | ) | (159.8 | ) | ||||||
|
Income tax expense
|
(4.3 | ) | (4.0 | ) | (1.2 | ) | ||||||
|
Gain (loss) on sale of assets
|
(0.2 | ) | - | - | ||||||||
|
Gain (loss) on debt repurchases
|
- | - | (1.5 | ) | ||||||||
|
Other, net (1)
|
2.6 | 31.4 | (25.2 | ) | ||||||||
|
Targa Resources Partners LP Net income
|
$ | 245.5 | $ | 134.0 | $ | 7.2 | ||||||
__________
|
(1)
|
Includes gain on mark-to-market derivatives, equity earnings, insurance claims, and other income (expense).
|
|
|
2011
|
2010
|
2009
|
|||||||||
|
Reconciliation of net cash provided by Targa Resources Partners LP
|
(In millions) | |||||||||||
|
operating activities to Adjusted EBITDA:
|
|
|
|
|||||||||
|
Net cash provided by (used in) operating activities
|
$ | 400.9 | $ | 367.9 | $ | 422.9 | ||||||
|
Net income attributable to noncontrolling interests
|
(41.0 | ) | (24.9 | ) | (19.3 | ) | ||||||
|
Interest expense, net (1)
|
95.3 | 74.8 | 48.2 | |||||||||
|
Gain (loss) on debt repurchases
|
- | - | (1.5 | ) | ||||||||
|
Current income tax expense
|
3.5 | 2.8 | 0.3 | |||||||||
|
Other (2)
|
7.9 | (11.4 | ) | (13.9 | ) | |||||||
|
Changes in operating assets and liabilities which used (provided) cash:
|
||||||||||||
|
Accounts receivable and other assets
|
150.3 | 71.2 | 57.0 | |||||||||
|
Accounts payable and other liabilities
|
(126.1 | ) | (84.3 | ) | (93.1 | ) | ||||||
|
Targa Resources Partners LP Adjusted EBITDA
|
$ | 490.8 | $ | 396.1 | $ | 400.6 | ||||||
|
(1)
|
Net of amortization of debt issuance costs, discount and premium included in interest expense of: $12.4 million for the year ended December 31, 2011; $6.6 million for the year ended December 31, 2010, and $3.9 million for the year ended December 31, 2009. Excludes affiliate and allocated interest expense.
|
|
(2)
|
Includes equity earnings net of distributions, accretion expense associated with asset retirement obligations, amortization of stock based compensation and gain (loss) on sale of assets.
|
|
|
2011
|
2010
|
2009
|
|||||||||
|
Reconciliation of net income attributable to
|
(In millions)
|
|||||||||||
|
Targa Resources Partners LP to Adjusted EBITDA:
|
|
|
|
|||||||||
|
Net income attributable to Targa Resources Partners LP
|
$ | 204.5 | $ | 109.1 | $ | (12.1 | ) | |||||
|
Add:
|
||||||||||||
|
Interest expense, net (1)
|
107.7 | 110.8 | 159.8 | |||||||||
|
Income tax expense
|
4.3 | 4.0 | 1.2 | |||||||||
|
Depreciation and amortization expenses
|
178.2 | 176.2 | 166.7 | |||||||||
|
Risk management activities
|
7.2 | 6.4 | 95.5 | |||||||||
|
Noncontrolling interests adjustment
|
(11.1 | ) | (10.4 | ) | (10.5 | ) | ||||||
|
Targa Resources Partners LP Adjusted EBITDA
|
$ | 490.8 | $ | 396.1 | $ | 400.6 | ||||||
________
|
(1)
|
Includes affiliate and allocated interest expense.
|
|
|
2011
|
2010
|
2009
|
|||||||||
|
Reconciliation of net income attributable to Targa
|
(In millions)
|
|||||||||||
|
Resources Partners LP to distributable cash flow:
|
|
|
|
|||||||||
|
Net income attributable to Targa Resources Partners LP
|
$ | 204.5 | $ | 109.1 | $ | (12.1 | ) | |||||
|
Affiliate and allocated interest expense
|
- | 29.4 | 107.7 | |||||||||
|
Depreciation and amortization expenses
|
178.2 | 176.2 | 166.7 | |||||||||
|
Deferred income tax expense
|
0.8 | 1.2 | 0.9 | |||||||||
|
Amortization in interest expense
|
12.4 | 6.1 | 3.9 | |||||||||
|
Loss (gain) on debt repurchases
|
- | - | 1.5 | |||||||||
|
Risk management activities
|
7.2 | 6.4 | 95.5 | |||||||||
|
Maintenance capital expenditures
|
(81.8 | ) | (50.4 | ) | (44.5 | ) | ||||||
|
Other (1)
|
15.4 | (1.0 | ) | (7.4 | ) | |||||||
|
Distributable cash flow
|
$ | 336.7 | $ | 277.0 | $ | 312.2 | ||||||
_______
|
(1)
|
Includes reimbursements of certain environmental maintenance capital expenditures by us and the noncontrolling interest portion of maintenance capital expenditures and depreciation expense.
|
Financial Information – Partnership versus Non-Partnership
As a supplement to the financial statements included in this 10-K, we present the following tables which segregate our consolidated balance sheet, results of operations and statement of cash flows between Partnership and Non-Partnership activities. Partnership results are presented on a common control accounting basis – the same basis reported in the Partnership’s Annual Report on Form 10-K (the “Partnership Form 10-K”). Except when otherwise noted, the remainder of this management’s discussion and analysis refers to these disaggregated results.
Balance Sheets – Partnership versus Non-Partnership
|
|
2011
|
2010
|
||||||||||||||||||||||
|
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
||||||||||||||||||
|
|
(In millions)
|
|||||||||||||||||||||||
|
ASSETS
|
|
|
|
|
|
|
||||||||||||||||||
|
Current assets:
|
|
|
|
|
|
|
||||||||||||||||||
|
Cash and cash equivalents (1)
|
$ | 145.8 | $ | 55.6 | $ | 90.2 | $ | 188.4 | $ | 76.3 | $ | 112.1 | ||||||||||||
|
Trade receivables, net
|
575.7 | 575.9 | (0.2 | ) | 466.6 | 466.1 | 0.5 | |||||||||||||||||
|
Inventory
|
92.2 | 92.1 | 0.1 | 50.4 | 50.3 | 0.1 | ||||||||||||||||||
|
Deferred income taxes (2)
|
0.1 | - | 0.1 | 3.6 | - | 3.6 | ||||||||||||||||||
|
Assets from risk management activities
|
41.0 | 41.0 | - | 25.2 | 25.2 | - | ||||||||||||||||||
|
Other current assets (1)
|
11.7 | 2.7 | 9.0 | 16.3 | 2.9 | 13.4 | ||||||||||||||||||
|
Total current assets
|
866.5 | 767.3 | 99.2 | 750.5 | 620.8 | 129.7 | ||||||||||||||||||
|
Property, plant and equipment, at cost (1)
|
3,821.1 | 3,786.9 | 34.2 | 3,331.4 | 3,299.5 | 31.9 | ||||||||||||||||||
|
Accumulated depreciation
|
(1,001.6 | ) | (980.8 | ) | (20.8 | ) | (822.4 | ) | (804.3 | ) | (18.1 | ) | ||||||||||||
|
Property, plant and equipment, net
|
2,819.5 | 2,806.1 | 13.4 | 2,509.0 | 2,495.2 | 13.8 | ||||||||||||||||||
|
Long-term assets from risk management activities
|
10.9 | 10.9 | - | 18.9 | 18.9 | - | ||||||||||||||||||
|
Other long-term assets (3)
|
134.1 | 73.7 | 60.4 | 115.4 | 51.5 | 63.9 | ||||||||||||||||||
|
Total assets
|
$ | 3,831.0 | $ | 3,658.0 | $ | 173.0 | $ | 3,393.8 | $ | 3,186.4 | $ | 207.4 | ||||||||||||
|
|
||||||||||||||||||||||||
|
LIABILITIES AND OWNERS' EQUITY
|
||||||||||||||||||||||||
|
Current liabilities:
|
||||||||||||||||||||||||
|
Accounts payable and accrued liabilities (4)
|
$ | 700.0 | $ | 647.8 | $ | 52.2 | $ | 590.0 | $ | 524.2 | $ | 65.8 | ||||||||||||
|
Affiliate payable (receivable) (5)
|
- | 60.0 | (60.0 | ) | - | 51.4 | (51.4 | ) | ||||||||||||||||
|
Liabilities from risk management activities
|
41.1 | 41.1 | - | 34.2 | 34.2 | - | ||||||||||||||||||
|
Total current liabilities
|
741.1 | 748.9 | (7.8 | ) | 624.2 | 609.8 | 14.4 | |||||||||||||||||
|
Long-term debt (6)
|
1,567.0 | 1,477.7 | 89.3 | 1,534.7 | 1,445.4 | 89.3 | ||||||||||||||||||
|
Long-term liabilities from risk management activities
|
15.8 | 15.8 | - | 32.8 | 32.8 | - | ||||||||||||||||||
|
Deferred income taxes (2)
|
120.5 | 9.5 | 111.0 | 111.6 | 8.7 | 102.9 | ||||||||||||||||||
|
Other long-term liabilities (7)
|
55.9 | 44.4 | 11.5 | 54.4 | 40.6 | 13.8 | ||||||||||||||||||
|
Total liabilities
|
2,500.3 | 2,296.3 | 204.0 | 2,357.7 | 2,137.3 | 220.4 | ||||||||||||||||||
|
Total owners' equity
|
1,330.7 | 1,361.7 | (31.0 | ) | 1,036.1 | 1,049.1 | (13.0 | ) | ||||||||||||||||
|
Total liabilities and owners' equity
|
$ | 3,831.0 | $ | 3,658.0 | $ | 173.0 | $ | 3,393.8 | $ | 3,186.4 | $ | 207.4 | ||||||||||||
_________
The major Non-Partnership balance sheet items relate to:
|
(1)
|
Corporate assets consisting of cash, administrative property and equipment, and prepaid insurance.
|
|
(2)
|
Current and long-term deferred income tax balances.
|
|
(3)
|
Long-term tax assets primarily related to gains on 2010 drop down transactions recognized as sales of assets for tax purposes.
|
|
(4)
|
Accrued current employee liabilities related to payroll and incentive compensation plans and taxes payable.
|
|
(5)
|
Intercompany receivable with the Partnership related to the ongoing execution of the Omnibus Agreement.
|
|
(6)
|
Long-term debt obligations of TRC and TRI.
|
|
(7)
|
Long-term liabilities related to incentive compensation plans and deferred rent related to the headquarters office lease.
|
Results of Operations – Partnership versus Non-Partnership
|
|
2011
|
2010
|
2009
|
|||||||||||||||||||||||||
|
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
|||||||||||||||||||
|
|
(In millions)
|
|||||||||||||||||||||||||||
|
Revenues (1)
|
$ | 6,994.5 | $ | 6,987.1 | $ | 7.4 | $ | 5,476.1 | $ | 5,467.0 | $ | 9.1 | $ | 4,542.3 | $ | 4,510.2 | $ | 32.1 | ||||||||||
|
Costs and Expenses:
|
||||||||||||||||||||||||||||
|
Product purchases
|
6,039.0 | 6,039.0 | - | 4,695.5 | 4,695.7 | (0.2 | ) | 3,797.4 | 3,799.3 | (1.9 | ) | |||||||||||||||||
|
Operating expenses
|
287.1 | 287.0 | 0.1 | 259.3 | 258.6 | 0.7 | 235.0 | 234.4 | 0.6 | |||||||||||||||||||
|
Depreciation and amortization (2)
|
181.0 | 178.2 | 2.8 | 185.5 | 176.2 | 9.3 | 170.3 | 166.7 | 3.6 | |||||||||||||||||||
|
General and administrative (3)
|
136.1 | 127.8 | 8.3 | 144.4 | 122.4 | 22.0 | 120.4 | 118.5 | 1.9 | |||||||||||||||||||
|
Other
|
0.2 | 0.2 | - | (4.7 | ) | (3.3 | ) | (1.4 | ) | 2.0 | (3.6 | ) | 5.6 | |||||||||||||||
|
Income from operations
|
351.1 | 354.9 | (3.8 | ) | 196.1 | 217.4 | (21.3 | ) | 217.2 | 194.9 | 22.3 | |||||||||||||||||
|
Other income (expense):
|
||||||||||||||||||||||||||||
|
Interest expense, net - third party (4)
|
(111.7 | ) | (107.7 | ) | (4.0 | ) | (110.9 | ) | (81.4 | ) | (29.5 | ) | (132.1 | ) | (52.1 | ) | (80.0 | ) | ||||||||||
|
Interest expense - intercompany (5)
|
- | - | - | - | (29.4 | ) | 29.4 | - | (107.7 | ) | 107.7 | |||||||||||||||||
|
Equity earnings
|
8.8 | 8.8 | - | 5.4 | 5.4 | - | 5.0 | 5.0 | - | |||||||||||||||||||
|
Loss on debt repurchases (4)
|
- | - | - | (17.4 | ) | - | (17.4 | ) | (1.5 | ) | (1.5 | ) | - | |||||||||||||||
|
Gain on early debt extinguishment (4)
|
- | - | - | 12.5 | - | 12.5 | 9.7 | - | 9.7 | |||||||||||||||||||
|
Gain (loss) on mark-to-market derivative instruments
|
(5.0 | ) | (5.0 | ) | - | (0.4 | ) | 26.0 | (26.4 | ) | 0.3 | (30.9 | ) | 31.2 | ||||||||||||||
|
Other income (expense)
|
(1.2 | ) | (1.2 | ) | - | 0.5 | - | 0.5 | 1.2 | 0.7 | 0.5 | |||||||||||||||||
|
Income before income taxes
|
242.0 | 249.8 | (7.8 | ) | 85.8 | 138.0 | (52.2 | ) | 99.8 | 8.4 | 91.4 | |||||||||||||||||
|
Income tax expense
|
(26.6 | ) | (4.3 | ) | (22.3 | ) | (22.5 | ) | (4.0 | ) | (18.5 | ) | (20.7 | ) | (1.2 | ) | (19.5 | ) | ||||||||||
|
Net income (loss)
|
215.4 | 245.5 | (30.1 | ) | 63.3 | 134.0 | (70.7 | ) | 79.1 | 7.2 | 71.9 | |||||||||||||||||
|
Less: Net income attributable to noncontrolling interests (6)
|
184.7 | 41.0 | 143.7 | 78.3 | 24.9 | 53.4 | 49.8 | 19.3 | 30.5 | |||||||||||||||||||
|
Net income (loss) after noncontrolling interests
|
$ | 30.7 | $ | 204.5 | $ | (173.8 | ) | $ | (15.0 | ) | $ | 109.1 | $ | (124.1 | ) | $ | 29.3 | $ | (12.1 | ) | $ | 41.4 | ||||||
_________
The major Non-Partnership results of operations relate to:
|
(1)
|
Business interruption revenues of $3.0 million, $6.0 million and $21.5 million for the years ended December 31, 2011, 2010, and 2009 and amortization of OCI related to Versado hedges dropped down to the Partnership, and OCI related to terminated hedges.
|
|
(2)
|
Depreciation on assets excluded from drop down transactions and corporate administrative assets.
|
|
(3)
|
General and administrative expenses retained by TRC, related to its status as a public entity.
|
|
(4)
|
Interest expense and other gains and losses related to TRC and TRI debt obligations.
|
|
(5)
|
Interest on pre-drop down intercompany debt obligations.
|
|
(6)
|
TRC noncontrolling interest in the Partnership.
|
Statements of Cash Flows – Partnership versus Non-Partnership
|
|
2011
|
2010
|
2009
|
||||||||||||||||||||||||
|
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
||||||||||||||||||
|
Cash flows from operating activities
|
(In millions)
|
||||||||||||||||||||||||||
|
Net income (loss)
|
$ | 215.4 | $ | 245.5 | $ | (30.1 | ) | $ | 63.3 | $ | 134.0 | $ | (70.7 | ) | $ | 79.1 | $ | 7.2 | $ | 71.9 | |||||||
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|||||||||||||||||||||||||||
|
Amortization in interest expense
|
13.0 | 12.4 | 0.6 | 9.4 | 6.6 | 2.8 | 10.2 | 3.9 | 6.3 | ||||||||||||||||||
|
Paid-in-kind interest expense
|
- | - | - | 10.9 | - | 10.9 | 25.9 | - | 25.9 | ||||||||||||||||||
|
Compensation on equity grants
|
15.2 | 1.5 | 13.7 | 13.4 | 0.4 | 13.0 | 0.7 | 0.3 | 0.4 | ||||||||||||||||||
|
Interest expense on affiliate and allocated indebtedness (1)
|
- | - | - | - | 29.4 | (29.4 | ) | - | 107.7 | (107.7 | ) | ||||||||||||||||
|
Depreciation and amortization expense (2)
|
181.0 | 178.2 | 2.8 | 174.7 | 171.3 | 3.4 | 168.8 | 165.2 | 3.6 | ||||||||||||||||||
|
Asset impairment charges
|
- | - | - | 10.8 | 4.9 | 5.9 | 1.5 | 1.5 | - | ||||||||||||||||||
|
Accretion of asset retirement obligations
|
3.6 | 3.6 | - | 3.2 | 3.2 | - | 2.9 | 2.9 | - | ||||||||||||||||||
|
Deferred income tax expense
|
12.3 | 0.8 | 11.5 | 33.1 | 1.2 | 31.9 | 19.1 | 0.9 | 18.2 | ||||||||||||||||||
|
Equity earnings, net of distributions (3)
|
(0.4 | ) | (0.4 | ) | - | - | - | - | - | - | - | ||||||||||||||||
|
Risk management activities (4)
|
(21.2 | ) | (16.7 | ) | (4.5 | ) | 29.9 | 3.8 | 26.1 | 40.3 | 95.6 | (55.3 | ) | ||||||||||||||
|
Loss (gain) on sale of assets
|
0.2 | 0.2 | - | (1.5 | ) | - | (1.5 | ) | 0.1 | 1.5 | (1.4 | ) | |||||||||||||||
|
Gain on debt repurchases
|
- | - | - | 17.4 | - | 17.4 | 1.5 | 0.1 | 1.4 | ||||||||||||||||||
|
Loss on early debt extinguishment
|
- | - | - | (12.5 | ) | - | (12.5 | ) | (9.7 | ) | - | (9.7 | ) | ||||||||||||||
|
Payments of interest on Holdco loan facility
|
- | - | - | (0.9 | ) | - | (0.9 | ) | (6.0 | ) | - | (6.0 | ) | ||||||||||||||
|
Changes in operating assets and liabilities: (5)
|
(39.8 | ) | (24.2 | ) | (15.6 | ) | (146.0 | ) | 13.1 | (159.1 | ) | 1.4 | 36.1 | (34.7 | ) | ||||||||||||
|
Net cash provided by (used in) operating activities
|
379.3 | 400.9 | (21.6 | ) | 205.2 | 367.9 | (162.7 | ) | 335.8 | 422.9 | (87.1 | ) | |||||||||||||||
|
Cash flows from investing activities
|
|||||||||||||||||||||||||||
|
Outlays for property, plant and equipment (2)
|
(331.9 | ) | (328.7 | ) | (3.2 | ) | (139.3 | ) | (137.0 | ) | (2.3 | ) | (99.4 | ) | (95.9 | ) | (3.5 | ) | |||||||||
|
Business acquisitions
|
(156.5 | ) | (156.5 | ) | - | - | - | - | - | - | - | ||||||||||||||||
|
Investment in unconsolidated affiliate
|
(21.2 | ) | (21.2 | ) | - | - | - | - | - | - | - | ||||||||||||||||
|
Return of capital from unconsolidated affiliate (3)
|
- | - | - | 3.3 | 3.3 | - | - | - | - | ||||||||||||||||||
|
Other
|
0.3 | 0.3 | - | 4.7 | 2.1 | 2.6 | 40.1 | 1.3 | 38.8 | ||||||||||||||||||
|
Net cash provided by (used in) investing activities
|
(509.3 | ) | (506.1 | ) | (3.2 | ) | (131.3 | ) | (131.6 | ) | 0.3 | (59.3 | ) | (94.6 | ) | 35.3 | |||||||||||
|
Cash flows from financing activities
|
|||||||||||||||||||||||||||
|
Loan Facilities of the Partnership:
|
|||||||||||||||||||||||||||
|
Borrowings
|
2,112.0 | 2,112.0 | - | 1,593.1 | 1,593.1 | - | 806.6 | 806.6 | - | ||||||||||||||||||
|
Repayments
|
(2,082.0 | ) | (2,082.0 | ) | - | (1,057.0 | ) | (1,057.0 | ) | - | (596.6 | ) | (596.6 | ) | - | ||||||||||||
|
Repayment of affiliated indebtedness (1)
|
- | - | - | - | (737.7 | ) | 737.7 | - | (397.5 | ) | 397.5 | ||||||||||||||||
|
Loan Facilities- Non-Partnership:
|
|||||||||||||||||||||||||||
|
Borrowings (6)
|
- | - | - | 495.0 | - | 495.0 | - | - | - | ||||||||||||||||||
|
Repayments (6)
|
- | - | - | (1,087.4 | ) | - | (1,087.4 | ) | (589.2 | ) | - | (589.2 | ) | ||||||||||||||
|
Proceeds from sale of common units of the Partnership
|
- | - | - | 224.4 | - | 224.4 | - | - | - | ||||||||||||||||||
|
Partnership equity transactions (7)
|
298.0 | 304.1 | (6.1 | ) | 317.8 | 317.8 | - | 103.8 | 103.1 | 0.7 | |||||||||||||||||
| Noncontrolling interest contributions (distributions) (8) | (196.2 | ) | (256.6 | ) | 60.4 | (136.9 | ) | (138.1 | ) | 46.2 | (98.5 | ) | (136.9 | ) | 38.4 | ||||||||||||
|
Capital contributions (distributions)
|
- | 13.2 | (13.2 | ) | - | (95.7 | ) | 95.7 | - | (149.7 | ) | 149.7 | |||||||||||||||
|
Distributions under common control
|
- | - | - | - | (68.1 | ) | 68.1 | - | - | - | |||||||||||||||||
|
Repurchases of common stock
|
- | - | - | (0.1 | ) | - | (0.1 | ) | - | - | - | ||||||||||||||||
|
Stock options exercised
|
- | - | - | 0.9 | - | 0.9 | 0.3 | - | 0.3 | ||||||||||||||||||
|
Dividends to common and common equivalent shareholders
|
(38.2 | ) | - | (38.2 | ) | (210.1 | ) | - | (210.1 | ) | - | - | - | ||||||||||||||
|
Dividends to preferred shareholders
|
- | - | - | (238.0 | ) | - | (238.0 | ) | - | - | - | ||||||||||||||||
|
Costs incurred in connection with financing arrangements (6)
|
(6.2 | ) | (6.2 | ) | - | (39.6 | ) | (20.2 | ) | (19.4 | ) | (13.3 | ) | (9.6 | ) | (3.7 | ) | ||||||||||
|
Net cash provided by (used in) financing activities
|
87.4 | 84.5 | 2.9 | (137.9 | ) | (250.9 | ) | 113.0 | (386.9 | ) | (380.6 | ) | (6.3 | ) | |||||||||||||
|
Net change in cash and cash equivalents
|
(42.6 | ) | (20.7 | ) | (21.9 | ) | (64.0 | ) | (14.6 | ) | (49.4 | ) | (110.4 | ) | (52.3 | ) | (58.1 | ) | |||||||||
|
Cash and cash equivalents, beginning of period
|
188.4 | 76.3 | 112.1 | 252.4 | 90.9 | 161.5 | 362.8 | 143.2 | 219.6 | ||||||||||||||||||
|
Cash and cash equivalents, end of period
|
$ | 145.8 | $ | 55.6 | $ | 90.2 | $ | 188.4 | $ | 76.3 | $ | 112.1 | $ | 252.4 | $ | 90.9 | $ | 161.5 | |||||||||
_________
The major Non-Partnership cash flow items relate to:
|
(1)
|
Affiliated indebtedness that was settled in drop down transactions.
|
|
(2)
|
Cash and non-cash activity related to corporate administrative assets.
|
|
(3)
|
Pursuant to the Purchase and Sale Agreement of the Downstream Business acquisition, we were entitled to receive GCF distributions of $2.3 million in both 2010 and 2009.
|
|
(4)
|
Non-cash OCI hedge realizations related to predecessor operations.
|
|
(5)
|
See Balance Sheet – Partnership versus Non-Partnership for a description of the Non-Partnership operating assets and liabilities.
|
|
(6)
|
Cash activity related to TRC and TRI debt obligations.
|
|
(7)
|
Contribution to the Partnership to maintain our 2% general partner interest.
|
|
(8)
|
Cash distributions received by TRC for its general partners and limited partner interests and IDRs in the Partnership.
|
Consolidated Results of Operations
The following table and discussion is a summary of our consolidated results of operations for the year ended December 31, 2011, 2010 and 2009 (in millions, except operating statistics and price amounts):
|
Variance
|
||||||||||||||||||||||||||||
|
2011
|
2010
|
2009
|
2011 vs. 2010
|
2010 vs. 2009
|
||||||||||||||||||||||||
|
Revenues
|
$ | 6,994.5 | $ | 5,476.1 | $ | 4,542.3 | $ | 1,518.4 | 28% | $ | 933.8 | 21% | ||||||||||||||||
|
Product purchases
|
6,039.0 | 4,695.5 | 3,797.4 | 1,343.5 | 29% | 898.1 | 24% | |||||||||||||||||||||
|
Gross margin (1)
|
955.5 | 780.6 | 744.9 | 174.9 | 22% | 35.7 | 5% | |||||||||||||||||||||
|
Operating expenses
|
287.1 | 259.3 | 235.0 | 27.8 | 11% | 24.3 | 10% | |||||||||||||||||||||
|
Operating margin (2)
|
668.4 | 521.3 | 509.9 | 147.1 | 28% | 11.4 | 2% | |||||||||||||||||||||
|
Depreciation and amortization expenses
|
181.0 | 185.5 | 170.3 | (4.5 | ) | (2% | ) | 15.2 | 9% | |||||||||||||||||||
|
General and administrative expenses
|
136.1 | 144.4 | 120.4 | (8.3 | ) | (6% | ) | 24.0 | 20% | |||||||||||||||||||
|
Other
|
0.2 | (4.7 | ) | 2.0 | 4.9 | (104% | ) | (6.7 | ) | (335% | ) | |||||||||||||||||
|
Income from operations
|
351.1 | 196.1 | 217.2 | 155.0 | 79% | (21.1 | ) | (10% | ) | |||||||||||||||||||
|
Interest expense, net
|
(111.7 | ) | (110.9 | ) | (132.1 | ) | (0.8 | ) | 1% | 21.2 | (16% | ) | ||||||||||||||||
|
Equity earnings
|
8.8 | 5.4 | 5.0 | 3.4 | 63% | 0.4 | 8% | |||||||||||||||||||||
|
Loss on debt repurchases
|
- | (17.4 | ) | (1.5 | ) | 17.4 | (100% | ) | (15.9 | ) | 1,060% | |||||||||||||||||
|
Gain on early debt extinguishment, net
|
- | 12.5 | 9.7 | (12.5 | ) | (100% | ) | 2.8 | 29% | |||||||||||||||||||
|
Loss on mark-to-market derivative instruments
|
(5.0 | ) | (0.4 | ) | 0.3 | (4.6 | ) | 1,150% | (0.7 | ) | (233% | ) | ||||||||||||||||
|
Other
|
(1.2 | ) | 0.5 | 1.2 | (1.7 | ) | (340% | ) | (0.7 | ) | (58% | ) | ||||||||||||||||
|
Income tax expense
|
(26.6 | ) | (22.5 | ) | (20.7 | ) | (4.1 | ) | 18% | (1.8 | ) | 9% | ||||||||||||||||
|
Net income
|
215.4 | 63.3 | 79.1 | 152.1 | 240% | (15.8 | ) | (20% | ) | |||||||||||||||||||
|
Less: Net income attributable to noncontrolling interests
|
184.7 | 78.3 | 49.8 | 106.4 | 136% | 28.5 | 57% | |||||||||||||||||||||
|
Net income (loss) attributable to Targa Resources Corp.
|
30.7 | (15.0 | ) | 29.3 | 45.7 | (305% | ) | (44.3 | ) | (151% | ) | |||||||||||||||||
|
Less:
|
||||||||||||||||||||||||||||
|
Dividends on Series B preferred stock
|
- | (9.5 | ) | (17.8 | ) | 9.5 | (100% | ) | 8.3 | (47% | ) | |||||||||||||||||
|
Undistributed earnings attributable to preferred shareholders
|
- | - | (11.5 | ) | - | 0% | 11.5 | (100% | ) | |||||||||||||||||||
|
Dividends to common equivalents
|
- | (177.8 | ) | - | 177.8 | (100% | ) | (177.8 | ) | 0% | ||||||||||||||||||
|
Net income (loss) available to common shareholders
|
$ | 30.7 | $ | (202.3 | ) | $ | - | $ | 233.0 | (115% | ) | $ | (202.3 | ) | 0% | |||||||||||||
|
Operating statistics:
|
||||||||||||||||||||||||||||
|
Plant natural gas inlet, MMcf/d (3) (4)
|
2,162.1 | 2,268.0 | 2,139.8 | (105.9 | ) | (5% | ) | 128.2 | 6% | |||||||||||||||||||
|
Gross NGL production, MBbl/d
|
123.9 | 121.2 | 118.3 | 2.7 | 2% | 2.9 | 2% | |||||||||||||||||||||
|
Natural gas sales, BBtu/d (4)
|
779.3 | 685.8 | 598.4 | 93.5 | 14% | 87.4 | 15% | |||||||||||||||||||||
|
NGL sales, MBbl/d
|
269.6 | 251.5 | 279.7 | 18.1 | 7% | (28.2 | ) | (10% | ) | |||||||||||||||||||
|
Condensate sales, MBbl/d
|
3.0 | 3.5 | 4.7 | (0.5 | ) | (14% | ) | (1.2 | ) | (26% | ) | |||||||||||||||||
_________
|
(1)
|
Gross margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate the Partnership’s Operations.”
|
|
(2)
|
Operating margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate the Partnership’s Operations.”
|
|
(3)
|
Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a gas processing plant.
|
|
(4)
|
Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.
|
2011 Compared to 2010
Revenues (including the impacts of hedging) increased due to the net impact of higher realized prices on NGLs and condensate ($1,077.2 million), higher NGL and natural gas sales volumes ($488.4 million) and higher fee-based and other revenues ($80.7 million), offset by lower realized prices on natural gas ($116.8 million) and lower condensate sales volumes ($11.1 million).
The $174.9 million increase in gross margin reflects higher revenues ($1,518.4 million) offset by higher product purchase costs ($1,343.5 million). For additional information regarding the period to period changes in our gross margins see “– Results of Operations – By Segment.”
The $27.8 million increase in operating expenses was primarily attributable to increased compensation and benefit expenses ($7.4 million), increased maintenance, utility and catalyst costs ($16.0 million). See “– Results of Operations – By Segment” for additional discussion regarding changes in operating expenses.
The decrease in depreciation and amortization expenses of $4.5 million was driven by an impairment charge in 2010 ($10.8 million) related to idled terminal and processing assets, plus assets that became fully depreciated in 2010 ($2.2 million). Partially offsetting these factors were: (1) depreciation on assets and expansions that were placed in service during 2010 and had a full year of expense in 2011 ($4.1 million); (2) the impact of Petroleum Logistics acquisitions in 2011 ($2.0 million); and (3) expansion projects that went online during 2011 ($4.4 million).
General and administrative expenses decreased $8.3 million, primarily due to lower professional service fees in 2011, as compared to 2010, when we incurred professional fees associated with our IPO and drop-down transactions.
Interest expense was essentially flat as higher interest expense ($26.3 million) from an increase in third-party debt obligations of the Partnership was offset by lower interest expense ($25.5 million) from a reduction in our outstanding borrowings. See “—Liquidity and Capital Resources” for information regarding our and the Partnership’s outstanding debt obligations.
The increase in loss on mark-to-market derivative instruments ($4.6 million) is attributable to a portion of interest rate swaps that no longer qualified for hedge accounting treatment as of February 11, 2011.
At December 31, 2011 our ownership in the Partnership was 16.5% versus 17.1% at year-end 2010. After adjusting for the impact of the incentive distribution rights, our weighted average percentages of the net income of the Partnership were 29.8% in 2011 and 35.5% in 2010. The dilution of our earnings of the Partnership is a result of our sale of common units in April 2010 (6%). This impact was partially offset by issuance of common units to us associated with the assets dropped down to the Partnership, which were also offset by an increasing share of earnings from our ownership of the IDR’s (1%) due to increased distributions from the Partnership. Additionally, $16.1 million of the increase was due to increased net income subject to noncontrolling interest for CBF, Versado and VESCO.
2010 Compared to 2009
Revenues (including the impacts of hedging) increased due to higher realized commodity prices ($1,194.1 million) and natural gas sales volumes ($125.4 million) offset by lower NGL and condensate sales volumes ($365.5 million), lower business interruption insurance proceeds ($15.5 million) and lower fee-based and other revenues ($4.6 million).
The $35.7 million increase in gross margin reflects higher revenues ($933.8 million) offset by higher product purchase costs ($898.1 million). For additional information regarding the period to period changes in our gross margins, see “— Results of Operations —By Segment.”
The $24.3 million increase in operating expenses was primarily attributable to increased compensation and benefits expense ($14.6 million), increased maintenance costs and utility costs of ($14.5 million), partially offset by lower contract services and professional fees of $6.1 million. See “— Results of Operations—By Segment” for additional discussion regarding changes in operating expenses.
The increase in depreciation and amortization expenses of $15.2 million was attributable to a $13.0 million impairment charge related to idled terminal and processing assets as well as assets acquired in 2009 that have a full period of depreciation in 2010 and expansion projects that went online in 2010 ($3.7 million) offset by assets that became fully depreciated in 2009 ($1.5 million).
General and administrative expenses increased $24.0 million reflecting increased professional services, compensation and transactional costs related to our December IPO and drop down transactions.
Other operating items were an overall gain of $4.7 million during 2010 versus an overall loss of $2.0 million during 2009. This improvement primarily reflects lower project abandonment costs during 2010. Both years included income related to favorable hurricane reserve adjustments due to lower than expected hurricane repair outlays and higher than expected insurance recoveries.
The decrease in interest expense of $21.2 million is due to reductions in our total outstanding indebtedness primarily funded by equity issuances by the Partnership. See “— Liquidity and Capital Resources” for information regarding our outstanding debt obligations.
The effects of an overall net loss on debt retirements lowered pre-tax earnings by $13.1 million.
Net income subject to noncontrolling interest for the Partnership increased in 2010, primarily due to the impact of the full year ownership of the Downstream Business by the Partnership, as well as the partial year impact of the 2010 dropdowns of assets into the Partnership. In addition, our ownership interest in the Partnership decreased in 2010 due to the impact of the secondary sales of our units to the public in April 2010, as well as the Partnership’s sales of common units in January and August 2010. At December 31, 2010 our ownership in the Partnership was 17.1% versus 33.9% at year-end 2009. After adjusting for the impact of the incentive distribution rights, our weighted average percentages of net income were 35.5% in 2010 and 40.5% in 2009. In addition, $5.5 million of the increase was due to increased net income subject to noncontrolling interest for CBF, Versado and VESCO.
Dividends were paid to our Series B Preferred shareholders in April 2010, November 2010 and December 2010, which reduced the accretive value of these shares. At our IPO, the outstanding Series B Preferred shares converted to common shares.
