Edgar Filing: Targa Resources Corp.

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, 2013

¨ 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)

Delaware		20-3701075
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1000 Louisiana St, Suite 4300, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 584-1000

(Registrant’s telephone number, including area code)

Securities registered pursuant to section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock		New York Stock Exchange

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 þ No o

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 o No þ

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 þ No o

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 þ No o

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. o

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.

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

(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 o No þ.

The aggregate market value of the common stock held by non-affiliates of the registrant was approximately $2,119.3 million on June 28, 2013, based on $64.33 per share, the closing price of the common stock as reported on the New York Stock Exchange (NYSE) on such date.

As of February 10, 2014, there were 42,167,343 shares of the registrant’s common stock, $0.001 par value, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

PART I

Item 1. Business.	4

Item 1A. Risk Factors.	32

Item 1B. Unresolved Staff Comments.	53

Item 2. Properties.	53

Item 3. Legal Proceedings.	53

Item 4. Mine Safety Disclosures.	53

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	54

Item 6. Selected Financial Data.	57

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.	58

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.	98

Item 8. Financial Statements and Supplementary Data.	101

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.	101

Item 9A. Controls and Procedures.	101

Item 9B. Other Information.	101

PART III

Item 10. Directors, Executive Officers and Corporate Governance.	102

Item 11. Executive Compensation.	108

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	138

Item 13. Certain Relationships and Related Transactions, and Director Independence.	140

Item 14. Principal Accounting Fees and Services.	145

PART IV

Item 15. Exhibits, Financial Statement Schedules.	146

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Corp.’s (together with its subsidiaries, other than Targa Resources Partners LP (the “Partnership”), 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 statements, 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 “Part I, Item 1A. Risk Factors.” of this Annual Report on Form 10-K (“Annual Report”) as well as the following risks and uncertainties:

the Partnership’s 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;

the amount of collateral required to be posted from time to time in the Partnership’s transactions;

the Partnership’s success in risk management activities, including the use of derivative instruments to hedge commodity risks;

the level of creditworthiness of counterparties to various transactions with the Partnership;

changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;

the timing and extent of changes in natural gas, natural gas liquids (“NGL”), crude oil and other commodity prices, interest rates and demand for the Partnership’s services;

weather and other natural phenomena;

industry changes, including the impact of consolidations and changes in competition;

the Partnership’s ability to obtain necessary licenses, permits and other approvals;

the level and success of crude oil and natural gas drilling around the Partnership’s assets, its success in connecting natural gas supplies to its gathering and processing systems, oil supplies to its gathering systems and NGL supplies to its logistics and marketing facilities and the Partnership’s success in connecting its facilities to transportation and markets;

the Partnership’s and our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets;

general economic, market and business conditions; and

the risks described elsewhere in “Part I, Item 1A. Risk Factors.” in this Annual Report and our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”).

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 “Part I, 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.

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As generally used in the energy industry and in this Annual Report, the identified terms have the following meanings:

Bbl	Barrels (equal to 42 U.S. gallons)
Bcf	Billion cubic feet
Btu	British thermal units, a measure of heating value
BBtu	Billion British thermal units
/d	Per day
/hr	Per hour
gal	U.S. gallons
GPM	Liquid volume equivalent expressed as gallons per 1000 cu. ft. of natural gas
LPG	Liquefied petroleum gas
MBbl	Thousand barrels
MMBbl	Million barrels
MMBtu	Million British thermal units
MMcf	Million cubic feet
NGL(s)	Natural gas liquid(s)
NYMEX	New York Mercantile Exchange
GAAP	Accounting principles generally accepted in the United States of America
LIBOR	London Interbank Offer Rate
NYSE	New York Stock Exchange

Price Index Definitions
IF-NGPL MC	Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-PB	Inside FERC Gas Market Report, Permian Basin
IF-WAHA	Inside FERC Gas Market Report, West Texas WAHA
NY-WTI	NYMEX, West Texas Intermediate Crude Oil
OPIS-MB	Oil Price Information Service, Mont Belvieu, Texas

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PART I

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 and NGL products, and gathering, storing and terminaling crude oil, and storing, terminaling and selling refined petroleum products.

On December 10, 2010, we completed an initial public offering (“IPO”) of common shares in the Company. In the IPO, the selling shareholders, including a member of our senior management, sold 18,831,250 common shares at a price of $22.00 per share. We did not receive any proceeds from the sale of shares by the selling shareholders. On completion of the IPO, there were 42,292,348 shares outstanding.

Financial Presentation

One of our indirect subsidiaries is the sole general partner of the Partnership. Because we control the general partner, under generally accepted accounting principles we must reflect our ownership interest in the Partnership on a consolidated basis. Accordingly, the Partnership’s financial results are included in our consolidated financial statements even though the distribution or transfer of Partnership assets are limited by the terms of the partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by us are reflected in our results of operations as net income attributable to noncontrolling interests. Throughout this Annual Report, we make a distinction where relevant between financial results and disclosures applicable to the Partnership versus those applicable to us as a standalone parent including our non-Partnership subsidiaries (“Non-Partnership”). In addition, we provide condensed Parent only financial statements as required by the SEC.

The Partnership files its own separate Annual Report. The financial results presented in our consolidated financial statements will differ from the financial statements of the Partnership primarily due to the effects of:

our separate debt obligations;

federal income taxes;

certain retained general and administrative costs applicable to us as a public company;

certain administrative assets and liabilities incumbent as a provider of operational and support services to the Partnership;

certain non-operating assets and liabilities that we retained;

Partnership distributions and earnings allocable to third-party common unitholders which are included in non-controlling interest in our statements; and

Partnership distributions applicable to our General Partner interest, Incentive Distribution Rights and investment in Partnership common units. While these are eliminated when preparing our consolidated financial statements, they nonetheless are the primary source of cash flow that supports the payment of dividends to our stockholders.

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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 10, 2014, our interests in the Partnership consist of the following:

a 2% general partner interest, which we hold through our 100% ownership interest in the general partner;

all of the outstanding IDRs; and

12,945,659 of the 112,390,094 outstanding common units of the Partnership, representing an 11.5% limited partnership interest.

Our cash flows are generated from the cash distributions we receive from the Partnership. The Partnership is required to distribute all available cash at the end of each quarter after establishing reserves to provide for the proper conduct of its business or to provide for future distributions. Our ownership of the general partner interest entitles us to receive 2% of all cash distributed in a quarter.

Our ownership of the IDRs of the Partnership entitles us to receive:

13% of all cash distributed in a quarter after $0.3881 has been distributed in respect of each common unit of the Partnership for that quarter;

23% of all cash distributed in a quarter after $0.4219 has been distributed in respect of each common unit of the Partnership for that quarter; and

48% of all cash distributed in a quarter after $0.50625 has been distributed in respect of each common unit of the Partnership for that quarter.

The Partnership Agreement between the Partnership and us governs our relationship regarding certain reimbursement and indemnification matters. So long as our only cash generating assets 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.”

We employ 1,277 people. See “—Employees.” The Partnership does not have any employees to carry out its operations.

Overview of the Business of the Partnership

We formed the Partnership in October 2006 to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. The Partnership is a leading provider of midstream natural gas, and NGL services in the United States, with a growing presence in crude oil gathering and petroleum terminaling.

The Partnership is engaged in the business of:

gathering, compressing, treating, processing and selling natural gas;

storing, fractionating, treating, transporting, terminaling and selling NGLs and NGL products;

gathering, storing and terminaling crude oil; and

storing, terminaling and selling refined petroleum products.

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To provide these services, the Partnership operates in two primary divisions: (i) Gathering and Processing, consisting of two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing (also referred to as the Partnership’s Downstream Business), consisting of two reportable segments—(a) Logistics Assets and (b) Marketing and Distribution. For a detailed description of these assets, please see “—The Partnership’s Business Operations.”

The Partnership’s midstream natural gas and NGL services footprint was initially established through several acquisitions from us, totaling $3.1 billion, that occurred from 2007 through 2010. In these transactions the Partnership acquired (1) natural gas gathering, processing and treating assets in North Texas, West Texas, New Mexico and the Louisiana Gulf Coast and (2) NGL assets consisting of fractionation, transport, storage and terminaling facilities, low sulfur natural gasoline treating facilities (“LSNG”), pipeline transportation and distribution assets, propane storage and truck terminals primarily located near Houston, Texas and in Lake Charles, Louisiana.

Since the completion of the final drop down acquisitions from us in 2010, the Partnership has grown substantially, with large increases in a number of metrics as of year-end 2013, including its total assets (95%), adjusted EBITDA (70%), distributable cash flow (69%) and distributions to its common unitholders (39%). The expansion of the Partnership’s business has been fueled by a combination of major organic growth investments in its businesses and acquisitions.

Organic Growth Projects

The Partnership continues to invest significant capital to expand through organic growth projects. The Partnership has invested approximately $1.9 billion in growth capital expenditures since 2007, including approximately $1 billion in 2013. These expansion investments were distributed across its businesses, with 54% related to Logistics and Marketing and 46% to Gathering and Processing. The Partnership will continue to invest in both large and small organic growth projects in 2014, with $650 million of estimated growth capital expenditures for announced projects.

Major organic growth projects completed or underway include:

International Exports. In September 2013, the Partnership commissioned Phase I of its international export expansion project, which includes facilities at both of its Mont Belvieu facility and at its Galena Park Marine Terminal near Houston, Texas. Phase I of this project expanded the Partnership’s export capability to approximately 3.5 to 4 MMBbl per month of propane and/or butane. Included in the Partnership’s Phase I expansion is the capability to export international grade low ethane propane. With the completion of Phase I, the Partnership’s capabilities expanded to include loading very large gas carrier (“VLGC”) vessels in addition to the small and medium-sized vessels that the Partnership load for export. Construction is underway to further expand our propane and butane international export capacity by approximately 2 MMBbl per month, with an expected completion of Phase II in the third quarter of 2014. The Partnership expects that the total cost of both phases of its international export project to be approximately $480 million.

Cedar Bayou Fractionator Train 4. In August 2013, the Partnership commissioned an additional fractionator, Train 4, at its 88%-owned Cedar Bayou Fractionator (“CBF”) in Mont Belvieu, Texas. This expansion added 100 MBbl/d of fractionation capacity at CBF. The gross cost of Train 4 was approximately $385 million (the Partnership net cost was approximately $352 million).

Badlands expansion program. During 2013, the Partnership invested approximately $250 million to expand its gathering and processing business in the Williston Basin, North Dakota assets. The Partnership increased its crude gathering and natural gas gathering operations substantially with the addition of pipelines, and associated facilities and added an additional 20 MMcf/d natural gas processing plant. During 2014, the Partnership anticipates an investment of approximately $180 million for further expansion of this business, including an additional cryogenic processing plant.

North Texas Longhorn plant. The Partnership is constructing a new 200 MMcf/d cryogenic processing plant and related gathering and compression facilities for North Texas to meet increasing production and continued producer activity in the area, with an anticipated completion in the second quarter of 2014. The Partnership expects a total estimated cost of approximately $150 million for the plant and associated projects.

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SAOU High Plains plant. The Partnership is constructing a new 200 MMcf/d cryogenic processing plant and related gathering and compression facilities for SAOU to meet increasing production and continued producer activity on the eastern side of the Permian Basin, with an anticipated completion date in mid-2014. The Partnership expects a total estimated cost of approximately $225 million for the plant and associated projects.

Additionally, the Partnership expects to have other growth capital expenditures in 2014 related to the continued build out of its gathering and processing systems and logistics capabilities.

Acquisitions of Businesses and Assets

In addition to the Partnership’s organic growth projects, the Partnership has made several business and asset acquisitions, including:

Badlands

On December 31, 2012, the Partnership acquired Saddle Butte Pipeline LLC’s crude oil gathering pipeline and terminal system and natural gas gathering and processing operations, collectively referred to as “Badlands” for cash consideration of approximately $976 million. The business is located in the Bakken and Three Forks Shale plays of the Williston Basin in North Dakota.

Petroleum Logistics

During 2011 and 2012, the Partnership acquired refined petroleum products and crude oil storage facilities, including potential export capabilities in a series of transactions. Facilities acquired were located on the Houston Ship Channel, the Hylebos Waterway in the Port of Tacoma, Washington (the “Sound Terminal”) and on the Patapsco River in Baltimore, Maryland (the “Baltimore Terminal”).

Growth Drivers

The Partnership believes its near-term growth will be driven by significant organic growth investments to meet strong supply and demand fundamentals for its existing businesses. The Partnership believes its assets are not easily duplicated and are located in active producing areas and near key markets and logistics centers. Over the longer term, the Partnership expects its growth will continue to be driven by production from shale plays and by the deployment of shale exploration and production technologies in both liquids-rich natural gas and crude oil resource plays. The Partnership expects that third-party acquisitions will also continue to be a focus of its growth strategy.

Strong supply and demand fundamentals for the Partnership’s existing businesses

The Partnership believes that the current levels of oil, condensate and NGL prices and the forecasted prices for these energy commodities have caused producers in and around its crude oil gathering and natural gas gathering and gas processing areas of operation to focus their drilling programs on regions rich in these forms of hydrocarbons. Liquids rich gas is prevalent from oil wells in the Wolfberry, Cline and Canyon Sands plays, which are accessible by the SAOU processing business in the Permian Basin; from the oil wells in the Wolfberry and Bone Springs plays and re-development of the Central Basin, which are accessible by the Sand Hills system and the Versado system; from “oilier” portions of the Barnett Shale natural gas play, especially portions of Montague, Cooke, Clay and Wise counties, which are accessible by the North Texas System and from oil wells in the Bakken and Three Forks plays, which are accessible by its Badlands business in North Dakota.

The impact of high producer activity and resulting NGL supplies from areas rich in oil, condensate and NGLs continue to generate demand for the Partnership’s fractionation services at the Mont Belvieu market hub. As a result of increasing demand, since 2010 the Partnership has added 178 MBbl/d of fractionation capacity with the additions of CBF Trains 3 and 4. The Partnership also funded its share of the NGL fractionation expansion at Gulf Coast Fractionators (“GCF”). The strength of demand continues to benefit fractionation service providers in the form of long-term, “take-or-pay” contracts for new and existing fractionation capacity. We believe that the higher volumes of fractionated NGLs will also result in increased demand for other related fee-based services provided by the Partnership’s Downstream Business. Continued demand for fractionation capacity will lead to other growth opportunities, such as the potential to provide fractionation services at Mont Belvieu for producers in the Utica and Marcellus Shale plays in Ohio, West Virginia and Pennsylvania.

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As domestic producers have focused their drilling in crude oil and liquids-rich areas, new gas processing facilities are being built to accommodate liquids-rich gas, which results in an increasing supply of NGLs. As drilling in these areas continues, demand for NGLs requiring transportation and fractionation to market hubs is expected to continue. As the supply of NGLs increase, the Partnership’s integrated Mont Belvieu and Galena Park Terminal assets allow the Partnership to provide the raw product, fractionation, storage, interconnected terminaling, refrigeration and ship loading capabilities to support exports by third party customers.

Active drilling and production activity from liquids-rich natural gas shale plays and similar crude oil resource plays

The Partnership is actively pursuing natural gas gathering and processing and NGL fractionation opportunities associated with liquids-rich natural gas from shale and other resource plays, such as portions of the Barnett, Eagle Ford, Utica and Marcellus Shales and with even richer casinghead gas opportunities from active crude oil resource plays, such as the Wolfberry (and other named variants of Wolfcamp, Spraberry, Dean and other geologic cross-section combinations) and the Bone Springs, Avalon and Bakken Shale plays. We believe that the Partnership’s leadership position in the Downstream Business, which includes its fractionation services, provides it with a competitive advantage relative to other gathering and processing companies without these capabilities.

