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.