Results of Operations—By Reportable Segment
We have segregated the following segment operating margins between Partnership and TRC Non-Partnership activities. Partnership activities have been presented on a common control accounting basis which reflects the dropdown transactions between Targa and the Partnership as if they occurred in prior periods. TRC Non-Partnership segment results include certain assets and liabilities contractually excluded from the dropdown transactions and certain historical hedge activities that could not be reflected as such under GAAP in the Partnership common control results. See “—Financial Information – Partnership Versus Non-Partnership.”
|
Partnership
|
||||||||||||||||||||||||||||
|
Field Gathering and Processing
|
Coastal Gathering and Processing
|
Logistics Assets
|
Marketing and Distribution
|
Other
|
TRC Non- Partnership
|
Consolidated Operating Margin
|
||||||||||||||||||||||
|
(In millions)
|
||||||||||||||||||||||||||||
|
2011
|
$ | 287.9 | $ | 174.3 | $ | 123.1 | $ | 113.4 | $ | (37.6 | ) | $ | 7.3 | $ | 668.4 | |||||||||||||
|
2010
|
236.6 | 107.8 | 83.8 | 80.5 | 4.0 | 8.6 | 521.3 | |||||||||||||||||||||
|
2009
|
183.2 | 89.7 | 74.3 | 83.0 | 46.3 | 33.4 | 509.9 | |||||||||||||||||||||
Results of Operations of the Partnership – By Reportable Segment
Natural Gas Gathering and Processing Segments
Field Gathering and Processing
|
|
2011
|
2010
|
2009
|
2011 vs. 2010
|
2010 vs. 2009
|
|||||||||||||||||||||||
|
|
($ in millions)
|
|||||||||||||||||||||||||||
|
Gross margin
|
$ | 403.6 | $ | 338.8 | $ | 268.3 | $ | 64.8 | 19% | $ | 70.5 | 26% | ||||||||||||||||
|
Operating expenses
|
115.7 | 102.2 | 85.1 | 13.5 | 13% | 17.1 | 20% | |||||||||||||||||||||
|
Operating margin
|
$ | 287.9 | $ | 236.6 | $ | 183.2 | $ | 51.3 | 22% | $ | 53.4 | 29% | ||||||||||||||||
|
Operating statistics:
|
||||||||||||||||||||||||||||
|
Plant natural gas inlet, MMcf/d (1),(2)
|
611.5 | 587.7 | 581.9 | 23.8 | 4% | 5.8 | 1% | |||||||||||||||||||||
|
Gross NGL production, MBbl/d
|
74.2 | 71.2 | 69.8 | 3.0 | 4% | 1.4 | 2% | |||||||||||||||||||||
|
Natural gas sales, BBtu/d (2),(3)
|
285.5 | 258.6 | 242.7 | 26.9 | 10% | 15.9 | 7% | |||||||||||||||||||||
|
NGL sales, MBbl/d (3)
|
59.8 | 56.6 | 56.2 | 3.2 | 6% | 0.4 | 1% | |||||||||||||||||||||
|
Condensate sales, MBbl/d (3)
|
2.8 | 2.9 | 3.2 | (0.1 | ) | (3% | ) | (0.3 | ) | (9% | ) | |||||||||||||||||
|
Average realized prices (4):
|
||||||||||||||||||||||||||||
|
Natural gas, $/MMBtu
|
3.80 | 4.09 | 3.33 | (0.29 | ) | (7% | ) | 0.76 | 23% | |||||||||||||||||||
|
NGL, $/gal
|
1.23 | 0.93 | 0.69 | 0.30 | 32% | 0.24 | 35% | |||||||||||||||||||||
|
Condensate, $/Bbl
|
91.55 | 75.48 | 55.84 | 16.07 | 21% | 19.64 | 35% | |||||||||||||||||||||
________
|
(1)
|
Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.
|
|
(2)
|
Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.
|
|
(3)
|
Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
|
|
(4)
|
Average realized prices exclude the impact of hedging activities.
|
2011 Compared to 2010
The increase in gross margin for 2011 was primarily due to higher NGL and condensate sales prices ($290.9 million), higher natural gas and NGL volumes ($85.9 million) and higher fee-based and other revenues ($4.0 million), partially offset by higher product purchases ($281.2 million), lower natural gas sales prices ($30.9 million), and lower condensate sales volumes ($3.8 million). The increase in plant inlet volumes was largely attributable to new well connects, particularly at North Texas and SAOU. These factors were partially offset by the impact of severe cold weather, operational outages in 2011 and production declines at our Versado system. Natural gas sales increased on higher throughput and a decrease in take-in-kind volumes.
The increase in operating expenses was primarily due to higher fuel, utilities and catalysts expenses ($4.1 million), higher system maintenance expenses ($3.4 million) driven by severe cold weather and operational outages in 2011, higher compensation and benefit costs ($3.4 million) and higher contract and professional service expenses ($2.4 million).
2010 Compared to 2009
The increase in gross margin was primarily due to higher commodity sales prices ($302.0 million), higher natural gas and NGL sales volumes ($22.5 million), and higher fee-based and other revenue ($6.5 million) partially offset by higher product purchases ($253.6 million) and lower condensate sales volumes ($6.8 million). The increased natural gas and NGL sales volumes were due primarily to higher natural gas and NGL production.
The increase in operating expenses was primarily due to higher system maintenance expenses ($8.2 million), higher compensation and benefit costs ($4.7 million), higher contract and professional services ($2.0 million) and higher utilities, power and catalysts costs ($1.3 million).
Coastal Gathering and Processing
|
|
2011
|
2010
|
2009
|
2011 vs. 2010
|
2010 vs. 2009
|
|||||||||||||||||||||||
|
|
($ in millions)
|
|||||||||||||||||||||||||||
|
Gross margin
|
$ | 221.6 | $ | 151.2 | $ | 132.6 | $ | 70.4 | 47% | $ | 18.6 | 14% | ||||||||||||||||
|
Operating expenses
|
47.3 | 43.4 | 42.9 | 3.9 | 9% | 0.5 | 1% | |||||||||||||||||||||
|
Operating margin
|
$ | 174.3 | $ | 107.8 | $ | 89.7 | $ | 66.5 | 62% | $ | 18.1 | 20% | ||||||||||||||||
|
Operating statistics:
|
||||||||||||||||||||||||||||
|
Plant natural gas inlet, MMcf/d (1),(2),(3)
|
1,550.6 | 1,680.3 | 1,557.8 | (129.7 | ) | (8% | ) | 122.5 | 8% | |||||||||||||||||||
|
Gross NGL production, MBbl/d
|
49.8 | 50.1 | 48.5 | (0.3 | ) | (1% | ) | 1.6 | 3% | |||||||||||||||||||
|
Natural gas sales, BBtu/d (3),(4)
|
268.4 | 294.2 | 258.9 | (25.8 | ) | (9% | ) | 35.3 | 14% | |||||||||||||||||||
|
NGL sales, MBbl/d (4)
|
43.5 | 43.7 | 40.6 | (0.2 | ) |
(%)
|
3.1 | 8% | ||||||||||||||||||||
|
Condensate sales, MBbl/d (4)
|
0.3 | 0.5 | 1.6 | (0.2 | ) | (40% | ) | (1.1 | ) | (69% | ) | |||||||||||||||||
|
Average realized prices (5):
|
||||||||||||||||||||||||||||
|
Natural gas, $/MMBtu
|
4.02 | 4.48 | 4.00 | (0.46 | ) | (10% | ) | 0.48 | 12% | |||||||||||||||||||
|
NGL, $/gal
|
1.31 | 1.03 | 0.77 | 0.28 | 27% | 0.26 | 34% | |||||||||||||||||||||
|
Condensate, $/Bbl
|
105.10 | 78.82 | 53.31 | 26.28 | 33% | 25.51 | 48% | |||||||||||||||||||||
__________
|
(1)
|
Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.
|
|
(2)
|
The majority of our Coastal Straddle plant volumes are gathered on third-party offshore pipeline systems and delivered to the plant inlets.
|
|
(3)
|
Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.
|
|
(4)
|
Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation.
|
|
(5)
|
Average realized prices exclude the impact of hedging activities.
|
2011 Compared to 2010
The increase in gross margin is primarily attributable to higher NGL and condensate sales prices, favorable frac spread as a result of low gas prices relative to NGLs and crude oil, a significant increase in higher GPM keep-whole volumes at VESCO and Lowry and higher system average GPM at LOU, largely due to increased traditional wellhead volumes. The decrease in plant inlet volumes was largely attributable to a decline in other offshore and off-system supply volumes. Despite the lower inlet volumes, NGL production and sales volumes remained relatively flat as a result of the above-mentioned higher GPM gas and the optimization of throughput to more efficient, higher recovery plants. Natural gas sales volumes decreased due to lower demand from industrial customers and lower sales to other reportable segments for resale.
The increase in operating expenses was primarily due to higher contract and professional service expenses ($0.9 million), higher miscellaneous and other expenses ($1.6 million), higher operating expenses on non-operated joint ventures ($0.6 million) and a decrease in recovery of expenses from an operated joint venture ($0.9 million).
2010 Compared to 2009
The increase in gross margin was primarily due to an increase in commodity sales prices ($230.4 million) and an increase in natural gas and NGL sales volumes ($88.6 million), partially offset by an increase in product purchases ($266.8 million), a decrease in condensate sales volumes ($21.8 million), a decrease in revenue from business interruption insurance ($10.9 million) and a decrease in fee-based and other revenue ($0.9 million). Natural gas sales volumes increased due to increased sales to other reportable segments for resale partially offset by a small decrease in demand from industrial customers. NGL, natural gas and inlet sales volumes increased primarily because the straddle plants were recovering operations in the first two quarters of 2009 after Hurricanes Gustav and Ike disrupted operations in 2008.
Operating expenses were flat.
Logistics and Marketing Segments
Logistics Assets
|
|
2011
|
2010
|
2009
|
2011 vs. 2010
|
2010 vs. 2009
|
|||||||||||||||||||||||
|
|
($ in millions)
|
|||||||||||||||||||||||||||
|
Gross margin
|
$ | 221.1 | $ | 171.4 | $ | 156.2 | $ | 49.7 | 29% | $ | 15.2 | 10% | ||||||||||||||||
|
Operating expenses
|
98.0 | 87.6 | 81.9 | 10.4 | 12% | 5.7 | 7% | |||||||||||||||||||||
|
Operating margin
|
$ | 123.1 | $ | 83.8 | $ | 74.3 | $ | 39.3 | 47% | $ | 9.5 | 13% | ||||||||||||||||
|
Operating statistics: (1)
|
||||||||||||||||||||||||||||
|
Fractionation volumes, MBbl/d
|
268.4 | 230.8 | 217.2 | 37.6 | 16% | 13.6 | 6% | |||||||||||||||||||||
|
Treating volumes, MBbl/d
|
15.3 | 18.0 | 21.9 | (2.7 | ) | (15% | ) | (3.9 | ) | (18% | ) | |||||||||||||||||
________
|
(1)
|
Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
|
2011 Compared to 2010
The increase in gross margin was primarily due to higher fractionation and treating revenue
($28.2 million), higher terminaling and storage revenue ($16.7 million) and higher fee-based and other revenue ($4.4 million). Higher fractionation revenues were driven by the expansion at CBF. LSNG customers, contractually bound to take-or-pay for treating services, decided not to use their reserved throughput in the fourth quarter of 2011, leading to lower treating volumes compared to 2010. The increase in terminaling and storage revenue was partially due to the impact of propane and normal butane exports. The increase in fee-based and other revenue is due to the 2011 acquisitions of petroleum terminaling assets.
The increase in operating expenses was primarily due to higher utilities, power and catalyst costs as a result of the expansion of the CBF facility ($6.4 million), higher compensation and benefits expense ($4.4 million), system maintenance costs ($2.6 million), and contract and professional services fees ($2.7 million), partially offset by an increase in system product gains ($5.3 million) as a result of increased volumes at the recently expanded CBF, which provides more favorable product upgrades. Higher operating expenses also reflect the 2011 acquisitions of petroleum terminaling assets.
2010 Compared to 2009
The increase in gross margin was primarily due to higher fractionation and treating revenue
($16.5 million), higher terminaling and storage revenue ($2.6 million) partially offset by lower fee-based and other revenue ($2.4 million) and lower revenue from business interruption insurance ($1.9 million). Fractionation facilities operating at or near capacity drove increases in fractionation volumes in 2010.
The increase in operating expenses was primarily due to higher natural gas prices for fuel to fractionators ($6.2 million), higher compensation and benefits expense ($5.0 million), higher system maintenance expenses ($3.0 million) and a decrease in system product gains ($7.3 million).
Marketing and Distribution
|
|
2011
|
2010
|
2009
|
2011 vs. 2010
|
2010 vs. 2009
|
|||||||||||||||||||||||
|
|
($ in millions)
|
|||||||||||||||||||||||||||
|
Gross margin
|
$ | 156.4 | $ | 125.3 | $ | 128.9 | $ | 31.1 | 25% | $ | (3.6 | ) | (3% | ) | ||||||||||||||
|
Operating expenses
|
43.0 | 44.8 | 45.9 | (1.8 | ) | (4% | ) | (1.1 | ) | (2% | ) | |||||||||||||||||
|
Operating margin
|
$ | 113.4 | $ | 80.5 | $ | 83.0 | $ | 32.9 | 41% | $ | (2.5 | ) | (3% | ) | ||||||||||||||
|
Operating statistics: (1)
|
||||||||||||||||||||||||||||
|
Natural gas sales, BBtu/d
|
877.8 | 634.9 | 510.3 | 242.9 | 38% | 124.6 | 24% | |||||||||||||||||||||
|
NGL sales, MBbl/d
|
272.5 | 246.7 | 276.1 | 25.8 | 10% | (29.4 | ) | (11% | ) | |||||||||||||||||||
|
Average realized prices:
|
||||||||||||||||||||||||||||
|
Natural gas, $/MMBtu
|
3.94 | 4.31 | 3.65 | (0.37 | ) | (9% | ) | 0.66 | 18% | |||||||||||||||||||
|
NGL realized price, $/gal
|
1.34 | 1.10 | 0.80 | 0.24 | 22% | 0.30 | 38% | |||||||||||||||||||||
________
|
(1)
|
Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
|
2011 Compared to 2010
The increase in gross margin was primarily due to higher NGL sales prices ($996.1 million), higher natural gas and NGL sales volumes ($816.3 million) and increased fee-based and other revenues ($37.5 million), partially offset by increased product purchases ($1,698.2 million), lower natural gas sales prices ($119.9 million) and lower condensate sales volumes ($1.0 million). NGL sales volumes rose on increased demand from industrial customers and from increased export sales. Natural gas sales volumes increased due to higher natural gas purchases which resulted in incremental increases in volumes processed by other reportable segments.
Operating expenses decreased $1.8 million due to lower railcar expenses ($2.2 million) and contractor and professional services fees ($1.9 million), partially offset by higher system maintenance costs ($1.7 million) and compensation and benefits expenses ($0.8 million).
2010 Compared to 2009
The decrease in gross margin was primarily due to increased commodity prices ($1,287.9 million) and higher natural gas volumes ($166.2 million) partially offset by increased product purchases ($1,083.8 million), lower NGL sales volumes ($359.8 million) and lower fee-based and other revenues ($14.5 million).
Lower 2010 margins were primarily due to the 2009 impact of higher margins on forward sales agreements that were fixed at relatively high 2008 prices, along with spot fractionation volumes and associated fees. These items were partially offset by higher marketing fees on contract purchase volumes due to overall higher 2010 market prices. Margin on transportation activity decreased due to expiration of a barge contract partially offset by increased truck activity.
Natural gas sales volumes were higher due to increased purchases for resale. NGL sales volumes were lower due to a change in contract terms with a petrochemical supplier that had minimal impact to gross margin.
Operating expenses were essentially flat.
Other
|
|
2011
|
2010
|
2009
|
2011 vs. 2010
|
2010 vs. 2009
|
|||||||||||||||
|
|
(In millions)
|
|||||||||||||||||||
|
Gross margin
|
$ | (37.6 | ) | $ | 4.0 | $ | 46.3 | $ | (41.6 | ) | $ | (42.3 | ) | |||||||
|
Operating margin
|
$ | (37.6 | ) | $ | 4.0 | $ | 46.3 | $ | (41.6 | ) | $ | (42.3 | ) | |||||||
Other contains the financial effects of the Partnership’s hedging program on profitability. It typically represents the cash settlements on the Partnership’s derivative contracts. Other also includes deferred gains or losses on previously terminated or de-designated hedge contracts that are reclassified to revenues upon the occurrence of the underlying physical transactions.
The primary purpose of the Partnership’s commodity risk management activities is to manage its exposure to commodity price risk and reduce volatility in its operating cash flow due to fluctuations in commodity prices. The Partnership has hedged the commodity price associated with a portion of its expected natural gas, NGL and condensate equity volumes by entering into derivative financial instruments. Because the Partnership is essentially forward selling a portion of its plant equity volumes, these hedge positions will move favorably in periods of falling prices and unfavorably in periods of rising prices.
The following table provides a breakdown of the Partnership’s hedge revenue by product:
|
|
2011
|
2010
|
2009
|
2011 vs. 2010
|
2010 vs. 2009
|
|||||||||||||||
|
|
(In Millions)
|
|||||||||||||||||||
|
Natural gas
|
$ | 21.2 | $ | 20.2 | $ | 28.6 | $ | 1.0 | $ | (8.4 | ) | |||||||||
|
NGL
|
(53.1 | ) | (14.2 | ) | 17.1 | (38.9 | ) | (31.3 | ) | |||||||||||
|
Crude oil
|
(5.7 | ) | (2.0 | ) | 0.6 | (3.7 | ) | (2.6 | ) | |||||||||||
|
|
$ | (37.6 | ) | $ | 4.0 | $ | 46.3 | $ | (41.6 | ) | $ | (42.3 | ) | |||||||
The decrease in gross margin from the Partnership’s risk management activities between 2011 and 2010, and between 2010 and 2009, was primarily due to increasing NGL and crude oil prices to levels above the fixed prices we received on derivative instruments, partially offset by decreasing prices of natural gas to levels below the fixed prices we received.
Our Liquidity and Capital Resources
We have no separate, direct operating activities apart from those conducted by the Partnership. As such, our ability to finance our operations, including payment of dividends to our common stockholders, funding capital expenditures and acquisitions, or to meet our indebtedness obligations, will depend on cash inflows from future cash distributions to us 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. See “Item 1A. Risk Factors.” As of February 17, 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 of the outstanding IDRs; and
|
|
•
|
12,945,659 of the 89,170,989 outstanding common units of the Partnership, representing a 14.5% limited partnership interest.
|
Our ownership of the general partner interest entitles us to receive:
|
•
|
2% of all cash distributed in respect for that quarter.
|
Our ownership of the IDRs of the Partnership entitles us to receive:
|
•
|
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;
|
|
•
|
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
|
|
•
|
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.
|
Subsequent Event. On January 12, 2012, the Partnership announced that the board of directors of its general partner declared a quarterly distribution for the three months ended December 31, 2011 of $0.6025 per common unit, or an annual rate of $2.41 per common unit. This distribution was paid on February 14, 2012. Based on these current distribution rates, we will receive distributions in future quarters and years of:
|
•
|
$7.8 million or $31.2 million annually based on our common units in the Partnership;
|
|
•
|
$11.0 million or $44.0 million annually based on our IDRs; and
|
|
•
|
$1.3 million or $5.3 million annually based on our 2% general partner interests.
|
We intend to pay to our stockholders, on a quarterly basis, dividends equal to the cash the Partnership distributes to us based on our ownership of Partnership securities, less the expenses of being a public company, other general and administrative expenses, federal income taxes, capital contributions to the Partnership and reserves established by our board of directors.
Dividends since our initial public offering on December 10, 2010 through December 31, 2011 were as follows:
|
Date Paid
|
For the Three Months Ended
|
Total Dividend Declared
|
Amount of Dividend Paid
|
Accrued Dividends (1)
|
Dividend Declared per Share of Common Stock
|
||||||||||||
|
(In millions, except per share amounts)
|
|||||||||||||||||
|
2011
|
|
|
|
|
|
||||||||||||
|
November 15, 2011
|
September 30, 2011
|
$ | 13.0 | $ | 12.6 | $ | 0.4 | $ | 0.3075 | ||||||||
|
August 16, 2011
|
June 30, 2011
|
12.3 | 11.9 | 0.4 | 0.2900 | ||||||||||||
|
May 13, 2011
|
March 31, 2011
|
11.6 | 11.2 | 0.4 | 0.2725 | ||||||||||||
|
February 14, 2011
|
December 31, 2010
|
2.6 | 2.5 | 0.1 | 0.0616 | (2) | |||||||||||
________
|
(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.
|
Subsequent Event. On January 12, 2012, we announced a quarterly dividend of $0.33625 per share of our common stock for the three months ended December 31, 2011, or $1.345 per share on an annualized basis. The declared dividend totals $14.3 million, including $0.5 million with respect to accrued dividends related to unvested restricted stock grants. The cash dividend of $13.8 million was paid on February 14, 2012.
As of December 31, 2011, we had $145.8 million of cash on hand, including $55.6 million of cash belonging to the Partnership. We do not have access to the Partnership’s cash as it is restricted for the use of the Partnership. We have the ability to use $90.2 million of the cash on hand and available to us to satisfy our aggregate tax liability of approximately $78 million over the next thirteen years associated with our sales of assets to the Partnership and related financings. On January 23, 2012, we used $49.8 million of available cash to purchase an additional 1,300,000 common units of the Partnership as part of a public offering by the Partnership of 4,000,000 common units.
The Partnership’s cash generated from operations has been sufficient to finance its operating expenditures and non-acquisition related capital expenditures. Based on our anticipated levels of the Partnership’s operations and absent any disruptive events, we believe that internally generated cash flow, borrowings available under the Partnership’s Revolver and proceeds from unit offerings should provide sufficient resources to finance its operations, capital expenditures, long-term debt obligations, collateral requirements and minimum quarterly cash distribution for at least the next twelve months.
Our future cash flows will consist of distributions to us from our interests in the Partnership, from which we intend to make quarterly cash dividends to our stockholders from available cash. Based on our anticipated levels of distributions that we expect to receive from the Partnership, cash generated from this interest should provide sufficient resources to finance our operations, long-term debt and quarterly cash dividends for at least the next twelve months.
The impact on us of changes in the Partnership’s distribution levels will vary depending on several factors, including the Partnership’s total outstanding partnership interests on the record date for the distribution, the aggregate cash distributions made by the Partnership and the interests in the Partnership owned by us. If the Partnership increases distributions to its unitholders, including us, we would expect to increase dividends to our stockholders, although the timing and amount of such increased dividends, if any, will not necessarily be comparable to the timing and amount of the increase in distributions made by the Partnership. In addition, the level of distributions we receive and of dividends we pay to our stockholders may be affected by the various risks associated with an investment in us and the underlying business of the Partnership. Please read “Item 1A. Risk Factors” for more information about the risks that may impact your investment in us.
The Partnership’s Liquidity and Capital Resources
The Partnership’s ability to finance its operations, including funding capital expenditures and acquisitions, to meet its debt obligations, to refinance its debt and to meet its collateral requirements will depend on its ability to generate cash in the future. The Partnership’s ability to generate cash is subject to a number of factors, some of which are beyond its control, including weather, commodity prices, particularly for natural gas and NGLs, and its ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.
The Partnership’s main sources of liquidity and capital resources are internally generated cash flow from operations, borrowings under its Revolver, the issuance of additional common units and access to debt markets. The capital markets continue to experience volatility. Many financial institutions have had liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. The Partnership’s exposure to current credit conditions includes its credit facility, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.
As of February 17, 2012, the Partnership’s liquidity of $1.1 billion consisted of $123.0 million of available cash and $1.0 billion of available borrowings under its credit facility. The Partnership continually monitors its liquidity and the credit markets, as well as events and circumstances surrounding each of the lenders in its credit facility.
The Partnership may issue additional equity or debt securities to assist in meeting future liquidity and capital spending requirements. The Partnership has filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows it to issue up to an aggregate of $500 million of debt or equity securities (the “2009 Shelf”). As of December 31, 2011, the Partnership had $245.3 million of available securities under the 2009 Shelf. On October 21, 2011, the Partnership filed a prospectus supplement under the 2009 Shelf that allows it to issue common units, representing limited partner interests having an aggregate offering price of up to $100 million from time to time through an Equity Distribution Agreement with Citigroup Global Markets, Inc. Sales of common units, if any, will be by means of ordinary brokers’ transactions through the facilities of the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent. The 2009 Shelf expires in July 2012.
The Partnership also has filed with the SEC a universal shelf registration statement (the “2010 Shelf”), which provides it with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and its capital needs. The Partnership’s August 2010, January 2011 and January 2012 equity offerings were conducted under the 2010 Shelf.
Subsequent Events. On January 23, 2012, the Partnership completed a public offering of 4,000,000 common units under its 2010 Shelf at a price of $38.30 per common unit ($37.11 per common unit, net of underwriting discounts). As part of this offering, we purchased 1,300,000 common units with an aggregate value of $49.8 million (based on the offering price of $38.30). The units we purchased were not subject to any underwriter discounts or commissions. Net proceeds to the Partnership from this offering were approximately $150 million. Pursuant to the exercise of the underwriters’ overallotment option, the Partnership sold an additional 405,000 common units, providing net proceeds of approximately $15 million. In addition, we contributed $3.4 million for 89,898 general partner units to maintain our 2% general partner interest.
On January 30, 2012 the Partnership privately placed $400 million in aggregate principal amount of 6⅜% Senior Notes (the “6⅜% Notes”) due 2022. The 6⅜% Notes resulted in approximately $395 million of net proceeds, which was used to reduce borrowings under the Partnership’s Revolver and for general partnership purposes.
Risk Management. The Partnership continues to evaluate counterparty risks related to its commodity derivative contracts and trade credit. The Partnership has all of its commodity derivatives with major financial institutions or major oil companies. Should any of these financial counterparties not perform, the Partnership may not realize the benefit of some of its hedges under lower commodity prices, which could have a material adverse effect on its results of operation. The Partnership sells its natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.
Crude oil and natural gas prices are also volatile. In an effort to reduce the variability of the Partnership’s cash flows, the Partnership has hedged the commodity price associated with a portion of its expected natural gas and NGL equity volumes through 2013 and its 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 this period. See “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.” The current market conditions may also impact the Partnership’s ability to enter into future commodity derivative contracts. A significant reduction in commodity prices could reduce the Partnership’s operating margins and cash flow from operations to the extent that such operating margins and cash flows derive from the portion of equity volumes that are not hedged.
The Partnership’s risk management position has moved from a net liability of $22.9 million at December 31, 2010 to a net liability of $5.0 million at December 31, 2011. The Partnership terminated its interest rate swap contracts in September 2011, which eliminated a liability of $23.0 million from its books. Additionally, forward prices for natural gas are below the fixed prices the Partnership receives on those derivative contracts, creating an asset valued at $41.7 million, while forward prices on crude oil and NGLs are above the fixed prices the Partnership receives on those derivative contracts, creating a liability valued at $46.7 million. Consequently, expected future receipts on derivative contracts are less than expected future payments, creating a net liability of $5.0 million. The Partnership accounts for derivatives that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in OCI until the underlying hedged transactions settle.
Working Capital. Working capital is the amount by which current assets exceed current liabilities. The Partnership’s working capital is primarily impacted by changes in inventory, which is closely managed to maintain minimum levels. On a consolidated basis at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced with Downstream receivables from NGL customers offset by plant settlements payable owed producers.
The Partnership’s cash generated from operations has been sufficient to finance its operating expenditures and both acquisition and non-acquisition related capital expenditures. Based on our anticipated levels of the Partnership’s operations and absent any disruptive events, we believe that the Partnership’s internally generated cash flow, borrowings available under its Revolver and proceeds from unit offerings and debt offerings should provide sufficient resources to finance its operations, capital expenditures, long-term debt obligations, collateral requirements and minimum quarterly cash distribution for at least the next twelve months.
A significant portion of the Partnership’s capital resources may be utilized in the form of letters of credit to satisfy certain counterparty credit requirements. While the Partnership’s credit rating has improved this year, these letters of credit reflect the Partnership’s non-investment grade status, as assigned to us by Moody’s Investors Service, Inc. and Standard & Poor’s Corporation, and counterparties’ views of the Partnership’s financial condition and ability to satisfy its performance obligations, as well as commodity prices and other factors. At December 31, 2011, the Partnership’s total outstanding letter of credit postings were $92.5 million.
Cash Flow
The following table and discussion summarize our consolidated cash flows provided by or used in operating activities, investing activities and financing activities for the periods indicated. See “Statement of Cash Flows – Partnership versus Non-Partnership” for a detailed presentation of cash flow activity:
|
2011
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
|||||||||
|
Net cash provided by (used in):
|
(In millions)
|
|||||||||||
|
Operating activities
|
$ | 379.3 | $ | 400.9 | $ | (21.6 | ) | |||||
|
Investing activities
|
(509.3 | ) | (506.1 | ) | (3.2 | ) | ||||||
|
Financing activities
|
87.4 | 84.5 | 2.9 | |||||||||
|
2010
|
||||||||||||
|
Net cash provided by (used in):
|
||||||||||||
|
Operating activities
|
$ | 205.2 | $ | 367.9 | $ | (162.7 | ) | |||||
|
Investing activities
|
(131.3 | ) | (131.6 | ) | 0.3 | |||||||
|
Financing activities
|
(137.9 | ) | (250.9 | ) | 113.0 | |||||||
|
2009
|
||||||||||||
|
Net cash provided by (used in):
|
||||||||||||
|
Operating activities
|
$ | 335.8 | $ | 422.9 | $ | (87.1 | ) | |||||
|
Investing activities
|
(59.3 | ) | (94.6 | ) | 35.3 | |||||||
|
Financing activities
|
(386.9 | ) | (380.6 | ) | (6.3 | ) | ||||||
Cash Flow from Operating Activities - Partnership
The Consolidated Statement of Cash Flows employs the traditional indirect method of presenting cash flows from operating activities. Under the indirect method, net cash provided by operating activities is derived by adjusting the Partnership’s net income for non-cash items related to operating activities. An alternative GAAP presentation employs the direct method in which the actual cash receipts and outlays comprising cash flow are presented. The following table displays the Partnership’s operating cash flows using the direct method as a supplement to the presentation in the Partnership’s financial statements.
|
|
2011
|
2010
|
2009
|
2011 vs. 2010
|
2010 vs. 2009
|
|||||||||||||||
|
Cash flows from operating activities:
|
(In millions)
|
|||||||||||||||||||
|
Cash received from customers
|
$ | 6,916.0 | $ | 5,400.1 | $ | 4,345.6 | $ | 1,515.9 | $ | 1,054.5 | ||||||||||
|
Cash paid for goods and services:
|
||||||||||||||||||||
|
Product purchases
|
(5,960.1 | ) | (4,643.7 | ) | (3,626.4 | ) | (1,316.4 | ) | (1,017.3 | ) | ||||||||||
|
Operating expenses
|
(286.1 | ) | (274.6 | ) | (238.3 | ) | (11.5 | ) | (36.3 | ) | ||||||||||
|
General and administrative expenses
|
(120.7 | ) | (84.5 | ) | (108.5 | ) | (36.2 | ) | 24.0 | |||||||||||
|
Derivative settlement receipts (payments)
|
(56.6 | ) | 38.1 | 78.1 | (94.7 | ) | (40.0 | ) | ||||||||||||
|
Cash distributions from equity investment
|
8.3 | 5.4 | 5.0 | 2.9 | 0.4 | |||||||||||||||
|
Interest paid - net
|
(96.1 | ) | (70.0 | ) | (27.0 | ) | (26.1 | ) | (43.0 | ) | ||||||||||
|
Income taxes paid
|
(2.5 | ) | (3.1 | ) | - | 0.6 | (3.1 | ) | ||||||||||||
|
Other cash receipts (payments)
|
(1.3 | ) | 0.2 | (5.6 | ) | (1.5 | ) | 5.8 | ||||||||||||
|
Net cash provided by operating activities
|
$ | 400.9 | $ | 367.9 | $ | 422.9 | $ | 33.0 | $ | (55.0 | ) | |||||||||
In 2011, Partnership derivative settlements were a net cash outflow, as opposed to a net inflow in 2010. The change in cash paid to derivative counterparties reflects (1) the change in the Partnership’s net position from in-the-money for the period ending December 31, 2010 to out-of-the-money for the period ending December 31, 2011 (reflecting higher commodity prices than the fixed prices we receive on derivative contracts), (2) a payment for interest rate swap termination in the amount of $23.0 million in September 2011 and (3) total payments for ethane call options in the amount of $1.5 million in October 2011.
Partnership cash receipts from derivative counterparties were lower in 2010 compared to 2009 because commodity prices, although higher than the fixed prices we receive on derivative contracts, were closer to the fixed prices compared to 2009, when commodity prices were much higher than the fixed prices of our contracts.
The changes in Partnership general and administrative cash payments primarily result from the timing differences in settlements between us and the Partnership, especially those related to allocations of incentive and long-term compensation programs and insurance, which, for the most part, the Partnership does not fund until Targa makes payments to participants or providers.
Cash Flow from Operating Activities - Non-Partnership
The operating activities of TRC – Non-Partnership are primarily related to interest, taxes, retained general and administrative expenses and business interruption insurance proceeds.
Cash Flow from Investing Activities - Partnership
Partnership net cash used in investing activities increased by $374.5 million for 2011 compared to 2010. The increase was primarily due to the Partnership’s petroleum logistics acquisitions of $156.5 million and a $157.0 million increase in expansion capital projects in gathering and processing assets and in fractionation capacity. The Partnership also invested $21.2 million in equity contributions associated with the expansion of fractionation capacity at GCF.
Partnership net cash used in investing activities increased by $37.0 million for 2010 compared to 2009. The increase is attributable to higher capital expenditures in 2010 compared to 2009.
Cash Flow from Investing Activities – Non-Partnership
During 2011, Non-Partnership net cash used in investing activities consisted of $3.2 million in outlays for corporate administrative assets. During 2010, net cash provided by investing activities primarily consisted of $3.5 million in insurance recoveries, partially offset by outlays for corporate administrative assets of $2.3 million. During 2009, net cash provided by investing activities primarily consisted of $38.8 million in insurance recoveries, partially offset by $3.5 million in outlays for corporate administrative assets.
Cash Flow from Financing Activities - Partnership
Net cash provided by financing activities for 2011 was $84.5 million compared to net cash used in financing activities of $250.9 million for 2010. The increase was due to two primary factors: changes in the Partnership’s equity offerings and financing activities and distributions.
Net proceeds from public offerings, issuance of senior notes and borrowings under the Partnership’s credit facility less repayments on the Partnership’s credit facility increased $211.1 million from $123.0 million for the year ended December 31, 2010 to $334.1 million for the year ended December 31, 2011. The Partnership’s primary financing activities that occurred during the year ended December 31, 2011 were:
|
·
|
On January 24, 2011, the Partnership completed a public offering of 8,000,000 common units under an existing shelf registration statement on Form S-3 at a price of $33.67 per common unit ($32.41 per common unit, net of underwriting discounts), providing net proceeds of $259.2 million. Pursuant to the exercise of the underwriters’ overallotment option, on February 3, 2011 the Partnership issued an additional 1,200,000 common units, providing net proceeds of approximately $38.8 million. In addition, we contributed $6.3 million for 187,755 general partner units to maintain our 2% general partner interest.
|
|
·
|
On February 2, 2011, the Partnership closed a private placement of $325.0 million in aggregate principal amount of its 6⅞% Notes resulting in net proceeds of $318.8 million.
|
|
·
|
On February 4, 2011, the Partnership exchanged an additional $158.6 million principal amount of its 6⅞% Notes for $158.6 million aggregate principal amount of the Partnership’s 11¼% Notes. In conjunction with the exchange the Partnership paid a cash premium of $28.6 million including $0.9 million of accrued interest.
|
Net cash from the completion of the unit offering and the note offering less cash paid in connection with the exchange offer was used to reduce outstanding borrowings under the Partnership’s Revolver by $553.4 million.
Net cash used in financing decreased $129.7 million for 2010 compared to 2009. The decrease was primarily due to the purchase from us of the Permian Business and Straddle Assets and our interests in Versado and VESCO, the repayment to us of $737.7 million in affiliate and allocated indebtedness, including interest, and net borrowings under the Partnership’s Revolver increasing by $294.6 million in 2010 compared to 2009, partially offset by cash distributions to unitholders, including us and our incentive distribution rights, increased $49.7 million in 2010.