Bakken Shale / Three Forks opportunities

The production from the Bakken Shale and Three Forks plays is expected to make the Williston Basin one of the fastest growing crude oil basins in the world. As producers increased their knowledge of the basin, drilling efficiencies and completion techniques have improved and production has increased significantly. Currently, much of the current oil production is transported by truck from wells to terminals to be loaded onto rail cars or injected into pipelines. In addition, much of the current gas production is being flared. The Partnership believes that competition with trucking and incentives to reduce flaring provide opportunities to grow volumes and expand its crude gathering and natural gas gathering and processing infrastructure; and that its position in the Williston Basin should allow us to compete for expansion opportunities. In addition, the significant amount of uncommitted acreage in proximity to its system should provide further opportunities for system expansions.

Third party acquisitions

While the Partnership’s growth through 2010 was primarily driven by the implementation of a focused drop down strategy, the Partnership and Targa also have a record of completing third party acquisitions. Since their formation, their strategy has included approximately $5.3 billion in acquisitions and growth capital expenditures of which approximately $1.2 billion was for acquisitions from third-parties. The Partnership expects that third-party acquisitions will continue to be a focus of its growth strategy.

Competitive Strengths and Strategies

We believe that the Partnership is well positioned to execute its business strategies due to the following competitive strengths:

Strategically located gathering and processing asset base

Its gathering and processing businesses are predominantly located in active and growth-oriented oil and gas producing basins. Activity in the shale resource plays underlying its gathering assets is driven by oil, condensate and NGL production and currently favorable prices for those energy commodities. Increased drilling and production activities in these areas would likely increase the volumes of natural gas and crude oil available to its gathering and processing systems.

Leading fractionation and NGL infrastructure 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 most are located at the major U.S. hub of NGL infrastructure, Mont Belvieu, which includes a number of mixed NGL (“mixed NGLs” or “Y-grade”) supply pipelines, storage, takeaway pipelines and other transportation infrastructure. Its Logistics assets, including fractionation facilities, storage wells, its marine export/import terminal and related pipeline systems and interconnects, are also located near and connected to key consumers of NGL products including the petrochemical and industrial markets. The location and interconnectivity of these assets are not easily replicated, and the Partnership has sufficient additional capability to expand their capacity. The Partnership has extensive experience in operating these assets and developing, permitting and constructing new midstream assets.

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Comprehensive package of midstream services

The Partnership provides a comprehensive package of services to natural gas and crude oil producers. These services are essential to gather crude and to process and treat wellhead gas to meet pipeline standards and to extract NGLs for sale into petrochemical, industrial, commercial and export markets. We believe that the Partnership’s ability to provide these integrated services provides an advantage in competing for new supplies because the Partnership 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, the Partnership believes the barriers to enter the midstream sector on a scale similar to the Partnership’s are reasonably high 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.

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 its 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 $80 million per year over the last three years. We believe that the Partnership’s assets are well-maintained and anticipate that a similar level of maintenance capital expenditures will be sufficient for the Partnership 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 gas gathering and processing positions in strategic oil and gas producing areas across multiple basins and provides services under attractive contract terms to a diverse mix of customers across its areas of operation. Consequently, the Partnership is not dependent on any one oil and gas basin or customer. The Partnership’s Logistics and Marketing assets are typically located near key market hubs and near its 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 Partnership’s contract portfolio has attractive rate and term characteristics, with a heavy fee-based component, especially in its Downstream Business and its Badlands operations. The Partnership expects an increasing percentage of its net operating cash flows to be fee-based given the higher rates for logistics assets contracts that are being newly executed or renewed under long-term contracts, the new projects underway, and continuing strong supply and demand fundamentals for this business. The Partnership’s continuous growth of the fee-based Badlands business in North Dakota will also contribute to increasing fee-based cash flow.

Financial flexibility

The Partnership has historically maintained a conservative leverage ratio and ample liquidity and has funded its growth investments with a mix of equity and debt over time. Disciplined management of leverage, liquidity and commodity price volatility allows the Partnership to be flexible in its long-term growth strategy and enables it to pursue strategic acquisitions and large growth projects.

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Experienced and long-term focused management team

The executive management team that formed us in 2004 continues to manage us today. They possess a breadth and depth of combined experience working in the midstream energy business. Other officers and key operational, commercial and financial employees provide significant experience in the industry and with its assets and businesses.

Attractive cash flow characteristics

The Partnership believes that its 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 its cash flow profile. The Partnership’s Field Gathering and Processing segment has a favorable contract mix that is primarily percent-of-proceeds, but also has increasing fee-based revenues from natural gas treating and compression, natural gas gathering, and processing and crude oil gathering in its Bakken Shale assets. Contracts in its Coastal Gathering and Processing segment are primarily hybrid (percent-of-liquids with a fee floor) or percent-of-liquids contracts. The Partnership’s favorable contract mix, along with its commodity hedging program, serves to mitigate the impact of commodity price movements on cash flow.

The Partnership has hedged the commodity price risk associated with a portion of its expected natural gas equity volumes through 2016 and NGL and condensate equity volumes through 2014 by entering into financially settled derivative transactions. Historically, these transactions have included both swaps and purchased puts (or floors). The primary purpose of its 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. Although the degree of hedging will vary, the Partnership intends to continue to manage some of 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 the Partnership 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 its assets provides the Partnership with access to stable natural gas and crude oil supplies and proximity to end-use markets and liquid market hubs while positioning the Partnership to capitalize on drilling and production activity in those areas. The Partnership’s existing infrastructure has the capacity to handle some incremental increases in volumes without significant investments as well as opportunities to leverage existing assets with meaningful expansions. We believe that as domestic supply and demand for natural gas, crude oil and NGLs, and services for each, grows over the long term, the Partnership’s infrastructure will increase in value as such infrastructure takes on increasing importance in meeting that growing supply and demand.

While we have set forth the Partnership’s strategies and competitive strengths above, its business involves numerous risks and uncertainties which may prevent the Partnership from executing its strategies or impact the amount of distributions to unitholders. These risks include the adverse impact of changes in natural gas, NGL and condensate/crude oil prices or in the supply of or demand for these commodities, and its 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.”

The Partnership’s Relationship with Us

We have used the Partnership as a growth vehicle to pursue the acquisition and expansion of midstream natural gas, NGL, oil and other complementary energy businesses and assets as evidenced by the Partnership’s acquisitions of businesses from us. However, we are not prohibited from competing with the Partnership and may evaluate acquisitions and dispositions that do not involve the Partnership. In addition, through its relationship with us, the Partnership has access to a significant pool of management talent, strong commercial relationships throughout the energy industry and access to our broad operational, commercial, technical, risk management and administrative infrastructure.

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As of December 31, 2013, we and our named executive officers and directors have a significant ownership interest in the Partnership through our ownership of a 12.0% limited partner interest and our 2% general partner interest. In addition, we own incentive distribution rights that entitle us to receive an increasing percentage of quarterly distributions of available cash from the Partnership’s operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. The Partnership Agreement with us governs its relationship regarding certain reimbursement and indemnification matters. See “Item 13. Certain Relationships and Related Transactions and Director Independence.”

The Partnership does not have any employees to carry out its operations. We employ 1,277 people. See “—Employees.” Following the conveyance of assets to the Partnership in September 2010, we charge the Partnership for all the direct costs of the employees assigned to its operations, as well as all general and administrative support costs other than its direct support costs of being a separate reporting company and our cost of providing management and support services to certain unaffiliated spun-off entities. The Partnership generally reimburses us for cost allocations to the extent that the Partnership has required a current cash outlay by us.

The Partnership’s Challenges

The Partnership faces a number of challenges in implementing its business strategy. For example:

The Partnership has a substantial amount of indebtedness which may adversely affect its financial position.

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.

The Partnership’s long-term success depends on its ability to obtain new sources of supplies of natural gas, crude oil and NGLs, which is subject to certain factors beyond its control. Any decrease in supplies of natural gas, crude oil or NGLs could adversely affect the Partnership’s business and operating results.

If the Partnership does not successfully integrate assets from acquisitions, its results of operations and financial condition could be adversely affected.

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.

The Partnership is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect its results of operations and financial condition.

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.

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.

The Partnership’s industry is highly competitive, and increased competitive pressure could adversely affect its business and operating results.

For a further discussion of these and other challenges the Partnership faces, please read “Item 1A. Risk Factors.”

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The Partnership’s Business Operations

The Partnership’s operations are reported in two divisions: (i) 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.

Gathering and Processing Division

The Partnership’s Gathering and Processing Division consists of gathering, compressing, dehydrating, treating, conditioning, processing and marketing natural gas and gathering crude oil. 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. Once processed, the residue gas is transported to markets through pipelines that are owned by either the gatherers and 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 gathering of crude oil consists of aggregating crude oil production primarily through gathering pipeline systems, which deliver crude to a combination of other pipelines, rail and truck.

The Partnership continually seeks new supplies of natural gas and crude oil, both to offset the natural decline in production from connected wells and to increase throughput volumes. The Partnership obtains additional natural gas and crude oil 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 and crude oil 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 and crude oil gathering 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.

The Partnership believes that its 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 and crude oil production to its areas of operations. We believe that the Partnership’s size and scope gives it a strong competitive position through close proximity to a large number of existing and new 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

In 2013, the Field Gathering and Processing segment gathered and processed natural gas from the Permian Basin in West Texas and Southeast New Mexico, the Fort Worth Basin, including the Barnett Shale, in North Texas and the Williston Basin in North Dakota. The natural gas processed in this segment is supplied through the Partnership’s gathering systems which, in aggregate, consist of approximately 11,300 miles of natural gas pipelines and include ten owned and operated processing plants. During 2013, the Partnership processed an average of a 780.1 MMcf/d of natural gas and produced an average of 91.9 MBbl/d of NGLs.

In addition to the Partnership natural gas gathering and processing, its Badlands operations include a crude oil gathering system and two terminals with crude oil operational storage capacity of 70 MBbl.

The Partnership believes that it is well positioned as a gatherer and processor in the Permian, Fort Worth and Williston Basins. The Partnership believes that its proximity to production and development activities allows the Partnership to compete for new supplies of natural gas and crude oil because of its lower 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 its processing plants, providing operational flexibility and allowing it to optimize processing efficiency and further improve the profitability of its operations.

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The Field Gathering and Processing segment’s operations consist of Sand Hills, Versado, SAOU, North Texas and Badlands, each as described below.

Sand Hills

The Sand Hills operations consist of the Sand Hills and Puckett gathering systems in West Texas. These systems consist of approximately 1,500 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 175 MMcf/d and residue gas connections to pipelines owned by affiliates of Enterprise Products Partners L.P. (“EPP”), Kinder Morgan, Inc. (“Kinder Morgan”) and ONEOK, Inc. (“ONEOK”).

Versado

Versado consists of the Saunders, Eunice and Monument gas processing plants and related gathering systems in Southeastern New Mexico and in West Texas. Versado consists of approximately 3,350 miles of natural gas gathering pipelines. The Saunders, Eunice and Monument refrigerated cryogenic processing plants have aggregate processing capacity of 240 MMcf/d (151 MMcf/d, net to the Partnership’s ownership interest). These plants have residue gas connections to pipelines owned by affiliates of Kinder Morgan and MidAmerican Energy Company. The Partnership’s ownership in Versado is held through Versado Gas Processors, L.L.C., a consolidated joint venture that is 63% owned by the Partnership and 37% owned by Chevron U.S.A. Inc.

SAOU

SAOU includes approximately 1,800 miles of pipelines in the Permian Basin that gathers natural gas for delivery to the Mertzon, Sterling and Conger processing plants. SAOU is connected to thousands of producing wells and over 840 central delivery points. SAOU’s processing facilities are refrigerated cryogenic processing plants, with an aggregate processing capacity of approximately 169 MMcf/d. These plants have residue gas connections to pipelines owned by affiliates of Atmos Energy Corporation (“Atmos”), EPP, Kinder Morgan, Northern Natural Gas Company and ONEOK.

The Partnership is currently constructing the High Plains plant, a new 200 MMcf/d cryogenic processing plant and related gathering and compression facilities with an anticipated completion date in mid-2014. The new plant will enable SAOU to meet increasing production and continued producer activity on the eastern side of the Permian Basin.

North Texas

North Texas includes two interconnected gathering systems with approximately 4,500 miles of pipelines, 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 Transfer Fuel LP, EPP and Natural Gas Pipeline Company of America LLC.

The Chico gathering system consists of approximately 2,400 miles of 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 includes approximately 2,100 miles of gathering pipelines and gathers 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.

To meet increasing production and producer activity in North Texas, the Partnership is currently constructing the Longhorn plant, a new 200 MMcf/d cryogenic processing plant, with expected completion in the second quarter of 2014.

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Badlands

The Badlands operations are located in the Bakken and Three Forks Shale of the Williston Basin in North Dakota and include crude oil gathering pipelines, 40 MBbl of operational crude storage capacity at the Johnsons Corner Terminal, and 30 MBbl of operational crude storage capacity at the Alexander Terminal. The Partnership has an additional 30 MBbl of operational crude oil storage under construction at New Town and 25 MBbl of operational crude oil storage under construction at Stanley. Badlands also includes natural gas gathering pipelines and a natural gas processing plant that was expanded in the third quarter of 2013 by 20 MMcf/d to a gross processing capacity of about 38 MMcf/d.

During 2013, the Partnership invested approximately $250 million to expand its Badlands crude oil gathering and gas gathering and processing systems, including the natural gas processing plant expansion mentioned above.

The following table lists the Field Gathering and Processing segment’s processing plants and related volumes for the year ended December 31, 2013:

Facility	% Owned		Location	Estimated Gross Processing Capacity (MMcf/d)(1)		Gross Plant Natural Gas Inlet Throughput Volume (MMcf/d) (9)		Gross NGL Production (MBbl/d) (9)		Process Type (8)	Operated or Non-Operated
Sand Hills
Sand Hills		100	Crane, TX		175.0		148.8		17.4	Cryo	Operated
Puckett (2)							7.0		0.1
			Area Total		175.0		155.8		17.5
Versado
Saunders (3), (4)		63	Lea, NM		60.0		29.4		3.1	Cryo	Operated
Eunice (3), (4)		63	Lea, NM		95.0		75.4		9.7	Cryo	Operated
Monument (3), (4)		63	Lea, NM		85.0		51.5		6.0	Cryo	Operated
			Area Total		240.0		156.3		18.8
SAOU
Mertzon		100	Irion, TX		52.0		52.8		8.3	Cryo	Operated
Sterling		100	Sterling, TX		92.0		77.2		11.1	Cryo	Operated
Conger		100	Sterling, TX		25.0		23.3		3.0	Cryo	Operated
			Area Total (7)		169.0		153.3		22.4
North Texas
Chico (5)		100	Wise, TX		265.0		284.4		30.0	Cryo	Operated
Shackelford		100	Shackelford, TX		13.0		9.2		1.1	Cryo	Operated
			Area Total (7)		278.0		293.6		31.1
Badlands
Little Missouri (6)		100	McKenzie, ND		38.0		21.4		1.9	RA	Operated
	Segment System Total				900.0		780.4		91.7

(1)	Gross processing capacity may differ from nameplate processing capacity due to multiple factors including items such as compression limitations, and quality and composition of the gas being processed.

(2)	Puckett volumes are gathered in our pipelines and processed at third-party plants.

(3)	Includes throughput other than plant inlet, primarily from compressor stations.

(4)	These plants are part of our Versado joint venture. Capacity and volumes represent 100% of ownership interest.

(5)	The Chico plant has fractionation capacity of approximately 15 MBbl/d.

(6)	Additional refrigerated compression will be installed in March 2014, bringing the gas plant throughput capacity to 44 MMcf/d.

(7)	Includes volumes gathered in our pipelines that are beyond our current plant capacity and are processed at other third-party plants.

(8)	Cryo – Cryogenic; RA – Refrigerated Absorption Processing.

(9)	Operational reports are used as the source of the Gross Inlet Throughput and NGL Production for certain plant statistics listed above, which may vary from financial statistics by insignificant amounts.