The following table shows the historical distributions of the Partnership to us for 2011 and 2010 with respect of our 2% general partner interest, the associated IDRs and actual common units that we held during the periods indicated along with dividends declared by us to our shareholders for the same periods. The amount of these Partnership distributions available for distribution to us and the Partnership’s shareholders will be after reserves are established for the Partnership’s capital contributions, debt service requirements, general, administrative and other expenses, future distributions and other miscellaneous uses of cash:
|
|
|
|
Cash Distributions (1)
|
Dividend
|
Total
|
||||||||||||||||||||||||
|
|
|
Cash
|
|
|
|
Distributions
|
Declared
|
Dividend
|
|||||||||||||||||||||
|
|
|
Distribution
|
Limited
|
General
|
|
to Targa
|
Per TRC
|
Declared to
|
|||||||||||||||||||||
|
|
For the Three
|
Per Limited
|
Partner
|
Partner
|
|
Resources
|
Common
|
Common
|
|||||||||||||||||||||
|
Date Paid
|
Months Ended
|
Partner Unit
|
Units
|
Interest
|
IDRs
|
Corp. (2)
|
Share
|
Shareholders
|
|||||||||||||||||||||
|
|
|
(In millions, except per unit amounts)
|
|||||||||||||||||||||||||||
|
2011
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||
|
November 14, 2011
|
September 30, 2011
|
$ | 0.5825 | $ | 6.8 | $ | 1.2 | $ | 8.8 | $ | 16.8 | $ | 0.3075 | $ | 13.0 | ||||||||||||||
|
August 12, 2011
|
June 30, 2011
|
0.5700 | 6.6 | 1.2 | 7.8 | 15.6 | 0.2900 | 12.3 | |||||||||||||||||||||
|
May 13, 2011
|
March 31, 2011
|
0.5575 | 6.5 | 1.1 | 6.8 | 14.4 | 0.2725 | 11.5 | |||||||||||||||||||||
|
February 14, 2011
|
December 31, 2010
|
0.5475 | 6.4 | 1.1 | 6.0 | 13.5 | 0.0616 | (3) | 2.6 | ||||||||||||||||||||
|
|
|
||||||||||||||||||||||||||||
|
2010
|
|
||||||||||||||||||||||||||||
|
November 12, 2010
|
September 30, 2010
|
$ | 0.5375 | $ | 6.3 | $ | 0.9 | $ | 4.6 | $ | 11.8 | N/A | N/A | ||||||||||||||||
|
August 13, 2010
|
June 30, 2010
|
0.5275 | 6.1 | 0.8 | 3.5 | 10.4 | N/A | N/A | |||||||||||||||||||||
|
May 14, 2010
|
March 31, 2010
|
0.5175 | 6.0 | 0.8 | 2.8 | 9.6 | N/A | N/A | |||||||||||||||||||||
|
February 12, 2010
|
December 31, 2009
|
0.5175 | 10.4 | 0.8 | 2.8 | 14.0 | N/A | N/A | |||||||||||||||||||||
|
|
|
||||||||||||||||||||||||||||
|
2009
|
|
||||||||||||||||||||||||||||
|
November 14, 2009
|
September 30, 2009
|
$ | 0.5175 | $ | 10.4 | $ | 0.7 | $ | 2.6 | $ | 13.7 | N/A | N/A | ||||||||||||||||
|
August 14, 2009
|
June 30, 2009
|
0.5175 | 6.0 | 0.5 | 2.0 | 8.5 | N/A | N/A | |||||||||||||||||||||
|
May 15, 2009
|
March 31, 2009
|
0.5175 | 6.0 | 0.5 | 1.9 | 8.4 | N/A | N/A | |||||||||||||||||||||
|
February 13, 2009
|
December 31, 2008
|
0.5175 | 6.0 | 0.5 | 1.9 | 8.4 | N/A | N/A | |||||||||||||||||||||
________
|
(1)
|
Subsequent Event. On January 12, 2011, the Partnership announced a cash distribution of $0.6025 per common unit on its outstanding common units for the three months ended December 31, 2011 that was paid on February 14, 2011. The distribution was $45.9 million to the Partnership’s third-party limited partners, and $7.8 million, $11.0 million and $1.3 million to us for our ownership of common units, incentive distribution rights and our 2% general partner interest in the Partnership. We distributed to our shareholders $13.8 million on February 15, 2011.
|
|
(2)
|
Distributions to us are comprised of amounts attributable to our (i) limited partner units, (ii) general partner units, and (iii) IDRs.
|
|
(3)
|
Represents a prorated dividend for the portion of the fourth quarter of 2010 that the Company was public.
|
Cash Flow Financing Activities - Non-Partnership
Non-Partnership net cash provided by financing activities decreased by $110.0 million during 2011. During 2010, we received from the Partnership $737.7 million in repayments of affiliated indebtedness, and received $224.4 million from the sale of Partnership interests. These proceeds were primarily used to pay $448.1 million in dividends to common and common equivalent shareholders and preferred shareholders, and $592.4 million in outstanding balances on our loan facilities during 2010. Distributions to us from the Partnership increased $14.3 million in 2011 compared to 2010 primarily from a $15.7 million increase in distributions related to our incentive distribution rights, partially offset by a $2.5 million decrease in limited partner distributions due to our sale of Partnership interests during 2010.
During 2009, Non-Partnership net cash used in financing activities primarily consisted of net repayments on loan facilities of $589.2 million, partially offset by receipts from the Partnership’s repayment of affiliated indebtedness and $149.7 million from intercompany capital contributions.
Capital Requirements
The following table lists gross additions to property, plant and equipment, cash flows used in property, plant and equipment additions and the difference, which is primarily settled accruals:
|
|
2011
|
2010
|
2009
|
|||||||||||||||||||||||||||||||||
|
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
|||||||||||||||||||||||||||
|
|
(In millions)
|
|||||||||||||||||||||||||||||||||||
|
Gross additions to property, plant and equipment
|
$ | 492.2 | $ | 490.0 | $ | 2.2 | $ | 148.6 | $ | 145.2 | $ | 3.4 | $ | 92.2 | $ | 89.5 | $ | 2.7 | ||||||||||||||||||
|
Change in accruals
|
(3.8 | ) | (4.8 | ) | 1.0 | (9.3 | ) | (8.2 | ) | (1.1 | ) | 7.2 | 6.4 | 0.8 | ||||||||||||||||||||||
|
Cash expenditures
|
$ | 488.4 | $ | 485.2 | $ | 3.2 | $ | 139.3 | $ | 137.0 | $ | 2.3 | $ | 99.4 | $ | 95.9 | $ | 3.5 | ||||||||||||||||||
The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. A significant portion of the cost of constructing new gathering lines to connect to the Partnership’s gathering system is generally paid for by the natural gas producer. However, the Partnership expects to make significant expenditures during the next year for the construction of additional natural gas gathering and processing infrastructure and the expansion of its logistics assets.
We categorize capital expenditures as either: (i) maintenance expenditures or (ii) expansion expenditures. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets including the replacement of system components and equipment which is worn, obsolete or completing its useful life, the addition of new sources of natural gas supply to our systems to replace natural gas production declines and expenditures to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of businesses or assets.
|
|
2011
|
2010
|
2009
|
|||||||||||||||||||||||||||||||||
|
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
Targa Resources Corp. Consolidated
|
Targa Resources Partners LP
|
TRC - Non-Partnership
|
|||||||||||||||||||||||||||
|
|
(In millions)
|
|||||||||||||||||||||||||||||||||||
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||
|
Business acquisitions
|
$ | 156.5 | $ | 156.5 | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||||||||||
|
Expansion
|
252.3 | 251.7 | 0.6 | 95.3 | 94.7 | 0.6 | 45.7 | 45.0 | 0.7 | |||||||||||||||||||||||||||
|
Maintenance
|
83.4 | 81.8 | 1.6 | 53.3 | 50.5 | 2.8 | 46.5 | 44.5 | 2.0 | |||||||||||||||||||||||||||
|
|
$ | 492.2 | $ | 490.0 | $ | 2.2 | $ | 148.6 | $ | 145.2 | $ | 3.4 | $ | 92.2 | $ | 89.5 | $ | 2.7 | ||||||||||||||||||
The Partnership estimates that its total capital expenditures for 2012 will be approximately $680 million gross and $650 million net of noncontrolling interest share and reimbursements. The Partnership also estimates that of the $650 million net capital expenditures, approximately 12% will be for maintenance capital expenditures. Given the Partnership’s objective of growth through acquisitions, expansions of existing assets and other internal growth projects, the Partnership anticipates that over time they will invest significant amounts of capital to grow and acquire assets. Major capital projects include:
|
·
|
$360 million expansion project at CBF to add a fourth fractionation train and related infrastructure enhancements at Mont Belvieu;
|
|
·
|
$250 million expansion of the Partnership’s Mont Belvieu complex and the Partnership’s existing import/export marine terminal at Galena Park to export international grade propane;
|
|
·
|
$150 million North Texas Longhorn project for a new cryogenic processing plant with associated projects;
|
|
·
|
$60 million expansion of the Partnership’s petroleum logistics assets;
|
|
·
|
$45 million capital expansion programs to expand the gathering and processing capability of SAOU and the Permian Business;
|
|
·
|
$40 million benzene treating project at Mont Belvieu to construct a treater designed to reduce benzene content of natural gasoline to meet new, more stringent environmental standards;
|
|
·
|
$20 million capital expansion program to expand the gathering and processing capability of the North Texas System;
|
|
·
|
$13 million HD-5 Refrigeration Export project to expand the Partnership’s dock facilities and related infrastructure enhancements at Galena Park; and
|
|
·
|
the Partnership’s share of the $90 million expansion at Gulf Coast Fractionators, which is expected to be approximately $35 million, funded via cash calls and suspended earning distributions.
|
These capital projects will extend through 2013. For a detailed discussion of these projects, see “Item 1. Business –Overview of the Partnership.” Future expansion capital expenditures may vary significantly based on investment opportunities.
The Partnership expects to fund future capital expenditures with funds generated from their operations, borrowings under the Revolver, and proceeds from the issuance of additional common units and debt offerings.
Credit Facilities and Long-Term Debt
The following table summarizes consolidated debt obligations as of December 31, 2011 (in millions):
|
Non-Partnership Obligations:
|
|
|||
|
TRC Holdco Loan, due February 2015
|
$ | 89.3 | ||
|
TRI Senior secured revolving credit facility due July 2014
|
- | |||
|
Partnership Obligations
|
||||
|
Senior secured revolving credit facility, due July 2015
|
498.0 | |||
|
Senior unsecured notes, 8 1/4% fixed rate, due July 2016
|
209.1 | |||
|
Senior unsecured notes, 11 1/4% fixed rate, due July 2017
|
72.7 | |||
|
Unamortized discount
|
(2.9 | ) | ||
|
Senior unsecured notes, 7 7/8% fixed rate, due July 2018
|
250.0 | |||
|
Senior unsecured notes, 6 7/8% Fixed rate, due July 2021
|
483.6 | |||
|
Unamortized discount
|
(32.8 | ) | ||
|
Total debt
|
1,567.0 | |||
|
Current maturities of debt
|
- | |||
|
Total long-term debt
|
$ | 1,567.0 | ||
We consolidate the debt of the Partnership with that of our own; however, we do not have the contractual obligation to make interest or principal payments with respect to the debt of the Partnership. We have retired all amounts outstanding under our Senior Secured Term Loan Facility due July 2016 as of December 2010. Our debt obligations including those of TRI Resources, Inc. (“TRI”) do not restrict the ability of the Partnership to make distributions to us. TRI’s Senior Secured Credit Facility has restrictions and covenants that may limit our ability to pay dividends to our stockholders. Please read “—TRI Senior Secured Credit Facility” for a discussion of the restrictions and covenants in TRI’s Senior Secured Credit Facility.
As of December 31, 2011, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.
Holdco Loan
In August 2007, we borrowed $450 million under the Holdco loan facility. Interest on borrowings under the facility are payable, at our option, either (i) entirely in cash, (ii) entirely by increasing the principal amount of the outstanding borrowings or (iii) 50% in cash and 50% by increasing the principal amount of the outstanding borrowings.
In connection with our repurchase of $301.6 million of outstanding Holdco notes in 2010, we removed all of the restrictive covenants under the Holdco credit agreement.
In November 2010, we amended our Holdco Loan to name our wholly-owned subsidiary, TRI, as guarantor to our obligations under the credit agreement. The operations and assets of the Partnership continue to be excluded as guarantors of the Holdco Loan. In conjunction with the guaranty agreement, the applicable margin for borrowings under the facility was reduced from 5.0% to 3.75%. At our option, if we choose to pay the interest on this loan in cash versus increasing the principal amount of the outstanding borrowings, the applicable margin for borrowings would be further reduced to 3.0%.
TRI Senior Secured Credit Facility
On January 5, 2010, we entered into a Senior Secured Credit Facility providing senior secured financing of $600 million, consisting of:
|
·
|
$500 million Senior Secured Term Loan Facility (fully repaid as of December 2010); and
|
|
·
|
$100 million Senior Secured Revolving Credit Facility (subsequently reduced to $75 million and undrawn as of December 2010 and 2011).
|
The entire amount of our credit facility is available for letters of credit and includes a limited borrowing capacity for borrowings on same-day notice referred to as swing line loans. Our available capacity under this facility is currently $75 million. TRI is the borrower under this facility.
Borrowings under the credit agreement bear interest at a rate equal to an applicable margin, plus at our option, either (a) a base rate determined by reference to the higher of (1) the prime rate of Deutsche Bank, (2) the federal funds rate plus 0.5%, and (3) solely in the case of term loans, 3%, or (b) LIBOR as determined by reference to the higher of (1) the British Bankers Association LIBOR Rate and (2) solely in the case of term loans, 2%.
Principal amounts outstanding under our Senior Secured Revolving Credit Facility are due and payable in full on July 5, 2014. During 2010, we used the proceeds from our sales of the Permian and Coastal Straddles Systems, Versado and VESCO, as well as the secondary public offering of 8,500,000 common units of the Partnership that we owned to fully repay the outstanding balance on the Senior Secured Term Loan.
The credit agreement is secured by a pledge of our ownership in our restricted subsidiaries and contains a number of covenants that, among other things, restrict, subject to certain exceptions, our ability to incur additional indebtedness (including guarantees and hedging obligations); create liens on assets; enter into sale and leaseback transactions; engage in mergers or consolidations; sell assets; pay dividends and make distributions or repurchase capital stock and other equity interests; make investments, loans or advances; make capital expenditures; repay, redeem or repurchase certain indebtedness; make certain acquisitions; engage in certain transactions with affiliates; amend certain debt and other material agreements; and change our lines of business.
The credit agreement requires us to maintain a consolidated leverage ratio of less than 5.75 to 1.0 prior to 2012, less than 5.50 to 1.0 during 2012, and less than 5.25 to 1.0 thereafter. We are also required to maintain an interest coverage ratio of greater than 1.50 to 1.0. As of December 31, 2011, we were in compliance with these ratios. In addition, we are required to comply with certain limitations, including minimum cash consideration requirements for non-ordinary course asset sales. If we were to breach our leverage or interest ratios or otherwise fail to comply with the requirements of our credit agreement, we would not be able to make any further borrowings or dividends to stockholders. If such default was not cured within the time periods allowed under the credit agreement, and not otherwise waived by the lenders, the lenders would have the right to pursue their remedies against us, including declaring all amounts outstanding under the credit agreement to be immediately due and payable.
The Partnership’s Revolving Credit Facility due 2015
On July 19, 2010, the Partnership entered into a new five-year $1.1 billion amended and restated Revolver, which allows it to request increases in commitments up to an additional $300 million. The new Revolver amended and restated the Partnership’s former $977.5 million Senior Secured Revolving Credit Facility due February 2012.
For the year ended December 31, 2011, the Partnership had gross borrowings under its Revolver of $1,787.0 million, and repayments totaling $2,054.3 million, for a net decrease for the year ended December 31, 2011 of $267.3 million. The Revolver balance at December 31, 2011 was $498.0 million.
The amended and restated Revolver bears interest at LIBOR plus an applicable margin ranging from 2.25% to 3.5% (or base rate at the borrower’s option) dependent on the Partnership’s consolidated funded indebtedness to consolidated adjusted EBITDA ratio. The Partnership’s amended and restated Revolver is secured by substantially all of the Partnership’s assets.
The Partnership’s Revolver restricts its ability to make distributions of available cash to unitholders if a default or an event of default (as defined in our Senior Secured Credit Agreement) has occurred and is continuing. The Revolver requires the Partnership to maintain a consolidated funded indebtedness to consolidated adjusted EBITDA of less than or equal to 5.50 to 1.00. The Revolver also requires the Partnership to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, as defined in the Senior Secured Credit Agreement) of greater than or equal to 2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination, as well as upon the occurrence of certain events, including the incurrence of additional permitted indebtedness.
The Partnership’s Outstanding Senior Unsecured Notes
On June 18, 2008, the Partnership privately placed $250 million in aggregate principal amount at par value of 8¼% senior notes due 2016 (the “8¼% Notes”).
On July 6, 2009, the Partnership privately placed $250 million in aggregate principal amount of 11¼% senior notes due 2017 (the “11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million.
On August 13, 2010, the Partnership privately placed $250 million in aggregate principal amount at par value of its 7⅞% senior notes due 2018 (the “7⅞% Notes”).
On February 2, 2011, the Partnership closed a private placement of $325.0 million in aggregate principal amount of 6⅞% Senior Notes due 2021 (the “6⅞% Notes”).
All four 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, to the extent of the value of the collateral securing that indebtedness.
On February 4, 2011, the Partnership exchanged an additional $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% Senior Notes due 2017 (the “11¼% Notes”). 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.
Subsequent Event. On January 31, 2012 the Partnership privately placed $400.0 million in aggregate principal amount of 6⅜% Senior Notes (the “6⅜% Notes”) due 2022. The 6⅜% Notes resulted in approximately $395.0 million of net proceeds, which was used to reduce borrowings under the Partnership’s Revolver and for general partnership purposes.
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.
Off-Balance Sheet Arrangements
We currently have no off-balance sheet arrangements as defined by the Securities and Exchange Commission. See “Contractual Obligations” below and “Commitments and Contingencies” included under Note 17 to our “Audited Consolidated Financial Statements” beginning on page F-1 of this Annual Report for a discussion of our commitments and contingencies.
Contractual Obligations
Following is a summary of our contractual cash obligations over the next several fiscal years, representing amounts that were fixed and determinable as of December 31, 2011:
|
|
Payments Due By Period
|
|||||||||||||||||||
|
|
|
Less Than
|
|
|
More Than
|
|||||||||||||||
|
Contractual Obligations
|
Total
|
1 Year
|
1-3 Years
|
4-5 Years
|
5 Years
|
|||||||||||||||
|
|
(In millions)
|
|||||||||||||||||||
|
Non-Partnership Obligations:
|
|
|
|
|
|
|||||||||||||||
|
Debt obligations (1)
|
$ | 89.3 | $ | - | $ | 89.3 | $ | - | $ | - | ||||||||||
|
Interest on debt obligations (2)
|
10.3 | 3.3 | 7.0 | - | - | |||||||||||||||
|
Operating lease obligations (3)
|
12.9 | 2.1 | 6.7 | 4.1 | - | |||||||||||||||
|
Partnership Obligations:
|
||||||||||||||||||||
|
Debt obligations (1)
|
1,513.4 | - | 498.0 | 281.8 | 733.6 | |||||||||||||||
|
Interest on debt obligations (2)
|
631.3 | 97.2 | 283.8 | 127.8 | 122.5 | |||||||||||||||
|
Operating lease and service contract obligations (3)
|
35.1 | 7.5 | 15.6 | 8.9 | 3.1 | |||||||||||||||
|
Pipeline capacity and throughput agreements (4)
|
195.8 | 8.3 | 55.5 | 36.8 | 95.2 | |||||||||||||||
|
Land site lease and right-of-way (5)
|
6.4 | 1.8 | 3.5 | 1.1 | - | |||||||||||||||
|
Asset retirement obligation
|
42.3 | - | - | - | 42.3 | |||||||||||||||
|
Commodities (6)
|
109.6 | 109.4 | 0.2 | - | - | |||||||||||||||
|
Purchase commitments (7)
|
228.5 | 228.5 | - | - | - | |||||||||||||||
|
|
$ | 2,874.9 | $ | 458.1 | $ | 959.6 | $ | 460.5 | $ | 996.7 | ||||||||||
|
Commodity volumetric commitments:
|
||||||||||||||||||||
|
Natural Gas (MMBtu)
|
15.4 | 15.4 | - | - | - | |||||||||||||||
|
NGL (millions of gallons)
|
63.2 | 57.2 | 6.0 | - | - | |||||||||||||||
________
|
(1)
|
Represents scheduled future maturities of consolidated debt obligations for the periods indicated.
|
|
(2)
|
Represents interest expense on debt obligations based on interest rates as of December 31, 2011 and the scheduled future maturities of those debt obligations.
|
|
(3)
|
Includes minimum payments on lease obligations for office space, railcars and tractors, and service contracts.
|
|
(4)
|
Consists of pipeline capacity payments for firm transportation and throughput and deficiency agreements.
|
|
(5)
|
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.
|
|
(6)
|
Includes natural gas and NGL purchase commitments.
|
|
(7)
|
Includes commitments for capital expenditures and operating expenses.
|
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates. The policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.
Property, Plant and Equipment. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the period it benefits. Our property, plant and equipment are depreciated using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. At the time we place our assets in-service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation amounts prospectively. Examples of such circumstances include:
|
·
|
changes in energy prices;
|
|
·
|
changes in competition;
|
|
·
|
changes in laws and regulations that limit the estimated economic life of an asset
|
|
·
|
changes in technology that render an asset obsolete;
|
|
·
|
changes in expected salvage values; and
|
|
·
|
changes in the forecast life of applicable resources basins.
|
As of December 31, 2011, the net book value of our property, plant and equipment was $2.8 billion and we recorded $181.0 million in depreciation and amortization expense for the year ended December 31, 2011. The weighted average life of our long-lived assets is approximately 20 years. If the useful lives of these assets were found to be shorter than originally estimated, depreciation expense may increase, liabilities for future asset retirement obligations may be insufficient and impairments in carrying values of tangible and intangible assets may result. For example, if the depreciable lives of our assets were reduced by 10%, we estimate that depreciation expense would increase by $80.4 million per year, which would result in a corresponding reduction in our operating income. In addition, if an assessment of impairment resulted in a reduction of 1% of our long-lived assets, our operating income would decrease by $28.2 million in the year of the impairment. There have been no material changes impacting estimated useful lives of the assets.
Revenue Recognition. As of December 31, 2011, our balance sheet reflects total accounts receivable from third parties of $575.7 million. We have recorded an allowance for doubtful accounts as of December 31, 2011 of $2.4 million.
The Partnership’s exposure to uncollectible accounts receivable relates to the financial health of its counterparties. We have 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 $5.8 million in the year of the assessment.
Price Risk Management (Hedging). The Partnership’s net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. To reduce the volatility of our cash flows, the Partnership has entered into derivative financial instruments related to a portion of its equity volumes to manage the purchase and sales prices of commodities. We are exposed to the credit risk of the Partnership’s counterparties in these derivative financial instruments. We also monitor NGL inventory levels with a view to mitigating losses related to downward price exposure.
The Partnership’s cash flow is affected by the derivative financial instruments it enters into to the extent these instruments are settled by (i) making or receiving a payment to/from the counterparty or (ii) making or receiving a payment for entering into a contract that exactly offsets the original derivative financial instrument. Typically a derivative financial instrument is settled when the physical transaction that underlies the derivative financial instrument occurs.
One of the primary factors that can affect the Partnership’s operating results each period is the price assumptions used to value the Partnership’s derivative financial instruments, which are reflected at their fair values in the balance sheet. The relationship between the derivative financial instruments 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 derivative financial instrument and on an ongoing basis. Hedge accounting is discontinued prospectively when a derivative financial instrument becomes ineffective. Gains and losses deferred in other comprehensive income related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the derivative financial instrument are reclassified to earnings immediately.
The estimated fair value of the Partnership’s derivative financial instruments was a net liability of $5.0 million as of December 31, 2011, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities by year as indicated by the counterparties’ credit default swap transactions. These default probabilities have been applied to the unadjusted fair values of the derivative financial instruments to arrive at the credit risk adjustment, which aggregates to $0.3 million as of December 31, 2011. The Partnership has an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If a financial instrument counterparty were to declare bankruptcy, we and the Partnership would be exposed to the loss of fair value of the financial instrument transaction with that counterparty. Ignoring the adjustment for credit risk, if a bankruptcy by a financial instrument counterparty impacted 10% of the fair value of commodity-based financial instruments that are in an asset position, we estimate that the Partnership’s operating income would decrease by $5.2 million in the year of the bankruptcy.
Use of Estimates. When preparing financial statements in conformity with GAAP, 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.
2011 Accounting Pronouncements. For a discussion of recent accounting pronouncements that will affect us, see “2011 Accounting Pronouncements” included under Note 3 to our “Consolidated Financial Statements” beginning on page F-1 in this Annual Report.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The Partnership’s principal market risks are its exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, 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 majority of the Partnership’s revenues are derived from percent-of-proceeds contracts under which it receives a portion of the natural gas and/or NGL 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, 2011, the Partnership has hedged the commodity price associated with a portion of its expected natural gas, NGL and condensate equity volumes that result from its percent of proceeds processing arrangements in Field Gathering and Processing, and the LOU portion of the Coastal Gathering and Processing Operations through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of expected equity volumes that are hedged decrease over time. 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) to hedge additional expected equity commodity volumes without creating volumetric risk. 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 NGL hedges’ fair values are based on published index prices for delivery at Mont Belvieu through 2013. The natural gas hedges’ fair values are based on published index prices for delivery at various locations which closely approximate the actual NGL and natural gas 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 currently 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 requiring the deposit of cash collateral resulting from the Dodd-Frank Wall Street Reform and Consumer Protection 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. 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, 2011, 2010 and 2009, our consolidated operating revenues were increased (decreased) by net hedge adjustments on commodity derivative contracts of $(33.9) million, $4.7 million and $44.1 million. The net hedge adjustments that impact our consolidated revenues (but do not affect the Partnership’s revenues) include amortization of other comprehensive income (“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, 2011, the Partnership had the following hedge arrangements which will settle during the years ending December 31, 2012 through 2014:
|
Natural Gas
|
|
|
|
|||||||||||
|
Instrument
|
|
|
|
Price
|
|
MMBtu per day
|
|
|
|
|
|
|
||
|
Type
|
|
Index
|
|
$/MMBtu
|
|
2012
|
|
2013
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Swap
|
|
IF-WAHA
|
|
6.61
|
|
14,850
|
|
|
|
$
|
18.8
|
|
|
|
|
Swap
|
|
IF-WAHA
|
|
5.28
|
|
|
|
7,230
|
|
|
3.8
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
14,850
|
|
7,230
|
|
|
|
|
|
|
|
Swap
|
|
IF-PB
|
|
4.98
|
|
10,200
|
|
|
|
|
7.0
|
|
|
|
|
Swap
|
|
IF-PB
|
|
5.23
|
|
|
|
7,084
|
|
|
3.7
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
10,200
|
|
7,084
|
|
|
|
|
|
|
|
Swap
|
|
IF-NGPL MC
|
|
6.03
|
|
6,740
|
|
|
|
|
7.1
|
|
|
|
|
Swap
|
|
IF-NGPL MC
|
|
4.89
|
|
|
|
2,775
|
|
|
1.1
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
6,740
|
|
2,775
|
|
|
|
|
|
|
|
Total Sales
|
|
|
|
|
|
31,790
|
|
17,089
|
|
|
|
|
|
|
|
Natural Gas Basis Swaps
|
|
|
|
|
|
|
|
|
|
|||||
|
Basis Swaps
|
|
Various Indexes, Maturities Through December 2012
|
|
0.2
|
|
|
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
$
|
41.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL
|
|
|
|
|||||||||||
|
Instrument
|
|
|
|
Price
|
|
Barrels per day
|
|
|
|
|
|
|
||
|
Type
|
|
Index
|
|
$/Gal
|
|
2012
|
|
2013
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Swap
|
|
OPIS-MB
|
|
0.95
|
|
9,361
|
|
|
|
$
|
(32.2)
|
|
|
|
|
Swap
|
|
OPIS-MB
|
|
0.98
|
|
|
|
4,150
|
|
|
(11.1)
|
|
|
|
|
Total Swaps
|
|
|
|
|
|
9,361
|
|
4,150
|
|
|
|
|
|
|
|
Floor
|
|
OPIS-MB
|
|
1.43
|
|
294
|
|
|
|
|
0.7
|
|
|
|
|
Cap
|
|
OPIS-MB
|
|
0.66
|
|
2,000
|
|
|
|
|
2.7
|
|
|
|
|
Total Floors
|
|
|
|
|
|
2,294
|
|
-
|
|
|
|
|
|
|
|
Total Sales
|
|
|
|
|
|
11,655
|
|
4,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(39.9)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate
|
||||||||||||||
|
Instrument
|
|
|
|
Price
|
|
Barrels per day
|
|
|
|
|||||
|
Type
|
|
Index
|
|
$/Bbl
|
|
2012
|
|
2013
|
|
2014
|
|
Fair Value
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
||
|
Swap
|
|
NY-WTI
|
|
91.37
|
|
1,660
|
|
|
|
|
|
$
|
(4.5)
|
|
|
Swap
|
|
NY-WTI
|
|
93.34
|
|
|
|
1,795
|
|
|
|
|
(1.6)
|
|
|
Swap
|
|
NY-WTI
|
|
90.03
|
|
|
|
|
|
700
|
|
|
(0.7)
|
|
|
Total Sales
|
|
|
|
|
|
1,660
|
|
1,795
|
|
700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(6.8)
|
|
These contracts may expose the Partnership to the risk of financial loss in certain circumstances. Its 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.
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 value of the NGL derivative contracts is determined 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 NGL contracts that have inputs from quoted prices, the classification of these instruments is Level 2 within the fair value hierarchy. For those NGL 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 NGL valuations are classified as Level 3 within the fair value hierarchy. See Note 14 to the Consolidated Financial Statements in this Annual Report for more information regarding classifications within the fair value hierarchy.
Interest Rate Risk. We and the Partnership are exposed to the risk of changes in interest rates. We are exposed to interest rate changes due to our variable rate Holdco loan facility. The Partnership is exposed to interest rate changes as a result of variable rate borrowings under the Revolver of the Partnership. To the extent that interest rates increase, interest expense for our Holdco loan facility and the Partnership’s revolving debt will also increase. As of December 31, 2011, the Partnership had variable rate borrowings of $498.0 million, and we had variable rate borrowings of $89.3 million. A hypothetical change of 100 basis points in the interest rate of variable rate debt would impact the Partnership’s annual interest expense by $5.0 million and would impact the TRC Non-Partnership annual interest expense by $0.9 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, 2011, affiliates of Barclays PLC (“Barclays”), Credit Suisse AG (“Credit Suisse”), Natixis and JP Morgan Chase Bank N.A. (“JP Morgan”) accounted for 38%, 15%, 14% and 10% of the Partnership’s counterparty credit exposure related to commodity derivative instruments. Barclays, Credit Suisse, Natixis and JP Morgan 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.
Item 8. Financial Statements and Supplementary Data.
Our Consolidated Financial Statements, together with the report of our independent registered public accounting firm begin on page F-1 of this Annual Report.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
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, 2011 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, 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, 2011 as stated in its report included in our consolidated financial statements on page F-2 of this Annual Report, which is incorporated herein by reference.
The business of the refined petroleum products and crude oil storage and terminaling facility that the Partnership purchased in Tacoma, Washington on September 30, 2011 was excluded from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2011. This business constituted 0.7% of our total revenues for 2011 and 3.3% of our total assets as of December 31, 2011.
(b) Changes in Internal Control Over Financial Reporting
During the three months ended December 31, 2011, 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. Other Information.
None.
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 17, 2012.
|
Name
|
Age
|
Position
|
||
|
Rene R. Joyce
|
64
|
Executive Chairman of the Board and Director
|
||
|
Joe Bob Perkins
|
51
|
Chief Executive Officer and Director
|
||
|
James W. Whalen
|
70
|
Advisor to Chairman & CEO and Director
|
||
|
Michael A. Heim
|
63
|
President and Chief Operating Officer
|
||
|
Jeffrey J. McParland
|
57
|
President-Finance and Administration
|
||
|
Roy E. Johnson
|
67
|
Executive Vice President
|
||
|
Paul W. Chung
|
51
|
Executive Vice President, General Counsel and Secretary
|
||
|
Matthew J. Meloy
|
34
|
Senior Vice President, Chief Financial Officer and Treasurer
|
||
|
John R. Sparger
|
58
|
Senior Vice President and Chief Accounting Officer
|
||
|
Charles R. Crisp
|
64
|
Director
|
||
|
In Seon Hwang
|
35
|
Director
|
||
|
Peter R. Kagan
|
43
|
Director
|
||
|
Chris Tong
|
55
|
Director
|
||
|
Ershel C. Redd Jr.
|
64
|
Director
|
Rene R. Joyce has served as Executive Chairman of the Board of TRC, the general partner and TRI Resources Inc. (“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 RTM Media (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, Omega Energia Renovavel S.A. 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, Broad Oak, Canbriam Energy, Fairfield Energy Limited, Laredo Petroleum and MEG Energy Corp. 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 Cloud Peak Energy Inc. and Kosmos Energy Ltd. 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, 2012 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 Securities Exchange Act of 1934, as amended (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 2011, 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. Executive Compensation.
Compensation Discussion and Analysis
The following discussion and analysis contains statements regarding our and our executive officers’ future performance targets and goals. These targets and goals are disclosed in the limited context of our compensation programs and should not be understood to be statements of management’s expectations or estimates of results or other guidance.
Overview
Compensatory arrangements with our executive officers identified in the Summary Compensation Table (“named executive officers”) are approved by the Compensation Committee (the “Compensation Committee”) of our Board of Directors. The Compensation Committee is responsible for overseeing the development of an executive compensation philosophy, strategy, framework and individual compensation elements for our named executive officers based on our business priorities.
The following Compensation Discussion and Analysis describes the material elements of compensation for our named executive officers as determined by the Compensation Committee.
Compensation Philosophy
The Compensation Committee believes that total compensation of 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 “The Role of Peer Groups and Benchmarking” below. The following compensation objectives guide the Compensation Committee in its deliberations about executive compensation matters:
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provide a competitive total compensation program that enables us to attract and retain key executives;
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ensure an alignment between our strategic and financial performance and the total compensation received by our named executive officers;
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provide compensation for performance that reflects individual and company performance both in absolute terms and relative to our peer group;
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ensure a balance between short-term and long-term compensation while emphasizing at-risk or variable, compensation as a valuable means of supporting our strategic goals and aligning the interests of our named executive officers with those of our shareholders; and
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ensure that our total compensation program supports our business objectives and priorities.
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Consistent with this philosophy and compensation objectives, we do not pay for perquisites for any of our named executive officers, other than minimal parking subsidies.
The Role of Peer Groups and Benchmarking
When evaluating compensation levels for each named executive officer, the Compensation Committee reviews publicly available compensation data for executives in our peer group and compensation surveys and uses that information to set compensation levels for each named executive officer in the context of their roles and levels of responsibility, accountability and decision-making authority. 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, such as salaries “above the median” or total compensation “at the 50th percentile.” The peer 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 about 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 performance relative to expectations and actual market/business conditions. All of these factors, including peer company data, are utilized in a subjective assessment of each year’s decisions relating to annual cash incentives, long-term incentives and base compensation changes with a view towards total compensation and pay-for-performance.