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, accessing natural gas from the 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 LOU and the Coastal Straddles, each as described below. For the year ended 2013, the Partnership processed an average of 1,330.1 MMcf/d of plant natural gas inlet and produced an average of 44.9 MBbl/d of NGLs.

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LOU

LOU consists of approximately 1,000 miles of gathering system pipelines in Southwest Louisiana. The gathering system is connected to numerous producing wells, central delivery points and/or pipeline interconnects 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. The Big Lake plant, also cryogenic, is located near the LOU gathering system. These processing plants have an aggregate processing capacity of approximately 440 MMcf/d. In addition, the Gillis plant has integrated fractionation with operating capacity of approximately 11 MBbl/d.

Coastal Straddles

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. The industry continues to rationalize gas processing capacity along the Gulf Coast by moving gas from older, less efficient plants to higher efficiency cryogenic plants. In the last two years, the Yscloskey, Calumet and other third-party plants have been shut-down, with most of the producer volumes going to more efficient plants such as its Venice, Lowry and Barracuda plants.

VESCO

Through the Partnership’s 76.8% ownership interest in Venice Energy Services Company, L.L.C., it operates the Venice gas plant, which has a aggregate processing capacity of 750 MMcf/d and the Venice Gathering System (“VGS”) that is approximately 150 miles in length and has a nominal capacity of 320 MMcf/d (collectively “VESCO”). VESCO receives unprocessed gas directly or indirectly from seven offshore pipelines and gas gathering systems including the VGS system. VGS gathers natural gas from the shallow waters of the eastern Gulf of Mexico and supplies the VESCO gas plant.

Other Coastal Straddles

Other Coastal Straddles consists of three wholly owned and operated gas processing plants (one now idled) and three partially owned plants which are not operated by the Partnership. These plants, having an aggregate processing capacity of approximately 3,555 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 two offshore gathering systems that are operated by the Partnership. The Pelican and Seahawk gathering systems have a combined length of approximately 175 miles and a combined capacity of approximately 230 MMcf/d. 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.

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The following table lists the Coastal Gathering and Processing segment’s natural gas processing plants and related volumes for the year ended December 31, 2013:

Facility	% Owned		Location Parish, State	Estimated Gross Processing Capacity (MMcf/d) (1)		Plant Natural Gas Inlet Throughput Volume (MMcf/d)		NGL Production (MBbl/d)		Process Type (2)	Operated or Non-operated

LOU
Gillis (3)		100	Calcasieu, LA		180		171.0		6.8	Cryo	Operated
Acadia		100	Acadia, LA		80		21.8		0.9	Cryo	Operated
Big Lake		100	Calcasieu, LA		180		158.1		2.6	Cryo	Operated
			Area Total		440		350.9		10.3

VESCO (4), (5)		76.8	Plaquemines, LA		750		515.5		21.5	Cryo	Operated

Other Coastal Straddles (6)
Barracuda		100	Cameron, LA		190		58.9		1.7	Cryo	Operated
Stingray (7)		100	Cameron, LA		300		96.6		2.5	RA	Operated
Lowry		100	Cameron, LA		265		176.8		4.3	Cryo	Operated
Terrebonne (8), (9)		4.6	Terrebonne, LA		950		19.6		0.6	RA	Non-operated
Toca (8), (9)		9.2	St. Bernard, LA		1,150		38.3		1.2	Cryo/RA	Non-operated
Sea Robin (8)		0.8	Vermillion, LA		700		15.9		0.5	Cryo	Non-operated
Other (10)							57.6		2.3
			Area Total		3,555		463.7		13.1

	Consolidated System Total				4,745		1,330.1		44.9

(1)	Gross processing capacity may differ from nameplate processing capacity due to multiple factors including items such as compression limitations, and the quality and composition of the gas being processed

(2)	Cryo – Cryogenic Processing; RA – Refrigerated Absorption Processing.

(3)	The Gillis plant has fractionation capacity of approximately 11 MBbl/d.

(4)	Plant natural gas inlet throughput volumes for VESCO represent 100% of the volumes associated with the plant as we consolidate VESCO’s results due to our 76.8% ownership interest.

(5)	VESCO also includes an offshore gathering system with a combined length of approximately 150 miles.

(6)	Other Coastal Straddles also includes two offshore gathering systems which have a combined length of approximately 175 miles.

(7)	The Stingray Plant was idled on December 8, 2013. Most of the producer volumes from this plant were moved to either the Barracuda or Lowry Plants.

(8)	Plant natural gas inlet throughput volumes for non-operated plants represent volumes associated with our ownership percentages.

(9)	Our ownership is adjustable and subject to annual redetermination based on our proportionate share of owners production.

(10)	Other includes Sabine Pass and Neptune volumes processed at plants not owned by us. The Sabine Pass Plant was shut down on January 3, 2013 with most of the producer volumes going to our Barracuda Plant.

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 and NGL products; the storing and terminaling of refined petroleum products and crude oil; and certain natural gas supply and marketing activities in support of the Partnership’s other businesses. These products 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.

Logistics Assets Segment

The Logistics Assets 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 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.

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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, ethane-propane mix, propane, normal butane, iso-butane and natural gasoline.

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’s 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 the Gathering and Processing division.

The Partnership expanded the fractionation capacity of its assets during 2011 through 2013 with the following projects:

CBF Train 3 and 4. In the second quarter of 2011, the Partnership commissioned 78 MBbl/d of additional fractionation capacity, Train 3, at CBF, in Mont Belvieu, Texas, at a cost of approximately $64 million. Train 3 is supported by long-term fee-based contracts that have certain guaranteed volume commitments or provisions for deficiency payments. In August 2013, the Partnership commissioned an additional fractionator, Train 4. This expansion added 100 MBbl/d of fractionation capacity. The gross cost of Train 4 was approximately $385 million (the Partnership’s net cost was approximately $345 million) and is also supported by long-term contracts that have certain guaranteed volume commitments or provisions for deficiency payments.

GCF expansion. In the second quarter of 2012, GCF, a partnership with Phillips 66 and Devon Energy Corporation, in which the Partnership owns a 38.8% interest, completed an expansion to increase the capacity of its NGL fractionation facility in Mont Belvieu. The gross cost was approximately $92 million (the Partnership’s net cost was approximately $35 million) for an estimated ultimate capacity of approximately 125 MBbl/d.

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.

The Partnership believes 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, the 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 on Provisions Governing Natural Gas Quality and Interchangeability in Interstate Natural Gas Pipeline Company Tariffs enacted in 2006 by the Federal Energy Regulatory Commission (“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 Partnerships 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. The Partnership believes that the location, scope and capability of the Partnership’s logistics assets, including its transportation and distribution systems, gives the Partnership access to both substantial sources of mixed NGLs and a large number of end-use markets.

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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 long-term fee-based contracts that have certain guaranteed volume commitments or provisions for deficiency payments. In 2012, the Partnership completed modifications to the hydrotreater to add the capability to reduce benzene content of natural gasoline to meet new, even more stringent environmental standards for one of its long-term customer accounts. 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		Gross Capacity (MBbl/d) (1)		Gross Throughput for 2013 (MBbl/d)(2)
Operated Facilities:
Lake Charles Fractionator (Lake Charles, LA)		100.0		55.0		24.0
Cedar Bayou Fractionator (Mont Belvieu, TX) (3)		88.0		393.0		278.1
Targa LSNG Hydrotreater (Mont Belvieu, TX)		100.0		30.0		20.2
Non-operated Facilities:
Gulf Coast Fractionator (Mont Belvieu, TX)		38.8		125.0		115.8

(1)	Actual fractionation capacities may also vary due to the Y-grade composition of the gas being processed and does not assume ethane rejection.

(2)	Gross throughput for 2013 only includes a partial year for Train 4, which was placed in service in August 2013.

(3)	Gross capacity represents 100% of the volume associated with the plant following the completion of Train 4. Capacity includes 40 MBbl/d of additional butane/gasoline fractionation capacity.

Storage, Terminaling and Petroleum Logistics

In general, the Partnership’s NGL 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 NGL 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 the Partnership’s facilities are connected to marine, rail and truck loading and unloading facilities that provide services and products to 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 Petroleum Logistics business consists of storage and terminaling facilities in Texas (the Channelview Terminal and the Patriot facility), Maryland (the Baltimore Terminal) and Washington (the Sound Terminal). These facilities primarily serve the refined petroleum products and crude oil markets, but potentially may also include LPG 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, and refineries have excess NGL products. Demand for storage and terminaling at its propane facilities typically peaks during fall, winter and early spring. In September 2013, the Partnership commissioned Phase I of its international export expansion project that includes facilities at both of its Mont Belvieu facility and its Galena Park Marine Terminal near Houston, Texas. Phase I of this project expanded its export capability to approximately 3.5 to 4 MMBbl per month of propane and/or butane. Included in the Phase I expansion was the capability to export international grade low ethane propane. With the completion of Phase I, the Partnership also added capabilities to load VLGC vessels alongside the small and medium sized export vessels that we load for export. The Partnership expects completion of Phase II of its International Exports project by the third quarter of 2014, which will add another estimated 2 MMBbl per month of export capacity. The Partnership continues to experience significant demand growth for NGL (primarily propane) exports.

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The Partnership’s fractionation, storage and terminaling business is supported by approximately 900 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, 2013:

Facility	% Owned		County/Parish, State	Number of Permitted Wells			Gross Storage 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. (“CPC”)

The following table details the Logistics Assets NGL and Petroleum Terminal Facilities for the year ended December 31, 2013:

Facility

Owned

County/Parish,

State

Description

Throughput for 2013 (Million gallons)

Usable

Storage

Capacity

(MMBbl)

Galena Park Terminal (1)

100

Harris, TX

NGL import/export terminal, chemicals

1,900.0

0.7

Mont Belvieu Terminal

100

Chambers, TX

Transport and storage terminal

4,965.0

39.0

Hackberry Terminal

100

Cameron, LA

Storage terminal

889.3

17.8

Channelview Terminal

100

Harris, TX

Refined products, crude - transport and storage terminal

153.8

0.5

Baltimore Terminal

100

Baltimore, MD

Refined products - transport and storage terminal

8.0

0.5

Sound Terminal

100

Pierce, WA

Refined products, crude oil/propane - transport and storage terminal

422.4

0.9

Patriot

100

Harris, TX

Dock and land for expansion (Not in service)

N/A

(1)	Volumes reflect total import and export across the dock/terminal and may also include volumes that have also been handled at the Mont Belvieu Terminal.

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. Additionally, the Partnership also purchases product for resale in its Logistics segment, including exports. During the year ended December 31, 2013, its distribution and marketing services business sold an average of approximately 318.4 MBbl/d of NGLs.

The Partnership generally purchases mixed NGLs at a monthly pricing index less applicable fractionation, transportation and marketing fees and resell these products to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical settlement business in which the Partnership earns margins from purchasing and selling NGL products from customers 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.

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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 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, it earns margin on a netback 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 the Partnership serves and impact the ability to deliver propane to satisfy peak demand.

Refinery Services

In the Partnership’s refinery services business, it 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 netback 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 netback 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 the Partnership’s customers.

The Partnership’s transportation assets, as of December 31, 2013, include:

approximately 700 railcars that the Partnership leases and manages;

approximately 80 owned and leased transport tractors; and

18 company-owned pressurized NGL barges.

Natural Gas Marketing

The Partnership also markets natural gas available to it from the Gathering and Processing segments, purchases and resells natural gas in selected United States markets, and manages the scheduling and logistics for these activities.

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The following table details the Marketing and Distribution segment’s Terminal Facilities:

Facility	% Owned	County/Parish, State	Description	Throughput for 2013 (Million gallons) (1)		Usable Storage Capacity (Million gallons)
Calvert City Terminal	100	Marshall, KY	Propane terminal		12.2		0.1
Greenville Terminal	100	Washington, MS	Marine propane terminal		18.3		1.5
Port Everglades Terminal	100	Broward, FL	Marine propane terminal		8.8		1.6
Tyler Terminal	100	Smith, TX	Propane terminal		12.8		0.2
Abilene Transport (2)	100	Taylor, TX	Raw NGL transport terminal		0.8	Less than 0.1
Bridgeport Transport (2)	100	Jack, TX	Raw NGL transport terminal		0.3		0.1
Gladewater Transport (2)	100	Gregg, TX	Raw NGL transport terminal		3.9		0.3
Chattanooga Terminal	100	Hamilton, TN	Propane terminal		9.1		0.9
Sparta Terminal	100	Sparta, NJ	Propane terminal		16.0		0.2
Hattiesburg Terminal (3)	50	Forrest, MS	Propane terminal		259.6		269.6
Winona Terminal	100	Flagstaff, AZ	Propane terminal		14.6		0.3
Sound Terminal (4)	100	Pierce, WA	Propane terminal		3.3		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 reflects 100% of the facility volumes.

(4)	Operated by Logistics Assets segment.

Operational Risks and Insurance

The Partnership is subject to all risks inherent in the midstream natural gas, crude oil 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 environmental pollution, 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 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 loss that is 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 Customers

The following table lists the percentage of the Partnership’s consolidated sales with its significant customer:

	2013			2012			2011
% of consolidated revenues
Chevron Phillips Chemical Company LLC		8	%		10	%		12	%

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 ten-year term. In September 2009, the Partnership executed a new feedstock and storage agreement with CPC for a term of five years, and the Partnership amended these agreements in 2013, with a new term through August 2019. 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.

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No customer accounted for more than 10% of the Partnership’s consolidated revenues during the year ended December 31, 2013.

Competition

The Partnership faces strong competition in acquiring new natural gas or crude oil 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 our current operating regions include Atlas Gas Pipeline Company, Kinder Morgan Energy Partners, L.P., WTG Gas Processing, L.P. (“WTG”), DCP Midstream Partners LP (“DCP”), Devon Energy Corporation (“Devon”), Enbridge Inc, ONEOK – Rockies Midstream, L.L.C., GulfSouth Pipeline Company, LP, Hanlon Gas Processing, Ltd., J W Operating Company, Louisiana Intrastate Gas and several other interstate pipeline companies. The Partnership’s competitors for crude oil gathering services in North Dakota include Arrow Midstream Holdings, LLC, Hiland Partners, LP, Great Northern Midstream LLC, Caliber Midstream Partners, LP and Bridger Pipeline LLC. The Partnership’s competitors may have greater financial resources than it possesses.

The Partnership also competes for NGL products to market through its 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. (“EPP”), 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 EPP, ONEOK, Inc. and LoneStar NGL LLC. 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. Its primary competitor in providing export services to its customers is EPP.

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 the rates and the 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.

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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 it 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. The Partnership believes that the natural gas pipelines in its gathering systems, including the gas gathering systems that are part of the Badlands and of the Pelican and Seahawk 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, to the extent the Partnership’s gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, are now subject to Order No. 704. See “—Other Federal Laws and Regulation Affecting Our Industry—FERC Market Transparency Rules.”

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 Railroad Commission of Texas (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, ten-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 other intrastate pipeline, Targa Gas Pipeline LLC, owns a multi-county intrastate pipeline that transports gas in Crane, Ector, Midland, and Upton Counties, Texas, as well as some line in North Texas. Targa Gas Pipeline LLC is a gas utility subject to regulation by the RRC.

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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.

The Partnership’s intrastate NGL pipelines in Louisiana gather mixed NGLs streams that we own 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. We deliver 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.

The Partnership’s intrastate pipelines in North Dakota are subject to the various regulations of the State of North Dakota. In addition, various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Land Management, Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, as well as the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation, on which the Partnership operates a significant portion of its Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain laws and regulations independent from federal, state and local statutes and regulations.

Natural Gas Processing

The Partnership’s natural gas gathering and processing operations are not presently subject to FERC regulation. However, since May 2009, the Partnership has been 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.

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.” Since May 1, 2009, the Partnership has been required to report to FERC information regarding natural gas sale and purchase transactions for some of the Partnership’s 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. In addition, the Three Affiliated Tribes promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation, on which the Partnership operates a significant portion of its Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain laws and regulations independent from federal, state and local statutes and regulations. For additional information regarding the potential impact of federal, state, tribal or local regulatory measures on the Partnership’s business, see “Risk Factors—Risks Related to Our Business.”