The peer group reviewed by the Compensation Committee in consultation with senior management for compensation comparison includes midstream master limited partnerships (“MLPs”) and other energy companies to better reflect the market for executive talent in the energy industry. Because many companies in the peer group are larger than the Company as measured by market capitalization and total assets, with the assistance of BDO USA, LLP (“BDO”), a compensation consultant engaged by the Compensation Committee, compensation data for the peer companies is analyzed using multiple regression analysis to develop a prediction of the total compensation that peer companies of comparable size to the Company would offer similarly-situated executives. This regressed data is then weighted as follows to develop a reference point for judging the adequacy of executive pay at the Company: MLPs (given a 70% weighting), exploration and production companies (“E&Ps”) (given a 15% weighting) and utility companies (given a 15% weighting). The peer group companies in each of the three categories are:
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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., El Paso Corp., 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.
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Senior management and the Compensation Committee review our compensation practices and peer 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 BDO, the compensation consultant engaged by the Compensation Committee, and reviews market data and evaluates relevant compensation levels and compensation program elements. Based on these consultations and assessment of performance relative to key business priorities, senior management submits emerging conclusions and later a proposal to the Chairman of the Compensation Committee. The proposal includes a recommendation of base salary, annual bonus and new long-term compensation to be paid or awarded to executive officers and employees. The Chairman of the Compensation Committee reviews and discusses the proposal with senior management and the consultant and may discuss it with the other members of the Compensation Committee, other board members, or the full boards of the Company and Targa Resources GP LLC and may request that senior management provide him with additional information or reconsider or revise their proposal. The resulting recommendation is then submitted to the Compensation Committee for consideration, which also meets separately with the compensation consultant. The final compensation decisions are reported to the Board.
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 Chairman of the Board of Directors 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.
Elements of Compensation for Named Executive Officers
The elements of compensation for our named executive officers consist of the following: (i) annual base salary; (ii) discretionary annual cash bonus awards; (iii) long term incentive awards, consisting of performance awards under the Partnership’s long-term incentive plan and awards under our stock incentive plan; (iv) contributions under our 401(k) and profit sharing plan; (v) participation in our health and welfare plans on the same basis as all of our other employees; and (vi) participation in a change in control-related severance plan.
Base Salary. The base salaries for our named executive officers are set and reviewed annually by the Compensation Committee. The salaries are intended to provide fixed compensation based on historical salaries paid to our named executive officers for services rendered to us, market data on compensation paid to similarly situated executives and responsibilities and performance of our named executive officers.
Annual Cash Incentives. The discretionary annual cash bonus awards available to our named executive officers provide an opportunity to supplement annual base salary based on performance so that, on a combined basis, the annual cash compensation opportunity yields competitive cash compensation levels and drives performance in support of our business strategies. It is our general policy to pay these incentive awards prior to the end of the first quarter of the fiscal year following the fiscal year to which they related. The payment of individual cash bonuses to executive management, including our named executive officers, is subject to the sole discretion of the Compensation Committee.
The discretionary annual cash awards are designed to reward our employees for contributions towards our achievement of financial and operational business priorities (including business priorities of the Partnership) approved by the Compensation Committee and to aid us in retaining and motivating employees. 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 or that of our personnel. The Compensation Committee considers all strategic priorities and reviews performance against the priorities and context but does not assign specific weightings to the strategic priorities in advance.
A discretionary cash bonus pool is recommended by our senior management and approved by the Compensation Committee annually based on our achievement of certain strategic, financial and operational objectives. Near or following the end of each year, senior management recommends to the Compensation Committee the total amount of cash to be allocated to the bonus pool based upon our overall performance relative to these objectives. Following receipt of our senior management’s recommendation, the Compensation Committee, in its sole discretion, determines the total amount of cash to be allocated to the bonus pool. Additionally, the Compensation Committee, in its sole discretion, determines the amount of the cash bonus awards to each of our executive officers, including the CEO. The executive officers determine the amount of the cash bonus pool to be allocated to our departments, groups and employees (other than our executive officers) based on performance and on the recommendation of supervisors, managers and line officers.
Long Term Incentive Awards: Stock Incentive Plan and Partnership Long-Term Incentive Plan Awards. In connection with 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 awards, including restricted stock, bonus stock and performance awards. The Stock Incentive Plan provides for discretionary grants of the following types of awards: (a) incentive stock options qualified as such under U.S. federal income tax laws, (b) stock options that do not qualify as incentive stock options, (c) phantom stock awards, (d) restricted stock awards, (e) performance awards, (f) bonus stock awards, or (g) any combination of such awards, although we are currently utilizing only restricted stock and bonus stock awards. The maximum aggregate number of shares of our common stock that may be granted in connection with awards under the Stock Incentive Plan is 5 million, of which approximately 1.9 million shares were awarded in connection with our IPO. The Stock Incentive Plan awards are granted on such terms and conditions and at such purchase price (if any) determined by the Compensation Committee and may, but need not be, subject to performance criteria, objectives, or forfeiture. Additional details relating to shares of restricted stock and bonus stock granted under the Stock Incentive Plan are included below under “—Application of Compensation Elements—Equity Ownership Generally” and “—Executive Compensation Tables—Outstanding Equity Awards at 2011 Fiscal Year-End.”
We may grant to the named executive officers and other key employees performance unit awards under the Partnership’s long-term incentive plan linked to the performance of the Partnership’s common units, with the amounts vesting under such awards dependent on the Partnership’s performance compared to a peer-group consisting of the Partnership and other publicly traded partnerships. These awards, which may be settled in cash or equity, are designed to further align the interests of the named executive officers and other key employees with those of the Partnership’s equity holders. Additional details relating to our peer group applicable to LTIP awards payouts are included below under “—Application of Compensation Elements—Long-Term Cash Incentives.”
Awards to our named executive officers under the Stock Incentive Plan and Partnership’s long-term incentive plan are made near or following the end of each year. For 2011, the long term incentive component of compensation was allocated approximately twenty-five percent to restricted stock awards under the Stock Incentive Plan and seventy-five percent to equity settled performance unit awards under the Partnership’s long-term incentive plan.
Retirement Benefits. We offer eligible employees 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 annual compensation on a pre-tax basis and have it contributed to the plan or contribute such amount on a post-tax basis via a Roth contribution, subject to certain limitations under 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. We may also make discretionary contributions to the 401(k) Plan for the benefit of employees depending on our performance. Contributions made by the Company may be subject to certain limitations under the Code for certain employees.
Health and Welfare Benefits. All full-time employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, health, life insurance and dental coverage and disability insurance.
Perquisites. It is the Compensation Committee’s policy not to pay for perquisites for any of our named executive officers, other than minimal parking subsidies.
Severance and Change in Control Benefits. We maintained the Targa Resources Officer Change in Control Severance Program (the “Officer Change in Control Program”) during the 2011 year for certain officers and key employees other than executive officers. Mr. Meloy was the only named executive officer that met the criteria of an “officer” under the Officer Change in Control Program and participated in this plan during the 2011 year. Following the 2011 year, we adopted the Targa Resources Executive Officer Change in Control Severance Program (the “Executive Change in Control Program”) for our executive officers. Mr. Meloy and the other named executive officers will now participate in the Executive Change in Control Program during the 2012 calendar year. The two plans are similar in the fact that they provide for certain severance payments in the event that a participant incurs a qualifying termination within an eighteen month period following a change in control, although the amounts payable will differ between participants and plans. For more details on the terms and conditions of each of these plans, as well as the potential payment that would have been due to Mr. Meloy in the 2011 year under the Officer Change in Control Program, please see the section below under “—Potential Payments Upon Termination or Change in Control.”
Relation of Compensation Elements to Compensation Philosophy
Our named executive officers, other executives and Section 16 officers and directors, through a combination of personal investment and equity grants, own approximately 11.2% of our fully diluted equity. Based on our named executive officers’ ownership interests in us and their direct ownership of the Partnership’s common units, they own, directly and indirectly, approximately 0.4% of the Partnership’s limited partner interests. The Compensation Committee believes that the executive officers’ ownership interests and the elements of the annual compensation programs available to them align the interests of the executive officers and investors and drive the officers’ performance in support of our and the Partnership’s business strategies.
Application of Compensation Elements
Base Salary. Base salaries for our named executive officers have been established based on historical levels for these officers, taking into consideration officer salaries in our peer group and the value of the total compensation opportunities available to our executive officers including the long-term equity component of our compensation program. During 2010, the Compensation Committee engaged BDO to conduct a new review of executive and key employee compensation to help it assure that compensation goals were being met and that the most recent trends in compensation were appropriately considered. The compensation review indicated that the compensation for our named executive officers was not consistent with compensation paid at MLP peer companies or with our expanded peer group generally when the data is adjusted for company size. In order to begin closing this gap in compensation, the Compensation Committee authorized increases in base salary for our executive officers in 2010 and the Compensation Committee authorized the following increased base salaries for our named executive officers effective April 1, 2011.
|
|
Effective
|
|
|||||
|
|
April 1, 2011
|
Prior Salary
|
|||||
|
Rene R. Joyce
|
$ | 547,000 | $ | 475,000 | |||
|
Joe Bob Perkins
|
468,000 | 412,000 | |||||
|
James W. Whalen
|
468,000 | 412,000 | |||||
|
Michael A. Heim
|
415,000 | 369,000 | |||||
|
Matthew J. Meloy
|
235,000 | 207,500 | |||||
Annual Cash Incentives. The Compensation Committee approved our 2011 Annual Incentive Plan (the “Bonus Plan”) in February 2011. 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 is determined by summing, on an employee by employee basis, the product of base salaries and market-based target bonus percentages that generally range from 6.0% to 100% of each participant’s base salary. For 2011 bonus pool funding purposes, the percentage of salary that was set as the “target” amount for each named executive officer’s bonus was as follows: Mr. Joyce, 100%; Messrs. Perkins, Whalen and Heim, 80%, and Mr. Meloy, 40%.
The CEO and the Compensation Committee relied on compensation consultants and market data from peer companies and broader industry compensation practices to establish the threshold, target and maximum percentage levels, which are generally consistent with both peer company and broader energy compensation practices. The Compensation Committee, after consultation with the CEO, established the following overall threshold, target and maximum levels for the Company’s bonus pool: 50% 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; 100% for the target level and 200% for the maximum level. The Compensation Committee approved the following eight key business priorities to be considered when funding the bonus pool and making awards under the 2011 Bonus Plan: (i) continue to control all operating, capital and general and administrative costs, (ii) invest in our businesses, (iii) continue priority emphasis and strong performance relative to a safe workplace, (iv) reinforce business philosophy and mindset that promotes compliance with all aspects of our business including environmental and regulatory compliance, (v) continue to manage tightly credit, inventory, interest rate and commodity price exposures, (vi) execute on major capital and development projects, such as finalizing negotiations, completing projects on time and on budget, and optimizing economics and capital funding, (vii) pursue selected growth opportunities, including new gathering and processing build-outs leveraging our NGL logistics platform for development projects, other fee-based capital expenditure projects and potential purchases of strategic assets and (viii) execute on all business dimensions to maximize value and manage risks.
In January 2012, the Compensation Committee approved a cash bonus pool equal to 200% of the target level for the employee group, including our named executive officers, under the Bonus Plan for performance during 2011 in recognition of outstanding efforts and organizational performance. 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 2011 based on the eight key business priorities it established for 2011. The Compensation Committee considered or subjectively evaluated (rather than measured) organizational performance by reviewing the apparent overall performance of our personnel with respect to the initial and subsequent business priorities relative to both the overall and management-specific performance expectations of the Compensation Committee, each on an absolute level and relative to the Compensation Committee’s sense of peer performance. 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. Aspects of performance important to this qualitative determination included (i) very strong execution on financial performance, (ii) outstanding pursuit and capture of growth projects, (iii) recent and ongoing capital projects completed or being completed on time and on budget and (iv) strong safety and environmental performance and record and corporate philosophy to promote and maintain safe working conditions as represented by safety awards and industry recognition. This subjective evaluation that performance had substantially exceeded expectations occurred with the background and ongoing context of detailed board and committee refinements of the 2011 business priorities both before the beginning of and during the year, continued board and committee discussion and active dialogue with management about priorities and performance, including routine reports sent to the board or the committee, and presentations and discussions in subsequent board and committee meetings, and further board and committee discussion of performance relative to expectations near the end and following the end of 2011. The extensive business and board experience 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 the executive officers.
With respect to Mr. Meloy’s bonus payment, the Compensation Committee determined that a performance multiplier of 1.25x should be applied to Mr. Meloy’s target bonus amount for the year, which is a similar multiple to the multiple used for other higher performing employees, based on his 2011 contribution in his first full year as the Chief Financial Officer. All other executives recommended and received a 1.0x multiplier equivalent to the average of the bonus pool. The named executive officers received the following bonus awards, which are equivalent to 200% of each individual’s target bonus amount and reflects a 1.25x multiplier for Mr. Meloy and a 1.0x multiplier for the other named executives officers as previously discussed:
|
Rene R. Joyce
|
$ | 1,094,000 | ||
|
Joe Bob Perkins
|
748,800 | |||
|
James W. Whalen
|
748,800 | |||
|
Michael A. Heim
|
664,000 | |||
|
Matthew J. Meloy
|
235,000 |
In addition to the cash bonus awards approved under the Bonus Plan, in February 2011, the Compensation Committee approved an aggregate cash bonus pool of $1.5 million for our executive officers and two other employees in recognition of their role in extraordinary execution of the business priorities, completion of drop downs to the Partnership and clarification of our strategic direction in 2010.
Equity Ownership Generally. Prior to the closing of our IPO, we used both stock options and restricted stock to compensate our employees, including our named executive officers. Based on recommendations by our compensation consultant after completing its compensation review for 2010, we have recently awarded, and we expect future awards under our incentive plans to consist primarily of, restricted stock, restricted units and performance based awards of restricted stock or units or cash-settled performance units (rather than stock options or unit options). In connection with our IPO, our employees, including the named executive officers, were granted an aggregate of approximately 1.9 million shares of restricted stock and bonus stock under the Stock Incentive Plan.
Long-Term Incentive Awards. On February 14, 2011, our named executive officers were awarded restricted common stock of the Company under our Stock Incentive Plan that will vest in three years from the grant date as follows: 7,690 shares to Mr. Joyce, 4,250 shares to Mr. Perkins, 4,250 shares to Mr. Whalen, 3,770 shares to Mr. Heim, and 1,260 shares to Mr. Meloy.
On February 17, 2011, our named executive officers were awarded equity-settled performance units under the Partnership’s long-term incentive plan that will vest in June 2014 as follows: 21,110 performance units to Mr. Joyce, 11,690 performance units to Mr. Perkins, 11,690 performance units to Mr. Whalen, 10,360 performance units to Mr. Heim, and 3,470 performance units to Mr. Meloy. These performance unit awards will be settled by the issuance of an equivalent number of Partnership common units at the time of vesting plus associated distributions over the three year period multiplied by a performance vesting percentage which may be zero or range from 25% to 150%. This equity settlement value of each unit may be higher or lower than the Partnership common unit price at the time of the grant. If the Partnership’s performance equals or exceeds the performance for the 25th percentile of the peer group but is less than or equal to the 50th percentile of the group, then 25% to 100% of the award will vest. If the Partnership’s performance equals or exceeds the performance for the 50th percentile of the group but is less than or equal to the 75th percentile of the group, then 100% to 150% of the award will vest. The vesting between the 25th percentile and the 50th percentile will be done on an interpolated basis between 25% and 100% and the vesting between the 50th percentile and 75th percentile will be done on an interpolated basis between 100% and 150%. If the Partnership’s performance is above the performance of the 75th percentile of the group, the performance percentage will be 150% of the award. If the Partnership’s performance is below the performance of the 25th percentile of the group, the performance percentage will be zero. The performance period for these performance unit awards began on June 30, 2011 and ends on June 30, 2014. The Partnership’s peer group companies for purposes of our long term incentive awards for 2011 were: Copano, Crosstex, DCP Midstream, Enbridge Energy Partners, Energy Transfer Partners, Magellan Midstream, MarkWest Energy Partners, Martin Midstream, ONEOK Partners, Plains All American Pipeline, Regency Energy Partners, Targa Resources Partners LP and Williams Energy Partners.
Set forth below is the “performance for the median” of the peer group for each of the 2011 equity-settled performance unit grants and a comparison of the Partnership’s performance to the peer group as of December 31, 2011:
|
|
|
Performance (1)
|
|
|
||
|
Grant
|
|
Peer Group Median
|
|
Partnership
|
|
Partnership Position (2)
|
|
2011 Performance Units
|
|
8.6%
|
|
10.7%
|
|
Second Quartile (6 of 13)
|
____________
|
(1)
|
Total return 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 (the result being referred to as the “Value Increase”) and (ii) dividing the Value Increase by the Beginning Price. The performance period for the 2011 awards begins on June 30, 2011, and all awards end on the third anniversary of such date.
|
|
(2)
|
Award level based on Partnership Position and linear interpolation as described above.
|
In January 2009 and in December 2009, we granted our executive officers cash-settled performance unit awards linked to the performance of the Partnership’s common units that will vest in June of 2012 and June of 2013, respectively, with the amounts vesting under such awards dependent on the Partnership’s performance compared to a peer-group consisting of the Partnership and other publicly traded partnerships. The Partnership’s peer group companies for purposes of the long term incentive awards made in 2009 is the same peer group used for the equity settled performance units awarded to our executives in 2011.
Severance and Change in Control Benefits. Certain of our equity compensation award agreements contain a “single trigger” for accelerated vesting of equity awards, which means vesting accelerates upon our change in control irrespective of whether the officer is terminated. We also have certain change-of-control severance plans (the Officer Change in Control Program and the Executive Change in Control Program) that provide 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. We believe that these provisions create important retention tools for us, as providing for accelerated vesting of equity awards upon a change in control enables employees to realize value from these awards in the event that we undergo a change in control transaction, while post-termination payments provide employees with value in the event of certain terminations of employment that were beyond their control. In addition, we believe that these benefits may, in part, mitigate some of the potential uncertainty created by a potential or actual change in control transaction, including future employment of the named executive officers. We believe that change in control protections allows management to focus on the business transaction at hand without any distractions regarding the effects of a change in control. Likewise, post-termination payments allow management to focus on making the objective business decisions that are in the interest of our company. Further, we believe that such protections encourage the named executive officers to review objectively any proposed transaction in determining whether such proposed transaction is in the best interest of our shareholders, whether or not the executive will continue to be employed. Executive officers at other companies in our industry and the general market against which we compete for executive talent commonly have equity compensation plans that provide for accelerated vesting upon a change in control event of that company and post-termination payments, and we intend to provide this benefit to the named executive officers in order to remain competitive in attracting and retaining skilled professionals in our industry.
Changes for 2012
Base Salary. The Compensation Committee authorized, and executive management will implement, the following increased base salaries for our named executive officers effective March 1, 2012:
|
|
Effective
|
||||||
|
|
March 1, 2012
|
Current Salary
|
|||||
|
Rene R. Joyce
|
$ | 560,000 | $ | 547,000 | |||
|
Joe Bob Perkins
|
480,000 | 468,000 | |||||
|
James W. Whalen
|
480,000 | 468,000 | |||||
|
Michael A. Heim
|
460,000 | 415,000 | |||||
|
Matthew J. Meloy
|
275,000 | 235,000 | |||||
Annual Cash Incentives. In preparing the Company’s business plan for 2012, senior management developed and proposed a set of strategic priorities to the Compensation Committee. In January 2012, the Compensation Committee approved our 2012 Annual Incentive Compensation Plan (the “2012 Bonus Plan”), the cash bonus plan for performance during 2012, and established the following nine key business priorities: (i) continue to control all operating, capital and general and administrative costs, (ii) invest in our businesses, (iii) continue priority emphasis and strong performance relative to a safe workplace, (iv) reinforce business philosophy and mindset that promotes compliance with all aspects of our business including environmental and regulatory compliance, (v) continue to manage tightly credit, inventory, interest rate and commodity price exposures, (vi) execute on major capital and development projects, such as finalizing negotiations, completing projects on time and on budget, and optimizing economics and capital funding, (vii) pursue selected growth opportunities, including new gathering and processing build-outs, fee-based capital expenditure projects and potential purchases of strategic assets, (viii) pursue commercial and financial approaches to achieve maximum value and manage risks and (ix) execute on all business dimensions, including the financial business plan. The Compensation Committee also established the following overall threshold, target and maximum levels for the Company’s bonus pool: 50% of the cash bonus pool will be funded in the event that the Compensation Committee determines that our business priorities have been met for the year at a threshold level; 100% for the target level and 200% for the maximum level. As with the 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.
For 2012, pursuant to our annual incentive plan and in accordance with prior approval by the Compensation Committee, each executive’s target amount is set as a percentage of his annual base salary. Mr. Joyce’s target amount is set at 100% and Messrs. Perkins, Whalen and Heim’s target amount is set at 80%. Mr. Meloy’s target amount was 40% for 2011. In January 2012 the Compensation Committee decided to increase Mr. Meloy’s target amount to 50% to recognize his increased responsibilities as the Chief Financial Officer. Other than Mr. Meloy, the 2012 bonus targets for the named executive officers are the same levels that were utilized for the 2011 year.
Long-Term Incentive Awards. On January 12, 2012, our named executive officers were awarded restricted common stock of the Company under our stock incentive plan for the 2012 compensation cycle that will vest in three years from the grant date as follows: 6,565 shares to Mr. Joyce, 5,035 shares to Mr. Perkins, 4,235 shares to Mr. Whalen, 4,399 shares to Mr. Heim, and 1,866 shares to Mr. Meloy.
On January 12, 2012, our named executive officers were awarded equity-settled performance units under the Partnership’s long-term incentive plan for the 2012 compensation cycle that will vest in June 2015 as follows: 21,240 performance units to Mr. Joyce, 16,290 performance units to Mr. Perkins, 13,702 performance units to Mr. Whalen, 14,233 performance units to Mr. Heim, and 6,039 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 February 17, 2011 except that the performance period for the 2012 awards will begin on June 30, 2012 and end on June 30, 2015. Please see “Application of Compensation Elements – Long-Term Incentive Awards”.
Severance and Change in Control Benefits. On January 12, 2012, we adopted the Executive Change in Control Program. Specific terms, conditions, and potential payments are detailed under “—Potential Payments Upon Termination or Change in Control.”
Tax and Accounting Considerations. We account for the equity compensation expense for our employees, including our named executive officers, under the rules of FASB ASC Topic 718, which requires us to estimate and record an expense for each award of long-term 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.
Review of the Results of the “Say-on-Pay” Proposal: At the 2011 Annual Meeting, the Company’s stockholders were requested to conduct a non-binding advisory vote to approve the compensation of the Company’s named executive officers. The Board proposal seeking approval, on an advisory basis, of the compensation of the Company’s named executive officers was approved by the stockholders. The Board and Compensation Committee reviewed the results of the vote and concluded that no changes to the Company’s compensation design and philosophy needed to be considered as a result of the vote.
Compensation Committee Interlocks and Insider Participation
No member of our Compensation Committee has been an employee of ours at any time. None of our executive officers served on the Board of Directors or Compensation Committee of a company that has an executive officer that served on our board or Compensation Committee. No member of our board is an executive officer of a company in which one of our executive officers serves as a member of the Board of Directors or Compensation Committee of that company.
Messrs. Kagan and Hwang, both of whom were members of our Compensation Committee during 2011, were affiliates of Warburg Pincus during 2011. Mr. Kagan was a director of Broad Oak during 2011, from whom we bought natural gas and NGL products and provided other services and in which affiliates of Warburg Pincus own a controlling interest. Mr. Kagan was also a director of Antero Resources Corporation (“Antero”) during 2011, from whom we bought natural gas and NGL products and in which affiliates of Warburg Pincus own a controlling interest. Mr. Kagan was a director of Laredo Petroleum, Inc. during 2011, from whom we bought natural gas and in which affiliates of Warburg Pincus own a controlling interest. Messrs. Kagan and Hwang are party to indemnification agreements with us. Warburg Pincus is a party to the Registration Rights Agreement with us. Please read “Transactions With Related Persons” for a description of these transactions.
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, 2011. 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, 2011 for filing with the SEC.
The information contained in this report shall not be deemed to be “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings with the SEC, or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that the company specifically incorporates it by reference into a document filed under the Securities Act of 1933, as amended, or the Exchange Act.
The Compensation Committee
Peter R. Kagan Charles R. Crisp, Chairman In Seon Hwang
Executive Compensation Tables
The following Summary Compensation Table sets forth the compensation of our named executive officers for 2011, 2010 and 2009. Additional details regarding the applicable elements of compensation in the Summary Compensation Table are provided in the footnotes following the table.
|
|
Summary Compensation Table for 2011
|
||||||||||||||||
|
Name
|
Year
|
Salary
|
Bonus (2)
|
Stock Awards (3)
|
All Other Compensation (4)
|
Total Compensation
|
|||||||||||
|
Rene R. Joyce (1)
|
2011
|
$ | 529,000 | $ | 1,094,000 | $ | 979,380 | $ | 23,394 | $ | 2,625,774 | ||||||
|
Chief Executive Officer
|
2010
|
410,000 | 1,120,067 | 5,358,408 | 22,410 | 6,910,885 | |||||||||||
|
|
2009
|
337,500 | 510,000 | 1,398,946 | 20,187 | 2,266,633 | |||||||||||
|
|
|
||||||||||||||||
|
Matthew J. Meloy
|
2011
|
228,125 | 235,000 | 160,859 | 19,771 | 643,755 | |||||||||||
|
Senior Vice President, Chief
|
2010
|
195,625 | 224,100 | 493,350 | 19,740 | 932,815 | |||||||||||
|
Financial Officer and Treasurer
|
|
||||||||||||||||
|
|
|
||||||||||||||||
|
Joe Bob Perkins (1)
|
2011
|
454,000 | 748,800 | 542,079 | 20,715 | 1,765,594 | |||||||||||
|
President
|
2010
|
361,250 | 823,191 | 3,831,960 | 20,448 | 5,036,849 | |||||||||||
|
|
2009
|
303,750 | 459,000 | 970,109 | 20,129 | 1,752,988 | |||||||||||
|
|
|
||||||||||||||||
|
James W. Whalen (1)
|
2011
|
454,000 | 748,800 | 542,079 | 29,587 | 1,774,466 | |||||||||||
|
Executive Chairman of
|
2010
|
356,750 | 593,280 | 3,831,960 | 22,338 | 4,804,328 | |||||||||||
|
the Board of Directors
|
2009
|
297,000 | 445,500 | 543,150 | 19,936 | 1,305,586 | |||||||||||
|
|
|
||||||||||||||||
|
Michael A. Heim (1)
|
2011
|
403,500 | 664,000 | 480,517 | 22,400 | 1,570,417 | |||||||||||
|
Chief Operating Officer
|
2010
|
328,000 | 1,469,275 | 2,699,620 | 21,776 | 4,518,671 | |||||||||||
| 2009 | 281,000 | 425,500 | 810,117 | 20,089 | 1,535,706 | ||||||||||||
____________
|
(1)
|
Mr. Joyce became Executive Chairman of the Board of Directors in January 2012 but served as Chief Executive Officer during the 2011 year. Mr. Perkins became Chief Executive Officer in January 2012 but served as President during the 2011 year. Mr. Whalen became Advisor to Chairman and Chief Executive Officer in January 2012 but served as Executive Chairman of the Board of Directors during the 2011 year. Mr. Heim became President and Chief Operating Officer in January 2012 but served as Chief Operating Officer during the 2011 year.
|
|
(2)
|
For 2011, represents payments pursuant to our Bonus Plan. For the 2010 year, payments pursuant to our Bonus Plan were made in the following amounts: Mr. Joyce, $855,000; Mr. Meloy, $224,100; Mr. Perkins, $593,280; Mr. Whalen, $593,280; and Mr. Heim, $531,360. For 2010, also represents discretionary cash bonuses paid to the named executive officers in recognition of the executive team’s role in extraordinary execution of the business priorities, completion of drop downs to the Partnership and clarification of our strategic direction in 2010 ($265,067 for Mr. Joyce, $229,911 for Mr. Perkins, and $205,915 for Mr. Heim). For 2010, $732,000 of the amount reported for Mr. Heim represents a cash bonus paid in lieu of equity in connection with the IPO. For 2009, represents payments pursuant to our Bonus Plan. Please see “—Application of Compensation Elements—Annual Cash Incentives.” Note that, in prior filings, the payments reported under this column pursuant to our Bonus Plan for the 2009 and 2010 years 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.
|
|
(3)
|
Includes restricted stock awards and equity-settled performance units. For 2010, includes bonus stock and restricted stock awards. Amounts represent the aggregate grant date fair value of awards 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 F-1 of our Annual Report on Form 10-K. Detailed information about the amount recognized for specific awards is reported in the table under “—Grants of Plan-Based Awards for 2011” below. The grant date fair value of a common stock award granted on February 14, 2011, assuming vesting will occur, is $31.745 and the grant date fair value of an equity settled performance award on February 17, 2011 is $34.83 assuming the probable outcome of the performance criteria assigned to the awards. The grant date value of a equity-settled performance unit award granted on February 17, 2011 (for the 2011 compensation cycle) assuming the highest performance condition will be achieved, is $34.83 per unit and a payout of 150% of the units granted. Accordingly, the highest aggregate value of the performance unit awards granted in 2011 for the named executive officers is as follows: Mr. Joyce - $1,102,892; Mr. Meloy - $181,290; Mr. Perkins - $610,774; Mr. Whalen - $610,774; and Mr. Heim - $541,258.
|
|
(4)
|
For 2011 “All Other Compensation” includes the (i) aggregate value of matching and non-matching contributions to our 401(k) plan and (ii) the dollar value of life insurance coverage provided by the Company.
|
|
|
401(k) and Profit
|
Dollar Value of
|
|
|||||||
|
Name
|
Sharing Plan
|
Life Insurance
|
Total
|
|||||||
|
Rene R. Joyce
|
$ | 19,600 | $ | 3,794 | $ | 23,394 | ||||
|
Matthew J. Meloy
|
19,600 | 171 | 19,771 | |||||||
|
Joe Bob Perkins
|
19,600 | 1,115 | 20,715 | |||||||
|
James W. Whalen
|
19,600 | 9,987 | 29,587 | |||||||
|
Michael A. Heim
|
19,600 | 2,800 | 22,400 | |||||||
Grants of Plan Based Awards for 2011
The following table and the footnotes thereto provide information regarding grants of plan-based equity and non-equity awards made to the named executive officers during 2011:
|
|
|
Estimated Possible Payouts Under
|
||||||||||||||||
|
|
|
Equity Incentive Plan Awards (1)
|
||||||||||||||||
|
Name
|
Grant Date
|
Threshold
|
Target
|
Maximum
|
All Other Stock Awards: Number of Shares of Stocks or Units (1)
|
Grant Date Fair Value
of Stock and Unit
Awards (2)
|
||||||||||||
|
Mr. Joyce
|
2/14/2011
|
|
|
|
7,690 | $ | 244,119 | |||||||||||
|
|
2/17/2011
|
5,278 | 21,110 | 31,665 | 735,261 | |||||||||||||
|
|
|
|||||||||||||||||
|
Mr. Meloy
|
2/14/2011
|
1,260 | 39,999 | |||||||||||||||
|
|
2/17/2011
|
868 | 3,470 | 5,205 | 120,860 | |||||||||||||
|
|
|
|||||||||||||||||
|
Mr. Perkins
|
2/14/2011
|
4,250 | 134,916 | |||||||||||||||
|
|
2/17/2011
|
2,923 | 11,690 | 17,535 | 407,163 | |||||||||||||
|
|
|
|||||||||||||||||
|
Mr. Whalen
|
2/14/2011
|
4,250 | 134,916 | |||||||||||||||
|
|
2/17/2011
|
2,923 | 11,690 | 17,535 | 407,163 | |||||||||||||
|
|
|
|||||||||||||||||
|
Mr. Heim
|
2/14/2011
|
3,770 | 119,679 | |||||||||||||||
|
|
2/17/2011
|
2,590 | 10,360 | 15,540 | 360,839 | |||||||||||||
____________
|
(1)
|
The grants on February 14, 2011 are restricted common stock awards granted under our Stock Incentive Plan. The grants on February 17, 2011 are 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 Partnership’s performance units, see “——Application of Compensation Elements—Long-Term Incentive Awards.”
|
|
(2)
|
The dollar amounts shown for the common stock awards granted on February 14, 2011 are determined by multiplying the shares reported in the table by $31.745 (the grant date fair value of awards computed in accordance with FASB ASC Topic 718). The dollar amounts shown for the performance units granted on February 17, 2011 are determined by multiplying the number of units reported in the table under the “Target” column by $34.83 (the grant date fair value of awards computed in accordance with FASB ASC Topic 718).
|
Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards Table
A discussion of 2011 salaries, bonuses, incentive plans and awards is included in “—Compensation Discussion and Analysis.”
Stock Incentive Plan
Restricted Stock Awards. Subject to the terms of the applicable restricted stock agreement, restricted stock granted under the Stock Incentive Plan during 2011 vests 100% three years from the date of grant. The named executive officers have all of the rights of a stockholder of the Company with respect to the restricted stock granted in 2011 including, without limitation, voting rights. The named executive officers do not have the right to receive any dividends or other distributions, including any special or extraordinary dividends or distributions, with respect to the restricted stock granted in 2011 unless and until the restricted stock vests. Dividends on unvested restricted stock are credited to an unfunded account maintained by the Company. These credited dividends are paid to the employee when the shares of restricted stock vest. In the event all or any portion of the restricted stock granted in 2011 fails to vest, such restricted stock and dividends will be forfeited to us.
LTIP Performance Unit Awards. Subject to the terms of the applicable performance unit award agreement, performance units granted under the Partnership’s long term incentive plan during 2011 vest in June 2014. The vesting and settlement value of these performance unit awards will be determined using the formula adopted for the performance unit awards, as described under “—Application of Compensation Elements – Long=Term Incentive Awards.” The named executive officers do not have the rights of a unitholder of the Partnership with respect to the performance unit awards granted in 2011. The named executive officers do not have the right to receive any distribution with respect to the performance unit awards granted in 2011 unless and until the performance units vest. Distributions on unvested performance unit awards are credited to an unfunded account maintained by the Partnership. These credited distributions are paid to the employee when the performance units vest. In the event all or any portion of the performance units granted in 2011 fails to vest, such performance units and distributions will be forfeited to us. Please see “—Compensation Discussion and Analysis—Elements of Compensation for Named Executive Officers—Long-Term Incentive Awards: Stock Incentive Plan and Partnership Long-Term Incentive Awards” and “—Application of Compensation Elements— Long-Term Incentive Awards” for a detailed discussion of the grants of restricted stock and performance unit awards.
Outstanding Equity Awards at 2011 Fiscal Year-End
The following table and the footnotes related thereto provide information regarding each stock option and other equity-based awards outstanding as of December 31, 2011 for each of our named executive officers.
|
|
Outstanding Equity Awards at 2011 Fiscal Year-End
|
||||||||||||
|
|
Stock Awards
|
||||||||||||
|
Name
|
Number of Shares of Stock That Have Not Vested (1)
|
Market Value of Shares of Stock That Have Not Vested (2)
|
Equity Incentive Plan Awards: Number of Unearned Performance Units That Have Not
Vested (3)
|
Equity Incentive Plan Awards: Market or Payout Value of Unearned Performance Units That Have Not
Vested (4)
|
|||||||||
|
Rene R. Joyce
|
128,815 | $ | 5,241,482 | 85,167 | $ | 3,750,672 | |||||||
|
Matthew J. Meloy
|
23,685 | 963,743 | 17,466 | 768,892 | |||||||||
|
Joe Bob Perkins
|
72,230 | 2,939,039 | 54,952 | 2,419,976 | |||||||||
|
James W. Whalen
|
72,230 | 2,939,039 | 33,558 | 1,481,962 | |||||||||
|
Michael A. Heim
|
64,655 | 2,630,812 | 47,482 | 2,090,324 | |||||||||
____________
|
(1)
|
Represents shares of our restricted common stock awarded on December 10, 2010 and February 14, 2011. The 340,395 shares granted in 2010 (121,125 shares held by Mr. Joyce, 22,425 shares held by Mr. Meloy, 67,980 shares held by Mr. Perkins, 67,980 shares held by Mr. Whalen, and 60,885 shares held by Mr. Heim) vest as follows: 60% on December 10, 2012 and 40% on December 10, 2013. The 21,220 shares granted in 2011 (7,690 shares held by Mr. Joyce, 1,260 shares held by Mr. Meloy, 4,250 shares held by Mr. Perkins, 4,250 shares held by Mr. Whalen, and 3,770 shares held by Mr. Heim) vest 100% on February 14, 2014.
|
|
(2)
|
The dollar amounts shown are determined by multiplying the number of shares of common stock reported in the table by the sum of the closing price of a share of common stock on December 31, 2011 ($40.69).
|
|
(3)
|
Represents the number of performance units awarded on January 22, 2009, December 3, 2009 and February17, 2011under the Partnership’s and our long-term incentive plans. With respect to Mr. Meloy, the performance units were granted on August 4, 2009, August 2, 2010 and February 17, 2011. These awards vest in June 2012, June 2013 and June 2014, based on the Partnership’s performance over the applicable period measured against a peer group of companies. These awards are discussed in more detail under the heading “—Application of Compensation Elements— Long-Term Incentive Awards.”
|
|
(4)
|
The dollar amounts shown are determined by multiplying the number of performance units reported in the table by the sum of the closing price of a common unit of the Partnership on December 31, 2011 ($37.28) and the related distribution equivalent rights for each award and assume full payout under the awards at the time of vesting.
|
Option Exercises and Stock Vested in 2011
The following table provides the amount realized during 2011 by each named executive officer upon the vesting of our restricted common stock and performance units. None of our named executive officers exercised stock option awards during the 2011 year and currently, there are no stock options outstanding under any of our plans.
|
|
Stock Vested for 2011
|
||||||
|
Name
|
Number of Shares Acquired on
Vesting (1)
|
Value Realized on Vesting (2)
|
|||||
|
Rene R. Joyce
|
4,000 | $ | 170,880 | ||||
|
Matthew J. Meloy
|
1,500 | 62,089 | |||||
|
Joe Bob Perkins
|
3,500 | 149,520 | |||||
|
James W. Whalen
|
3,500 | 149,520 | |||||
|
Michael A. Heim
|
3,500 | 149,520 | |||||
____________
|
(1)
|
Represents performance units granted in January 2008 that vested in August 2011 and were settled by cash payment (Mr. Meloy’s grant was made in August 2008).
|
|
(2)
|
Computed by multiplying the number of performance units by the value of an equivalent Partnership common unit at the time of vesting and adding associated distributions over the vesting period
|
Potential Payments Upon Termination or Change in Control
Aggregate Payments. The table below reflects the aggregate amount of payments that we believe our named executive officers would have received under our Stock Incentive Plan, the Partnership’s long term incentive plan, the Officer Change in Control Program and the Executive Change in Control Program upon a termination of employment and/or a change in control that occurred on December 31, 2011. Details regarding individual plans and arrangements follow the table.
|
Name
|
Change of Control
(No Termination)
|
Qualifying Termination Following Change in Control
|
Termination by us Without Cause
|
Termination for Death or Disability
|
|||||||||
|
Rene R. Joyce
|
$ | 8,352,952 | $ | 8,352,952 | $ | 8,352,952 | $ | 8,352,952 | |||||
|
Matthew J. Meloy
|
1,601,202 | 2,301,839 | 1,601,202 | 1,601,202 | |||||||||
|
Joe Bob Perkins
|
4,904,523 | 4,904,523 | 4,904,523 | 4,904,523 | |||||||||
|
James W. Whalen
|
4,000,856 | 4,000,856 | 4,000,856 | 4,000,856 | |||||||||
|
Michael A. Heim
|
4,377,255 | 4,377,255 | 4,377,255 | 4,377,255 | |||||||||
Stock Incentive Plan. If a Change in Control (as defined below) 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 our form of restricted stock agreement (the “Stock Agreement”) 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 Agreement and related dividends then credited to him will fully vest if his employment is terminated by reason of death or a Disability (as defined below). 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 Agreement:
|
·
|
Affiliate means an entity or organization which, directly or indirectly, controls, is controlled by, or is under common control with, the Company.
|
|
·
|
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 Company’s voting stock or more than 50% of the combined voting power of the equity interests in the Partnership or the general partner of the Partnership; (ii) the liquidation or dissolution of the Company 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 the Company of all or substantially all of its 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 the Partnership of all or substantially all of its assets in one or more transactions to any person other than to Warburg Pincus LLC, Targa Resources GP LLC, 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 directors of the Company before such election shall cease to constitute a majority of the Company’s Board of Directors. Notwithstanding the foregoing, with respect to an award under the Stock Incentive Plan that is subject to section 409A of the Code, and with respect to which a Change in Control will accelerate payment, “Change in Control” shall mean a “change of control event” as defined in the regulations and guidance issued under section 409A of the Code.
|
|
·
|
Disability means a disability that entitles the named executive officer to disability benefits under our long-term disability plan.
|
The following table reflects payments that would have been made to each of the named executive officers under the Stock Incentive Plan and related agreements in the event there was a Change in Control or their employment was terminated, each as of December 31, 2011.
|
|
|
Termination for
|
||||||
|
Name
|
Change of Control (1)
|
Death or Disability (1)
|
||||||
|
Rene R. Joyce
|
$ | 5,358,917 | (1) | $ | 5,358,917 | |||
|
Matthew J. Meloy
|
985,387 | (2) | 985,387 | |||||
|
Joe Bob Perkins
|
3,004,908 | (3) | 3,004,908 | |||||
|
James W. Whalen
|
3,004,908 | (4) | 3,004,908 | |||||
|
Michael A. Heim
|
2,689,785 | (5) | 2,689,785 | |||||
_________
|
(1)
|
Of each amount under the “Change of Control” column and the “Termination for Death or Disability” column, $2,957,146 and $67,704 relate to the restricted stock and related distribution equivalent rights granted on December 10, 2010 which vest December 10, 2012; $1,971,430 and $45,136 relate to the restricted stock and related distribution equivalent rights granted on December 10, 2010 which vest December 10, 2013; and $312,906 and $4,595 relate to the restricted stock and related distribution equivalent rights granted on February 14, 2011.
|
|
(2)
|
Of each amount under the “Change of Control” column and the “Termination for Death or Disability” column, $547,485 and $12,535 relate to the restricted stock and related distribution equivalent rights granted on December 10, 2010 which vest December 10, 2012; $364,989 and $8,356 relate to the restricted stock and related distribution equivalent rights granted on December 10, 2010 which vest December 10, 2013; and $51,269 and $753 relate to the restricted stock and related distribution equivalent rights granted on February 14, 2011.
|
|
(3)
|
Of each amount under the “Change of Control” column and the “Termination for Death or Disability” column, $1,659,664 and $37,998 relate to the restricted stock and related distribution equivalent rights granted on December 10, 2010 which vest December 10, 2012; $1,106,442 and $25,332 relate to the restricted stock and related distribution equivalent rights granted on December 10, 2010 which vest December 10, 2013; and $172,933 and $2,539 relate to the restricted stock and related distribution equivalent rights granted on February 14, 2011.
|
|
(4)
|
Of each amount under the “Change of Control” column and the “Termination for Death or Disability” column, $1,659,664 and $37,998 relate to the restricted stock and related distribution equivalent rights granted on December 10, 2010 which vest December 10, 2012; $1,106,442 and $25,332 relate to the restricted stock and related distribution equivalent rights granted on December 10, 2010 which vest December 10, 2013; and $172,933 and $2,539 relate to the restricted stock and related distribution equivalent rights granted on February 14, 2011.
|
|
(5)
|
Of each amount under the “Change of Control” column and the “Termination for Death or Disability” column, $1,486,446 and $34,031 relate to the restricted stock and related distribution equivalent rights granted on December 10, 2010 which vest December 10, 2012; $990,964 and $22,688 relate to the restricted stock and related distribution equivalent rights granted on December 10, 2010 which vest December 10, 2013; and $153,401 and $2,253 relate to the restricted stock and related distribution equivalent rights granted on February 14, 2011.
|
Partnership’s Long-Term Incentive Plan. If a Change of Control (as defined below) occurs during the performance period established for the cash-settled performance units and related distribution equivalent rights granted to a named executive officer under the Partnership’s form of Performance Unit Grant Agreement (a “Performance Unit Agreement”), the performance units and related distribution equivalent rights then credited to a named executive officer will be cancelled and the named executive officer will be paid an amount of cash equal to the sum of (i) the product of (a) the fair market value of a common unit of the Partnership multiplied by (b) the number of performance units granted to the named executive officer, plus (ii) the amount of distribution equivalent rights then credited to the named executive officer, if any. Following a Change of Control, equity-settled performance units will be settled by providing the holder with a number of common units of the Partnership equal to the 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.
Performance units and the related distribution equivalent rights granted to a named executive officer under a Performance Unit Agreement will be automatically forfeited without payment upon the termination of his employment with us and our affiliates, except that: if his employment is terminated by reason of his death, a disability that entitles him to disability benefits under our long-term disability plan or by us other than for Cause (as defined below), he will be vested in his performance units that he is otherwise qualified to receive payment for based on achievement of the performance goal at the end of the performance period.
The following terms have the specified meanings for purposes of the Partnership’s long-term incentive plan: :
|
·
|
Change of Control means (i) any person or group, other than an affiliate of us, becoming the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Partnership or its general partner, (ii) the limited partners of the Partnership approving 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 the Partnership’s general partner or one of such general partner’s affiliates being the general partner of the Partnership. With respect to an award subject to Section 409A of the Code, Change of Control will mean a “change of control event” as defined in the regulations and guidance issued under Section 409A of the Code.
|
|
·
|
Cause means (i) failure to perform assigned duties and responsibilities, (ii) engaging in conduct which is injurious (monetarily of 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 our long-term incentive plan and the Performance Unit Agreement.
|
The following table reflects payments that would have been made to each of the named executive officers under the Partnership’s long-term incentive plan and related agreements in the event there was a Change of Control or their employment was terminated, each as of December 31, 2011.
|
|
|
Death or Disability
|
||||||
|
Name
|
Change of Control
|
or by us Without Cause
|
||||||
|
Rene R. Joyce
|
$ | 2,994,035 | (1) | $ | 2,994,035 | (1) | ||
|
Matthew J. Meloy
|
615,815 | (2) | 615,815 | (2) | ||||
|
Joe Bob Perkins
|
1,899,615 | (3) | 1,899,615 | (3) | ||||
|
James W. Whalen
|
995,948 | (4) | 995,948 | (4) | ||||
|
Michael A. Heim
|
1,687,470 | (5) | 1,687,470 | (5) | ||||
_________
|
(1)
|
Of each amount under the “Change of Control” column and the “Termination for Death or Disability, or by us without Cause” column, $1,267,520 and $183,345 relate to the performance units and related distribution equivalent rights granted on January 22, 2009; $671,972 and $59,888 relate to the performance units and related distribution equivalent rights granted on December 3, 2009; and $786,981 and $24,329 relate to the performance units and related distribution equivalent rights granted on February 17, 2011.
|
|
(2)
|
Of each amount under the “Change of Control” column and the “Termination for Death or Disability, or by us without Cause” column, $279,600 and $40,444 relate to the performance units and related distribution equivalent rights granted on August 4, 2009; $149,120 and $13,290 relate to the performance units and related distribution equivalent rights granted on August 2, 2010; and $129,362 and $3,999 relate to the performance units and related distribution equivalent rights granted on February 17, 2011.
|
|
(3)
|
Of each amount under the “Change of Control” column and the “Termination for Death or Disability, or by us without Cause” column, $775,424 and $112,164 relate to the performance units and related distribution equivalent rights granted on January 22, 2009; $516,701 and $46,050 relate to the performance units and related distribution equivalent rights granted on December 3, 2009; and $435,803 and $13,473 relate to the performance units and related distribution equivalent rights granted on February 17, 2011.
|
|
(4)
|
Of each amount under the “Change of Control” column and the “Termination for Death or Disability, or by us without Cause” column, none relate to the performance units and related distribution equivalent rights granted on January 22, 2009; $501,938 and $44,734 relate to the performance units and related distribution equivalent rights granted on December 3, 2009; and $435,803 and $13,473 relate to the performance units and related distribution equivalent rights granted on February 17, 2011.
|
|
(5)
|
Of each amount under the “Change of Control” column and the “Termination for Death or Disability, or by us without Cause” column, $775,424 and $112,164 relate to the performance units and related distribution equivalent rights granted on January 22, 2009; $368,848 and $32,873 relate to the performance units and related distribution equivalent rights granted on December 3, 2009; and $386,221 and $11,940 relate to the performance units and related distribution equivalent rights granted on February 17, 2011.
|
Executive Officer Change in Control Severance Program
We adopted the Executive Change in Control Program on and effective as of January 12, 2012. Each of our named executive officers became eligible to participate in the Executive Change in Control Program during the 2012 calendar year.
The Executive Change in Control Program is administered by our Vice President – Human Resources. The Executive 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 within 60 days following the date of termination, equal to three times (i) the individual’s annual salary as of the date of the Change in Control or the date or termination, whichever is greater, and (ii) an amount of the named executive officer’s annual cash incentive bonus equal to performance at the “target” level under the applicable annual incentive compensation plan in place at the time the termination occurs. In addition, the participant (and his dependents, as applicable) will receive the continuation of their medical and dental benefits for a period of three years from the date of termination.
For purposes of the Executive Change in Control Program, the following terms will generally have the meanings set forth below:
|
·
|
Cause will be defined in substantially the same manner as noted above with respect to the Partnership’s long-term incentive plan.
|
|
·
|
Change in Control will be defined in substantially the same manner as noted above with respect to the Stock Incentive Plan.
|
|
·
|
Good Reason means, without the express written consent of the individual: (i) a material reduction in the individual’s authority, duties or responsibilities, (ii) a material reduction in the individual’s base compensation, or (iii) a material change in the geographical location at which the individual normally performs the individual’s services, except for travel reasonably required in the performance of the individual’s responsibilities. 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 without Cause or (ii) a voluntary termination of the individual’s employment for Good Reason.
|
All payments due under the Executive 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 Executive 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 Executive 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. .
Officer Change in Control Severance Program
Mr. Meloy participated in the Officer Change in Control Program during the 2011 year, which became effective July 1, 2010. The Officer Change in Control Program is very similar to the Executive Change in Control Program described above. Other than the eligibility provisions, the material differences in the plan are that the severance multiplier for participants will be set at one to two, rather than the multiplier of three utilized in the Executive Change in Control Program. Under the Officer Change in Control Program in 2011, Mr. Meloy would receive a severance multiplier of two. In addition, he (and his dependents, as applicable) would receive the continuation of their medical and dental benefits for a period of two years following his termination of employment. Other definitions and terms described above for the Officer Change in Control Program are similar to those in the Executive Change in Control Program.
In the event that Mr. Meloy had incurred a Qualifying Termination on December 31, 2011 that was within the eighteen month protection period following a Change in Control, and assuming he had properly executed a release in our favor, he would have received a cash severance payment equal to $658,000, and our best estimate of the amount of the continued health and welfare benefits to Mr. Meloy would equal a value of $42,637.
Effective January 12, 2012, Mr. Meloy was included in the Executive Change in Control Program and not included in the Officer Change in Control Program.
Director Compensation
The following table sets forth the compensation earned by our non-employee directors for 2011:
|
|
Director Compensation for 2011
|
|||||||||
|
Name
|
Fees Earned or
Paid in Cash
|
Stock Awards (5)
|
Total Compensation
|
|||||||
|
Charles R. Crisp (1)(2)(3)
|
$ | 87,000 | $ | 301,895 | $ | 388,895 | ||||
|
Ershel C. Redd Jr. (1)(2)
|
69,500 | 73,331 | 142,831 | |||||||
|
Chris Tong (1)(2)(3)
|
92,500 | 247,928 | 340,428 | |||||||
|
Peter R. Kagan (1)(2)(4)
|
84,000 | 73,331 | 157,331 | |||||||
|
In Seon Hwang (1)(2)(4)
|
69,500 | 73,331 | 142,831 | |||||||
_________
|
(1)
|
On February 14, 2011, each director received 2,310 shares of common stock of the Company in connection with their service on our Board of Directors and on February 17, 2011, Messrs. Kagan and Hwang each received 2,120 common units of the Partnership in connection with their service on the Board of Directors of the general partner. The grant date fair value of each share of common stock or common unit granted to each of these named individuals computed in accordance with FAS 123R was $31.745 for shares of Company common stock and $33.525 for the Partnership’s common units, based on the average of the high and low price of the shares or common units on the date of grant.
|
|
(2)
|
As of December 31, 2011, Mr. Crisp held 11,350 common units and 149,590 shares of common stock, Mr. Redd held 1,100 common units and 2,510 shares of common stock, Mr. Tong held 23,150 common units and 58,249 shares of common stock, Mr. Kagan held 12,370 common units and 2,310 shares of common stock and Mr. Hwang 2,120 common units and 2,310 shares of common stock.
|
|
(3)
|
On February 14, 2011, Mr. Crisp received 7,200 shares of common stock of the Company and Mr. Tong received 5,500 shares of common stock of the Company in partial consideration of their agreement to cancel outstanding stock options to acquire common stock in connection with our IPO. The grant date fair value of each common unit granted to each of these named individuals computed in accordance with FASB ASC Topic 718 was $31.745, based on the average of the high and low price of the common units on the day of the grant date.
|
|
(4)
|
Each of Messrs. Kagan and Hwang earned $63,500 in fees for service on the Board of Directors of the partnership’s general partner in 2011. Mr. Kagan’s compensation included $63,500 in fees, $71,073 in common unit awards and $99,273 in all other compensation. Mr. Hwang’s compensation included $63,500 in fees, $71,073 in common unit awards and $0 in all other compensation.
|
|
(5)
|
Amounts represent the aggregate grant date fair value of awards 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 of common unit and common stock awards 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, 2011.
|
Narrative to Director Compensation Table
For 2011, all independent directors received an annual cash retainer of $50,000. The Chairman of the Audit Committee received an additional annual retainer of $20,000 and the Chairman of each of the Compensation Committee and Governing and Nominating Committee received additional retainers of $10,000. All of our independent directors receive $1,500 for each Board, Audit Committee, Compensation Committee, Governance and Nominating Committee and Conflicts Committee meeting attended. Payment of independent director fees is generally made twice annually, at the second regularly scheduled meeting of the Board and the final regularly scheduled meeting of the Board for the fiscal year. All independent directors are reimbursed for out-of-pocket expenses incurred in attending Board and committee meetings.
A director who is also an employee receives no additional compensation for services as a director. Accordingly, the Summary Compensation Table reflects total compensation received by Messrs. Joyce, Perkins and Whalen for services performed for us and our affiliates.
Director Long-term Equity Incentives. The Company made equity-based awards in February 2011 to our non-management and independent directors under the Stock Incentive Plan. Each of these directors received an award of 2,310 shares of common stock of the Company, which reflected our intent to provide them with a target value of approximately $75,000 in long-term incentive awards. The awards are intended to align the long-term interests of our directors with those of the Company’s stockholders. Our independent and non-management directors currently participate in the Stock Incentive Plan.
Changes for 2012
Director Compensation. In January 2012, the Board of Directors approved changes to director compensation for the 2012 fiscal year. For 2012, the Chairman of the Compensation Committee will receive an additional annual retainer of $5,000 to bring the total retainer to $15,000. This increase is intended to compensate the Chairman for increased time he will expend on committee matters due to new regulations that are applicable to compensation matters.
Director Long-term Equity Incentives. In January 2012, each of our non-management and independent directors received an award of 1,851 shares of our common stock under the Stock Incentive Plan, which reflects our desire to increase the target value of those awards from approximately $70,000 to $75,000 per year.
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 17, 2012 held by:
|
·
|
each person who beneficially owns more than 5% of our 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 42,441,543 shares of our common stock and 89,170,989 common units of the Partnership outstanding on February 17, 2012.
|
|
Targa Resources Partners LP
|
Targa Resources Corp.
|
|||||||||||
|
Name of Beneficial Owner (1)
|
Common Units Beneficially Owned (8)
|
Percentage of Common Units Beneficially Owned
|
Common Stock Beneficially Owned
|
Percentage of Common Stock Beneficially Owned
|
|||||||||
|
Warburg Pincus Private Equity VIII, L.P. (2)
|
|
|
6,085,611 | 14.3% | |||||||||
|
Warburg Pincus Netherlands Private Equity VIII C.V.I (2)
|
|
|
176,395 | * | |||||||||
|
WP-WPVIII Investors, L.P. (2)
|
|
|
17,645 | * | |||||||||
|
Warburg Pincus Private Equity IX, L.P. (2)
|
|
|
3,528,488 | 8.3% | |||||||||
|
Rene R. Joyce (3)
|
81,000 | * | 1,129,161 | 2.7% | |||||||||
|
Joe Bob Perkins (4)
|
32,100 | * | 620,093 | 1.5% | |||||||||
|
Michael A. Heim (5)
|
8,000 | * | 614,951 | 1.4% | |||||||||
|
Jeffrey J. McParland
|
16,500 | * | 473,206 | 1.1% | |||||||||
|
James W. Whalen (6)
|
111,152 | * | 641,914 | 1.5% | |||||||||
|
Matthew J Meloy
|
6,000 | * | 81,465 | * | |||||||||
|
In Seon Hwang (7)
|
4,116 | * | 9,812,300 | 23.1% | |||||||||
|
Peter R. Kagan (7)
|
14,366 | * | 9,812,300 | 23.1% | |||||||||
|
Chris Tong
|
23,150 | * | 60,100 | * | |||||||||
|
Charles R. Crisp
|
11,350 | * | 151,441 | * | |||||||||
|
Ershel C. Redd Jr.
|
1,100 | * | 4,361 | * | |||||||||
|
|
|||||||||||||
|
All directors and executive officers
|
|||||||||||||
|
as a group (14 persons) (7)
|
383,232 | * | 14,572,543 | 34.3% | |||||||||
_________
* 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 23% 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)
|
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.
|
|
(4)
|
Shares of common stock beneficially owned by Mr. Perkins include 407,370 shares issued to the Perkins Blue House Investments Limited Partnership.
|
|
(5)
|
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 Nicholas Heim are co-trustees and have shared voting and investment power; and (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.
|
|
(6)
|
Shares of common stock beneficially owned by Mr. Whalen include 459,249 shares issued to the Whalen Family Investments Limited Partnership.
|
|
(7)
|
All shares indicated as owned by Messrs. Hwang and Kagan other than 4,161 shares issued to each of Messrs. Hwang and Kagan in their capacity as directors are included because of their affiliation with the Warburg Pincus entities.
|
|
(8)
|
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, 2011 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.
|
Plan category
|
|
Number of securities to be issued upon exercise of outstanding options, warrants and rights
|
|
Weighted average exercise price of outstanding options, warrants and rights
|
|
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
|
|
|
|
|
|
|
(a)
|
|
(b) |
|
(c)
|
|
|
Equity compensation plans approved by security holders
|
|
-
|
|
-
|
|
2,987,686
|
(1)
|
|
|
|
Total
|
|
-
|
|
-
|
|
2,987,686
|
|
____________
|
(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. 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 17, 2012 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 89,170,989 outstanding common units of the Partnership, representing a 14.5% limited partnership interest.
|
Omnibus Agreement
Our Omnibus Agreement with the Partnership addresses the reimbursement to us for costs incurred 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 are 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.
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,.
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 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. Sajet owns certain technology rights, real property and ownership interests in Floridian Natural Gas Storage Company LLC. We provide general and administrative services to Sajet and are reimbursed for these amounts at our actual cost. During 2011, we were reimbursed $0.3 million for such services provided.
Relationship with Warburg Pincus LLC
Affiliates of Warburg Pincus beneficially own approximately 23.1% 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 Broad Oak, Antero and Laredo from whom the Partnership buys natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak, Antero and Laredo. Purchases from Antero were less than $120,000.
The following table shows the Partnership’s transactions with Broad Oak and Laredo:
|
|
Purchases
|
|||
|
|
2011
|
|||
|
|
(In millions)
|
|||
|
Broad Oak
|
$ | 71.3 | ||
|
Laredo
|
34.1 | |||
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 director of Total Safety US Inc. (“Total Safety”) which provides us safety services and equipment, including detection and monitoring systems. Affiliates of Warburg Pincus own a controlling interest in Total Safety. During 2011, we made payments of $170,157 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 Sequent Energy Management, LP (“Sequent”) from and to whom the Partnership purchases and sells natural gas and NGL products. 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. (“ICE”) from whom the Partnership purchases brokerage services. The following table shows the Partnership’s transactions with each of these entities.
|
|
Sales
|
Purchases
|
|||||
|
|
2011
|
2011
|
|||||
|
|
(In millions)
|
||||||
|
Sequent
|
$ | 22.6 | $ | 20.0 | |||
|
EOG
|
- | 5.4 | |||||
|
ICE
|
- | 0.1 | |||||
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 has 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.
|
|
Sales
|
Purchases
|
|||||
|
|
2011
|
2011
|
|||||
|
|
(In millions)
|
||||||
|
Martin Gas
|
$ | 0.9 | $ | 9.3 | |||
|
Southwest Energy
|
7.9 | 2.7 | |||||
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. 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:
|
|
2011
|
2010
|
|||||
|
|
(In millions)
|
||||||
|
Audit fees (1)
|
$ | 2.7 | $ | 4.6 | |||
|
Audit related fees (2)
|
- | - | |||||
|
Tax fees (3)
|
- | - | |||||
|
All other fees (4)
|
- | - | |||||
|
|
$ | 2.7 | $ | 4.6 | |||
____________
|
(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.
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 F-1 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
|
2.1***
|
Purchase and Sale Agreement, dated as of September 18, 2007, by and between Targa Resources Holdings LP and Targa Resources Partners LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 21, 2007 (File No. 001-33303)).
|
|
2.2
|
Amendment to Purchase and Sale Agreement, dated October 1, 2007, by and between Targa Resources Holdings LP and Targa Resources Partners LP (incorporated by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)).
|
|
2.3
|
Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners LP, Targa GP Inc. and Targa LP Inc. (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 29, 2009 (File No. 001-33303)).
|
|
2.4
|
Purchase and Sale Agreement, dated as of March 31, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC and Targa Midstream Holdings LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 1, 2010 (File No. 001-33303)).
|
|
2.5
|
Purchase and Sale Agreement, dated as of August 6, 2010, by and among Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 9, 2010 (File No. 001-33303)).
|
|
2.6
|
Purchase and Sale Agreement, dated September 13, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 17, 2010 (File No. 001-33303)).
|
|
3.1
|
Amended and Restated Certificate of Incorporation of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 16, 2010 (File No. 001-34991)).
|
|
3.2
|
Form of Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 16, 2010 (File No. 001-34991)).
|
|
3.3
|
Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).
|
|
3.4
|
Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
|
|
3.5
|
First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s current report on Form 8-K filed February 16, 2007 (File No. 001-33303)).
|
|
3.6
|
Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).
|
|
3.7
|
Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
|
|
3.8
|
Amended and Restated Certificate of Incorporation of Targa Resources, Inc. (incorporated by reference to Exhibit 3.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
|
|
3.9
|
Amendment to Amended and Restated Certificate of Incorporation of Targa Resources, Inc. (incorporated by reference to Exhibit 3.9 of Targa Resources Corp.’s Annual Report on Form 10-K filed February 28, 2011 (File No. 001-34991)).
|
|
3.10
|
Amended and Restated Bylaws of Targa Resources, Inc. (incorporated by reference to Exhibit 3.2 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
|
|
4.1
|
Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
|
|
10.1
|
Credit Agreement, dated as of January 5, 2010 among Targa Resources, Inc., as the borrower, Deutsche Bank Trust Company Americas, as the administrative agent, Deutsche Bank Securities Inc. and Credit Suisse Securities (USA) LLC, as joint lead arrangers, Credit Suisse Securities (USA) LLC and Citadel Securities LLC, as the co-syndication agents, Deutsche Bank Securities Inc., Credit Suisse Securities (USA) LLC, Citadel Securities LLC, Banc of America Securities LLC and Barclays Capital, as joint book runners, Bank of America, N.A., Barclays Bank PLC and ING Capital LLC, as the co-documentation agents and the other lenders party thereto (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
|
|
10.2
|
Amendment No. 1 to Credit Agreement, dated November 12, 2010 among TRI Resources Inc., as the Borrower, Deutsche Bank Trust Company Americas, Credit Suisse AG, Cayman Islands Branch, Bank of America, N.A., ING Capital LLC and Barclays Bank PLC, as Lenders, and Deutsche Bank Trust Company Americas, as Administrative Agent (incorporated by reference to Exhibit 10.94 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 16, 2010 (File No. 333-169277)).
|
|
10.3
|
Holdco Credit Agreement, dated as of August 9, 2007 among Targa Resources Investments Inc., as the borrower, Credit Suisse, as the administrative agent, Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc. and, as joint lead arrangers, Deutsche Bank Securities Inc., as the syndication agent, Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Lehman Brothers, Inc. and Merrill Lynch Capital Corporation, as joint book runners, Lehman Commercial Paper Inc. and Merrill Lynch Capital Corporation, as the co-documentation agents and the other lenders party thereto (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
|
|
10.4
|
Amendment No. 1 to Holdco Credit Agreement, dated January 5, 2010 among Targa Resources Investments Inc., as the Borrower, Targa Resources, Inc., as Lender, Targa Capital, LLC, as Lender, and Credit Suisse AG, Cayman Islands Brach, as Administrative Agent (incorporated by reference to Exhibit 10.92 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
|
|
10.5
|
Amended and Restated Credit Agreement, dated July 19, 2010, by and among Targa Resources Partners LP, as the borrower, Bank of America, N.A., as the administrative agent, Wells Fargo Bank, National Association and the Royal Bank of Scotland plc, as the co-syndication agents, Deutsche Bank Securities Inc. and Barclays Bank PLC, as the co-documentation agents, Banc of America Securities LLC, Wells Fargo Securities, LLC and RBS Securities Inc., as joint lead arrangers and co-book managers and the other lenders part thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Form 8-K filed on July 21, 2010 (File No. 001-33303)).
|
|
10.6
|
Targa Resources Investments Inc. Amended and Restated Stockholders’ Agreement dated as of October 28, 2005 (incorporated by reference to Exhibit 10.2 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.7
|
First Amendment to Amended and Restated Stockholders’ Agreement, dated January 26, 2006 (incorporated by reference to Exhibit 10.3 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.8
|
Second Amendment to Amended and Restated Stockholders’ Agreement, dated March 30, 2007 (incorporated by reference to Exhibit 10.4 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.9
|
Third Amendment to Amended and Restated Stockholders’ Agreement, dated May 1, 2007 (incorporated by reference to Exhibit 10.5 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.10
|
Fourth Amendment to Amended and Restated Stockholders’ Agreement, dated December 7, 2007 (incorporated by reference to Exhibit 10.6 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.11
|
Fifth Amendment to Amended and Restated Stockholders’ Agreement, dated December 1, 2009 (incorporated by reference to Exhibit 10.1 to Targa Resources, Inc.’s Current Report on Form 8-K filed December 2, 2009 (File No. 333-147066)).
|
|
10.12
|
Form of Sixth Amendment to Amended and Restated Stockholders’ Agreement (incorporated by reference to Exhibit 10.11 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
|
|
10.13+
|
Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.10 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.14+
|
First Amendment to Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.11 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.15+
|
Second Amendment to Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.12 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.16+
|
Form of Targa Resources Investments Inc. Nonstatutory Stock Option Agreement (Non-Employee Directors) (incorporated by reference to Exhibit 10.13 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.17+
|
Form of Targa Resources Investments Inc. Nonstatutory Stock Option Agreement (Non-Director Management and Other Employees) (incorporated by reference to Exhibit 10.14 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.18+
|
Form of Targa Resources Investments Inc. Incentive Stock Option Agreement (incorporated by reference to Exhibit 10.15 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.19+
|
Form of Targa Resources Investments Inc. Restricted Stock Agreement (incorporated by reference to Exhibit 10.16 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.20+
|
Form of Targa Resources Investments Inc. Restricted Stock Agreement (relating to preferred stock option exchange for directors) (incorporated by reference to Exhibit 10.17 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.21+
|
Form of Targa Resources Investments Inc. Restricted Stock Agreement (relating to preferred stock option exchange for employees) (incorporated by reference to Exhibit 10.18 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.22+
|
Targa Resources Corp. 2010 Stock Incentive Plan (incorporated by reference to Exhibit 4.3 of Targa Resources Corp.’s Registration Statement on Form S-8 filed December 9, 2010 (File No. 333-171082)).
|
|
10.23+
|
Form of Targa Resources Corp. Restricted Stock Agreement – 2010 (incorporated by reference to Exhibit 4.4 of Targa Resources Corp.’s Registration Statement on Form S-8 filed December 9, 2010 (File No. 333-171082)).
|
|
10.24+
|
Form of Targa Resources Corp. 2011 Restricted Stock Agreement – 2011 (incorporated by reference to Exhibit 10.2 of Targa Resources Corp.’s Current Report on Form 8-K filed February 18, 2011 (File No. 001-34991)).
|
|
10.25+
|
Targa Resources Investments Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.27 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
|
|
10.26+
|
Targa Resources Investments Inc. 2008 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.13 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No. 001-33303)).
|
|
10.27+
|
Targa Resources Investments Inc. 2009 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.14 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No. 001-33303)).
|
|
10.28+
|
Targa Resources Investments Inc. 2010 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.22 to Targa Resources Partners LP’s Annual Report on Form 10-K filed March 4, 2010 (File No. 001-33303)).
|
|
10.29+
|
Targa Resources Corp. 2011 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.27 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 25, 2011 (File No. 001-33303)).
|
|
10.30+
|
Targa Resources Corp. 2012 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.31 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2012 (File No. 001-33303)).
|
|
10.31+
|
Targa Resources Partners LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed February 1, 2007 (File No. 333-138747)).
|
|
10.32+
|
Form of Targa Resources Partners LP Restricted Unit Grant Agreement — 2007 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 13, 2007 (File No. 001-33303)).
|
|
10.33+
|
Form of Targa Resources Partners LP Restricted Unit Grant Agreement — 2010 (incorporated by reference to Exhibit 10.15 to Targa Resources Partners LP’s Form 10-K filed March 4, 2010 (File No. 001-33303)).
|
|
10.34+
|
Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2007 (incorporated by reference to Exhibit 10.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed with the SEC on February 13, 2007 (File No. 001-33303)).
|
|
10.35+
|
Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2008 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 22, 2008 (File No. 001-33303)).
|
|
10.36+
|
Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2009 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 28, 2009 (File No. 001-33303)).
|
|
10.37+
|
Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2010 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 7, 2009 (File No. 001-33303)).
|
|
10.38+
|
Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2011 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 18, 2011) (File No. 001-33303)).
|
|
10.39+
|
Targa Resources Executive Officer Change in Control Severance Program (incorporated by reference to Exhibit 10.3 to Targa Resources Corp.’s Current Report on Form 8-K filed January 19, 2012 (File No. 001-34991)).
|
|
10.40
|
Purchase Agreement dated as of June 12, 2008 among the Issuers, the Guarantors and Deutsche Bank Securities Inc., as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed June 18, 2008) (File No. 001-33303)).
|
|
10.41
|
Indenture dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Form 10-Q filed August 11, 2008 (File No. 333-147066)).
|
|
10.42
|
Registration Rights Agreement dated as of June 18, 2008 among the Issuers, the Guarantors and Deutsche Bank Securities Inc., as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed June 18, 2008) (File No. 001-33303)).