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Interstate Common Carrier Liquids Pipeline Regulation

Targa NGL Pipeline Company LLC (“Targa NGL”) has interstate NGL pipelines that are considered common carrier pipelines subject to regulation by FERC under the Interstate Commerce Act (the “ICA”). More specifically, Targa NGL owns a regulated 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 twenty-inch diameter pipeline, each of which runs between Mont Belvieu, Texas and Galena Park, Texas. The eight-inch and the twenty-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 these pipelines are subsidiaries of the Partnership.

The crude oil pipeline system that is part of the Badlands assets has qualified for a temporary waiver of applicable FERC regulatory requirements under the ICA based on current circumstances. Such waivers are subject to revocation, however, and should the pipeline’s circumstances change. FERC could, either at the request of other entities or on its own initiative, assert that some or all of the transportation on this pipeline system is within its jurisdiction. In the event that FERC were to determine that this pipeline system no longer qualified for waiver, the Partnership would likely be required to file a tariff with FERC, provide a cost justification for the transportation charge, and provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on this pipeline could adversely affect the Partnership’s results of operations.

Other Federal Laws and Regulations Affecting Our Industry

Domenici-Barton Energy Policy Act of 2005 (“EP Act of 2005”)

The EP 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, the EP 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 EP 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 No. 670 to implement the anti-market manipulation provision of the EP Act of 2005. Order No. 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 No.704), and the quarterly reporting requirement under Order No. 735. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

FERC Market Transparency Rules

Beginning in 2007, FERC has issued a number of rules intended to provide for greater marketing transparency in the natural gas industry, including Order Nos. 704, 720, and 735. Under Order No. 704, wholesale buyers and sellers of more than 2.2 Bcf 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, 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.

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Under Order No. 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 MMBtu of gas over the previous three calendar years, are required to post on a daily basis 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 No. 720, as clarified, was vacated by the Court of Appeals for the Fifth Circuit. We take the position that, at this time, all of the Partnership’s entities are exempt from Order No. 720 as currently effective.

Under Order No. 735, intrastate pipelines providing transportation services under Section 311 of the NGPA and “Hinshaw” pipelines operating under Section 1(c) of the NGA are required 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 also extends FERC’s periodic review of the rates charged by the subject pipelines from three years to five years. On rehearing, FERC reaffirmed Order No. 735 with some modifications. 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 we would be affected by any such FERC action materially differently than other midstream natural gas companies with whom we compete.

Environmental and Operational Health and Safety Matters

General

The Partnership’s operations are subject to stringent and complex federal, regional, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety, 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 wastes; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness or urban 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 its 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 sanctions including 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 management or disposal, pollution control 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 or natural resources or injury to persons. While we believe that the Partnership is in substantial compliance with existing environmental laws and regulations and that continued compliance with current legal requirements would not have a material adverse effect on the Partnership, there is no assurance that the current regulatory standards will not become more onerous in the future, resulting in more significant costs to maintain compliance or increased exposure to significant liabilities, which could diminish the Partnership’s ability to make distributions to its unitholders. For example, following the collapse of a cavern wall in a salt dome being developed by a third party and the resulting creation of a sinkhole near the community of Bayou Corne in Assumption Parish, Louisiana, the Louisiana Department of Natural Resources issued a proposed rulemaking in late 2013 that, if adopted, would impose more stringent requirements in the operation of Class III injection wells and hydrocarbon storage wells in salt dome caverns including, among other things, placing strict distance limitations on the location of solution-mined caverns in relation to the outer boundaries of a salt stock within a salt dome. As proposed, the rulemaking, if adopted, would require the Partnership to abandon the operation of at least one storage well. The Partnership is continuing to assess the effect that this proposed rulemaking might have on its operations in the state.

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The following is a summary of the more significant existing environmental and worker 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’s 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 other substances and wastes may have been disposed of or released on or under the properties owned or leased by the Partnership or on or under the other locations where these hydrocarbons or other substances 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 other substances and wastes was not under the Partnership’s control. These properties and any hydrocarbons, substances 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 would reasonably be expected to have a material adverse effect on the Partnership’s results of operations or financial condition.

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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 need to obtain permits has the potential to delay the development of oil and natural gas related projects. Over the next several years, the Partnership may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, on August 16, 2012, the EPA published final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants federal programs. These final rules, among other things, revise existing requirements for volatile organic compound emissions from equipment leaks at onshore natural gas processing plants by lowering the leak definition for valves from 10,000 parts per million to 500 parts per million and requires monitoring of connectors, pumps, pressure relief devices and open-ended lines. In addition, these rules establish requirements regarding emissions from: (i) wet seal and reciprocating compressors at gathering systems, boosting facilities, and onshore natural gas processing plants; (ii) specified pneumatic controllers at gathering systems, boosting facilities and onshore natural gas processing plants; and (iii) specified storage vessels at gathering systems, boosting facilities and onshore natural gas processing plants. Compliance with these requirements could increase the Partnership’s operational costs for upstream and midstream activities, which could be significant.

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 has adopted regulations under the Clean Air Act that, among other things, establish GHG emission limits from motor vehicles as well as establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. In October 2013, the U.S. Supreme Court agreed to hear a lawsuit challenging whether the EPA permissibly determined that the regulation of GHG emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit GHGs, with a decision expected in 2014. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore production sources, specified onshore and offshore production facilities and onshore processing, transmission and storage facilities in the United States on an annual basis. We are monitoring GHG emissions from the Partnership’s operations in accordance with the GHG emissions reporting rule and believe that the Partnership’s monitoring and reporting activities are in substantial compliance with applicable reporting obligations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce emissions of GHGs in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. 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 NGLs it gathers and processes or fractionates. Moreover, if Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products, which could adversely affect the services the Partnership provides. 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.

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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 United States. 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. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The CWA and analogous state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges.

The Federal 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. The 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 the OPA includes owners and operators of onshore facilities, such as the Partnership’s plants, and pipelines. Under the 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, the 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 has asserted limited regulatory authority over hydraulic fracturing, and has indicated it may seek to further expand its regulation of hydraulic fracturing. Also, the Bureau of Land Management has proposed regulations applicable to hydraulic fracturing conducted on federal and Indian oil and gas leases. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing. At the state level, a growing number of states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, or well construction requirements on hydraulic fracturing activities. In addition, local governments may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Further, several federal governmental agencies are conducting reviews and studies on the environmental aspects of hydraulic fracturing activities, including the White House Council on Environmental Quality, the EPA and the U.S. Department of Energy. These studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing. While the Partnership does not conduct hydraulic fracturing, if 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.

Endangered Species Act Considerations

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 in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on the listing of numerous species as endangered or threatened under the ESA before the completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where the Partnership or its oil and natural gas exploration and production customers operate could cause the Partnership or its customers to incur increased costs arising from species protection measures and could result in delays or limitations in its customers’ performance of operations, which could reduce demand for the Partnership’s midstream services.

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Employee Health and Safety

The Partnership is 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. The regulations apply to any process that (1) involves a listed chemical in a quantity at or above the threshold quantity specified in the regulation for that chemical, or (2) involves certain flammable gases or flammable liquids present on site in one location in a quantity of 10,000 pounds or more. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration is exempt. The Partnership has an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that the Partnership is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Pipeline Safety

Many of the Partnership’s natural gas, NGL and crude pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of 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. Both the NGPSA and the HLPSA were amended by the Pipeline Safety Improvement Act of 2002 (“PSI Act”) and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES Act”). The NGPSA and HLPSA, as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA 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. Additionally, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. 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.

Most recently, these pipeline safety laws were amended on January 3, 2012, when 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, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmission pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of PHMSA guidance with respect thereto 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 results of operations or financial position.

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In addition, states have adopted regulations, similar to existing PHMSA 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. North Dakota has similarly implemented regulatory programs applicable to intrastate natural gas pipelines. The Partnership currently estimates an annual average cost of $2.3 million for years 2014 through 2016 to perform necessary integrity management program testing on its pipelines required by existing PHMSA 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.

The Partnership, or the entities in which it owns an interest, inspect our pipelines regularly in compliance with state and federal maintenance requirements. Nonetheless, the adoption of new or amended regulations by PHMSA or the states that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on the Partnership and similarly situated midstream operators. For instance, in August 2011, PHMSA published an advance notice of proposed rulemaking in which the agency was seeking public comment on a number of changes to regulations governing the safety of gas transmission pipelines and gathering lines, including, for example, revising the definitions of “high consequence areas” and “gathering lines” and strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed. PHMSA continues to evaluate the public comments received with respect to more stringent integrity management programs and recently, pursuant to one of the requirements in the 2011 Pipeline Safety Act, published a proposed rulemaking on August 1, 2013, seeking comments on whether an expansion of high consequence areas would mitigate the need for class location requirements that have been used in the past primarily to differentiate risk along a pipeline.

Finally, notwithstanding the applicability of the OSHA’s Process Safety Management (“PSM”) regulations and the EPA’s Risk Management Plan (“RMP”) requirements at regulated facilities, PHMSA and one or more state regulators, including the RRC, have in the recent past expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, in order to assess compliance of such equipment and pipelines with hazardous liquid pipeline safety requirements. These recent actions by PHMSA are currently subject to judicial and administrative challenges by one or more midstream operators; however, to the extent that such legal challenges are unsuccessful, midstream operators of NGL fractionation facilities and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards beyond current PSM and RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.

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 the Partnership in fee title and we believe that the Partnership has satisfactory title to these lands. The remainder of the land on which the Partnership plant sites and major facilities are located is held by the Partnership pursuant to ground leases between the Partnership, 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, leases and licenses.

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Employees

Through a wholly-owned subsidiary of ours, we employ 1,277 people who primarily support the Partnership’s operations. None of those 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 of the “Consolidated Financial Statements” 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– By Segment” for a discussion of our and the Partnership’s financial results by segment.

Available Information

We make certain filings with the Securities and Exchange Commission (“SEC”), including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports. 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 entirely 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:

our obligation to satisfy tax obligations associated with previous sales of assets to the Partnership;

interest expense and principal payments on any indebtedness we incur;

restrictions on distributions contained in any existing or future debt agreements;

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;

income taxes;

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

reserves our board of directors establishes for the proper conduct of our business, to comply with applicable law or any agreement binding on us or our subsidiaries or to provide for future dividends by us.

The actual amount of cash that is available for dividends to our stockholders will depend on numerous factors, many of which are beyond our control.

A reduction in the Partnership’s distributions will disproportionately affect the amount of cash distributions to which we are entitled.

Our ownership of the IDRs in the Partnership entitles us to receive specified percentages of the amount of cash distributions made by the Partnership to its limited partners only in the event that the Partnership distributes more than $0.3881 per unit for such quarter. As a result, the holders of the Partnership’s common units have a priority over our IDRs to the extent of cash distributions by the Partnership up to and including $0.3881 per unit for any quarter.

Our IDRs entitle us to receive increasing percentages, up to 48%, of all cash distributed by the Partnership. Because the Partnership’s distribution rate is currently above the maximum target cash distribution level on the IDRs, future growth in distributions we receive from the Partnership will not result from an increase in the target cash distribution level associated with the IDRs. Furthermore, a decrease in the amount of distributions by the Partnership to less than $0.50625 per unit per quarter would reduce the general partner’s percentage of the incremental cash distributions above $0.3881 per common unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributions from the Partnership would have the effect of disproportionately reducing the distributions that we receive from the Partnership based on our IDRs as compared to distributions we receive from the Partnership with respect to our 2% general partner interest and our common units.

If the Partnership’s unitholders remove the general partner, we would lose our general partner interest and IDRs in the Partnership and the ability to manage the Partnership.

We currently manage our investment in the Partnership through our ownership interest in the general partner. The Partnership’s partnership agreement, however, gives unitholders of the Partnership the right to remove the general partner upon the affirmative vote of holders of 66⅔% of the Partnership’s outstanding units. If the general partner were removed as general partner of the Partnership, it would receive cash or common units in exchange for its 2% general partner interest and the IDRs and would also lose its ability to manage the Partnership. While the cash or common units the general partner would receive are intended under the terms of the Partnership’s partnership agreement to fully compensate us in the event such an exchange is required, the value of the investments we make with the cash or the common units may not over time be equivalent to the value of the general partner interest and the IDRs had the general partner retained them.

In addition, if the general partner is removed as general partner of the Partnership, we would face an increased risk of being deemed an investment company. Please read “—If in the future we cease to manage and control the Partnership, we may be deemed to be an investment company under the Investment Company Act of 1940.”

The Partnership, without our stockholders’ consent, may issue additional common units or other equity securities, which may increase the risk that the Partnership will not have sufficient available cash to maintain or increase its cash distribution level per common unit.

Because the Partnership distributes to its partners most of the cash generated by its operations, it relies primarily upon external financing sources, including debt and equity issuances, to fund its acquisitions and expansion capital expenditures. Accordingly, the Partnership has wide latitude to issue additional common units on the terms and conditions established by its general partner. We receive cash distributions from the Partnership on the general partner interest, IDRs and common units that we own. Because a significant portion of the cash we receive from the Partnership is attributable to our ownership of the IDRs, payment of distributions on additional Partnership common units may increase the risk that the Partnership will be unable to maintain or increase its quarterly cash distribution per unit, which in turn may reduce the amount of distributions we receive attributable to our common units, general partner interest and IDRs and the available cash that we have to pay as dividends to our stockholders.

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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 2013 fourth quarter distribution level of $0.7475 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 common units and general partner interests in the Partnership, our growth will be substantially dependent upon the Partnership. If we issue additional shares of common stock or we 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 ownership interests.

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’ commitments to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.

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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:

adversely affect our ability to obtain additional financing for future operations or capital needs;

limit our ability to pursue acquisitions and other business opportunities;

make our results of operations more susceptible to adverse economic or operating conditions; or

limit our ability to pay dividends.

Our payment of any principal and interest will reduce our cash available for dividends to our stockholders. In addition, we are able to incur substantial additional indebtedness in the future. If we incur additional debt, the risks associated with our leverage would increase. For more information regarding our credit facility, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

If dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’s payments in the future.

Dividends to our stockholders are not cumulative. Consequently, if dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’s payments in the future.

The Partnership’s practice of distributing all of its available cash may limit its ability to grow, which could impact distributions to us and the available cash that we have to dividend to our stockholders.

Because currently our only cash-generating assets are common units and general partner interests in the Partnership, including the IDRs, our growth will be dependent upon the Partnership’s ability to increase its quarterly cash distributions. The Partnership has historically distributed to its partners most of the cash generated by its operations. As a result, it relies primarily upon external financing sources, including debt and equity issuances, to fund its acquisitions and expansion capital expenditures. Accordingly, to the extent the Partnership is unable to finance growth externally, its ability to grow will be impaired because it distributes substantially all of its available cash. Also, if the Partnership incurs additional indebtedness to finance its growth, the increased interest expense associated with such indebtedness may reduce the amount of available cash that the Partnership distributes to us, which in turn may reduce the amount of available cash that we can distribute to our stockholders. In addition, to the extent the Partnership issues additional common units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional common units may increase the risk that the Partnership will be unable to maintain or increase its per unit distribution level, which in turn may impact the cash available for dividends to our stockholders.

Restrictions in the Partnership’s Senior Secured Revolving Credit Facility (the “TRP Revolver”) and indentures could limit its ability to make distributions to us.

The TRP Revolver and indentures contain covenants limiting its ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions. The TRP Revolver also contains covenants requiring the Partnership to maintain certain financial ratios. The Partnership is prohibited from making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a covenant under the TRP Revolver or the indentures, which in turn may impact the cash available for dividends to our stockholders.

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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.

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.

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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, 2013, we have 42,162,178 outstanding shares of common stock. Certain of our existing stockholders, including our executive officers, and certain of our directors 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 provisions which require:

a classified board of directors, so that only approximately one-third of our directors are elected each year;

limitations on the removal of directors; and

limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors. Please read “Description of Our Capital Stock—Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law.”

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.

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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, 2013 the Partnership had $395.0 million of borrowings outstanding, $86.8 million of letters of credit outstanding and $718.2 million of additional borrowing capacity under the TRP Revolver. In addition, the Partnership had $2,258.6 million outstanding under its senior unsecured notes, excluding $28.0 million in unamortized discounts. The Partnership also had $279.7 million of borrowings outstanding under its accounts receivable securitization facility (the “Securitization Facility”). The $1.2 billion TRP Revolver allows it to request increases in commitments up to an additional $300 million. For the years ended December 31, 2013, 2012 and 2011, the Partnership’s consolidated interest expense was $131.0 million, $116.8 million and $107.7 million, respectively.

This substantial level of indebtedness increases the possibility that the Partnership may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of indebtedness. This substantial indebtedness, combined with lease and other financial obligations and contractual commitments, could have other important consequences to the Partnership, including the following:

its ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

satisfying its obligations with respect to indebtedness may be more difficult and any failure to comply with the obligations of any debt instruments could result in an event of default under the agreements governing such indebtedness;

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;

the Partnership’s debt level will make it more vulnerable to competitive pressures or a downturn in its business or the economy generally; and

the Partnership’s debt level may limit flexibility in planning for, or responding to, changing business and economic conditions.

The Partnership’s ability to service its debt will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond its control. If the Partnership’s operating results are not sufficient to service its current or future indebtedness, it will be forced to take actions such as reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital, and its ability to make cash distributions may be adversely affected. 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, 2013, its total indebtedness was $2,933.3 million, excluding $28.0 million in unamortized discounts, of which $2,258.6 million was at fixed interest rates and $674.7 million was at variable interest rates. A one percentage point increase in the interest rate on the Partnership’s variable interest rate debt would have increased its consolidated annual interest expense by approximately $6.7 million. As a result of this significant amount of variable interest rate debt, the Partnership’s financial condition could be adversely affected by increases in interest rates.

Despite current indebtedness levels, the Partnership may still be able to incur substantially more debt. This could increase the risks associated with the Partnership’s substantial leverage.

The Partnership may be able to incur substantial additional indebtedness in the future. As of December 31, 2013, the Partnership had $395.0 million of borrowings outstanding, $86.8 million of letters of credit outstanding and $718.2 million of additional borrowing capacity available under the TRP Revolver. In addition, the Partnership had $279.7 million of borrowings outstanding under its Securitization Facility. The Partnership may be able to incur an additional $300 million of debt under the TRP Revolver if the Partnership requests and is able to obtain commitments from lenders for such additional amounts. Although the TRP Revolver contains restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial. If the Partnership incurs additional debt, the risks associated with its substantial leverage would increase.

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The terms of the TRP Revolver and indentures may restrict its current and future operations, particularly its ability to respond to changes in business or to take certain actions.

The credit agreement governing the TRP Revolver, the agreements governing the Securitization Facility and the indentures governing its senior notes contain, and any future indebtedness the Partnership incurs will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on its ability to engage in acts that may be in its best long-term interests. These agreements include covenants that, among other things, restrict the Partnership’s ability to:

incur or guarantee additional indebtedness or issue preferred stock;

pay distributions on its equity securities or redeem, repurchase or retire its equity securities or subordinated indebtedness;

make investments and certain acquisitions;

create restrictions on the payment of distributions to its equity holders;

sell or transfer assets, including equity securities of its subsidiaries;

engage in affiliate transactions,

consolidate or merge;

incur liens;

prepay, redeem and repurchase certain debt, other than loans under the TRP Revolver;

enter into sale and lease-back transactions or take-or-pay obligations; and

change business activities conducted by it.

In addition, the TRP Revolver requires the Partnership to satisfy and maintain specified financial ratios and other financial condition tests. The Partnership’s ability to meet those financial ratios and tests can be affected by events beyond its control, and we cannot assure you that the Partnership will meet those ratios and tests.

A breach of any of these covenants could result in an event of default under the TRP Revolver, the indentures, or the Securitization Facility, as applicable. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If the Partnership is unable to repay the accelerated debt under the TRP Revolver, the lenders under the TRP Revolver could proceed against the collateral granted to them to secure that indebtedness. If the Partnership is unable to repay the accelerated debt under the Securitization Facility, the lenders under the Securitization Facility could proceed against the collateral granted to them to secure the indebtedness. The Partnership has pledged substantially all of its assets as collateral under the TRP Revolver and the accounts receivables of Targa Receivables LLC under the Securitization Facility. If the indebtedness under the TRP Revolver, the indentures, or the Securitization Facility 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.

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The Partnership’s cash flow is affected by supply and demand for natural gas and NGL products and by natural gas, NGL, crude oil and condensate prices, and decreases in these prices could adversely affect its results of operations and financial condition.

The Partnership’s operations can be affected by the level of natural gas and NGL prices and the relationship between these prices. The prices of oil, natural gas and NGLs have been volatile and we expect this volatility to continue. The Partnership’s future cash flow may be materially adversely affected if it experiences significant, prolonged price 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 fluctuates with changes in market and economic conditions, and other factors, including:

the impact of seasonality and weather;

general economic conditions and economic conditions impacting the Partnership’s primary markets;

the economic conditions of the Partnership’s customers;

the level of domestic crude oil and natural gas production and consumption;

the availability of imported natural gas, liquefied natural gas, NGLs and crude oil;

actions taken by foreign oil and gas producing nations;

the availability of local, intrastate and interstate transportation systems and storage for residue natural gas and NGLs;

the availability and marketing of competitive fuels and/or feedstocks;

the impact of energy conservation efforts; and

the extent of governmental regulation and taxation.

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, 2013 and 2012, the Partnership’s percent-of-proceeds arrangements accounted for approximately 48% and 43%, respectively, 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 the Partnership’s processing facilities. In some percent-of-proceeds arrangements, the Partnership remits to the producer a percentage of an index-based price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. Under these types of arrangements, the Partnership’s revenues and cash flows increase or decrease, whichever is applicable, as the prices of natural gas, NGLs and crude oil fluctuates. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk.”

Because of the natural decline in production in the Partnership’s operating regions and in other regions from which it sources NGL supplies, its long-term success depends on its ability to obtain new sources of supplies of natural gas, NGLs and crude oil which depends on certain factors beyond its control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect the Partnership’s business and operating results.

The Partnership’s gathering systems are connected to oil and natural gas wells from which production will naturally decline over time, which means that the cash flows associated with these sources of natural gas and crude oil will likely also decline over time. The Partnership’s logistics assets are similarly impacted by declines in NGL supplies in the regions in which it operates as well as other regions from which it sources NGLs. To maintain or increase throughput levels on the Partnership’s gathering systems and the utilization rate at its processing plants and it’s treating and fractionation facilities, the Partnership must continually obtain new natural gas, NGL and crude oil supplies. A material decrease in natural gas production from producing areas on which the Partnership relies, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of natural gas or crude oil that it processes, NGL products delivered to its fractionation facilities or crude oil that the Partnership gathers. The Partnership’s ability to obtain additional sources of natural gas, NGLs and crude oil depends, in part, on the level of successful drilling and production activity near its gathering systems and, in part, on the level of successful drilling and production in other areas from which it sources NGL and crude oil supplies. The Partnership has no control over the level of such activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, the Partnership has no control over producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital.

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Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling and production activity generally decreases as oil and natural gas prices decrease. Prices of oil and natural gas have been historically volatile, and we expect this volatility to continue. Consequently, even if new natural gas or crude oil reserves are discovered in areas served by the Partnership’s assets, producers may choose not to develop those reserves. For example, current low prices for natural gas combined with relatively high levels of natural gas in storage could result in curtailment or shut-in of natural gas production. Reductions in exploration and production activity, competitor actions or shut-ins by producers in the areas in which the Partnership operates may prevent it from obtaining supplies of natural gas or crude oil to replace the natural decline in volumes from existing wells, which could result in reduced volumes through its facilities and reduced utilization of its gathering, treating, processing and fractionation assets.

If the Partnership does not make acquisitions or develop growth projects for expanding existing assets or constructing new midstream assets on economically acceptable terms or fails to efficiently and effectively integrate acquired or developed assets with its asset base, its future growth will be limited. In addition, any acquisitions the Partnership completes are subject to substantial risks that could adversely affect its financial condition and results of operations and reduce its ability to make distributions to unitholders.

The Partnership’s ability to grow depends, in part, on its ability to make acquisitions or develop growth projects that result in an increase in cash generated from operations per unit. The Partnership is unable to acquire businesses from us in order to grow because our only assets are the interests in the Partnership that we own. As a result, the Partnership will need to focus on third-party acquisitions and organic growth. If the Partnership is unable to make accretive acquisitions or develop accretive growth projects because it is (1) unable to identify attractive acquisition candidates and negotiate acceptable acquisition agreements or develop growth projects economically, (2) unable to obtain financing for these acquisitions or projects on economically acceptable terms, or (3) unable to compete successfully for acquisitions or growth projects, then the Partnership’s future growth and ability to increase distributions will be limited.

Any acquisition or growth project involves potential risks, including, among other things:

operating a significantly larger combined organization and adding new or expanded operations;

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 and/or geographic area;

the risk that crude oil and natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

the failure to realize expected volumes, revenues, profitability or growth;

the failure to realize any expected synergies and cost savings;

coordinating geographically disparate organizations, systems and facilities;

the assumption of environmental and other unknown liabilities;

limitations on rights to indemnity from the seller in an acquisition or the contractors and suppliers in growth projects;

failure to attain or maintain compliance with environmental and other governmental regulations;

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

customer or key employee losses at the acquired businesses or to a competitor.

If these risks materialize, any acquired assets or growth project may inhibit the Partnership’s growth, fail to deliver expected benefits and/or add further unexpected costs. Challenges may arise whenever businesses with different operations or management are combined, and the Partnership may experience unanticipated delays in realizing the benefits of an acquisition or growth project. If the Partnership consummates any future acquisition or growth project, its capitalization and results of operations may change significantly and you may not have the opportunity to evaluate the economic, financial and other relevant information that the Partnership will consider in evaluating future acquisitions or growth projects.

The Partnership’s acquisition and growth strategy is based, in part, on its expectation of ongoing divestitures of energy assets by industry participants and new opportunities created by industry expansion. A material decrease in such divestitures or in opportunities for economic commercial expansion would limit the Partnership’s opportunities for future acquisitions or growth projects and could adversely affect its operations and cash flows available for distribution to its unitholders.

Acquisitions may significantly increase the Partnership’s size and diversify the geographic areas in which it operates and growth projects may increase its concentration in a line of business or geographic region. The Partnership may not achieve the desired effect from any future acquisitions or growth projects.

The Partnership’s expansion or modification of existing assets or the construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect its results of operations and financial condition.

The construction of additions or modifications to the Partnership’s existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond its control and may require the expenditure of significant amounts of capital. If the Partnership undertakes these projects, they may not be completed on schedule or at the budgeted cost or at all. Moreover, the Partnership’s revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if the Partnership builds a new fractionation facility or gas processing plant, the construction may occur over an extended period of time and the Partnership will not receive any material increases in revenues until the project is completed. Moreover, the Partnership may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since the Partnership is not engaged in the exploration for and development of natural gas and oil reserves, it does not possess reserve expertise and it often does not have access to third-party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent the Partnership relies on estimates of future production in any decision to construct additions to its systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve the Partnership’s expected investment return, which could adversely affect its results of operations and financial condition. In addition, the construction of additions to the Partnership’s existing gathering and transportation assets may require it to obtain new rights-of-way prior to constructing new pipelines. The Partnership may be unable to obtain such rights-of-way to connect new natural gas supplies to its existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for the Partnership to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, the Partnership’s cash flows could be adversely affected.

The Partnership’s acquisition and growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair the Partnership’s ability to grow through acquisitions or growth projects.

The Partnership continuously considers and enters into discussions regarding potential acquisitions and growth projects. Any limitations on the Partnership’s access to capital will impair its ability to execute this strategy. If the cost of such capital becomes too expensive, the Partnership’s ability to develop or acquire strategic and accretive assets will be limited. The Partnership may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence the Partnership’s initial cost of equity include market conditions, fees it pays to underwriters and other offering costs, which include amounts it pays for legal and accounting services. The primary factors influencing the Partnership’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.

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In addition, the Partnership is experiencing increased competition for the types of assets it contemplates purchasing or developing. Current economic conditions and competition for asset purchases and development opportunities could limit its ability to fully execute its acquisition and growth strategy.

Demand for propane is significantly impacted by weather conditions and therefore seasonal, and requires increases in inventory to meet seasonal demand.

Weather conditions have a significant impact on the demand for propane because end-users principally utilize propane for heating purposes. Warmer-than-normal temperatures in one or more regions in which the Partnership operates can significantly decrease the total volume of propane it sells. Lack of consumer demand for propane may also adversely affect the retailers with which the Partnership transacts its wholesale propane marketing operations, exposing the Partnership to retailers’ inability to satisfy their contractual obligations to the Partnership.

If the Partnership fails to balance its purchases of natural gas and its sales of residue gas and NGLs, its exposure to commodity price risk will increase.

The Partnership may not be successful in balancing its purchases of natural gas and its sales of residue gas and NGLs. In addition, a producer could fail to deliver promised volumes to the Partnership or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause an imbalance between the Partnership’s purchases and sales. If the Partnership’s purchases and sales are not balanced, it will face increased exposure to commodity price risks and could have increased volatility in its operating income.

The Partnership’s hedging activities may not be effective in reducing the variability of its cash flows and may, in certain circumstances, increase the variability of its cash flows. Moreover, the Partnership’s hedges may not fully protect it against volatility in basis differentials. Finally, the percentage of the Partnership’s expected equity commodity volumes that are hedged decreases substantially over time.

The Partnership has entered into derivative transactions related to only a portion of its equity volumes. As a result, it will continue to have direct commodity price risk to the unhedged portion. The Partnership’s actual future volumes may be significantly higher or lower than it estimated at the time it entered into the derivative transactions for that period. If the actual amount is higher than the Partnership estimated, it will have greater commodity price risk than it intended. If the actual amount is lower than the amount that is subject to its derivative financial instruments, the Partnership might be forced to satisfy all or a portion of its derivative transactions without the benefit of the cash flow from its sale of the underlying physical commodity. The percentages of the Partnership’s expected equity volumes that are covered by its hedges decrease over time. To the extent the Partnership hedges its commodity price risk, it may forego the benefits it would otherwise experience if commodity prices were to change in its favor. The derivative instruments the Partnership utilizes for these hedges are based on posted market prices, which may be higher or lower than the actual natural gas, NGL and condensate prices that it realizes in its operations. These pricing differentials may be substantial and could materially impact the prices the Partnership ultimately realizes. In addition, market and economic conditions may adversely affect the Partnership’s hedge counterparties’ ability to meet their obligations. Given volatility in the financial and commodity markets, the Partnership may experience defaults by its hedge counterparties in the future. As a result of these and other factors, the Partnership’s hedging activities may not be as effective as it intended in reducing the variability of its cash flows, and in certain circumstances may actually increase the variability of its cash flows. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk.”

If third-party pipelines and other facilities interconnected to the Partnership’s natural gas and crude oil gathering systems, terminals and processing facilities become partially or fully unavailable to transport natural gas and NGLs, its revenues could be adversely affected.

The Partnership depends upon third-party pipelines, storage and other facilities that provide delivery options to and from its gathering and processing facilities. Since the Partnership does not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within its control. If any of these third-party facilities become partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict the Partnership’s ability to utilize them, its revenues could be adversely affected.

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The Partnership’s industry is highly competitive, and increased competitive pressure could adversely affect its business and operating results.