|
|
10.43
|
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.44
|
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.45
|
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.46
|
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.47
|
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.11 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.48
|
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.13 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.49
|
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.15 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.50
|
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.17 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.51
|
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.19 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.52
|
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.21 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.53
|
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.23 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.54
|
Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.25 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.55
|
Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Gas Marketing LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
|
|
10.56
|
Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Midstream Services Limited Partnership, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
|
|
10.57
|
Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Permian LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
|
|
10.58
|
Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
|
|
10.59
|
Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Straddle LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
|
|
10.60
|
Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Straddle GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.11 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
|
|
10.61
|
Supplemental Indenture dated August 10, 2010 to Indenture dated June 18, 2008, among Targa MLP Capital, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.46 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
|
|
10.62
|
Supplemental Indenture dated September 20, 2010 to Indenture dated June 18, 2008, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)).
|
|
10.63
|
Supplemental Indenture dated October 25, 2010 to Indenture dated June 18, 2008, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)).
|
|
10.64
|
Supplemental Indenture dated April 8, 2011 to Indenture dated June 18, 2008, among Targa Terminals LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2011 (File No. 001-33303)).
|
|
10.65
|
Supplemental Indenture dated October 28, 2011 to Indenture dated June 18, 2008, among Targa Gas Processing LLC, Targa Sound Terminal LLC and Sound Pipeline Company, LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 4, 2011 (File No. 001-33303)).
|
|
10.66
|
Purchase Agreement, dated June 30, 2009 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and Barclays Capital Inc., as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).
|
|
10.67
|
Indenture dated as of July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).
|
|
10.68
|
Registration Rights Agreement dated July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).
|
|
10.69
|
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.70
|
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.71
|
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.72
|
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.73
|
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.12 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.74
|
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.14 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.75
|
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.16 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.76
|
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.18 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.77
|
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.20 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.78
|
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.22 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.79
|
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.24 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.80
|
Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.26 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
|
|
10.81
|
Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Gas Marketing LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
|
|
10.82
|
Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Midstream Services Limited Partnership, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
|
|
10.83
|
Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Permian LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
|
|
10.84
|
Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
|
|
10.85
|
Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Straddle LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
|
|
10.86
|
Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Straddle GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.12 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
|
|
10.87
|
Supplemental Indenture dated August 10, 2010 to Indenture dated July 6, 2009, among Targa MLP Capital, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.66 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
|
|
10.88
|
Supplemental Indenture dated September 20, 2010 to Indenture dated July 6, 2009, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)).
|
|
10.89
|
Supplemental Indenture dated October 25, 2010 to Indenture dated July 6, 2009, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)).
|
|
10.90
|
First Supplemental Indenture dated February 2, 2011 to that certain Indenture dated July 6, 2009 (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).
|
|
10.91
|
Supplemental Indenture dated April 8, 2011 to Indenture dated July 6, 2009, among Targa Terminals LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2011 (File No. 001-33303)).
|
|
10.92
|
Purchase Agreement dated as of August 10, 2010 among the Issuers, the Guarantors and Banc of America Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303)).
|
|
10.93
|
Indenture dated as of August 13, 2010 among the Issuers and the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303)).
|
|
10.94
|
Registration Rights Agreement dated as of August 13, 2010 among the Issuers, the Guarantors and Banc of America Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303)).
|
|
10.95
|
Supplemental Indenture dated September 20, 2010 to Indenture dated August 13, 2010, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001- 33303)).
|
|
10.96
|
Supplemental Indenture dated October 25, 2010 to Indenture dated August 13, 2010, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)).
|
|
10.97
|
Supplemental Indenture dated April 8, 2011 to Indenture dated August 13, 2010, among Targa Terminals LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2011 (File No. 001-33303)).
|
|
10.98
|
Supplemental Indenture dated October 28, 2011 to Indenture dated August 13, 2010, among Targa Gas Processing LLC, Targa Sound Terminal LLC and Sound Pipeline Company, LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 4, 2011 (File No. 001-33303)).
|
|
10.99
|
Purchase Agreement dated January 19, 2011 by and among the Issuers, the Guarantors and Deutsche Bank Securities Inc., as representative of the several Initial Purchasers (incorporated by reference to Exhibit 1.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 24, 2011 (File No. 001-33303)).
|
|
10.100
|
Indenture dated February 2, 2011 among the Issuers, the Guarantors and U.S. Bank National Association, as trustee thereto (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).
|
|
10.101
|
Registration Rights Agreement dated February 2, 2011 among the Issuers, the Guarantors, Deutsche Bank Securities Inc., as representative of the several initial purchasers, and the Dealer Managers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).
|
|
10.102
|
Supplemental Indenture dated April 8, 2011 to Indenture dated February 2, 2011, among Targa Terminals LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2011 (File No. 001-33303)).
|
|
10.103
|
Supplemental Indenture dated October 28, 2011 to Indenture dated February 2, 2011, among Targa Gas Processing LLC, Targa Sound Terminal LLC and Sound Pipeline Company, LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 4, 2011 (File No. 001-33303)).
|
|
10.104
|
Contribution, Conveyance and Assumption Agreement, dated February 14, 2007, by and among Targa Resources Partners LP, Targa Resources Operating LP, Targa Resources GP LLC, Targa Resources Operating GP LLC, Targa GP Inc., Targa LP Inc., Targa Regulated Holdings LLC, Targa North Texas GP LLC and Targa North Texas LP (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 16, 2007 (File No. 001-33303)).
|
|
10.105
|
Contribution, Conveyance and Assumption Agreement, dated October 24, 2007, by and among Targa Resources Partners LP, Targa Resources Holdings LP, Targa TX LLC, Targa TX PS LP, Targa LA LLC, Targa LA PS LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)).
|
|
10.106
|
Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa GP Inc., Targa LP Inc., Targa Resources Operating LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (File No. 001-33303)).
|
|
10.107
|
Contribution, Conveyance and Assumption Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC, Targa Midstream Holdings LLC, Targa Resources Operating LP, Targa North Texas GP LLC and Targa Resources Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)).
|
|
10.108
|
Contribution, Conveyance and Assumption Agreement, dated August 25, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 26, 2010 (File No. 001-33303)).
|
|
10.109
|
Contribution, Conveyance and Assumption Agreement, dated September 28, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 4, 2010 (file No. 001-33303)).
|
|
10.110
|
Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).
|
|
10.111
|
First Amendment to Second Amended and Restated Omnibus Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)).
|
|
10.112+
|
Form of Indemnification Agreement between Targa Resources Investments Inc. and each of the directors and officers thereof (incorporated by reference to Exhibit 10.4 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 8, 2010 (File No. 333-169277)).
|
|
10.113+
|
Targa Resources Partners LP Indemnification Agreement for Barry R. Pearl dated February 14, 2007 (incorporated by reference to Exhibit 10.11 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
|
|
10.114+
|
Targa Resources Partners LP Indemnification Agreement for Robert B. Evans dated February 14, 2007 (incorporated by reference to Exhibit 10.12 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
|
|
10.115+
|
Targa Resources Partners LP Indemnification Agreement for Williams D. Sullivan dated February 14, 2007 (incorporated by reference to Exhibit 10.13 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
|
|
10.116
|
Amended and Restated Registration Rights Agreement dated as of October 31, 2005 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
|
|
21.1*
|
List of Subsidiaries of Targa Resources Corp.
|
|
23.1*
|
Consent of Independent Registered Public Accounting Firm.
|
|
31.1*
|
Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
|
|
31.2*
|
Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
|
|
32.1**
|
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
32.2**
|
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
* 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.
| Targa Resources Corp. | |||
| (Registrant) | |||
| Date: February 24, 2012 | By: /s/ Matthew J. Meloy | ||
| Matthew J. Meloy | |||
| Senior Vice President, Chief Financial Officer and Treasurer | |||
| (Principal Financial Officer) |
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 24, 2012.
|
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
|
140
|
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
TARGA RESOURCES CORP. AUDITED CONSDOLIDATED 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, 2011.
The effectiveness of our internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page F-3.
The business of the refined petroleum products and crude oil storage and terminaling facility that the Partnership purchased in Tacoma, Washington on September 30, 2011 was excluded from the scope of our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2011. This business constituted 0.7% of our total revenues for 2011 and 3.3% of our total assets as of December 31, 2011.
/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 at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 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, 2011, 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 audits (which was an integrated audit in 2011). 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 the business of a refined petroleum products and crude oil storage and terminaling facility in Tacoma, Washington from its assessment of internal control over financial reporting as of December 31, 2011 because the business was acquired in a purchase business combination during 2011. We have also excluded the acquired business from our audit of internal control over financial reporting. Total assets and total revenues of the business represent 3.3% and 0.7%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2011.
/s/PricewaterhouseCoopers LLP
Houston, Texas
February 24, 2012
|
CONSOLIDATED BALANCE SHEETS
|
||||||||
|
|
|
|
||||||
|
|
December 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
|
(In millions)
|
|||||||
|
ASSETS
|
||||||||
|
Current assets:
|
|
|
||||||
|
Cash and cash equivalents
|
$ | 145.8 | $ | 188.4 | ||||
|
Trade receivables, net of allowances of $2.4 million and $7.9 million
|
575.7 | 466.6 | ||||||
|
Inventory
|
92.2 | 50.4 | ||||||
|
Deferred income taxes
|
0.1 | 3.6 | ||||||
|
Assets from risk management activities
|
41.0 | 25.2 | ||||||
|
Other current assets
|
11.7 | 16.3 | ||||||
|
Total current assets
|
866.5 | 750.5 | ||||||
|
Property, plant and equipment
|
3,821.1 | 3,331.4 | ||||||
|
Accumulated depreciation
|
(1,001.6 | ) | (822.4 | ) | ||||
|
Property, plant and equipment, net
|
2,819.5 | 2,509.0 | ||||||
|
Long-term assets from risk management activities
|
10.9 | 18.9 | ||||||
|
Investment in unconsolidated affiliate
|
36.8 | 15.2 | ||||||
|
Other long-term assets
|
97.3 | 100.2 | ||||||
|
Total assets
|
$ | 3,831.0 | $ | 3,393.8 | ||||
|
|
||||||||
|
LIABILITIES AND OWNERS' EQUITY
|
||||||||
|
Current liabilities:
|
||||||||
|
Accounts payable
|
$ | 345.4 | $ | 254.2 | ||||
|
Accrued liabilities
|
354.6 | 335.8 | ||||||
|
Liabilities from risk management activities
|
41.1 | 34.2 | ||||||
|
Total current liabilities
|
741.1 | 624.2 | ||||||
|
Long-term debt
|
1,567.0 | 1,534.7 | ||||||
|
Long-term liabilities from risk management activities
|
15.8 | 32.8 | ||||||
|
Deferred income taxes
|
120.5 | 111.6 | ||||||
|
Other long-term liabilities
|
55.9 | 54.4 | ||||||
|
|
||||||||
|
Commitments and contingencies (see Note 17)
|
||||||||
|
|
||||||||
|
Owners' equity:
|
||||||||
|
Targa Resources Corp. stockholders' equity:
|
||||||||
|
Common stock ($0.001 par value, 300,000,000 shares authorized, 42,398,148 and 42,292,348 shares issued and outstanding as of December 31, 2011 and 2010)
|
- | - | ||||||
|
Preferred stock ($0.001 par value, 100,000,000 shares authorized, no shares issued and outstanding as of December 31, 2011 and 2010)
|
- | - | ||||||
|
Additional paid-in capital
|
229.5 | 244.5 | ||||||
|
Accumulated deficit
|
(70.1 | ) | (100.8 | ) | ||||
|
Accumulated other comprehensive income (loss)
|
(1.3 | ) | 0.6 | |||||
|
Total Targa Resources Corp. stockholders' equity
|
158.1 | 144.3 | ||||||
|
Noncontrolling interests in subsidiaries
|
1,172.6 | 891.8 | ||||||
|
Total owners' equity
|
1,330.7 | 1,036.1 | ||||||
|
Total liabilities and owners' equity
|
$ | 3,831.0 | $ | 3,393.8 | ||||
|
|
||||||||
|
See notes to consolidated financial statements
|
||||||||
|
TARGA RESOURCES CORP.
|
||||||||||||
|
CONSOLIDATED STATEMENTS OF OPERATIONS
|
||||||||||||
|
|
|
|
||||||||||
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
|
||||||||||||
|
Revenues
|
$ | 6,994.5 | $ | 5,476.1 | $ | 4,542.3 | ||||||
|
Costs and expenses:
|
||||||||||||
|
Product purchases
|
6,039.0 | 4,695.5 | 3,797.4 | |||||||||
|
Operating expenses
|
287.1 | 259.3 | 235.0 | |||||||||
|
Depreciation and amortization expenses
|
181.0 | 185.5 | 170.3 | |||||||||
|
General and administrative expenses
|
136.1 | 144.4 | 120.4 | |||||||||
|
Other
|
0.2 | (4.7 | ) | 2.0 | ||||||||
|
|
6,643.4 | 5,280.0 | 4,325.1 | |||||||||
|
Income from operations
|
351.1 | 196.1 | 217.2 | |||||||||
|
Other income (expense):
|
||||||||||||
|
Interest expense, net
|
(111.7 | ) | (110.9 | ) | (132.1 | ) | ||||||
|
Equity earnings
|
8.8 | 5.4 | 5.0 | |||||||||
|
Loss on debt repurchases (see Note 8)
|
- | (17.4 | ) | (1.5 | ) | |||||||
|
Gain (loss) on early debt extinguishment, net (see Note 8)
|
- | 12.5 | 9.7 | |||||||||
|
Loss on mark-to-market derivative instruments
|
(5.0 | ) | (0.4 | ) | 0.3 | |||||||
|
Other income (expense), net
|
(1.2 | ) | 0.5 | 1.2 | ||||||||
|
Income before income taxes
|
242.0 | 85.8 | 99.8 | |||||||||
|
Income tax benefit (expense):
|
||||||||||||
|
Current
|
(14.3 | ) | 10.6 | (1.6 | ) | |||||||
|
Deferred
|
(12.3 | ) | (33.1 | ) | (19.1 | ) | ||||||
|
|
(26.6 | ) | (22.5 | ) | (20.7 | ) | ||||||
|
Net income
|
215.4 | 63.3 | 79.1 | |||||||||
|
Less: Net income attributable to noncontrolling interests
|
184.7 | 78.3 | 49.8 | |||||||||
|
Net income (loss) attributable to Targa Resources Corp.
|
30.7 | (15.0 | ) | 29.3 | ||||||||
|
Dividends on Series B preferred stock
|
- | (9.5 | ) | (17.8 | ) | |||||||
|
Undistributed earnings attributable to preferred shareholders
|
- | - | (11.5 | ) | ||||||||
|
Dividends on common equivalents
|
- | (177.8 | ) | - | ||||||||
|
Net income (loss) available to common shareholders
|
$ | 30.7 | $ | (202.3 | ) | $ | - | |||||
|
|
||||||||||||
|
Net income (loss) available per common share - basic
|
$ | 0.75 | $ | (30.94 | ) | $ | - | |||||
|
Net income (loss) available per common share - diluted
|
$ | 0.74 | $ | (30.94 | ) | $ | - | |||||
|
Weighted average shares outstanding - basic
|
41.0 | 6.5 | 3.8 | |||||||||
|
Weighted average shares outstanding - diluted
|
41.4 | 6.5 | 3.8 | |||||||||
|
|
||||||||||||
|
See notes to consolidated financial statements
|
||||||||||||
|
TARGA RESOURCES CORP.
|
||||||||||||
|
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|
||||||||||||
|
|
|
|
||||||||||
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
|
||||||||||||
|
Net income (loss) attributable to Targa Resources Corp.
|
$ | 30.7 | $ | (15.0 | ) | $ | 29.3 | |||||
|
Other comprehensive income (loss) attributable to Targa Resources Corp.
|
||||||||||||
|
Commodity hedging contracts:
|
||||||||||||
|
Change in fair value
|
(5.2 | ) | 37.8 | (50.8 | ) | |||||||
|
Settlements reclassified to revenues
|
1.0 | (4.0 | ) | (38.2 | ) | |||||||
|
Interest rate swaps:
|
||||||||||||
|
Change in fair value
|
(0.3 | ) | (2.1 | ) | (1.6 | ) | ||||||
|
Settlements reclassified to interest expense, net
|
1.3 | 1.8 | 3.2 | |||||||||
|
Related income taxes
|
1.3 | (12.6 | ) | 31.0 | ||||||||
|
Other comprehensive income (loss) attributable to Targa Resources Corp.
|
(1.9 | ) | 20.9 | (56.4 | ) | |||||||
|
Comprehensive income (loss) attributable to Targa Resources Corp.
|
28.8 | 5.9 | (27.1 | ) | ||||||||
|
|
||||||||||||
|
Net income attributable to noncontrolling interests
|
184.7 | 78.3 | 49.8 | |||||||||
|
Other comprehensive income (loss) attributable to noncontrolling interests
|
||||||||||||
|
Commodity hedging contracts:
|
||||||||||||
|
Change in fair value
|
(28.4 | ) | 14.9 | (53.2 | ) | |||||||
|
Settlements reclassified to revenues
|
29.3 | (4.7 | ) | (31.8 | ) | |||||||
|
Interest rate swaps:
|
||||||||||||
|
Change in fair value
|
(4.0 | ) | (18.0 | ) | (0.4 | ) | ||||||
|
Settlements reclassified to interest expense, net
|
6.8 | 7.4 | 7.2 | |||||||||
|
Other comprehensive income (loss) attributable to noncontrolling interests
|
3.7 | (0.4 | ) | (78.1 | ) | |||||||
|
Comprehensive income attributable to noncontrolling interests
|
188.4 | 77.9 | (28.3 | ) | ||||||||
|
|
||||||||||||
|
Total comprehensive income (loss)
|
$ | 217.2 | $ | 83.8 | $ | (55.4 | ) | |||||
|
|
||||||||||||
|
See notes to consolidated financial statements
|
||||||||||||
|
TARGA RESOURCES CORP.
|
|||||||||||||||||||||||||
|
CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY
|
|||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
Other |
|
|
|
|
|
|
Non
|
|
|
|
|||
|
|
|
Common Stock
|
|
Paid in
|
|
Accumulated
|
|
Comprehensive |
Treasury Stock
|
|
Controlling
|
|
|
|
|||||||||||
|
|
|
Shares
|
|
Amount
|
|
Capital
|
|
Deficit
|
|
Income (Loss) | Shares | Amount |
|
Interests
|
|
Total
|
|||||||||
|
|
|
(In millions, except shares in thousands)
|
|||||||||||||||||||||||
|
Balance, December 31, 2008
|
3,807
|
|
$
|
-
|
|
$
|
214.2
|
|
$
|
(115.1)
|
|
$
|
36.1
|
|
88
|
|
$
|
(0.5)
|
|
$
|
687.3
|
|
$
|
822.0
|
|
|
Option exercises
|
106
|
|
|
-
|
|
|
0.3
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.3
|
|
|
Forfeiture of non-vested common stock
|
(3)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Repurchases of common stock
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
9
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Impact of Partnership equity transactions
|
-
|
|
|
-
|
|
|
(2.9)
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
2.9
|
|
|
-
|
|
|
Contributions
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
103.8
|
|
|
103.8
|
|
|
Distributions
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
(98.5)
|
|
|
(98.5)
|
|
|
Dividends on Series B preferred stock
|
-
|
|
|
-
|
|
|
(17.8)
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(17.8)
|
|
|
Compensation on equity grants
|
-
|
|
|
-
|
|
|
0.4
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
0.3
|
|
|
0.7
|
|
|
Tax expense on vesting of common stock
|
-
|
|
|
-
|
|
|
(0.2)
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(0.2)
|
|
|
Other comprehensive income (loss)
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(56.4)
|
|
-
|
|
|
-
|
|
|
(78.1)
|
|
|
(134.5)
|
|
|
Net income
|
-
|
|
|
-
|
|
|
-
|
|
|
29.3
|
|
|
-
|
|
-
|
|
|
-
|
|
|
49.8
|
|
|
79.1
|
|
|
Balance, December 31, 2009
|
3,910
|
|
|
-
|
|
|
194.0
|
|
|
(85.8)
|
|
|
(20.3)
|
|
97
|
|
|
(0.5)
|
|
|
667.5
|
|
|
754.9
|
|
|
Option exercises
|
1,161
|
|
|
-
|
|
|
0.6
|
|
|
-
|
|
|
-
|
|
(69)
|
|
|
0.3
|
|
|
-
|
|
|
0.9
|
|
|
Compensation on equity grants
|
1,906
|
|
|
-
|
|
|
13.8
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
|
13.8
|
|
|
Repurchases of common stock
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
13
|
|
|
(0.1)
|
|
|
-
|
|
|
(0.1)
|
|
| Proceeds from sale of limited partner interests in the Partnership | - | - | - | - | - | - | - | 224.4 | 224.4 | ||||||||||||||||
|
Impact of Partnership equity transactions
|
-
|
|
|
-
|
|
|
258.9
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
(258.9)
|
|
|
-
|
|
|
Tax impact of equity offerings
|
-
|
|
|
-
|
|
|
(79.6)
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(79.6)
|
|
|
Dividends to common and common equivalents
|
-
|
|
|
-
|
|
|
(213.3)
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(213.3)
|
|
|
Dividends on Series B preferred stock
|
-
|
|
|
-
|
|
|
(9.5)
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(9.5)
|
|
|
Contributions
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
317.8
|
|
|
317.8
|
|
|
Distributions
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
(136.9)
|
|
|
(136.9)
|
|
|
Series B Preferred Conversion
|
35,356
|
|
|
-
|
|
|
79.9
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
|
79.9
|
|
|
Other comprehensive income (loss)
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
20.9
|
|
-
|
|
|
-
|
|
|
(0.4)
|
|
|
20.5
|
|
|
Treasury shares retired
|
(41)
|
|
|
-
|
|
|
(0.3)
|
|
|
-
|
|
|
-
|
|
(41)
|
|
|
0.3
|
|
|
-
|
|
|
-
|
|
|
Net income (loss)
|
-
|
|
|
-
|
|
|
-
|
|
|
(15.0)
|
|
|
-
|
|
-
|
|
|
-
|
|
|
78.3
|
|
|
63.3
|
|
|
Balance, December 31, 2010
|
42,292
|
|
|
-
|
|
|
244.5
|
|
|
(100.8)
|
|
|
0.6
|
|
-
|
|
|
-
|
|
|
891.8
|
|
|
1,036.1
|
|
|
Compensation on equity grants
|
106
|
|
|
-
|
|
|
14.2
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
1.0
|
|
|
15.2
|
|
|
Sale of Partnership limited partner interests
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
298.0
|
|
|
298.0
|
|
|
Impact of Partnership equity transactions
|
-
|
|
|
-
|
|
|
10.3
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
(10.3)
|
|
|
-
|
|
|
Dividends
|
-
|
|
|
-
|
|
|
(39.5)
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
(0.1)
|
|
|
(39.6)
|
|
|
Distributions
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
(196.2)
|
|
|
(196.2)
|
|
|
Other comprehensive income (loss)
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(1.9)
|
|
-
|
|
|
-
|
|
|
3.7
|
|
|
1.8
|
|
|
Net income
|
-
|
|
|
-
|
|
|
-
|
|
|
30.7
|
|
|
-
|
|
-
|
|
|
-
|
|
|
184.7
|
|
|
215.4
|
|
|
Balance, December 31, 2011
|
42,398
|
|
$
|
-
|
|
$
|
229.5
|
|
$
|
(70.1)
|
|
$
|
(1.3)
|
|
-
|
|
$
|
-
|
|
$
|
1,172.6
|
|
$
|
1,330.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements
|
|||||||||||||||||||||||||
|
TARGA RESOURCES CORP.
|
||||||||||||
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
||||||||||||
|
|
|
|
|
|||||||||
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Cash flows from operating activities
|
(In millions)
|
|||||||||||
|
Net income
|
$ | 215.4 | $ | 63.3 | $ | 79.1 | ||||||
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
||||||||||||
|
Amortization in interest expense
|
13.0 | 9.4 | 10.2 | |||||||||
|
Paid-in-kind interest expense
|
- | 10.9 | 25.9 | |||||||||
|
Compensation on equity grants
|
15.2 | 13.4 | 0.7 | |||||||||
|
Depreciation and amortization expense
|
181.0 | 174.7 | 168.8 | |||||||||
|
Asset impairment charges
|
- | 10.8 | 1.5 | |||||||||
|
Accretion of asset retirement obligations
|
3.6 | 3.2 | 2.9 | |||||||||
|
Deferred income tax expense
|
12.3 | 33.1 | 19.1 | |||||||||
|
Equity earnings, net of distributions
|
(0.4 | ) | - | - | ||||||||
|
Risk management activities
|
(21.2 | ) | 29.9 | 40.3 | ||||||||
|
Loss (gain) on sale of assets
|
0.2 | (1.5 | ) | 0.1 | ||||||||
|
Loss on debt repurchases
|
- | 17.4 | 1.5 | |||||||||
|
Gain on early debt extinguishment
|
- | (12.5 | ) | (9.7 | ) | |||||||
|
Payments of interest on Holdco loan facility
|
- | (0.9 | ) | (6.0 | ) | |||||||
|
Changes in operating assets and liabilities:
|
||||||||||||
|
Receivables and other assets
|
(101.3 | ) | (119.2 | ) | (140.1 | ) | ||||||
|
Inventory
|
(41.1 | ) | (11.4 | ) | 19.3 | |||||||
|
Accounts payable and other liabilities
|
102.6 | (15.4 | ) | 122.2 | ||||||||
|
Net cash provided by operating activities
|
379.3 | 205.2 | 335.8 | |||||||||
|
Cash flows from investing activities
|
||||||||||||
|
Outlays for property, plant and equipment
|
(331.9 | ) | (139.3 | ) | (99.4 | ) | ||||||
|
Business acquisitions
|
(156.5 | ) | - | - | ||||||||
|
Investment in unconsolidated affiliate
|
(21.2 | ) | - | - | ||||||||
|
Unconsolidated affiliate distributions in excess of accumulated earnings
|
- | 3.3 | - | |||||||||
|
Other, net
|
0.3 | 4.7 | 40.1 | |||||||||
|
Net cash used in investing activities
|
(509.3 | ) | (131.3 | ) | (59.3 | ) | ||||||
|
Cash flows from financing activities
|
||||||||||||
|
Partnership loan facilities:
|
||||||||||||
|
Borrowings
|
1,787.0 | 1,343.1 | 806.6 | |||||||||
|
Repayments
|
(2,054.3 | ) | (1,057.0 | ) | (596.6 | ) | ||||||
|
Proceeds from issuance of senior notes
|
325.0 | 250.0 | - | |||||||||
|
Cash paid on note exchange
|
(27.7 | ) | - | - | ||||||||
|
Non-Partnership loan facilities:
|
||||||||||||
|
Borrowings
|
- | 495.0 | - | |||||||||
|
Repayments
|
- | (1,087.4 | ) | (589.2 | ) | |||||||
|
Costs incurred in connection with financing arrangements
|
(6.2 | ) | (39.6 | ) | (13.3 | ) | ||||||
|
Distributions to noncontrolling interests
|
(196.2 | ) | (136.9 | ) | (98.5 | ) | ||||||
|
Proceeds from sale of common units of the Partnership
|
- | 224.4 | - | |||||||||
|
Partnership equity transactions
|
298.0 | 317.8 | 103.8 | |||||||||
|
Repurchases of common stock
|
- | (0.1 | ) | - | ||||||||
|
Stock options exercised
|
- | 0.9 | 0.3 | |||||||||
|
Dividends to common and common equivalent shareholders
|
(38.2 | ) | (210.1 | ) | - | |||||||
|
Dividends to preferred shareholders
|
- | (238.0 | ) | - | ||||||||
|
Net cash provided by (used in) financing activities
|
87.4 | (137.9 | ) | (386.9 | ) | |||||||
|
Net change in cash and cash equivalents
|
(42.6 | ) | (64.0 | ) | (110.4 | ) | ||||||
|
Cash and cash equivalents, beginning of period
|
188.4 | 252.4 | 362.8 | |||||||||
|
Cash and cash equivalents, end of period
|
$ | 145.8 | $ | 188.4 | $ | 252.4 | ||||||
|
|
||||||||||||
|
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, 2011 and 2010, and the results of operations, comprehensive income, cash flows, and changes in owners’ equity for the years ended December 31, 2011, 2010 and 2009.
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.
During 2009, we recorded adjustments related to prior periods which decreased our income before income taxes for 2009 by $5.4 million. The adjustments consisted of $7.2 million related to debt issue costs that should have been expensed during 2007 and $1.8 million of revenue which should have been recorded during 2006. Had these adjustments been previously recorded in their appropriate periods, net income attributable to Targa for the year ended December 31, 2009 would have increased by $3.4 million. After evaluating the quantitative and qualitative aspects of these errors, we concluded that our previously issued financial statements were not materially misstated and the effect of recognizing these adjustments in the 2009 financial statements was not material to the 2009 results of operations, financial position or cash flows.
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, 2011, 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
|
|
·
|
11,645,659 common units of the Partnership, representing a 13.7% 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.
Inventory. Our product inventories consist primarily of NGLs. Most product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. Product inventories are primarily valued at the lower of cost or market using the average cost 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.
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 charged to operations.
We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. 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. See Note 5.
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 6.
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 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 share of the net assets of our consolidated subsidiaries are shown as noncontrolling interest 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 and condensate; |
|
·
|
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 revenues gross in our consolidated statements of operations. Except for fee-based contracts, we act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership.
Share-Based Compensation. We award share-based compensation to employees and directors in the form of restricted stock, stock options and performance unit awards. Compensation expense on restricted stock and stock options is measured by the fair value of the award 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 on performance unit awards that qualify as equity arrangements is initially measured by the fair value of the award at the grant date. 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.
2011 Accounting Pronouncements
In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. The amendment, which becomes effective during interim and annual periods beginning after December 15, 2011, requires additional disclosures with regard to fair value measurements categorized within Level 3 of the fair value hierarchy. Early adoption is not permitted.
In June 2011, the FASB issued Accounting Standards Update No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. The amendment, which becomes effective during interim and annual periods beginning after December 15, 2011, stipulates the financial statement presentation requirements for other comprehensive income. Our financial statement presentation complies with this standards update.
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 and related arrangements. We do not believe this amendment will have a material impact on our financial statements.
Note 4 –Business Acquisitions
On March 15, 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.
On September 30, 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 consideration for both facilities was $127.5 million plus an additional $7.5 million for estimated working capital.
Note 5 — Property, Plant and Equipment
|
|
2011
|
2010
|
|
||||||||||||||||||||||
|
|
|
|
Targa
|
|
|
Targa
|
Estimated
|
||||||||||||||||||
|
|
Targa
|
TRC
|
Resources
|
Targa
|
TRC
|
Resources
|
Useful
|
||||||||||||||||||
|
|
Resources
|
Non-
|
Corp.
|
Resources
|
Non-
|
Corp.
|
Lives
|
||||||||||||||||||
|
|
Partners LP
|
Partnership
|
Consolidated
|
Partners LP
|
Partnership
|
Consolidated
|
(In Years)
|
||||||||||||||||||
|
Natural gas gathering systems
|
$ | 1,740.6 | $ | - | $ | 1,740.6 | $ | 1,630.9 | $ | - | $ | 1,630.9 |
5 to 20
|
||||||||||||
|
Processing and fractionation facilities
|
1,062.7 | 6.6 | 1,069.3 | 961.9 | 6.6 | 968.5 |
5 to 25
|
||||||||||||||||||
|
Terminaling and storage facilities
|
380.7 | - | 380.7 | 244.7 | - | 244.7 |
5 to 25
|
||||||||||||||||||
|
Transportation assets
|
281.2 | - | 281.2 | 275.6 | - | 275.6 |
10 to 25
|
||||||||||||||||||
|
Other property, plant and equipment
|
54.9 | 24.0 | 78.9 | 46.8 | 22.6 | 69.4 |
3 to 25
|
||||||||||||||||||
|
Land
|
71.2 | - | 71.2 | 51.2 | - | 51.2 | - | ||||||||||||||||||
|
Construction in progress
|
195.6 | 3.6 | 199.2 | 88.4 | 2.7 | 91.1 | - | ||||||||||||||||||
|
|
$ | 3,786.9 | $ | 34.2 | $ | 3,821.1 | $ | 3,299.5 | $ | 31.9 | $ | 3,331.4 | |||||||||||||
Note 6 – 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:
|
|
2011
|
2010
|
2009
|
|||||||||
|
Beginning of Period
|
$ | 37.5 | $ | 34.1 | $ | 34.0 | ||||||
|
Change in cash flow estimate
|
1.2 | 0.2 | (2.8 | ) | ||||||||
|
Accretion expense
|
3.6 | 3.2 | 2.9 | |||||||||
|
End of period
|
$ | 42.3 | $ | 37.5 | $ | 34.1 | ||||||
Note 7 – Investment in Unconsolidated Affiliate
At December 31, 2011, 2010 and 2009, 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:
|
|
2011
|
2010
|
2009
|
|||||||||
|
Equity earnings
|
$ | 8.8 | $ | 5.4 | $ | 5.0 | ||||||
|
Cash distributions (1)
|
$ | 8.4 | $ | 8.7 | $ | 5.0 | ||||||
|
Cash calls for expansion projects
|
$ | 21.2 | $ | - | $ | - | ||||||
_________
|
(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 both 2010 and 2009.
|
The Partnership’s allocated cost basis in GCF at the date of its acquisition was less than its partnership equity balance by approximately $5.2 million. This basis difference is being amortized over the estimated useful life of the underlying fractionating assets (25 years) on a straight-line basis and is included as a component of the Partnership’s equity earnings.
Note 8 — Debt Obligations
|
|
2011
|
2010
|
||||||
|
Long-term debt:
|
|
|
||||||
|
Non-Partnership obligations:
|
|
|
||||||
|
TRC Holdco loan facility, variable rate, due February 2015
|
$ | 89.3 | $ | 89.3 | ||||
|
TRI Senior secured revolving credit facility, variable rate, due July 2014 (1)
|
- | - | ||||||
|
Obligations of the Partnership: (2)
|
||||||||
|
Senior secured revolving credit facility, variable rate, due July 2015 (3)
|
498.0 | 765.3 | ||||||
|
Senior unsecured notes, 8¼% fixed rate, due July 2016
|
209.1 | 209.1 | ||||||
|
Senior unsecured notes, 11¼% fixed rate, due July 2017
|
72.7 | 231.3 | ||||||
|
Unamortized discount
|
(2.9 | ) | (10.3 | ) | ||||
|
Senior unsecured notes, 7⅞% fixed rate, due October 2018
|
250.0 | 250.0 | ||||||
|
Senior unsecured notes, 6⅞% fixed rate, due February 2021
|
483.6 | - | ||||||
|
Unamortized discount
|
(32.8 | ) | - | |||||
|
Total long-term debt
|
$ | 1,567.0 | $ | 1,534.7 | ||||
|
Irrevocable standby letters of credit:
|
||||||||
|
Letters of credit outstanding under TRI Senior secured credit facility (1)
|
$ | - | $ | - | ||||
|
Letters of credit outstanding under the Partnership Senior secured revolving credit facility (3)
|
92.5 | 101.3 | ||||||
|
|
$ | 92.5 | $ | 101.3 | ||||
___________
|
(1)
|
As of December 31, 2011, the entire amount of TRI’s $75.0 million credit facility was available for letters of credit and available capacity under this facility was $75.0 million.
|
|
(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, 2011, availability under the Partnership’s $1.1 billion Senior Secured Revolving Credit Facility was $509.5 million.
|
The following table shows the range of interest rates paid and weighted average interest rate paid on our and the Partnership’s variable-rate debt obligations during the year ended December 31, 2011:
|
|
Range of Interest Rates Paid
|
|
Weighted Average Interest Rate Paid
|
|
|
|
||
|
TRC Holdco Loan Facility
|
3.2% - 3.3%
|
|
3.3%
|
|
Partnership Senior Secured Revolving Credit Facility
|
2.4% - 4.5%
|
|
2.7%
|
Compliance with Debt Covenants
As of December 31, 2011, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.
TRC Holdco Loan Facility
In August 2007, we borrowed $450 million under the TRC Holdco loan facility (“Holdco debt”). Interest on borrowings are payable, at our option, either (i) entirely in cash, (ii) entirely by increasing the principal amount of the outstanding borrowings or (iii) 50% cash and 50% by increasing the principal amount of the outstanding borrowings.