The Partnership competes with similar enterprises in its respective areas of operation. Some of the Partnership’s competitors are large oil, natural gas and NGL companies that have greater financial resources and access to supplies of natural gas and NGLs than it does. Some of these competitors may expand or construct gathering, processing, storage, terminaling and transportation systems that would create additional competition for the services the Partnership provides to its customers. In addition, customers who are significant producers of natural gas may develop their own gathering, processing, storage, terminaling and transportation systems in lieu of using those operated by the Partnership. The Partnership’s ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of its competitors and its customers. All of these competitive pressures could have a material adverse effect on the Partnership’s business, results of operations and financial condition.

The Partnership typically does not obtain independent evaluations of natural gas or crude oil reserves dedicated to its gathering pipeline systems; therefore, supply volumes on its systems in the future could be less than it anticipates.

The Partnership typically does not obtain independent evaluations of natural gas or crude oil reserves connected to its gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, the Partnership does not have independent estimates of total reserves dedicated to its gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to the Partnership’s gathering systems is less than it anticipates and it is unable to secure additional sources of supply, then the volumes of natural gas transported on its gathering systems in the future could be less than it anticipates. A decline in the volumes on the Partnership’s systems could have a material adverse effect on its business, results of operations and financial condition.

A reduction in demand for NGL products by the petrochemical, refining or other industries or by the fuel markets, or a significant increase in NGL product supply relative to this demand, could materially adversely affect the Partnership’s business, results of operations and financial condition.

The NGL products the Partnership produces have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general or industry-specific economic conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction industries), reduced demand for propane or butane exports whether for price or other reasons, 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 an 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.

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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, and demand for heating fuel, ethylene and propylene could adversely affect demand for normal butane.

Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.

Natural Gasoline. Natural gasoline is used as a blending component for certain refined petroleum products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition of motor gasoline resulting from governmental regulation, and in demand for ethylene and propylene, could adversely affect demand for natural gasoline.

NGLs and products produced from NGLs also compete with products from global markets. Any reduced demand or increased supply for ethane, propane, normal butane, isobutane or natural gasoline in the markets the Partnership accesses for any of the reasons stated above could adversely affect both demand for the services it provides and NGL prices, which could negatively impact its results of operations and financial condition.

The Partnership has significant relationships with CPC as a customer for its marketing and refinery services. In some cases, these agreements are subject to renegotiation and termination rights.

For the years ended December 31, 2013 and 2012, approximately 8% and 10%, respectively, 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 its cash flow from operating activities could decline.

The tax treatment of the Partnership depends on its status as a partnership for U.S. 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 11.5% 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 federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on the Partnership’s current operations we believe that the Partnership satisfies the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause the Partnership to be treated as a corporation for federal income tax purposes or otherwise subject the Partnership to taxation as an entity. The Partnership has not requested and does not plan to request a ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes.

If the Partnership were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to the Partnership’s unitholders, including us, would generally be taxed again as corporate distributions and no income, gains, losses or deductions would flow through to the Partnership’s unitholders, including us. If such tax was imposed upon the Partnership as a corporation, its cash available for distribution would be substantially reduced. Therefore, treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the Partnership’s unitholders, including us, and would likely cause a substantial reduction in the value of our investment in the Partnership.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income and franchise taxes 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.

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Current law may change so as to cause the Partnership to be treated as a corporation for federal income tax purposes or otherwise subject the Partnership to entity-level taxation for state or local income tax purposes. The present U.S. federal income tax treatment of publicly traded partnerships, including the Partnership, or an investment in the Partnership’s common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which the Partnership relies for its treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of our investment in the Partnership’s common units.

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, terminals 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 or 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 include, among others, 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. 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 interests of the Partnership or the particular joint venture.

In addition, subject to certain conditions, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint owners. Any such transaction could result in the Partnership partnering with different or additional parties.

Weather may limit the Partnership’s ability to operate its business and could adversely affect its operating results.

The weather in the areas in which the Partnership operates can cause disruptions and in some cases suspension of its operations. For example, unseasonably wet weather, extended periods of below freezing weather, or hurricanes may cause disruptions or suspensions of the Partnership’s operations, which could adversely affect its operating results. Potential climate changes may have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events and could have an adverse effect on the Partnership’s operations.

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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 for which it is not fully insured, if the Partnership fails to recover all anticipated insurance proceeds for significant accidents or events for which it is insured, or if the Partnership fails to rebuild facilities damaged by such accidents or events, its operations and financial results could be adversely affected.

The Partnership’s operations are subject to many hazards inherent in gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; gathering, storing and terminaling crude oil; and storing and terminaling refined petroleum products, including:

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;

inadvertent damage from third parties, including from motor vehicles and construction, farm or utility equipment;

damage that is the result of the Partnership’s negligence or any of its employees’ negligence;

leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;

spills or other unauthorized releases of natural gas, NGLs, crude oil, other hydrocarbons or waste materials that contaminate the environment, including soils, surface water and groundwater, and otherwise adversely impact natural resources; and

other hazards that could also result in personal injury, loss of life, pollution and/or suspension of operations.

These risks could result in substantial losses due to personal injury, loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage, and may result in curtailment or suspension of the Partnership’s related operations. A natural disaster or other hazard affecting the areas in which the Partnership operates could have a material adverse effect on its operations. For example, in 2005 Hurricanes Katrina and Rita damaged gathering systems, processing facilities, NGL fractionators and pipelines along the Gulf Coast, including certain of the Partnership’s facilities, and curtailed or suspended the operations of various energy companies with assets in the region. The Louisiana and Texas Gulf Coast was similarly impacted in September 2008 as a result of Hurricanes Gustav and Ike. The Partnership is not fully insured against all risks inherent to its business. Additionally, while the Partnership is insured for pollution resulting from environmental accidents that occur on a sudden and accidental basis, it may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs that is not fully insured, if the Partnership fails to recover all anticipated insurance proceeds for significant accidents or events for which it is insured, or if the Partnership fails to rebuild facilities damaged by such accidents or events, its operations and financial condition could be adversely affected. In addition, the Partnership may not be able to maintain or obtain insurance of the type and amount it desires at reasonable rates. As a result of market conditions, premiums and deductibles for certain of the Partnership’s insurance policies have increased substantially, and could escalate further. For example, following Hurricanes Katrina and Rita, insurance premiums, deductibles and co-insurance requirements increased substantially, and terms were generally less favorable than terms that could be obtained prior to such hurricanes. Insurance market conditions worsened as a result of the losses sustained from Hurricanes Gustav and Ike in September 2008. As a result, the Partnership experienced further increases in deductibles and premiums, and further reductions in coverage and limits, with some coverage unavailable at any cost.

The Partnership may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

Pursuant to the authority under the NGPSA and HLPSA, as amended by the PSI Act, the PIPES Act and the 2011 Pipeline Safety Act, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:

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perform ongoing assessments of pipeline integrity;

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

improve data collection, integration and analysis;

repair and remediate the pipeline as necessary; and

implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. The Partnership currently estimates an annual average cost of $2.3 million between 2014 and 2016 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 by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on the Partnership and similarly situated midstream operators. For instance, in August 2011, PHMSA published an advance notice of proposed rulemaking in which the agency sought public comment on a number of changes to regulations governing the safety of gas transmission pipelines and gathering lines, including, for example, revisions to the definitions of “high consequence areas” and “gathering lines” and strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed. PHMSA continues to evaluate the public comments received with respect to more stringent integrity management programs and recently, pursuant to one of the requirements in the 2011 Pipeline Safety Act, published a proposed rulemaking on August 1, 2013, seeking comments on whether an expansion of high consequence areas would mitigate the need for class location requirements that have been used in the past primarily to differentiate risk along a pipeline.

Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase the Partnership’s exposure to commodity price movements.

The Partnership sells processed natural gas to third parties at plant tailgates or at pipeline pooling points. Sales made to natural gas marketers and end-users may be interrupted by disruptions to volumes anywhere along the system. The Partnership attempts to balance sales with volumes supplied from processing operations, but unexpected volume variations due to production variability or to gathering, plant or pipeline system disruptions may expose it to volume imbalances which, in conjunction with movements in commodity prices, could materially impact its income from operations and cash flow.

The Partnership requires a significant amount of cash to service its indebtedness. The Partnership’s ability to generate cash depends on many factors beyond its control.

The Partnership’s ability to make payments on and to refinance its indebtedness and to fund planned capital expenditures depends on its ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond the Partnership’s control. We cannot assure you that the Partnership will generate sufficient cash flow from operations, that future borrowings will be available to it under the TRP Revolver, that it will be able to sell its accounts receivables or make borrowings under its Securitization Facility, or otherwise in an amount sufficient to enable it to pay its indebtedness or to fund its other liquidity needs. The Partnership may need to refinance all or a portion of its indebtedness at or before maturity. We cannot assure you that the Partnership will be able to refinance any of its indebtedness on commercially reasonable terms or at all.

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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, regional, 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 its operations including acquisition of a permit before conducting regulated activities, restrictions on the types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmentally sensitive areas such as wetlands, urban areas, wilderness regions and other protected areas; requiring capital expenditures to comply with pollution control requirements and imposition of substantial liabilities for pollution resulting from its operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, which can often require difficult and costly actions. Failure to comply with these laws and regulations or any newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties or other sanctions, the imposition of remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or waste products have been disposed or otherwise released, even under circumstances where the substances, hydrocarbons or waste have been released by a predecessor operator. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by noise, odor or the release of hazardous substances, hydrocarbons or waste products into the environment.

There is inherent risk of incurring environmental costs and liabilities in connection with the Partnership’s operations due to its handling of natural gas, NGLs, crude oil and other petroleum products because of air emissions and product-related discharges arising out of its operations, and as a result of historical industry operations and waste disposal practices. For example, an accidental release from one of the Partnership’s facilities could subject it to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, natural resource and property damages and fines or penalties for related violations of environmental laws or regulations. Moreover, stricter laws, regulations or enforcement policies could significantly increase the Partnership’s operational or compliance costs and the cost of any remediation that may become necessary. Additionally, environmental groups have, from time to time, advocated increased regulation on the issuance of drilling permits for new oil or gas wells in areas where the Partnership operates, including the Barnett Shale area. The adoption of any laws, regulations or other legally enforceable mandates that result in more stringent air emission limitations or that restrict or prohibit the drilling of new natural gas wells for any extended period of time could increase the Partnership’s natural gas customers’ operating and compliance costs as well as reduce the rate of production of natural gas or crude oil from operators with whom the Partnership has a business relationship, which could have a material adverse effect on its results of operations and cash flows.

Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact the Partnership’s revenues by decreasing the volumes of natural gas, NGLs or crude oil through its facilities and reducing the utilization of its assets.

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 limited regulatory authority over hydraulic fracturing, and has indicated it might seek to further expand its regulation of hydraulic fracturing. Also, the Bureau of Land Management has proposed regulations applicable to hydraulic fracturing conducted on federal and Indian oil and gas leases. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing. At the state level, a growing number of states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities. In addition, local governments may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions related 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. Further several federal governmental agencies are conducting reviews and studies on the environmental aspects of hydraulic fracturing activities, including the White House Council on Environmental Quality, the EPA and the U.S. Department of Energy. These studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing, 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.

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A change in the jurisdictional characterization of some of the Partnership’s assets by federal, state, tribal or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase or delay or increase the cost of expansion projects.

With the exception of the Partnership’s interest in VGS, its operations are generally exempt from FERC regulation under the NGA, but FERC regulation still affects its non-FERC jurisdictional businesses and the markets for products derived from these businesses, including certain FERC reporting and posting requirements in a given year. 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, ongoing 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.

The crude oil pipeline system that is part of the Badlands assets has qualified for a temporary waiver of applicable FERC regulatory requirements under the ICA based on current circumstances. Such waivers are subject to revocation, however, and should the pipeline’s circumstances change, FERC could, either at the request of other entities or on its own initiative, assert that some or all of the transportation on this pipeline system is within its jurisdiction. In the event that FERC were to determine that this pipeline system no longer qualified for a waiver, the Partnership would likely be required to file a tariff with FERC, provide a cost justification for the transportation charge, and provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on this pipeline could adversely affect the Partnership’s results of operations.

Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Land Management, Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, along with the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation, on which the Partnership operates a significant portion of its Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands can generally be subject to the Native American tribal court system. One or more of these factors may increase the Partnership’s costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on its ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct its operations on such lands.

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 the Partnership’s operations, see “Item 1. Business—Regulation of Operations.”

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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 Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While 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 the Partnership’s operations, see “Item 1. Business—Regulation of Operations.”

The adoption of climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the products and services the Partnership provides.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted rules under the Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore production facilities and onshore processing, transmission and storage facilities in the United States on an annual basis, which include certain of the Partnership’s operations. While Congress has from time to time considered adopting legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of 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 us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the natural gas and NGLs the Partnership gathers and processes or fractionates. Moreover, if Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products, which could adversely affect the services the Partnership provides.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject the Partnership to increased capital costs, operational delays and costs of operation.

The 2011 Pipeline Safety Act is the most recent federal legislation to amend the NGPSA and HLPSA pipeline safety laws, requiring 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, leak detection system installation, testing to confirm that the material strength of certain pipelines is above 30% of specified minimum yield strength, and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmission pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day and also from $1 million to $2 million for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto 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 the Partnership’s incurring increased operating costs that could be significant and have a material adverse effect on the Partnership’s results of operations or financial position. For example, PHMSA and one or more state regulators, including the RRC, have in the recent past, expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, in order to assess compliance of such equipment and pipelines with hazardous liquid pipeline safety requirements. These recent actions by PHMSA are currently subject to judicial and administrative challenges by one or more midstream operators; however, to the extent that such legal challenges are unsuccessful, midstream operators of NGL fractionation facilities and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards beyond current OSHA PSM and EPA RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.

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The enactment of derivatives legislation 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 Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Partnership, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require the Partnership, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although the Partnership expects to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that the Partnership uses for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce cash available to the Partnership for capital expenditures, therefore reducing its ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions to the Partnership is uncertain at this time.

The Dodd-Frank Act also may require the 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 full impact of the Dodd-Frank Act and related regulatory requirements upon the Partnership’s business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Partnership encounters, reduce its ability to monetize or restructure its existing derivative contracts or increase its exposure to less creditworthy counterparties. If the Partnership reduces its use of derivatives as a result of the Dodd-Frank Act and regulations implementing the Dodd-Frank Act, 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 Dodd-Frank Act 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 Dodd-Frank Act and implementing regulations is to lower commodity prices.

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Any of these consequences could have a material adverse effect on the Partnership, its financial condition and its results of operations.

The Partnership’s interstate common carrier liquids pipeline is regulated by the FERC.

Targa NGL has interstate NGL pipelines that are considered common carrier pipelines subject to regulation by FERC under the ICA. More specifically, Targa NGL owns a twelve-inch diameter pipeline that runs between Lake Charles, Louisiana and Mont Belvieu, Texas. This pipeline can move mixed NGL and purity NGL products. Targa NGL also owns an eight-inch diameter pipeline and a twenty-inch diameter pipeline, each of which run between Mont Belvieu, Texas and Galena Park, Texas. The eight-inch and the twenty-inch pipelines are part of an extensive mixed NGL and purity NGL pipeline receipt and delivery system that provides services to domestic and foreign import and export customers. The ICA requires that the Partnership maintain tariffs on file with FERC for each of these pipelines. Those tariffs set forth the rates the Partnership charges for providing transportation services as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. All shippers on these pipelines are the Partnership’s subsidiaries.

Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to the Partnership’s business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact the Partnership’s results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on the Partnership’s industry in general and on the Partnership in particular is not known at this time. However, resulting regulatory requirements and/or related business decisions associated with security are likely to increase the Partnership’s costs.

Increased security measures taken by the Partnership as a precaution against possible terrorist attacks have resulted in increased costs to its business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect the Partnership’s operations in unpredictable ways, including disruptions of crude oil supplies and markets for its products, and the possibility that infrastructure facilities could be direct targets, or indirect casualties, of an act of terror.

Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for the Partnership to obtain. Moreover, the insurance that may be available to the Partnership may be significantly more expensive than its existing insurance coverage or coverage may be reduced or unavailable. Instability in the financial markets as a result of terrorism or war could also affect the Partnership’s ability to raise capital.

Item 1B.

Unresolved Staff Comments.

None.

Item 2.

Properties.

A description of our properties is contained in “Item 1. Business” of this Annual Report.

Our principal executive offices are located at 1000 Louisiana Street, Suite 4300, Houston, Texas 77002 and our telephone number is 713-584-1000.

Item 3.

Legal Proceedings.

We are not a party to any legal proceedings other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. See “Item 1. Business—Regulation of Operations” and “Item 1. Business—Environmental, Health and Safety Matters.”

Item 4.

Mine Safety Disclosures.

Not applicable.

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PART II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information

Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “TRGP.”

The following table sets forth the high and low sales prices of the common stock at the end of each subsequent quarter, as reported by the NYSE through December 31, 2013 and the amount of cash dividends declared since our IPO. As of February 7, 2014, there were approximately 188 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. As of February 10, 2014, there were 42,167,343 shares of common stock outstanding.

	Stock Prices				Dividends
Quarter Ended	High		Low		Declared
December 31, 2013	$	89.74	$	72.24	$	0.60750
September 30, 2013		74.94		64.40		0.57000
June 30, 2013		69.43		60.01		0.53250
March 31, 2013		68.42		54.31		0.49500
December 31, 2012		53.38		45.74		0.45750
September 30, 2012		51.43		41.46		0.42250
June 30, 2012		49.91		39.89		0.39375
March 31, 2012		48.28		38.70		0.36500

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.

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Our Dividend Policy

We intend to pay to our stockholders, on a quarterly basis, dividends equal to the cash we receive from our Partnership distributions, less reserves for expenses, future dividends and other uses of cash, including:

federal income taxes, which we are required to pay because we are taxed as a corporation;

the expenses of being a public company;

other general and administrative expenses;

general and administrative reimbursements to the Partnership;

capital contributions to the Partnership upon the issuance by it of additional partnership securities if we choose to maintain the general partner’s 2.0% interest;

reserves our board of directors believes prudent to maintain;

our obligation to satisfy tax obligations associated with previous sales of assets to the Partnership; and

interest expense or principal payments on any indebtedness we incur.

If the Partnership is successful in implementing its business strategy and increasing distributions to its partners, we would generally expect to increase dividends to our stockholders, although the timing and amount of any such increased dividends will not necessarily be comparable to the increased Partnership distributions. We cannot assure you that any dividends will be declared or paid in the future.

The determination of the amount of cash dividends, including the quarterly dividend referred to above, if any, to be declared and paid will depend upon our financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects and any other matters that our board of directors deems relevant. The Partnership’s debt agreements contain restrictions on the payment of distributions and prohibit the payment of distributions if the Partnership is in default. If the Partnership cannot make incentive distributions to the general partner or limited partner distributions to us, we will be unable to pay dividends on our common stock.

The Partnership’s Cash Distribution Policy

Under the Partnership’s partnership agreement, available cash is defined, for each fiscal quarter, as the sum of all cash and cash equivalents on hand at the end of that quarter and all additional cash and cash equivalents on hand immediately prior to the date of the distribution of available cash resulting from borrowings for working capital purposes subsequent to the end of that quarter, less the amount of any cash reserves established by the general partner to:

provide for the proper conduct of the Partnership’s business including reserves for future capital expenditures and for anticipated future credit needs;

comply with applicable law or any loan agreements, security agreements, mortgages, debt instruments or other agreements binding on the Partnership and its subsidiaries; or

provide funds for distributions to the Partnership’s unitholders and to the general partner for any one or more of the next four quarters.

The determination of available cash takes into account the possibility of establishing cash reserves in some quarterly periods that the Partnership may use to pay cash distributions in other quarterly periods, thereby enabling it to maintain relatively consistent cash distribution levels even if the Partnership’s business experiences fluctuations in its cash from operations due to seasonal and cyclical factors. The general partner’s determination of available cash also allows the Partnership to maintain reserves to provide funding for its growth opportunities. The Partnership makes its quarterly distributions from cash generated from its operations, and those distributions have grown over time as its business has grown, primarily as a result of numerous acquisitions and organic expansion projects that have been funded through external financing sources and cash from operations.

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The actual cash distributions paid by the Partnership to its partners occur within 45 days after the end of each quarter. Since the second quarter of 2007, the Partnership has increased its quarterly cash distribution nineteen times. During that time period, the Partnership has increased its quarterly distribution by 121% from $0.3375 per common unit, or $1.35 on an annualized basis, to $0.7475 per common unit, or $2.99 on an annualized basis.

For a discussion of restrictions on our and our subsidiaries’ ability to pay dividends or make distributions, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Credit Facilities and Long-Term Debt” and Note 10, “Debt Obligations” of 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.

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Item 6.

Selected Financial Data.

The following table presents selected historical consolidated financial and operating data of Targa Resources Corp. for the periods ended, and as of, the dates indicated. We derived this information from our historical “Consolidated Financial Statements” and accompanying notes. This information should be read together with, and is qualified in its entirety, by reference to those financial statements and notes of this Annual Report.

	2013		2012		2011		2010			2009
	(In millions, except per share amounts)
Statement of operations data:
Revenues	$	6,556.0	$	5,885.7	$	6,994.5	$	5,476.1		$	4,542.3
Income from operations		368.2		336.3		351.1		196.1			217.2
Net income		201.3		159.3		215.4		63.3			79.1
Net income (loss) attributable to Targa Resources Corp.		65.1		38.1		30.7		(15.0	)		29.3
Dividends on Series B preferred stock		-		-		-		(9.5	)		(17.8	)
Net income (loss) available to common shareholders		65.1		38.1		30.7		(202.3	)		-
Net income (loss) per common share - basic		1.56		0.93		0.75		(30.94	)		-
Net income (loss) per common share - diluted		1.55		0.91		0.74		(30.94	)		-
Balance sheet data (at end of period):
Total assets	$	6,048.6	$	5,105.0	$	3,831.0	$	3,393.8		$	3,367.5
Long-term debt		2,989.3		2,475.3		1,567.0		1,534.7			1,593.5
Convertible cumulative participating series B preferred stock		-		-		-		-			308.4
Total owners' equity		2,091.3		1,753.4		1,330.7		1,036.1			754.9
Other:
Dividends declared per share	$	2.2050	$	1.6388	$	1.2063	$	0.0616			N/A
Dividends paid on series B preferred shares	$	-	$	-	$	-	$	238.0		$	-

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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

Targa Resources Corp. is a publicly traded Delaware corporation formed in October 2005. Our common stock is listed on the NYSE under the symbol “TRGP.” In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our,” the “Company,” or “Targa” are intended to mean our consolidated business and operations.

We own general and limited partner interests, including Incentive Distribution Rights (“IDRs”), in Targa Resources Partners LP (the “Partnership”) a publicly traded Delaware limited partnership that is a leading United States provider of midstream natural gas and NGL services, with a growing presence in crude oil gathering and petroleum terminaling. Common units of the Partnership are listed on the NYSE under the symbol “NGLS.”

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. We also may enter into other economic transactions intended to increase our ability to make cash available for dividends over time. In addition, we may acquire assets that could be candidates for acquisition by the Partnership, potentially after operational or commercial improvement or further development.

An indirect subsidiary of ours is the general partner of the Partnership. Because we control the general partner, under GAAP we must reflect our ownership interest in the Partnership on a consolidated basis. Accordingly, the Partnership’s financial results are included in our consolidated financial statements even though the distribution or transfer of Partnership assets are limited by the terms of the partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by us are reflected in our results of operations as net income attributable to noncontrolling interests. Therefore, throughout this discussion, we make a distinction where relevant between financial results of the Partnership versus those of us as a standalone parent including our non-Partnership subsidiaries.

our separate debt obligations;

federal income taxes;

certain retained general and administrative costs applicable to us as a public company;

certain administrative assets and liabilities incumbent as a provider of operational and support services to the Partnership;

certain non-operating assets and liabilities that we retained;

Partnership distributions and earnings allocable to third-party common unitholders which are included in non-controlling interest in our statements; and

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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 a leading provider of midstream natural gas and NGL services in the United States, with a growing presence in crude oil gathering and petroleum terminaling.

The Partnership is engaged in the business of:

gathering, compressing, treating, processing and selling natural gas;

storing, fractionating, treating, transporting, terminaling and selling NGLs and NGL products;

gathering, storing and terminaling crude oil; and

storing, terminaling and selling refined petroleum products.

The Partnership reports its operations in two divisions: (i) Gathering and Processing, consisting of two reportable segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing consisting of two reportable segments – (a) Logistics Assets and (b) Marketing and Distribution. The financial results of its hedging activities are reported in Other.

The Partnership’s Gathering and Processing division includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Field Gathering and Processing segment's assets are located in North Texas, the Permian Basin of West Texas, New Mexico and in North Dakota. 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 its Downstream Business. The Partnership’s Downstream Business includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as the storing, terminaling, distributing and marketing of NGLs and refined petroleum products. It also includes certain natural gas supply and marketing activities in support of the Partnership’s other operations, as well as transporting natural gas and NGLs.

The Partnership’s Logistics Assets segment is involved in transporting, storing, and fractionating mixed NGLs; storing, terminaling, and transporting finished NGLs, including services for exporting LPGs; and storing and terminaling of refined petroleum products. These assets are generally connected to and supplied in part by the Partnership’s Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas and in Lake Charles, Louisiana.

The Partnership’s Marketing and Distribution segment covers activities required to distribute and market raw and finished NGLs and all natural gas marketing activities. It includes (1) marketing the Partnership’s own NGL production and purchasing NGL products in selected United States markets; (2) providing LPG balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end-users; (4) providing propane, butane and services to LPG exporters; and (5) marketing natural gas available to the Partnership from its Gathering and Processing division and the purchase and resale and other value added activities related to third-party natural gas in selected United States markets.

Other contains the results of the Partnership’s commodity hedging activities included in operating margin.

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2013 Developments

Badlands Expansion Program

On January 1, 2013, the Partnership assumed operational control of the Badlands assets in the Williston Basin of North Dakota and commenced integration activities. The Badlands operational results are included as part of the Field Gathering and Processing segment.

During 2013, the Partnership invested approximately $250 million to expand the gathering and processing capabilities of Badlands. The Partnership added an additional 20 MMcf/d natural gas processing plant, and increased its crude gathering and natural gas gathering and processing operations substantially with the addition of pipelines and associated oil and gas facilities. During 2014 we anticipate that the Partnership will invest another $180 million for further expansion of its gathering and processing assets.

The acquisition agreement also provided for a contingent payment of $50 million conditioned on achieving stipulated crude gathering volumes by mid-2014. Management does not believe that those thresholds will be achieved during the contingency period. At December 31, 2012, based on a probability-based model measuring the likelihood of meeting the thresholds, the Partnership recorded a $15.3 million accrued liability representing the fair value of this contingent consideration. During 2013, the contingent consideration was re-estimated to be $0, resulting in the elimination of the contingent liability.

Cedar Bayou Fractionators Train 4

In August 2013, the Partnership commissioned an additional fractionator, Train 4, at CBF. This expansion added 100 MBbl/d of fractionation capacity at CBF. The gross cost of Train 4 was approximately $385 million (net cost to the Partnership was approximately $345 million).

International Export Project

In September 2013, the Partnership commissioned Phase I of its international export expansion project, which includes facilities at both the Partnership’s Mont Belvieu facility and Galena Park Marine Terminal near Houston, Texas. Phase I of this project expanded the Partnership’s export capability to approximately 3.5 to 4 MMBbl per month of propane and/or butane. Included in its Phase I expansion is the capability to export international grade low ethane propane. With the completion of Phase I, the Partnership also added capabilities to load VLGC vessels in addition to the small and medium-sized export vessels that it loads for export. Construction is underway to further expand the Partnership’s propane and butane international export capacity by approximately 2 MMBbl per month, with an expected completion of Phase II in the third quarter of 2014. The Partnership expects that the total cost of both phases of the international export project to be approximately $480 million.

North Texas Longhorn Plant

The Partnership started construction of a new 200 MMcf/d cryogenic processing plant for North Texas to meet increasing production and continued producer activity, with an anticipated completion in the second quarter of 2014. The Partnership expects to invest an estimated $150 million for the plant and associated projects.

SAOU High Plains Plant

The Partnership has started construction of a new 200 MMcf/d cryogenic processing plant and related gathering and compression facilities for SAOU to meet increasing production and continued producer activity on the eastern side of the Permian Basin, with an anticipated completion date in mid-2014. The Partnership expects to invest an estimated $225 million for the plant and associated projects.

Accounts Receivable Securitization Facility

In January 2013, the Partnership entered into a Securitization Facility that provides up to $200 million of borrowing capacity at commercial paper or LIBOR market index rates plus a margin through January 2014. Under this Securitization Facility, one of the Partnership’s consolidated subsidiaries (Targa Liquids Marketing and Trade LLC or “TLMT”) sells or contributes receivables, without recourse, to another of its consolidated subsidiaries (Targa Receivables LLC or “TRLLC”), a special purpose consolidated subsidiary created for the sole purpose of this Securitization Facility. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables to a third-party financial institution. Receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of TLMT or the Partnership. Any excess receivables are eligible to satisfy the claims of creditors of TLMT or the Partnership.

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In December 2013, the Partnership entered into an amendment to the Securitization Facility to increase the borrowing capacity to $300 million and extend the termination date to December 12, 2014. As of December 31, 2013, total funding under this Securitization Facility was $279.7 million.

Other Financing Activities

In 2012, the Partnership filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows the Partnership to issue up to an aggregate of $300 million of debt or equity securities (the “2012 Shelf”). In August 2012, the Partnership entered into an Equity Distribution Agreement (the “2012 EDA”) with Citigroup Global Markets Inc. (“Citigroup”) pursuant to which the Partnership may sell, at its option, up to an aggregate of $100 million of its common units through Citigroup, as sales agent, under the 2012 Shelf. During 2012, there were no sales of common units pursuant to this program. During 2013, the Partnership issued 2,420,046 common units under the 2012 EDA, receiving net proceeds of $94.8 million. We contributed $2.0 million to maintain our 2% general partner interest.

In March 2013, the Partnership entered into a second EDA under the Partnership’s 2012 Shelf (“March 2013 EDA”) with Citigroup, Deutsche Bank Securities Inc. (“Deutsche Bank”), Raymond James & Associates, Inc. (“Raymond James”) and UBS Securities LLC (“UBS”), as its sales agents, pursuant to which the Partnership may sell, at its option, up to an aggregate of $200 million of its debt or equity securities. During 2013, the Partnership issued 4,204,751 common units under the March 2013 EDA, receiving net proceeds of $197.5 million. We contributed $4.1 million to maintain our 2% general partner interest. The 2012 Shelf expires in August 2015.

In April 2013, the Partnership filed with the SEC a universal shelf registration statement (the “April 2013 Shelf”), which provides the Partnership with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and the Partnership’s capital needs. The April 2013 Shelf expires in April 2016. There was no activity under the April 2013 Shelf during the year ended December 31, 2013.

In May 2013, the Partnership privately placed $625.0 million in aggregate principal amount of its 4¼% Senior Notes due 2023 (the “4¼% Notes”). The 4¼% Notes resulted in approximately $618.1 million of net proceeds, which were used to reduce borrowings under the Partnership’s TRP Revolver and for general partnership purposes.

In June 2013, the Partnership redeemed $100 million of the outstanding 6⅜% Senior Notes due 2022 (the “6⅜% Notes”) at a redemption price of 106.375% plus accrued interest through the redemption date. The redemption resulted in a $7.4 million loss, including the write-off of unamortized debt issue costs.