Borrowings outstanding under the Holdco debt bear interest at a rate equal to an applicable rate plus, at our option, either (i) a base rate determined by reference to the higher of (1) the prime rate of Credit Suisse or (2) the federal funds rate plus 0.5% or (ii) LIBOR as determined by reference to the costs of funds for dollar deposits for the interest period relevant to such borrowing adjusted for certain statutory reserves. At December 31, 2011, the applicable rate for borrowings under the Holdco debt was 2% with respect to base rate borrowings and 3% with respect to LIBOR borrowings.
Principal amounts outstanding under the Holdco debt are due and payable in February 2015. We may prepay all or part of the principal amount outstanding, at our option, at 101% of the principal amount outstanding until August 9, 2011, then at 100% of the principal amount outstanding.
The following subsidiary repurchases of Holdco debt have been recognized in the accompanying consolidated financial statements as extinguishments of debt:
|
·
|
In 2009, TRI paid $39.3 million to acquire $64.5 million of outstanding borrowings (including accrued interest of $6.0 million), resulting in a pretax gain of $25.2 million. In addition, we wrote-off $0.7 million of associated unamortized deferred debt issuance costs.
|
|
·
|
In 2010, TRI and another wholly-owned subsidiary paid $269.3 million to acquire $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.
|
Following the 2010 Holdco debt acquisitions, we exercised our right as a majority holder of the debt issue to remove all of the debt covenants associated with the Holdco debt. In November 2010, we amended out Holdco debt agreement to name our wholly-owned subsidiary, TRI, as guarantor to our obligations under the credit agreement. The operations and assets of the Partnership continue to be excluded as guarantors of the Holdco debt.
TRI Senior Secured Credit Agreement
On January 5, 2010 TRI entered into a Senior Secured Credit Agreement (the “credit agreement”) providing senior secured financing of $600 million, consisting of a $500 million Senior Secured Term Loan Facility and a $100 million Senior Secured Revolving Credit Facility (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 Senior Secured Term Loan due 2012;
|
|
·
|
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, the available capacity of the revolving credit facility was reduced to $75.0 million. The full amount under this facility was available for borrowing as of December 31, 2011.The entire amount of our credit facility is 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.
Borrowings under the credit agreement bear interest at a rate equal to an applicable margin, plus at our option, either (a) a base rate determined by reference to the higher of (1) the prime rate of Deutsche Bank, (2) the federal funds rate plus 0.5%, and (3) solely in the case of term loans, 3%, or (b) LIBOR as determined by reference to the higher of (1) the British Bankers Association LIBOR Rate and (2) solely in the case of term loans, 2%.
TRI is required to pay a commitment fee equal to 0.5% of the current unutilized commitments. The commitment fee rate may fluctuate based upon TRI’s leverage ratios. TRI is also required to pay a fronting fee equal to 0.25% on outstanding letters of credit.
All obligations under the credit agreement and certain secured hedging arrangements are unconditionally guaranteed, subject to certain exceptions, by each of TRI’s existing and future domestic restricted subsidiaries, referred to, collectively, as the guarantors. TRI has pledged the following assets, subject to certain exceptions, as collateral:
|
·
|
the capital stock and other equity interests held by TRI or any guarantor; and
|
|
·
|
a security interest in, and mortgages on, TRI’s and its guarantors’ tangible and intangible assets.
|
The credit agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, TRI’s ability to incur additional indebtedness (including guarantees and hedging obligations); create liens on assets; enter into sale and leaseback transactions; engage in mergers or consolidations; sell assets; pay dividends and make distributions or repurchase capital stock and other equity interests; make investments, loans or advances; make capital expenditures; repay, redeem or repurchase certain indebtedness; make certain acquisitions; engage in certain transactions with affiliates; amend certain debt and other material agreements; change TRI’s lines of business; and impose certain restrictions on restricted subsidiaries that are not guarantors, including restrictions on the ability of such subsidiaries that are not guarantors to pay dividends.
The credit agreement requires TRI to maintain certain specified maximum total leverage ratios and certain specified minimum interest coverage ratios. In each case we are required to comply with certain limitations, including minimum cash consideration requirements.
In 2009, TRI repaid substantially all of its Senior Secured Term Loan facility and recognized a $14.8 million loss on early debt extinguishment consisting of the write-off of debt issue costs related to the facility.
The Partnership’s Revolving Credit Facility
On July 19, 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 Revolver increases available commitments to the Partnership to $1.1 billion from $958.5 million and allows 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 facility related to a change in syndicate members. The remaining balance in debt issue costs of $4.7 million is being amortized over the life of the amended and restated credit facility.
The Partnership’s amended and restated credit facility bears interest at LIBOR plus an applicable margin ranging from 2.25% to 3.5% dependent on the Partnership’s consolidated funded indebtedness to consolidated adjusted EBITDA ratio. The Partnership’s new credit facility is secured by substantially all of the Partnership’s assets. As of December 31, 2011, availability under the Partnership’s Revolver was $509.5 million, after giving effect to $92.5 million in outstanding letters of credit.
The Partnership’s Revolver restricts its ability to make distributions of available cash to unitholders if a default or an event of default (as defined in its Senior Secured Credit Agreement) has occurred and is continuing. The Revolver requires the Partnership to maintain a consolidated funded indebtedness to consolidated adjusted EBITDA of less than or equal to 5.50 to 1.00. The Partnership’s Revolver also requires it to maintain an interest coverage ratio (the ratio of its consolidated EBITDA to its consolidated interest expense, as defined in its Senior Secured Credit Agreement) of greater than or equal to 2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination, as well as upon the occurrence of certain events, including the incurrence of additional permitted indebtedness.
The Partnership’s Outstanding Senior Unsecured Notes
The Partnership has four issues of unsecured senior notes. On June 18, 2008, the Partnership privately placed $250 million in aggregate principal amount of 8¼% senior notes due 2016 (the “8¼% Notes”). On July 6, 2009, the Partnership privately placed $250 million in aggregate principal amount of 11¼% senior notes due 2017 (the “11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million. On August 13, 2010, the Partnership privately placed $250 million in aggregate principal amount of 7⅞% senior notes due 2018 (the “7⅞% Notes”). On February 2, 2011, the Partnership privately placed $325 million in aggregate principal amount of 6⅞% Senior Notes due 2021 (the “6⅞% Notes”).
On February 4, 2011, the Partnership exchanged an additional $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% Senior Notes due 2017 (the “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.
All four 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, to the extent of the value of the collateral securing that indebtedness.
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.
Interest on the 8¼% Notes accrues at the rate of 8¼% per annum and is payable semi-annually in arrears on January 1 and July 1. Interest on the 11¼% Notes accrues at the rate of 11¼% per annum and is payable semi-annually in arrears on January 15 and July 15. Interest on the 7⅞% Notes accrues at the rate of 7⅞% per annum and is payable semi-annually in arrears on April 15 and October 15. Interest on the 6⅞% Notes accrued at the rate of 6⅞% per annum and is payable semi-annually in arrears on February 1 and August 1, commencing on August 1, 2011.
The Partnership may redeem up to 35% of the aggregate principal amount at any time prior to July 15, 2012 for the 11¼% Notes (October 15, 2013 for the 7⅞% Notes, and February 1, 2014 for the 6⅞% Notes), with the net cash proceeds of one or more equity offerings. The Partnership must pay a redemption price of 111.25% of the principal amount for the 11¼% Notes (107.875% for the 7⅞ Notes, and 106.825% for the 6⅞% Notes), plus accrued and unpaid interest and liquidated damages, if any, to the redemption date provided that:
|
(1)
|
at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and
|
|
(2)
|
the redemption occurs within 90 days of the date of the closing of such equity offering.
|
The Partnership may also redeem all or a part of each of the series of notes, on or after July 1, 2012 for the 8¼% Notes (July 15, 2013 for the 11¼% Notes, October 15, 2014 for the 7⅞ Notes, and February 1, 2016 for the 6⅞% Notes) at the redemption prices set forth below (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidated damages, if any, on the notes redeemed, if redeemed during the twelve-month period beginning on July 1 for the 8¼% Notes (July 15 for the 11¼% Notes, October 15 for the 7⅞% Notes, and February 1 for the 6⅞% Notes) of each year indicated below:
|
8¼% Notes
|
|
11¼% Notes
|
|
7⅞% Notes
|
|
6⅞% Notes
|
||||||||
|
Year
|
|
Redemption %
|
|
Year
|
|
Redemption %
|
|
Year
|
|
Redemption %
|
|
Year
|
|
Redemption %
|
|
2012
|
|
104.125%
|
|
2013
|
|
105.625%
|
|
2014
|
|
103.938%
|
|
2016
|
|
103.438%
|
|
2013
|
|
102.063%
|
|
2014
|
|
102.813%
|
|
2015
|
|
101.969%
|
|
2017
|
|
102.292%
|
|
2014 and thereafter
|
|
100.000%
|
|
2015 and thereafter
|
|
100.000%
|
|
2016 and thereafter
|
|
100.000%
|
|
2018
|
|
101.146%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 and thereafter
|
|
100.000%
|
During 2009, the Partnership repurchased $18.7 million face value ($17.8 million carrying value) of the outstanding 11¼% Notes in open market transactions at an aggregated purchase price of $18.9 million plus accrued interest of $0.3 million. The Partnership recognized a loss on the debt repurchases of $1.5 million, including $0.4 million in debt issue costs associated with the repurchased notes. The repurchased 11¼% Notes were retired and are not eligible for re-issue at a later date.
The debt re-acquisitions described above were reported as follows in our Consolidated Statements of Operations.
|
|
2010
|
2009
|
||||||
|
Premium paid on tender of TRI of 8½ Senior Notes
|
$ | (10.9 | ) | $ | - | |||
|
Loss on open market repurchase of Partnership 11¼ Senior Notes
|
- | (1.1 | ) | |||||
|
Write-off of associated deferred debt issue costs
|
(6.5 | ) | (0.4 | ) | ||||
|
Loss on debt repurchases
|
$ | (17.4 | ) | $ | (1.5 | ) | ||
|
|
||||||||
|
Gain on acquisition of TRC Holdco Notes
|
$ | 36.8 | $ | 25.2 | ||||
|
Write-off of deferred debt issue costs:
|
||||||||
|
TRC Holdco Notes
|
(2.0 | ) | (0.7 | ) | ||||
|
TRI Term Loan Facilities
|
(21.5 | ) | (14.8 | ) | ||||
|
Amended Partnership Revolving Credit Facility
|
(0.8 | ) | - | |||||
|
Gain on early debt extinguishment, net
|
$ | 12.5 | $ | 9.7 | ||||
Subsequent Event. On January 30, 2012 the Partnership privately placed $400.0 million in aggregate principal amount of 6⅜% Senior Notes (the “6⅜% Notes”) due 2022. The 6⅜% Notes resulted in approximately $395.0 million of net proceeds, which was used to reduce borrowings under the Partnership’s Revolver and for general partnership purposes.
Note 9 — Partnership Units and Related Matters
Dropdown Transactions
On September 24, 2009, we completed our sale to the Partnership of our interests in Targa Downstream GP LLC, Targa LSNG GP LLC, Targa Downstream LP and Targa LSNG LP (collectively the “Downstream Business”) for $530.0 million. Consideration to us consisted of $397.5 million in cash and the issuance to us of 174,033 general partner units and 8,527,615 common units.
As part of our sale of the Downstream Business to the Partnership in 2009, we agreed to provide distribution support to the Partnership through the fourth quarter 2011, in the form of a reduction in the reimbursement for general and administrative expense that we allocate to the Partnership if necessary for a 1.0 times distribution coverage, at a distribution level of the Partnership’s at the time of the sale of the Downstream Business of $0.5175 per limited partners unit, subject to a maximum support of $8.0 million per any quarter. No distribution support was required during the term of this provision.
On April 27, 2010, we completed the sale of our interests to the Partnership in the Permian 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 Permian 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.
On August 25, 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.
On September 28, 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 2009, the Partnership filed with the Securities and Exchange Commission (“SEC”) a universal shelf registration statement, subject to effectiveness at the time of use, that allows the Partnership to issue up to an aggregate of $500 million of debt or equity securities (the “2009 Shelf”). The following transactions were completed under the 2009 shelf:
|
·
|
August 2009 – 6,900,000 common units at a price of $15.70 per common unit, providing net proceeds of $105.3 million. We contributed $2.2 million to maintain our 2% general partner interest. The Partnership used a portion of the proceeds to repay $103.5 million of outstanding borrowings under its Revolver.
|
|
·
|
January 2010 – 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.
|
As of December 31, 2011, the Partnership had $245.3 million of available debt or equity securities under the 2009 Shelf, which expires in July 2012.
On April 14, 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 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 this offering to reduce borrowings under its Revolver.
|
Subsequent Event. On January 23, 2012, the Partnership completed a public offering of 4,000,000 common units under its 2010 Shelf at a price of $38.30 per common unit ($37.11 per common unit, net of underwriting discounts). Net proceeds to the Partnership from this offering were approximately $150.0 million. Pursuant to the exercise of the underwriters’ overallotment option, the Partnership sold an additional 405,000 common units, providing net proceeds of approximately $15.0 million. As part of this offering, we purchased 1,300,000 common units with an aggregate value of $49.8 million (based on the offering price of $38.30). The units we purchased were not subject to any underwriter discounts or commissions. In addition, we contributed $3.4 million for 89,898 general partner units to maintain our 2% general partner interest. The Partnership will use the net proceeds from the offering for general partnership purposes, which may include repayment of indebtedness.
Distributions
The distributions by the Partnership for the years ended December 31, 2011 and 2010 were as follows:
|
|
|
Distributions
|
|
|
||||||||||||||||||
|
Date Paid
|
For the Three Months Ended
|
Limited Partners
|
General Partner
|
|
Distributions to Targa Resources Corp.
|
Distributions per limited partner unit
|
||||||||||||||||
|
Common
|
Subordinated
|
Incentive
|
2% |
Total
|
||||||||||||||||||
|
|
|
(In millions, except per unit amounts)
|
|
|
||||||||||||||||||
|
2011
|
|
|
|
|
|
|
|
|||||||||||||||
|
November 14, 2011
|
September 30, 2011
|
$ | 49.4 | $ | - | $ | 8.8 | $ | 1.2 | $ | 59.4 | $ | 16.8 | $ | 0.5825 | |||||||
|
August 12, 2011
|
June 30, 2011
|
48.3 | - | 7.8 | 1.2 | 57.3 | 15.6 | 0.5700 | ||||||||||||||
|
May 13, 2011
|
March 31, 2011
|
47.3 | - | 6.8 | 1.1 | 55.2 | 14.4 | 0.5575 | ||||||||||||||
|
February 14, 2011
|
December 31, 2010
|
46.4 | - | 6.0 | 1.1 | 53.5 | 13.5 | 0.5475 | ||||||||||||||
|
|
|
|||||||||||||||||||||
|
2010
|
|
|||||||||||||||||||||
|
November 12, 2010
|
September 30, 2010
|
$ | 40.6 | $ | - | $ | 4.6 | $ | 0.9 | $ | 46.1 | $ | 11.8 | $ | 0.5375 | |||||||
|
August 13, 2010
|
June 30, 2010
|
35.9 | - | 3.5 | 0.8 | 40.2 | 10.4 | 0.5275 | ||||||||||||||
|
May 14, 2010
|
March 31, 2010
|
35.2 | - | 2.8 | 0.8 | 38.8 | 9.6 | 0.5175 | ||||||||||||||
|
February 12, 2010
|
December 31, 2009
|
35.2 | - | 2.8 | 0.8 | 38.8 | 14.0 | 0.5175 | ||||||||||||||
|
|
|
|||||||||||||||||||||
|
2009
|
|
|||||||||||||||||||||
|
November 14, 2009
|
September 30, 2009
|
$ | 31.9 | $ | - | $ | 2.6 | $ | 0.7 | $ | 35.2 | $ | 13.7 | $ | 0.5175 | |||||||
|
August 14, 2009
|
June 30, 2009
|
23.9 | - | 2.0 | 0.5 | 26.4 | 8.5 | 0.5175 | ||||||||||||||
|
May 15, 2009
|
March 31, 2009
|
18.0 | 5.9 | 1.9 | 0.5 | 26.3 | 8.4 | 0.5175 | ||||||||||||||
|
February 13, 2009
|
December 31, 2008
|
18.0 | 6.0 | 1.9 | 0.5 | 26.4 | 8.4 | 0.5175 | ||||||||||||||
Subsequent Event. On January 12, 2012, the Partnership announced a cash distribution of $0.6025 per common unit on its outstanding common units for the three months ended December 31, 2011, which was paid on February 14, 2012. The distribution was $45.9 million to the Partnership’s non-affiliated common unit holders, and $7.8 million, $11.0 million and $1.3 million to Targa for its ownership of common units, incentive distribution rights and its 2% general partner interest in the Partnership.
Note 10 — Common Stock and Related Matters
Secondary Offering
On April 26, 2011, certain of our stockholders sold, in a secondary public offering, 5,650,000 shares of our common stock under a registration statement on Form S-1 at a price of $31.73 per share of common stock ($30.65 per share, net of underwriting discounts), providing additional net proceeds of $173.2 million to selling stockholders. We received no proceeds from the sale of shares by the selling stockholders. Pursuant to the exercise of the underwriters’ overallotment option, selling stockholders also sold an additional 847,500 shares of our common stock, providing net proceeds of $26.0 million. We incurred approximately $0.6 million of expenses in connection with the offering, including all expenses of the selling stockholders.
Dividends
Dividends since our initial public offering on December 10, 2010 through December 31, 2011 were as follows:
|
Date Paid
|
For the Three Months Ended
|
Total Dividend Declared
|
Amount of Dividend Paid
|
Accrued Dividends (1)
|
Dividend Declared per Share of Common Stock
|
||||||||||||
|
(In millions, except per share amounts)
|
|||||||||||||||||
|
2011
|
|
|
|
|
|
||||||||||||
|
November 15, 2011
|
September 30, 2011
|
$ | 13.0 | $ | 12.6 | $ | 0.4 | $ | 0.3075 | ||||||||
|
August 16, 2011
|
June 30, 2011
|
12.3 | 11.9 | 0.4 | 0.2900 | ||||||||||||
|
May 13, 2011
|
March 31, 2011
|
11.6 | 11.2 | 0.4 | 0.2725 | ||||||||||||
|
February 14, 2011
|
December 31, 2010
|
2.6 | 2.5 | 0.1 | 0.0616 | (2) | |||||||||||
________
|
(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.
|
Subsequent Event. On January 12, 2012, we announced a quarterly dividend of $0.33625 per share of our common stock on our outstanding common stock for the three months ended December 31, 2011. The declared dividend totals $14.3 million, including $0.5 million with respect to accrued dividends related to unvested restricted stock grants. The cash dividend of $13.8 million will be paid on February 15, 2012.
Note 11 — 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 2009, there was no net income available to common shareholders as the preferred shareholders are entitled to all undistributed earnings. As such, there were no earnings per share to our common shareholders during 2009. 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.
|
|
2010
|
|
2009
|
|
Restricted Stock - 2010 Stock Incentive Plan (1)
|
1,350.0
|
|
-
|
|
Restricted Stock - 2005 Incentive Compensation Plan (2)
|
10.6
|
|
488.9
|
|
Stock Options - 2005 Incentive Compensation Plan (3)
|
1,470.0
|
|
2,313.1
|
|
Conversion of Series B Preferred Stock (4)
|
33,322.5
|
|
31,515.3
|
________
|
(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.
|
|
(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 for each year. 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)
|
Amount in 2009 represents the assumed conversion of the Series B Preferred Stock into common shares as of January 1 for the year. 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 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:
|
|
2011
|
2010
|
2009
|
|||||||||
|
Net income
|
$ | 215.4 | $ | 63.3 | $ | 79.1 | ||||||
|
Less: Net income attributable to noncontrolling interest
|
184.7 | 78.3 | 49.8 | |||||||||
|
Net income attributable to Targa Resources Corp.
|
30.7 | (15.0 | ) | 29.3 | ||||||||
|
Dividends on Series B preferred stock
|
- | (9.5 | ) | (17.8 | ) | |||||||
|
Undistributed earnings attributable to preferred shareholders
|
- | - | (11.5 | ) | ||||||||
|
Dividends to common equivalents
|
- | (177.8 | ) | - | ||||||||
|
Net income attributable to common shareholders
|
$ | 30.7 | $ | (202.3 | ) | $ | - | |||||
|
|
||||||||||||
|
Weighted average shares outstanding - basic
|
41.0 | 6.5 | 3.8 | |||||||||
|
|
||||||||||||
|
Net income (loss) available per common share - basic
|
$ | 0.75 | $ | (30.94 | ) | $ | - | |||||
|
|
||||||||||||
|
Weighted average shares outstanding
|
41.0 | 6.5 | 3.8 | |||||||||
|
Dilutive effect of unvested stock awards
|
0.4 | - | - | |||||||||
|
Weighted average shares outstanding - diluted
|
41.4 | 6.5 | 3.8 | |||||||||
|
|
||||||||||||
|
Net income (loss) available per common share - diluted
|
$ | 0.74 | $ | (30.94 | ) | $ | - | |||||
Note 12 – Insurance Claims
Certain Louisiana and Texas facilities sustained damage and had disruption to their operations during the 2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a $19.3 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. During 2010 and 2009, the estimate was reduced by $3.3 million and $3.7 million to give effect to higher insurance recoveries and lower out of pocket costs. These amounts were reported in the Other line in the costs and expenses section of our Consolidated Statements of Operations.
During the year ended December 31, 2010, expenditures related to the hurricanes were $0.3 million. During the year ended December 31, 2009, expenditures related to the hurricanes included $35.9 million for repairs and $7.6 million capitalized as improvements.
Total business interruption proceeds related to Hurricanes Gustav and Ike recorded as revenues during 2011, 2010 and 2009 were $3.0 million, $5.5 million and $19.5 million. We were entitled to receive all post dropdown insurance proceeds under the terms of the Purchase and Sale Agreements with the Partnership. The insurance claim process was completed with respect to Hurricanes Gustav and Ike during 2011.
Note 13 — 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 natural gas and NGL equity volumes through 2013 and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (floors).
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 cover baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon the Partnership’s expected equity NGL composition, as well as specific NGL hedges of ethane and propane. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Additionally, the NGL hedges are based on published index prices for delivery at Mont Belvieu and the natural gas hedges are based on published index prices for delivery at Permian Basin, Mid-Continent and WAHA, which closely approximate the Partnership’s actual NGL and natural gas 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, 2011, the notional volumes of the Partnership’s commodity hedges were:
|
Commodity
|
|
Instrument
|
|
Unit
|
|
|
2012
|
|
2013
|
|
2014
|
|
Natural Gas
|
|
Swaps
|
|
MMBtu/d
|
|
|
31,790
|
|
17,089
|
|
-
|
|
NGL
|
|
Swaps
|
|
Bbl/d
|
|
|
9,361
|
|
4,150
|
|
-
|
|
NGL
|
|
Floors & Caps
|
|
Bbl/d
|
|
|
2,294
|
|
-
|
|
-
|
|
Condensate
|
|
Swaps
|
|
Bbl/d
|
|
|
1,660
|
|
1,795
|
|
700
|
The Partnership frequently enters into derivative instruments to manage location basis differentials with short-term fractionation arrangements. Based on the current application of the basis derivatives, the Partnership does not account for these derivatives as hedges and records changes in fair value and cash settlements to revenues.
Partnership Interest Rate Swaps
On September 6, 2011, the Partnership paid $24.2 million, including $1.2 million in accrued interest, to terminate all of its interest rate swaps. The interest rate swaps were originally entered into to mitigate interest rate risk on the Partnership’s Revolver. A total of $19.6 million in losses were deferred in other comprehensive income (“OCI”), of which, as of December 31, 2011, the Partnership has reclassified $3.3 million to expense. As long as the Partnership maintains its variable rate debt or maintains its borrowing capacity through its Revolver, the remaining deferred loss will be amortized into interest expense over the original terms of the swap contracts, which extend to April 2014.
The following schedules reflect the fair values of the Partnership’s derivative instruments in our financial statements:
|
|
|
|
Derivative Assets
|
|
Derivative Liabilities
|
||||||||||||
|
|
|
|
|
Fair Value as of
|
|
|
Fair Value as of
|
||||||||||
|
|
|
|
Balance Sheet Location
|
|
December 31, 2011
|
|
December 31, 2010
|
|
Balance Sheet Location
|
|
December 31, 2011
|
|
December 31, 2010
|
||||
|
Designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|||||||
|
|
Commodity contracts
|
Current assets
|
|
$
|
40.3
|
|
$
|
24.8
|
|
Current liabilities
|
$
|
40.6
|
|
$
|
25.5
|
||
|
|
|
|
Long-term assets
|
10.9
|
|
|
18.9
|
|
Long-term liabilities
|
|
15.8
|
|
|
20.5
|
|||
|
|
Interest rate contracts
|
Current assets
|
|
|
-
|
|
|
-
|
|
Current liabilities
|
|
-
|
|
|
7.8
|
||
|
|
|
|
Long-term assets
|
|
-
|
|
|
-
|
|
Long-term liabilities
|
|
-
|
|
|
12.3
|
||
|
Total designated as hedging instruments
|
|
$
|
51.2
|
|
$
|
43.7
|
|
|
|
$
|
56.4
|
|
$
|
66.1
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|||||||
|
|
Commodity contracts
|
Current assets
|
|
$
|
0.7
|
|
$
|
0.4
|
|
Current liabilities
|
$
|
0.5
|
|
$
|
0.9
|
||
|
|
|
|
Long-term assets
|
|
-
|
|
|
-
|
|
Long-term liabilities
|
|
-
|
|
|
-
|
||
|
Total not designated as hedging instruments
|
$
|
0.7
|
|
$
|
0.4
|
|
|
|
$
|
0.5
|
|
$
|
0.9
|
||||
|
Total derivatives
|
|
|
|
$
|
51.9
|
|
$
|
44.1
|
|
|
|
$
|
56.9
|
|
$
|
67.0
|
|
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 financial instruments was a net liability of $5.0 million as of December 31, 2011, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities by year as indicated by the counterparties’ credit default swap transactions. These default probabilities have been applied to the unadjusted fair values of the derivative financial instruments to arrive at the credit risk adjustment, which aggregates to $0.3 million as of December 31, 2011.
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 currently 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 OCI, amounts reclassified from OCI to revenue and expense and amounts recognized in income on the ineffective portion of the Partnership’s hedges:
|
|
Gain (Loss)
|
|||||||||||
|
Derivatives in
|
Recognized in OCI on
|
|||||||||||
|
Cash Flow Hedging
|
Derivatives (Effective Portion)
|
|||||||||||
|
Relationships
|
2011
|
2010
|
2009
|
|||||||||
|
Interest rate contracts
|
$ | (4.3 | ) | $ | (20.1 | ) | $ | (2.0 | ) | |||
|
Commodity contracts
|
(33.6 | ) | 52.7 | (104.0 | ) | |||||||
|
|
$ | (37.9 | ) | $ | 32.6 | $ | (106.0 | ) | ||||
|
|
||||||||||||
|
|
Gain (Loss)
|
|||||||||||
|
|
Reclassified from OCI into
|
|||||||||||
|
|
Income (Effective Portion)
|
|||||||||||
|
Location of Gain (Loss)
|
2011 | 2010 | 2009 | |||||||||
|
Interest expense, net
|
$ | (8.1 | ) | $ | (9.2 | ) | $ | (10.4 | ) | |||
|
Revenues
|
(30.3 | ) | 8.7 | 70.0 | ||||||||
|
|
$ | (38.4 | ) | $ | (0.5 | ) | $ | 59.6 | ||||
|
|
||||||||||||
|
|
Gain (Loss)
|
|||||||||||
|
|
Recognized in Income on
|
|||||||||||
|
|
Derivatives (Ineffective Portion)
|
|||||||||||
|
Location of Gain (Loss)
|
2011 | 2010 | 2009 | |||||||||
|
Revenues
|
$ | - | $ | (0.3 | ) | $ | (0.3 | ) | ||||
Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying price indices. During the years ended December 31, 2011, 2010 and 2009, we recorded the following mark-to-market gains (losses):
|
Gain (Loss) Recognized in Income on Derivatives
|
||||||||||
| Derivatives Not Designated as Hedging Instruments | Location of Gain (Loss) Recognized in Income on Derivatives |
2011
|
2010
|
2009
|
||||||
|
Commodity contracts
|
Revenue
|
$ | 1.7 | $ | (1.0 | ) | $ | (6.1 | ) | |
|
Commodity contracts
|
Other income (expense)
|
- | (0.4 | ) | 0.3 | |||||
|
Interest rate swaps
|
Other income (expense)
|
(5.0 | ) | - | - | |||||
|
|
|
$ | (3.3 | ) | $ | (1.4 | ) | $ | (5.8 | ) |
The following table shows the unrealized gains (losses) included in OCI:
|
|
2011
|
2010
|
||||||
|
Unrealized gain on commodity hedges, before tax
|
$ | 0.4 | $ | 4.5 | ||||
|
Unrealized gain on commodity hedges, net of tax
|
0.2 | 2.7 | ||||||
|
Unrealized loss on interest rate swaps, before tax
|
(2.5 | ) | (3.4 | ) | ||||
|
Unrealized loss on interest rate swaps, net of tax
|
(1.4 | ) | (2.1 | ) | ||||
As of December 31, 2011, deferred net losses of $6.1 million on commodity hedges and $7.9 million on terminated interest rate swaps recorded in OCI are expected to be reclassified to revenue and interest expense during the next twelve months.
In July 2008, Targa and the Partnership paid $9.6 million and $77.8 million, respectively, to terminate certain out-of-the-money natural gas and NGL commodity swaps. Targa and the Partnership also entered into new natural gas and NGL commodity swaps at then current market prices that matched the production volumes of the terminated swaps. Prior to the terminations, these swaps were designated as cash flow hedges. During the years ended December 31, 2011, 2010 and 2009, deferred losses of $0.4 million, $29.6 million and $40.0 million related to the terminated swaps were reclassified from OCI as non-cash reductions to revenue.
See Note 3 and Note 14 for additional disclosures related to derivative instruments and hedging activities.
Note 14 — Fair Value Measurements
We categorize the inputs to the fair value of financial assets and liabilities 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 are either directly or indirectly observable 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 requiring an entity to develop its own assumptions.
|
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 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 we 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 liability position of $5.0 million for the year ended December 31, 2011, are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. This liability position reflects the present value, adjusted for counterparty credit risk, of the amount the Partnership expects to pay 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 $54.5 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 $44.5 million, ignoring an adjustment for counterparty credit risk. Therefore, based on the fair value of the Partnership’s derivative instruments as of December 31, 2011, a 10% movement in forward commodity prices would lead to a change in the fair value of the Partnership’s derivative instruments of plus or minus $49.5 million.
The following tables present the fair value of the Partnership’s financial assets and liabilities according to the fair value hierarchy. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.
|
|
2011
|
|||||||||||||||
|
|
Total
|
Level 1
|
Level 2
|
Level 3
|
||||||||||||
|
Assets from commodity derivative contracts
|
$ | 51.9 | $ | - | $ | 51.9 | $ | - | ||||||||
|
Total assets
|
$ | 51.9 | $ | - | $ | 51.9 | $ | - | ||||||||
|
Liabilities from commodity derivative contracts
|
$ | 56.9 | $ | - | $ | 56.9 | $ | - | ||||||||
|
Total liabilities
|
$ | 56.9 | $ | - | $ | 56.9 | $ | - | ||||||||
|
|
2010
|
|||||||||||||||
|
|
Total
|
Level 1
|
Level 2
|
Level 3
|
||||||||||||
|
Assets from commodity derivative contracts
|
$ | 44.1 | $ | - | $ | 43.9 | $ | 0.2 | ||||||||
|
Total assets
|
$ | 44.1 | $ | - | $ | 43.9 | $ | 0.2 | ||||||||
|
Liabilities from commodity derivative contracts
|
$ | 46.9 | $ | - | $ | 35.1 | $ | 11.8 | ||||||||
|
Liabilities from interest rate derivatives
|
20.1 | - | 20.1 | - | ||||||||||||
|
Total liabilities
|
$ | 67.0 | $ | - | $ | 55.2 | $ | 11.8 | ||||||||
The following table sets forth a reconciliation of the changes in the fair value of the Partnership’s financial instruments classified as Level 3 in the fair value hierarchy:
|
|
Commodity Derivative Contracts
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Balance at January 1
|
$ | (11.6 | ) | $ | (13.7 | ) | $ | 148.2 | ||||
|
Unrealized losses included in OCI
|
- | 2.6 | (57.1 | ) | ||||||||
|
Settlements included in Net Income
|
3.7 | (0.5 | ) | (35.0 | ) | |||||||
|
Transfers out of Level 3
|
7.9 | - | (69.8 | ) | ||||||||
|
Balance at December 31
|
$ | - | $ | (11.6 | ) | $ | (13.7 | ) | ||||
The Partnership transferred $7.9 million in derivative liabilities and $69.8 million in derivative assets from Level 3 to Level 2 for the years ended December 31, 2011 and 2009. The transfer is attributable to increased transparency and liquidity in the NGL markets.
The Partnership designates all Level 3 derivative instruments as cash flow hedges, and, as such, all changes in their fair value are reflected in OCI. Therefore, there are no unrealized gains or losses reflected in revenues or other income (expense) with respect to Level 3 derivative instruments.
Note 15 — Fair Value of Financial Instruments
The estimated fair values of assets and liabilities classified as financial instruments have been determined using available market information and the valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current liabilities approximate fair values due to the short term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value.
The carrying value of the Senior Secured Revolving Credit Facilities approximate their fair value, as its interest rate is based on prevailing market rates. The fair value of the Partnership’s senior unsecured notes is based on quoted market prices based on trades of such debt as of the dates indicated in the following table:
|
|
2011
|
2010
|
||||||||||||||
|
|
Carrying Amount
|
Fair Value
|
Carrying Amount
|
Fair Value
|
||||||||||||
|
Holdco loan facility (1)
|
$ | 89.3 | $ | 87.5 | $ | 89.3 | $ | 86.8 | ||||||||
|
Senior unsecured notes of the Partnership, 8¼% fixed rate
|
209.1 | 220.5 | 209.1 | 219.4 | ||||||||||||
|
Senior unsecured notes of the Partnership, 11¼% fixed rate
|
69.8 | 82.1 | 221.0 | 253.2 | ||||||||||||
|
Senior unsecured notes of the Partnership, 7⅞% fixed rate
|
250.0 | 264.5 | 250.0 | 259.7 | ||||||||||||
|
Senior unsecured notes of the Partnership, 6⅞% fixed rate
|
450.8 | 490.2 | N/A | N/A | ||||||||||||
________
|
(1)
|
The Holdco loan is not widely held, and we are not able to obtain an indicative quote from external sources. The December 31, 2010 fair value was based on the November 2010 repurchases. The December 31, 2011 fair value is based on management’s consideration of changes in settlement value given the trades that took place in November 2010.
|
Note 16 — Related Party Transactions
Transactions with Unconsolidated Affiliate
For the years 2011, 2010 and 2009, transactions with GCF included in revenues were $0.8 million, $0.3 million and $0.2 million. For the same periods, transactions with GCF included in costs and expenses were $0.4 million, $1.1 million and $1.4 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. SAJET owns real and personal property as well as certain technology and project development rights. We provide general and administrative services to SAJET and are reimbursed for these amounts. During 2011, we were reimbursed $0.3 million for such services provided.
Relationship with Warburg Pincus LLC
Affiliates of Warburg Pincus beneficially own approximately 23.1% 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 Director 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 Antero Resources Corporation (“Antero”) and 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, Antero and Laredo.
The following table shows the transactions with each of these related parties.
|
|
Purchases
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Broad Oak
|
$ | 71.3 | $ | 41.5 | $ | 8.6 | ||||||
|
Antero
|
- | 0.1 | 0.5 | |||||||||
|
Laredo
|
34.1 | - | - | |||||||||
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, 2011.
|
|
In Aggregate
|
2012
|
2013
|
2014
|
2015
|
2016
|
||||||||||||||||||
|
Non-Partnership obligations:
|
|
|
|
|
|
|
||||||||||||||||||
|
Operating lease (1)
|
$ | 12.9 | $ | 2.1 | $ | 2.2 | $ | 2.2 | $ | 2.2 | $ | 2.2 | ||||||||||||
|
Partnership obligations:
|
||||||||||||||||||||||||
|
Operating lease and service contract (2)
|
35.1 | 7.5 | 5.8 | 4.9 | 4.9 | 4.5 | ||||||||||||||||||
|
Pipeline capacity and throughput agreements (3)
|
195.8 | 8.3 | 19.1 | 18.0 | 18.4 | 18.8 | ||||||||||||||||||
|
Land site lease and right-of-way (4)
|
6.4 | 1.8 | 1.3 | 1.2 | 1.1 | 1.1 | ||||||||||||||||||
|
|
$ | 250.2 | $ | 19.7 | $ | 28.5 | $ | 26.2 | $ | 26.6 | $ | 26.6 | ||||||||||||
______________
|
(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:
|
|
2011
|
2010
|
2009
|
|||||||||
|
Non-Partnership:
|
|
|
|
|||||||||
|
Operating leases
|
$ | 2.0 | $ | 2.1 | $ | 2.4 | ||||||
|
Partnership:
|
||||||||||||
|
Operating leases
|
14.2 | 13.9 | 14.1 | |||||||||
|
Pipeline capacity and throughput agreement payments
|
12.4 | 8.6 | 9.6 | |||||||||
|
Land site lease and right-of-way
|
2.8 | 2.8 | 2.3 | |||||||||
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 are not significant at December 31, 2011 and 2010.
In May 2007, the New Mexico Environment Department (“NMED”) alleged air emissions violations at the Eunice, Monument and Saunders gas processing plants, which are operated by the Partnership and owned by Versado Gas Processors, LLC (“Versado”), a joint venture that owns these plants and in which the Partnership owns a 63% interest. These alleged air emissions were identified in the course of an inspection of the Eunice plant conducted by the NMED in August 2005.
In January 2010, Versado settled the alleged violations with NMED for a penalty of approximately $1.5 million. As part of the settlement, Versado agreed to install two acid gas injection wells, additional emission control equipment and monitoring equipment. These projects were substantially complete as of December 31, 2011 at a total cost of approximately $27.5 million, of which the Partnership’s share was $17.4 million. Under the terms of the Versado purchase and sale agreement, we reimbursed the Partnership for post-dropdown maintenance capital expenditures of $13.2 million required pursuant to the NMED settlement agreement.
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, transporting, 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 (i) changes in the commodity prices of these hydrocarbon products and (ii) changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, 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 natural gas 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, NGL and condensate equity volumes for the years 2012 through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of expected equity volumes that are hedged decrease over time. 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. 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 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 13.
Interest Rate Risk. The Partnership is exposed to changes in interest rates, primarily as a result of variable rate borrowings under its credit facility.
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. The Partnership’s potential total loss in the event that all counterparties with whom it has asset positions default would be limited to approximately $22 million as of December 31, 2011 as a result of the master netting arrangements. The range of losses attributable to the Partnership’s individual counterparties would be between $1.6 and $7.0 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, 2011, affiliates of Barclays PLC (“Barclays”), Credit Suisse AG (“Credit Suisse”), Natixis and JP Morgan Chase Bank N.A. (“JP Morgan”) accounted for 38%, 15%, 14% and 10% of the Partnership’s counterparty credit exposure related to commodity derivative instruments. Barclays, Credit Suisse, Natixis and JP Morgan 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:
|
|
2011
|
2010
|
2009
|
|||||||||
|
Balance at beginning of year
|
$ | 7.9 | $ | 8.0 | $ | 9.2 | ||||||
|
Additions
|
0.5 | - | - | |||||||||
|
Deductions
|
(6.0 | ) | (0.1 | ) | (1.2 | ) | ||||||
|
Balance at end of year
|
$ | 2.4 | $ | 7.9 | $ | 8.0 | ||||||
Significant Commercial Relationships
The following customer accounted for more than 10% of our consolidated revenues for the periods indicated:
|
|
2011
|
2010
|
2009
|
|||||||||
|
% of consolidated revenues
|
|
|
|
|||||||||
|
Chevron Phillips Chemical Company LLC
|
12% | 10% | 15% | |||||||||
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 obligations.
Note 19 – Other Operating Income
Our other operating (income) expense consists of the following items for the periods indicated:
|
|
2011
|
2010
|
2009
|
|||||||||
|
Abandoned project costs
|
$ | - | $ | 0.1 | $ | 5.5 | ||||||
|
Casualty loss (gain) adjustment, See Note 12
|
- | (3.3 | ) | (3.6 | ) | |||||||
|
Loss (gain) on sale of assets
|
0.2 | (1.5 | ) | 0.1 | ||||||||
|
|
$ | 0.2 | $ | (4.7 | ) | $ | 2.0 | |||||
Note 20—Income Taxes
Our provisions for income taxes for the periods indicated are as follows:
|
|
2011
|
2010
|
2009
|
|||||||||
|
Current expense (benefit)
|
$ | 14.3 | $ | (10.6 | ) | $ | 1.6 | |||||
|
Deferred expense
|
12.3 | 33.1 | 19.1 | |||||||||
|
|
$ | 26.6 | $ | 22.5 | $ | 20.7 | ||||||
Our deferred income tax assets and liabilities at December 31, 2011 and 2010 consist of differences related to the timing of recognition of certain types of costs as follows:
|
|
2011
|
2010
|
||||||
|
Deferred tax assets:
|
|
|
||||||
|
Net operating loss
|
$ | - | $ | - | ||||
|
Other
|
3.5 | 3.4 | ||||||
|
Deferred tax assets before valuation allowance
|
3.5 | 3.4 | ||||||
|
Valuation allowance
|
(3.5 | ) | (3.5 | ) | ||||
|
|
- | (0.1 | ) | |||||
|
Deferred tax liabilities:
|
||||||||
|
Investments (1)
|
(95.5 | ) | (89.6 | ) | ||||
|
Risk management contracts
|
(9.8 | ) | (9.4 | ) | ||||
|
Property, Plant and Equipment
|
(13.8 | ) | (12.4 | ) | ||||
|
Other
|
(4.8 | ) | - | |||||
|
|
(123.9 | ) | (111.4 | ) | ||||
|
Net deferred tax liability
|
$ | (123.9 | ) | $ | (111.5 | ) | ||
|
Federal
|
$ | (115.6 | ) | $ | (106.6 | ) | ||
|
Foreign
|
0.6 | 0.5 | ||||||
|
State
|
(8.9 | ) | (5.4 | ) | ||||
|
|
$ | (123.9 | ) | $ | (111.5 | ) | ||
|
Balance sheet classification of deferred tax assets (liabilities):
|
||||||||
|
Current asset
|
$ | 0.1 | $ | 3.6 | ||||
|
Long-term asset
|
(3.5 | ) | (3.5 | ) | ||||
|
Current liability
|
- | - | ||||||
|
Long-term liability
|
(120.5 | ) | (111.6 | ) | ||||
|
|
$ | (123.9 | ) | $ | (111.5 | ) | ||
_________
|
(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 investment in the Partnership and a wholly-owned partnership.
|
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:
|
Income tax reconciliation:
|
2011
|
2010
|
2009
|
|||||||||
|
Income before income taxes
|
$ | 242.0 | $ | 85.8 | $ | 99.8 | ||||||
|
Less: Net income attributable to noncontrolling interest
|
(184.7 | ) | (78.3 | ) | (49.8 | ) | ||||||
|
Plus: Income taxes included in noncontrolling interest
|
(3.6 | ) | (3.1 | ) | (0.9 | ) | ||||||
|
Income attributable to TRC before income taxes
|
53.7 | 4.4 | 49.1 | |||||||||
|
Federal statutory income tax rate
|
35% | 35% | 35% | |||||||||
|
U.S. federal income tax provision at statutory rate
|
18.8 | 1.5 | 17.2 | |||||||||
|
State income taxes, net of federal tax benefit (1)
|
2.6 | 13.4 | 1.8 | |||||||||
|
Valuation allowance
|
- | 3.0 | - | |||||||||
|
Other, net
|
5.2 | 4.6 | 1.7 | |||||||||
|
Income Tax Provision
|
$ | 26.6 | $ | 22.5 | $ | 20.7 | ||||||
________
|
(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.
On April 14, 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. There was no tax impact on consolidated net income as a result of the secondary public offering.
On April 27, 2010, we sold our interests in the Permian 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 Permian 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.
Note 21 — Supplemental Cash Flow Information
Supplemental cash flow information was as follows for the periods indicated:
|
|
2011
|
2010
|
2009
|
|||||||||
|
Cash:
|
|
|
|
|||||||||
|
Interest paid
|
$ | 99.5 | $ | 90.8 | $ | 82.4 | ||||||
|
Income taxes paid
|
34.5 | 95.9 | 6.5 | |||||||||
|
Non-cash:
|
||||||||||||
|
Inventory line-fill transferred to property, plant and equipment
|
0.7 | 0.4 | 9.8 | |||||||||
|
Accrued dividends on unvested equity awards
|
1.4 | - | - | |||||||||
|
Paid-in-kind interest refinanced to Holdco principal
|
- | 10.9 | 25.9 | |||||||||
|
Conversion of Series B preferred Stock (accretive value)
|
- | 79.9 | - | |||||||||
|
Distribution of property to common shareholders
|
- | 3.2 | - | |||||||||
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.
During 2010 and 2009, we recognized compensation expenses associated with our 2005 Plan stock options of $0.2 million and $0.1 million. The compensation expenses associated with the vesting of our restricted stock was $0.2 million and $0.3 million during 2010 and 2009.
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 - The follow table summarizes the restricted stock awards in shares and in dollars for the years indicated:
|
|
|
Weighted-average
|
||||||
|
|
Number of shares
|
Grant-Date Fair Value
|
||||||
|
Outstanding at January 1, 2010
|
- | $ | - | |||||
|
Granted (1)
|
1,350,000 | 22.00 | ||||||
|
Outstanding at December 31, 2010
|
1,350,000 | 22.00 | ||||||
|
Granted (2)
|
84,220 | 33.39 | ||||||
|
Outstanding at December 31, 2011
|
1,434,220 | 22.67 | ||||||
_______
|
(1)
|
These awards were issued in conjunction with the Targa IPO and vest over a three year period at 60% in 24 months and the remaining 40% in 36 months.
|
|
(2)
|
These awards include 33,140 shares granted in February and 51,080 shares in August and will cliff vest at the end of three years in June 2014.
|
The compensation expense of the restricted stocks was calculated based on the fair value of the stock at the grant date. During 2011 and 2010, we recognized total compensation expenses associated with the restricted awards of $13.4 million and $1.1 million.
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. Total compensation expense associated with these awards in 2010 was $12.2 million based on the fair value of the stock of $22 per share at grant date.
On February 17, 2011, the Committee awarded 24,250 shares of our stock to our outside directors. The awards vested at the grant date. The total compensation expense for the awards was $0.8 million with a grant date fair value of $31.75.
Subsequent events. On January 12, 2012, the Committee made restricted stock awards of 34,140 to executive management under the TRC Plan for the 2012 compensation cycle that will cliff vest in three years from the grant date.
On January 12, 2012, the Committee also awarded 9,255 shares of our stock to our outside directors (1,851 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.
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, awards vest three years following the date of grant. 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 paid in cash for both cash-settled 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. Starting in 2010 we have used a Monte Carlo simulation model to estimate accruals throughout the vesting period. Previously we used a Black-Scholes option pricing model. We consider the Monte Carlo simulation model to be more appropriate for valuation purposes than the previous methodology because it directly incorporates the peer group ranking market conditions.
TRC LTIP -- Cash-settled Performance Units
The following table summarizes the cash-settled performance units for the year ended 2011 awarded under the Targa LTIP.
|
|
Program Year
|
|
||||||||||||||||||
|
|
2008 Plan
|
2009 Plan
|
2010 Plan
|
2011 Plan
|
Total
|
|||||||||||||||
|
Unit outstanding January 1, 2011
|
133,800 | 528,500 | 307,853 | - | 970,153 | |||||||||||||||
|
Granted
|
- | - | - | 120,360 | 120,360 | |||||||||||||||
|
Vested and paid
|
(132,600 | ) | - | - | - | (132,600 | ) | |||||||||||||
|
Forfeited
|
(1,200 | ) | (2,500 | ) | (800 | ) | (480 | ) | (4,980 | ) | ||||||||||
|
Units outstanding December 31, 2011
|
- | 526,000 | 307,053 | 119,880 | 952,933 | |||||||||||||||
|
|
||||||||||||||||||||
|
Calculated fair market value as of December 31, 2011
|
$ | 21,959,592 | $ | 13,484,900 | $ | 3,644,897 | $ | 39,089,389 | ||||||||||||
|
|
||||||||||||||||||||
|
Current liability
|
$ | 18,422,136 | $ | - | $ | - | $ | 18,422,136 | ||||||||||||
|
Long-term liability
|
6,842,324 | 616,734 | 7,459,058 | |||||||||||||||||
|
|
||||||||||||||||||||
|
To be recognized in future periods
|
3,537,456 | 6,642,576 | 3,028,163 | 13,208,195 | ||||||||||||||||
|
|
||||||||||||||||||||
|
Vesting date
|
June 2012
|
June 2013
|
June 2014
|
|||||||||||||||||
We recognized compensation expenses of $13.3 million, $13.9 million and $10.5 million for the years ended December 31, 2011, 2010 and 2009. Cash paid for vested awards was, $5.5 million, and $9.1 million during 2011 and 2010. The remaining weighted average recognition period for the unrecognized compensation cost is approximately 2 years. These expenses are allocated to the Partnership under the provisions of the Omnibus Agreement.
Partnership LTIP – Equity-Settled Performance Units
In February and August 2011, the Compensation Committee made awards to executive management and other officers for the 2011 compensation cycle of 91,010 and 44,860 equity-settled performance units under the Partnership LTIP that will vest in June 2014. The grant date fair values of $34.83 and $32.13 for these awards were determined using a Monte Carlo simulation model that employed discount rates of 6.5% and 7.5%, and implied volatilities of 20.4% and 21.6% respectively. The Partnership recognized $1.0 million of compensation expense on these awards during 2011.
Subsequent Event. On January 12, 2012, the Committee made awards to the executive management for the 2012 compensation cycle of 110,460 equity-settled performance units under the Partnership LITP that will vest in June 2015.
Partnership Director Grants
During 2011 the Committee made awards of 10,600 common units (2,120 common units to each of the Partnership’s non-management directors). The awards vested immediately at the grant date and a compensation expense of $0.3 million was recorded.
During 2010 and 2009, 15,750 and 32,000 of the Partnership’s restricted common units were granted (2,250 and 4,000 of the Partnership restricted common units to each of the Partnership’s and our non-management directors). The awards will settle with the delivery of common units and are subject to three-year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date. The Partnership estimates that the remaining fair value of an immaterial amount will be recognized in expense during the next year. As of December 31, 2011 there were 19,831 unvested common units outstanding.
The following table summarizes the unvested common unit-based awards of our and the Partnership’s Directors for 2011 (in units and dollars):
|
|
|
Weighted-average
|
||||||
|
|
Number of units
|
Grant-Date Fair Value
|
||||||
|
Outstanding at December 31, 2010
|
39,074 | $ | 16.12 | |||||
|
Granted
|
10,600 | 33.53 | ||||||
|
Vested and paid
|
(29,843 | ) | 22.18 | |||||
|
Outstanding at December 31, 2011
|
19,831 | 16.31 | ||||||
The weighted average grant-date fair value of the restricted awards granted during the years 2011, 2010 and 2009 were $33.53, $23.51 and $8.20. Total fair value of units vested during 2011, 2010 and 2009 were $0.7 million, $0.3 million and $0.2 million. The compensation expenses recognized during 2011, 2010 and 2009 were $0.5 million, $0.4 million and $0.3 million.
Subsequent Event. On January 12, 2012, the Committee made equity based awards of 9,980 of our common units (1,996 units to each of our non-management directors). The awards vested immediately at the grant date.
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 $7.8 million, $7.2 million, and $6.6 million during 2011, 2010, and 2009.
Note 23 — Segment Information
With the conveyance of all of our remaining operating assets to the Partnership in September 2010, all operating assets are now owned by the Partnership.
The Partnership reports its operations in two divisions: (i) Natural Gas 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 Natural Gas 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. 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 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 Natural Gas 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. See Note 4.
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 NGL production and purchasing NGL products in selected United States markets; (2) providing liquefied petroleum gas 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 the Partnership’s Natural Gas Gathering and Processing division and the purchase and resale of natural gas in selected United States markets.
Other contains the results of the Partnership’s commodity hedging activities. 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 Targa 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.
|
|
2011
|
|||||||||||||||||||||||||||||||
|
|
Partnership
|
|
|
|||||||||||||||||||||||||||||
|
|
Field Gathering and Processing
|
Coastal Gathering and Processing
|
Logistics Assets
|
Marketing and Distribution
|
Other
|
Corporate and Eliminations
|
TRC Non-Partnership
|
Consolidated
|
||||||||||||||||||||||||
|
Revenues
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
|
Sale of commodities
|
$ | 184.9 | $ | 325.7 | $ | 43.2 | $ | 6,209.9 | $ | (37.6 | ) | $ | - | $ | 4.4 | $ | 6,730.5 | |||||||||||||||
|
Fees from midstream services
|
26.8 | 18.3 | 128.5 | 56.6 | - | - | - | 230.2 | ||||||||||||||||||||||||
|
Other
|
0.7 | 1.5 | 1.5 | 27.2 | - | (0.1 | ) | 3.0 | 33.8 | |||||||||||||||||||||||
|
|
212.4 | 345.5 | 173.2 | 6,293.7 | (37.6 | ) | (0.1 | ) | 7.4 | 6,994.5 | ||||||||||||||||||||||
|
Intersegment revenues
|
||||||||||||||||||||||||||||||||
|
Sale of commodities
|
1,428.4 | 952.9 | 1.0 | 636.5 | - | (3,018.8 | ) | - | - | |||||||||||||||||||||||
|
Fees from midstream services
|
1.1 | 0.4 | 89.1 | 8.2 | - | (98.8 | ) | - | - | |||||||||||||||||||||||
|
Other
|
- | - | 0.2 | 28.4 | - | (28.6 | ) | - | - | |||||||||||||||||||||||
|
|
1,429.5 | 953.3 | 90.3 | 673.1 | - | (3,146.2 | ) | - | - | |||||||||||||||||||||||
|
Revenues
|
$ | 1,641.9 | $ | 1,298.8 | $ | 263.5 | $ | 6,966.8 | $ | (37.6 | ) | $ | (3,146.3 | ) | $ | 7.4 | $ | 6,994.5 | ||||||||||||||
|
Operating margin
|
$ | 287.9 | $ | 174.3 | $ | 123.1 | $ | 113.4 | $ | (37.6 | ) | $ | - | $ | 7.3 | $ | 668.4 | |||||||||||||||
|
Other financial information:
|
||||||||||||||||||||||||||||||||
|
Total assets
|
$ | 1,666.2 | $ | 427.5 | $ | 775.4 | $ | 650.5 | $ | 51.9 | $ | 86.5 | $ | 173.0 | $ | 3,831.0 | ||||||||||||||||
|
Capital expenditures
|
$ | 167.5 | $ | 12.8 | $ | 303.9 | $ | 3.5 | $ | - | $ | 2.3 | $ | 2.2 | $ | 492.2 | ||||||||||||||||
|
|
2010
|
|||||||||||||||||||||||||||||||
|
|
Partnership
|
|
|
|||||||||||||||||||||||||||||
|
|
Field Gathering and Processing
|
Coastal Gathering and Processing
|
Logistics Assets
|
Marketing and Distribution
|
Other
|
Corporate and Eliminations
|
TRC Non-Partnership
|
Consolidated
|
||||||||||||||||||||||||
|
Revenues
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
|
Sale of commodities
|
$ | 188.7 | $ | 432.2 | $ | - | $ | 4,663.2 | $ | 4.0 | $ | 0.1 | $ | 3.0 | $ | 5,291.2 | ||||||||||||||||
|
Fees from midstream services
|
24.6 | 13.0 | 83.7 | 42.1 | - | 0.1 | - | 163.5 | ||||||||||||||||||||||||
|
Other
|
(1.7 | ) | 1.4 | 0.8 | 15.0 | - | (0.2 | ) | 6.1 | 21.4 | ||||||||||||||||||||||
|
|
211.6 | 446.6 | 84.5 | 4,720.3 | 4.0 | - | 9.1 | 5,476.1 | ||||||||||||||||||||||||
|
Intersegment revenues
|
||||||||||||||||||||||||||||||||
|
Sale of commodities
|
1,083.2 | 753.7 | 0.8 | 492.3 | - | (2,330.0 | ) | - | - | |||||||||||||||||||||||
|
Fees from midstream services
|
1.2 | 2.0 | 86.3 | 2.3 | - | (91.8 | ) | - | - | |||||||||||||||||||||||
|
Other
|
- | - | - | 22.6 | - | (22.6 | ) | - | - | |||||||||||||||||||||||
|
|
1,084.4 | 755.7 | 87.1 | 517.2 | - | (2,444.4 | ) | - | - | |||||||||||||||||||||||
|
Revenues
|
$ | 1,296.0 | $ | 1,202.3 | $ | 171.6 | $ | 5,237.5 | $ | 4.0 | $ | (2,444.4 | ) | $ | 9.1 | $ | 5,476.1 | |||||||||||||||
|
Operating margin
|
$ | 236.6 | $ | 107.8 | $ | 83.8 | $ | 80.5 | $ | 4.0 | $ | - | $ | 8.6 | $ | 521.3 | ||||||||||||||||
|
Other financial information:
|
||||||||||||||||||||||||||||||||
|
Total assets
|
$ | 1,623.4 | $ | 451.5 | $ | 471.9 | $ | 519.9 | $ | 44.1 | $ | 75.6 | $ | 207.4 | $ | 3,393.8 | ||||||||||||||||
|
Capital expenditures
|
$ | 67.9 | $ | 8.8 | $ | 66.3 | $ | 2.2 | $ | - | $ | - | $ | 3.4 | $ | 148.6 | ||||||||||||||||
|
|
2009
|
|||||||||||||||||||||||||||||||
|
|
Partnership
|
|
|
|||||||||||||||||||||||||||||
|
|
Field Gathering and Processing
|
Coastal Gathering and Processing
|
Logistics Assets
|
Marketing and Distribution
|
Other
|
Corporate and Eliminations
|
TRC Non-Partnership
|
Consolidated
|
||||||||||||||||||||||||
|
Revenues
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
|
Sale of commodities
|
$ | 175.7 | $ | 367.5 | $ | 0.1 | $ | 3,725.5 | $ | 46.3 | $ | (0.4 | ) | $ | 23.9 | $ | 4,338.6 | |||||||||||||||
|
Fees from midstream services
|
17.6 | 13.2 | 73.9 | 66.1 | - | 0.1 | - | 170.9 | ||||||||||||||||||||||||
|
Other
|
(1.6 | ) | 11.3 | 2.7 | 11.9 | - | 0.3 | 8.2 | 32.8 | |||||||||||||||||||||||
|
|
191.7 | 392.0 | 76.7 | 3,803.5 | 46.3 | - | 32.1 | 4,542.3 | ||||||||||||||||||||||||
|
Intersegment revenues
|
||||||||||||||||||||||||||||||||
|
Sale of commodities
|
778.9 | 520.3 | 2.0 | 334.2 | - | (1,635.4 | ) | - | - | |||||||||||||||||||||||
|
Fees from midstream services
|
1.2 | 4.7 | 77.5 | 3.2 | - | (86.6 | ) | - | - | |||||||||||||||||||||||
|
Other
|
- | - | - | 16.2 | - | (16.2 | ) | - | - | |||||||||||||||||||||||
|
|
780.1 | 525.0 | 79.5 | 353.6 | - | (1,738.2 | ) | - | - | |||||||||||||||||||||||
|
Revenues
|
$ | 971.8 | $ | 917.0 | $ | 156.2 | $ | 4,157.1 | $ | 46.3 | $ | (1,738.2 | ) | $ | 32.1 | $ | 4,542.3 | |||||||||||||||
|
Operating margin
|
$ | 183.2 | $ | 89.7 | $ | 74.3 | $ | 83.0 | $ | 46.3 | $ | - | $ | 33.4 | $ | 509.9 | ||||||||||||||||
|
Other financial information:
|
||||||||||||||||||||||||||||||||
|
Total assets
|
$ | 1,668.2 | $ | 489.0 | $ | 414.4 | $ | 442.3 | $ | 46.8 | $ | 92.0 | $ | 214.8 | $ | 3,367.5 | ||||||||||||||||
|
Capital expenditures
|
$ | 53.4 | $ | 14.0 | $ | 15.8 | $ | 6.3 | $ | - | $ | - | $ | 2.7 | $ | 92.2 | ||||||||||||||||
|
The following table shows our consolidated revenues by product and service for each period presented:
|
|
|
2011
|
2010
|
2009
|
|||||||||
|
Sales of commodities
|
|
|
|
|||||||||
|
Natural gas sales
|
$ | 1,120.7 | $ | 1,075.6 | $ | 809.0 | ||||||
|
NGL sales
|
5,496.9 | 4,111.4 | 3,364.5 | |||||||||
|
Condensate sales
|
103.0 | 95.1 | 95.5 | |||||||||
|
Petroleum products
|
43.1 | - | - | |||||||||
|
Derivative activities
|
(33.2 | ) | 9.1 | 69.6 | ||||||||
|
|
6,730.5 | 5,291.2 | 4,338.6 | |||||||||
|
Fees from midstream services
|
||||||||||||
|
Fractionating and treating fees
|
86.7 | 55.7 | 61.2 | |||||||||
|
Storage and terminaling fees
|
52.0 | 40.1 | 41.0 | |||||||||
|
Transportation fees
|
58.4 | 35.5 | 44.8 | |||||||||
|
Gas processing fees
|
33.1 | 32.2 | 23.9 | |||||||||
|
|
230.2 | 163.5 | 170.9 | |||||||||
|
Other
|
||||||||||||
|
Business interruption insurance
|
3.0 | 6.0 | 21.5 | |||||||||
|
Other
|
30.8 | 15.4 | 11.3 | |||||||||
|
|
33.8 | 21.4 | 32.8 | |||||||||
|
Total revenues
|
$ | 6,994.5 | $ | 5,476.1 | $ | 4,542.3 | ||||||
The following table is a reconciliation of operating margin to net income for each period presented:
|
|
2011
|
2010
|
2009
|
|||||||||
|
Reconciliation of operating margin to net income
|
|
|
|
|||||||||
|
Operating margin
|
$ | 668.4 | $ | 521.3 | $ | 509.9 | ||||||
|
Depreciation and amortization expense
|
(181.0 | ) | (185.5 | ) | (170.3 | ) | ||||||
|
General and administrative expense
|
(136.1 | ) | (144.4 | ) | (120.4 | ) | ||||||
|
Interest expense, net
|
(111.7 | ) | (110.9 | ) | (132.1 | ) | ||||||
|
Income tax expense
|
(26.6 | ) | (22.5 | ) | (20.7 | ) | ||||||
|
Other, net
|
2.4 | 5.3 | 12.7 | |||||||||
|
Net income
|
$ | 215.4 | $ | 63.3 | $ | 79.1 | ||||||
Note 24—Selected Quarterly Financial Data (Unaudited)
Our results of operations by quarter for the years ended December 31, 2011 and 2010 were as follows:
|
|
First
|
Second
|
Third
|
Fourth
|
|
|||||||||||||||
|
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
Total
|
|||||||||||||||
|
|
(In millions, except per share amounts)
|
|||||||||||||||||||
|
2011
|
|
|
|
|
|
|||||||||||||||
|
Revenues (1)
|
$ | 1,618.6 | $ | 1,728.3 | $ | 1,713.6 | $ | 1,934.0 | $ | 6,994.5 | ||||||||||
|
Gross margin
|
217.4 | 250.5 | 228.1 | 259.5 | 955.5 | |||||||||||||||
|
Operating income
|
73.5 | 98.5 | 70.8 | 108.3 | 351.1 | |||||||||||||||
|
Net income
|
40.8 | 63.3 | 36.5 | 74.8 | 215.4 | |||||||||||||||
|
Net income attributable to Targa / common shareholders
|
6.8 | 10.5 | 4.9 | 8.5 | 30.7 | |||||||||||||||
|
Net income per common share - basic
|
$ | 0.17 | $ | 0.26 | $ | 0.12 | $ | 0.21 | $ | 0.75 | ||||||||||
|
Net income per common share - diluted
|
$ | 0.16 | $ | 0.25 | $ | 0.12 | $ | 0.20 | $ | 0.74 | ||||||||||
|
|
||||||||||||||||||||
|
2010
|
||||||||||||||||||||
|
Revenues (1)
|
$ | 1,486.2 | $ | 1,242.1 | $ | 1,220.0 | $ | 1,527.8 | $ | 5,476.1 | ||||||||||
|
Gross margin (2)
|
185.3 | 181.9 | 186.3 | 227.1 | 780.6 | |||||||||||||||
|
Operating income
|
54.8 | 48.4 | 43.3 | 49.6 | 196.1 | |||||||||||||||
|
Net income (loss)
|
35.9 | 7.4 | (4.3 | ) | 24.3 | 63.3 | ||||||||||||||
|
Net income (loss) attributable to Targa Resources Corp.
|
21.9 | (11.6 | ) | (17.5 | ) | (7.8 | ) | (15.0 | ) | |||||||||||
|
Net income (loss) available to common shareholders (3)
|
$ | - | $ | (191.8 | ) | $ | (18.9 | ) | $ | (8.9 | ) | $ | (202.3 | ) | ||||||
|
Net income (loss) per common share - basic
|
$ | - | $ | (48.10 | ) | $ | (3.77 | ) | $ | (0.67 | ) | $ | (30.94 | ) | ||||||
|
Net income (loss) per common share - diluted
|
$ | - | $ | (48.10 | ) | $ | (3.77 | ) | $ | (0.67 | ) | $ | (30.94 | ) | ||||||
________
|
(1)
|
First and second quarter 2011 and 2010 revenue amounts differ than what was presented in prior Form 10-Qs due to reclassifying gross revenues on certain fees that were previously reported as reductions of product purchases.
|
|
(2)
|
First and second quarter 2010 gross margin amounts differ than what was presented in prior Form 10-Qs due to reclassifying certain items as product purchases that were previously reported as operating expenses.
|
|
(3)
|
We paid dividends of $177.8 million to Series B Preferred shareholders during the second quarter of 2010, which is causing a reduction in the net income available to common shares.
|
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 8) 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 F-3 of this Annual Report.
|
TARGA RESOURCES CORP.
|
||||||||
|
PARENT ONLY
|
||||||||
|
CONDENSED BALANCE SHEET
|
||||||||
|
|
|
|
||||||
|
|
December 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
|
(In millions)
|
|||||||
|
ASSETS
|
||||||||
|
Current assets
|
$ | - | $ | - | ||||
|
Long-term debt issue costs
|
0.4 | 0.6 | ||||||
|
Deferred income taxes
|
16.0 | 12.5 | ||||||
|
Investment in consolidated subsidiaries
|
232.3 | 223.2 | ||||||
|
Total assets
|
$ | 248.7 | $ | 236.3 | ||||
|
|
||||||||
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
||||||||
|
Accrued current liabilities
|
$ | - | $ | 2.7 | ||||
|
Long-term debt
|
89.3 | 89.3 | ||||||
|
Other long-term liabilities
|
1.3 | - | ||||||
|
|
||||||||
|
Commitments and contingencies
|
||||||||
|
|
||||||||
|
Convertible cumulative participating series B preferred stock
|
- | - | ||||||
|
|
||||||||
|
Targa Resources Corp. stockholders' equity
|
158.1 | 144.3 | ||||||
|
Total liabilities and stockholders' equity
|
$ | 248.7 | $ | 236.3 | ||||
|
TARGA RESOURCES CORP.
|
||||||||||||
|
PARENT ONLY
|
||||||||||||
|
CONDENSED STATEMENT OF OPERATIONS
|
||||||||||||
|
|
|
|
|
|||||||||
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
|
(In millions, except per share amounts)
|
|||||||||||
|
Equity in net income (loss) of consolidated subsidiaries
|
$ | 38.9 | $ | (16.3 | ) | $ | 30.9 | |||||
|
General and administrative expenses
|
(8.5 | ) | (20.5 | ) | (0.2 | ) | ||||||
|
Gain on sale of assets
|
- | 1.1 | - | |||||||||
|
Income (loss) from operations
|
30.4 | (35.7 | ) | 30.7 | ||||||||
|
Other income (expense):
|
||||||||||||
|
Gain on debt extinguishment
|
- | 35.2 | 24.5 | |||||||||
|
Interest expense
|
(3.1 | ) | (11.2 | ) | (26.6 | ) | ||||||
|
Income (loss) before income taxes
|
27.3 | (11.7 | ) | 28.6 | ||||||||
|
Deferred income tax (expense) benefit
|
3.4 | (3.3 | ) | 0.7 | ||||||||
|
Net income (loss) attributable to Targa Resources Corp.
|
30.7 | (15.0 | ) | 29.3 | ||||||||
|
Dividends on Series B preferred stock
|
- | (9.5 | ) | (17.8 | ) | |||||||
|
Undistributed earnings attributable to preferred shareholders
|
- | - | (11.5 | ) | ||||||||
|
Dividends on common equivalents
|
- | (177.8 | ) | - | ||||||||
|
Net income (loss) available to common shareholders
|
$ | 30.7 | $ | (202.3 | ) | $ | - | |||||
|
Net income (loss) available per common share - basic
|
$ | 0.75 | $ | (30.94 | ) | $ | - | |||||
|
Net income (loss) available per common share - diluted
|
$ | 0.74 | $ | (30.94 | ) | $ | - | |||||
|
Weighted average shares outstanding - basic
|
41.0 | 6.5 | 3.8 | |||||||||
|
Weighted average shares outstanding - diluted
|
41.4 | 6.5 | 3.8 | |||||||||
|
TARGA RESOURCES CORP.
|
||||||||||||
|
PARENT ONLY
|
||||||||||||
|
CONDENSED STATEMENT OF CASH FLOWS
|
||||||||||||
|
|
|
|
|
|||||||||
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
|
(In millions)
|
|||||||||||
|
Net cash used in operating activities
|
$ | - | $ | (4.4 | ) | $ | (6.2 | ) | ||||
|
|
||||||||||||
|
Investing activities:
|
||||||||||||
|
Distribution and return of advances from consolidated subsidiaries
|
38.2 | 721.0 | 39.2 | |||||||||
|
Net cash provided by investing activities
|
38.2 | 721.0 | 39.2 | |||||||||
|
|
||||||||||||
|
Financing activities:
|
||||||||||||
|
Issuance of common stock
|
- | 0.9 | 0.3 | |||||||||
|
Repurchase of common stock
|
- | (0.1 | ) | - | ||||||||
|
Repurchase of long-term debt
|
- | (269.3 | ) | (33.3 | ) | |||||||
|
Dividends to preferred shareholders
|
- | (210.1 | ) | - | ||||||||
|
Dividends to common and common equivalent shareholders
|
(38.2 | ) | (238.0 | ) | - | |||||||
|
Net cash used in financing activities
|
(38.2 | ) | (716.6 | ) | (33.0 | ) | ||||||
|
|
||||||||||||
|
Net increase (decrease) in cash and cash equivalents
|
- | - | - | |||||||||
|
Cash and cash equivalents - beginning of year
|
- | - | - | |||||||||
|
Cash and cash equivalents - end of year
|
$ | - | $ | - | $ | - | ||||||
F-44