In July 2013, the Partnership redeemed the outstanding 11¼% Senior Notes due 2017 (the “11¼% Notes”) at a price of 105.625% plus accrued interest through July 15, 2013. The redemption resulted in a $7.4 million loss, including the write-off of unamortized debt issue costs.

In July 2013, the Partnership filed with the SEC a universal shelf registration statement (the “July 2013 Shelf”) that allows it to issue up to an aggregate of $800 million of debt or equity securities. The July 2013 Shelf expires in August 2016.

In August 2013, the Partnership entered into an Equity Distribution Agreement under its July 2013 Shelf (the “August 2013 EDA”) with Citigroup, Deutsche Bank, Morgan Stanley & Co. LLC, Raymond James, RBC Capital Markets, LLC, UBS and Wells Fargo Securities, LLC, as its sales agents, pursuant to which it may sell, at its option, up to an aggregate of $400 million of its common units. During the year ended December 31, 2013, the Partnership issued 4,529,641 common units under the August 2013 EDA, receiving net proceeds of $225.6 million, which were used to reduce borrowings under the Partnership’s TRP Revolver and for general partnership purposes. We contributed $4.7 million to maintain our 2% general partner interest. Based upon market conditions and the Partnership’s capital needs, the Partnership at its option, can sell additional common units up to an aggregate amount of $172.0 million under this agreement.

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During the year ended December 31, 2013, pursuant to both the 2012 Shelf and 2013 Shelf, the Partnership issued a total of 11,154,438 common units representing total net proceeds of $517.9 million, which were used to reduce borrowings under the TRP Revolver and for general partnership purposes. We contributed $10.8 million to the Partnership to maintain our 2% general partner interest during this period.

Recent Accounting Pronouncements

In January 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies that ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities, applies to financial instruments or derivative transactions accounted for under Accounting Standards Codification (“ASC”) Topic 815. We currently present the Partnership’s derivative assets and liabilities gross on our statement of financial position. The amendments require disclosure of both gross and net amounts of derivative assets and liabilities that are subject to master netting arrangements with counterparties. We have provided additional disclosures regarding the gross and net amounts of derivative assets and liabilities in Note 14 of the “Consolidated Financial Statements.”

In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. The amendment, required to be applied prospectively for reporting periods beginning after December 15, 2012, requires entities to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line item of net income. Our financial statement presentation complies with this standards update.

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 and the Partnership’s 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 the Partnership’s operations. The factors that impact the gathering and processing volumes also impact the total volumes that flow to the 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 its competitive and contractual position relative to other fractionators.

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Commodity Prices

The following table presents selected annual and quarterly industry index prices for natural gas, selected NGL products and crude oil for the periods presented:

Average Quarterly & Annual Prices	Natural Gas $/MMBtu (1)		Illustrative Targa NGL $/gal (2)		Crude Oil $/Bbl (3)
2013
4th Quarter	$	3.61	$	0.92	$	97.50
3rd Quarter		3.58		0.86		105.82
2nd Quarter		4.10		0.81		94.23
1st Quarter		3.34		0.86		94.35
2013 Average	$	3.65	$	0.86	$	97.98

2012
4th Quarter	$	3.41	$	0.88	$	88.23
3rd Quarter		2.80		0.86		92.20
2nd Quarter		2.21		0.94		93.35
1st Quarter		2.72		1.18		103.03
2012 Average	$	2.79	$	0.97	$	94.20

2011
4th Quarter	$	3.54	$	1.37	$	91.88
3rd Quarter		4.20		1.37		89.54
2nd Quarter		4.32		1.36		102.34
1st Quarter		4.11		1.23		94.60
2011 Average	$	4.04	$	1.33	$	94.59

(1)	Natural gas prices are based on average quarterly and annual prices from Henry Hub I-FERC commercial index prices.

(2)	NGL prices are based on quarterly and annual averages of prices from Mont Belvieu Non-TET monthly commercial index prices. Illustrative Targa NGL contains 44% ethane, 30% propane, 11% natural gasoline, 5% isobutane and 10% normal butane.

(3)	Crude oil prices are based on quarterly and annual averages of daily prices from West Texas Intermediate commercial index prices as measured on the NYMEX.

Contract Terms, Contract Mix and the Impact of Commodity Prices

Because of the potential for significant volatility of natural gas and NGL prices, the contract mix of the Partnership’s Gathering and Processing division, other than fee-based contracts in Badlands and certain other gathering and processing services, can have a material impact on its profitability, especially those contracts that create direct exposure to changes in energy prices by paying the Partnership for gathering and processing services with a portion of the commodities handled (“equity volumes”).

Contract terms in the Gathering and Processing division are based upon a variety of factors, including natural gas and crude quality, geographic location, competitive commodities and the pricing environment at the time the contract is executed, and customer requirements. The Partnership’s gathering and processing contract mix and, accordingly, their exposure to crude, 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, their expansion into regions where different types of contracts are more common and other market factors. For example, the Partnership’s Badlands crude and natural gas contracts are essentially 100% fee-based.

The contract terms and contract mix of our Downstream Business can also have a significant impact on the Partnership’s 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. The current demand for fractionation services has grown resulting in increases in fractionation fees and contract term. In addition, reservation fees are required. Increased demand for export services also supports fee-based contracts. 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.

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Impact of the Partnership’s Commodity Price Hedging Activities

In an effort to reduce the variability of its cash flows, the Partnership has hedged the commodity price associated with a portion of its expected natural gas equity volumes through 2016 and NGL and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps. With these arrangements, the Partnership has attempted to mitigate some of its exposure to commodity price movements with respect to its forecasted volumes for these periods. The Partnership also actively manages the Downstream Business product inventory and other working capital levels to reduce exposure to changing NGL prices. For additional information regarding the Partnership’s hedging activities, see “Item 7A. 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. The employees supporting the Partnership’s operations are employees of Targa Resources LLC, a Delaware limited liability company, and an indirect wholly-owned subsidiary of us. The Partnership reimburses us for the payment of certain operating expenses, including compensation and benefits of operating personnel assigned to the Partnership’s assets.

General and Administrative Expenses

We perform centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk management, health, safety, environmental, information technology, human resources, credit, payroll, internal audit, taxes engineering and marketing. Other than our direct costs of being a separate public reporting company, these costs are reimbursed by the Partnership. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”

General Trends and Outlook

We expect the midstream energy business environment to continue to be affected by the following key trends: demand for the Partnership’s 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, the Partnership’s 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 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 natural gas and crude oil 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

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.

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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. In a declining commodity price environment, without taking into account the Partnership’s hedges, the Partnership 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 the Partnership’s hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Volatile Capital Markets

The Partnership is dependent on its 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, NGLs, and crude oil 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, NGLs or crude oil through its facilities and reducing the utilization of its assets.” 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 types of 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 direct operating activities separate 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).

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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 comparable to similarly titled measures of other companies, thereby diminishing its utility.

Our Non-GAAP Measures

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.

	2013			2012			2011
	(In millions)
Reconciliation of Net Income attributable to Targa Resources Corp. to Distributable Cash Flow
Net income of Targa Resources Corp.	$	201.3		$	159.3		$	215.4
Less: Net income of Targa Resources Partners LP		(258.6	)		(203.2	)		(245.5	)
Net loss for TRC Non-Partnership		(57.3	)		(43.9	)		(30.1	)
TRC Non-Partnership income tax expense		45.3			32.7			22.3
Distributions from the Partnership		149.0			103.3			66.9
Non-cash loss (gain) on hedges		0.3			(2.2	)		(4.4	)
Loss on debt redemptions and amendments		-			0.2			-
Depreciation - Non-Partnership assets		0.3			0.3			2.8
Current cash tax expense (1)		(31.0	)		(20.8	)		(7.4	)
Taxes funded with cash on hand (2)		10.0			8.7			10.1
Distributable cash flow	$	116.6		$	78.3		$	60.2

(1)

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 years ended December 31, 2013, 2012, and 2011 and includes 2012 cash tax overpayment applied to 2013 cash tax liability.

(2)	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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	2013			2012			2011
	(In millions)
Targa Resources Corp. Distributable Cash Flow
Distributions declared by Targa Resources Partners LP associated with:
General Partner Interests	$	8.4		$	6.2		$	4.8
Incentive Distribution Rights		103.1			63.3			34.4
Common Units		37.5			33.8			27.7
Total distributions declared by Targa Resources Partners LP		149.0			103.3			66.9
Income (expenses) of TRC Non-Partnership
General and administrative expenses		(8.4	)		(8.2	)		(8.3	)
Interest expense, net		(3.1	)		(4.0	)		(4.0	)
Current cash tax expense (1)		(31.0	)		(20.8	)		(7.4	)
Taxes funded with cash on hand (2)		10.0			8.7			10.1
Other income (expense)		0.1			(0.7	)		2.9
Distributable cash flow	$	116.6		$	78.3		$	60.2

(1)

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 years ended December 31, 2013, 2012 and 2011, and includes 2012 cash tax overpayment applied to 2013 cash tax liability.

(2)	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.

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, 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 crude oil, natural gas and NGLs, and the volumes of crude oil, 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, utilization of its assets and changes in its customer mix.

The Partnership’s profitability is also impacted by fee-based revenues. The Partnership’s growth strategy, based on expansion of existing facilities as well as third-party acquisitions of businesses and assets, has been increasing the percentage of our revenues that are fee-based. Fixed fees for services such as fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities.

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, (3) capital expenditures and (4) 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 and crude oil supply to offset the natural decline of existing volumes from oil and 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 crude oil and 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 facilities.

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In addition, the Partnership seeks to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With its gathering systems’ extensive use of remote monitoring capabilities, the Partnership monitors the volumes 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 helps the Partnership increase efficiency and reduces 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 its facilities. Similar tracking is performed for its crude oil gathering and logistics assets. These volume, recovery and fuel consumption measurements are an important part of the Partnership’s operational efficiency analysis and safety programs.

Operating Expenses

Operating expenses are costs associated with the operation of specific assets. 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.

Capital Expenditures

Capital projects associated with growth and maintenance projects are closely monitored. Return on investment is analyzed before a capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval. The Partnership has seen a substantial increase in its total capital spent over the last three years and currently has significant internal growth projects that it closely monitors.

Gross Margin

The Partnership defines gross margin as revenues less purchases. It is impacted by volumes and commodity prices as well as by the Partnership’s contract mix and commodity hedging program. The Partnership defines Gathering and Processing gross margin as total operating revenues from (1) the sale of natural gas, condensate and NGLs (2) natural gas and crude oil gathering and service fee revenues and (3) settlement gains and losses on commodity hedges, 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, NGL and natural gas sales, less cost of sales, which consists primarily of NGL and natural gas purchases, transportation costs and changes in inventory valuation. The gross margin impacts of cash flow hedge settlements are reported in Other.

Operating Margin

The Partnership defines operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of the Partnership’s operations.

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 management uses in evaluating the Partnership’s operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by management and by external users of the Partnership’s 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;

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

the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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, the Partnership’s definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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 attributable to Targa Resources Partners LP before: interest; income taxes; depreciation and amortization; gains or losses on debt repurchases and redemptions, early debt extinguishments and asset disposals; non-cash risk management activities related to derivative instruments; changes in the fair value of the Badlands acquisition contingent consideration and the non-controlling interest portion of depreciation and amortization expenses. Adjusted EBITDA is used as a supplemental financial measure by the Partnership and by external users of its financial statements such as investors, commercial banks and others. The economic substance behind the Partnership’s use of Adjusted EBITDA is to measure the ability of its assets to generate cash sufficient to pay interest costs, support its indebtedness and make distributions to its investors.

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income attributable to Targa Resources Partners LP. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities or GAAP net income. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of the Partnership’s results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in the Partnership’s industry, the Partnership’s definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Distributable Cash Flow

The Partnership defines distributable cash flow as net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash risk management activities related to derivative instruments, debt repurchases and redemptions, early debt extinguishments and asset disposals, less maintenance capital expenditures (net of any reimbursements of project costs) and changes in the fair value of the Badlands acquisition contingent consideration. This measure includes any impact of noncontrolling interests.

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Distributable cash flow is a significant performance metric used by the Partnership and by external users of the Partnership’s financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by the Partnership (prior to the establishment of any retained cash reserves by the board of directors of its general partner) to the cash distributions the Partnership expects to pay the Partnership’s unitholders. Using this metric, the Partnership’s management and external users of its financial statements can quickly compute the coverage ratio of estimated cash flows to cash distributions. Distributable cash flow is also an important financial measure for the Partnership’s unitholders since it serves as an indicator of the Partnership’s success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Partnership is generating cash flow at a level that can sustain or support an increase in the Partnership’s quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder).

Distributable cash flow is a non-GAAP financial measure. The GAAP measure most directly comparable to distributable cash flow is net income attributable to Targa Resources Partners LP. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Partners LP. It has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of the Partnership’s results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in the Partnership’s industry, the Partnership’s definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Non-GAAP Financial Measures of the Partnership

The following tables reconcile the non-GAAP financial measures of the Partnership used by management to the most directly comparable GAAP measures for the periods indicated:

	2013			2012			2011
	(In millions)
Reconciliation of Targa Resources Partners LP gross margin and operating margin to net income:
Gross margin	$	1,177.7		$	1,004.7		$	948.1
Operating expenses		(376.2	)		(313.0	)		(287.0	)
Operating margin		801.5			691.7			661.1
Depreciation and amortization expenses		(271.6	)		(197.3	)		(178.2	)
General and administrative expenses		(143.1	)		(131.6	)		(127.8	)
Interest expense, net		(131.0	)		(116.8	)		(107.7	)
Income tax expense		(2.9	)		(4.2	)		(4.3	)
Loss on sale or disposition of assets		(3.9	)		(15.6	)		(0.2	)
Loss on debt redemptions and amendments		(14.7	)		(12.8	)		-
Change in contingent consideration		15.3			-			-
Other, net		9.0			(10.2	)		2.6
Targa Resources Partners LP net income	$	258.6		$	203.2		$	245.5

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	2013			2012			2011
	(In millions)
Reconciliation of net cash provided by Targa Resources Partners LP operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	411.4		$	465.4		$	400.9
Net income attributable to noncontrolling interests		(25.1	)		(28.6	)		(41.0	)
Interest expense, net (1)		115.5			99.2			95.3
Loss on debt redemptions and amendments		(14.7	)		(12.8	)		-
Change in contingent consideration		(15.3	)		-			-
Current income tax expense		2.0			2.5			3.5
Other (2)		(5.0	)		(6.4	)		7.9
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivable and other assets		230.3			(96.1	)		150.3
Accounts payable and other liabilities		(69.9	)		91.7			(126.1	)
Targa Resources Partners LP Adjusted EBITDA	$	629.2		$	514.9		$	490.8

(1)	Net of amortization of debt issuance costs, discount and premium included in interest expense of $15.5 million, $17.6 million and $12.4 million for 2013, 2012 and 2011.

(2)	Includes equity earnings from unconsolidated investments – net of distributions, accretion expense associated with asset retirement obligations, amortization of stock-based compensation and gain on sale or disposal of assets.

	2013			2012			2011
	(In millions)

Reconciliation of Net Income attributable to Targa Resources Partners LP to Adjusted EBITDA:
Net income attributable to Targa Resources Partners LP	$	233.5		$	174.6		$	204.5
Interest expense, net		131.0			116.8			107.7
Income tax expense		2.9			4.2			4.3
Depreciation and amortization expenses		271.6			197.3			178.2
Loss on sale or disposition of assets		3.9			15.6			-
Loss on debt redemptions and amendments		14.7			12.8			-
Change in contingent consideration		(15.3	)		-			-
Risk management activities		(0.5	)		5.4			7.2
Noncontrolling interests adjustment (1)		(12.6	)		(11.8	)		(11.1	)
Targa Resources Partners LP Adjusted EBITDA	$	629.2		$	514.9		$	490.8

(1)	Noncontrolling interest portion of depreciation and amortization expenses.

	2013			2012		2011
	(In millions)
Reconciliation of Net Income attributable to Targa Resources Partners LP to Distributable Cash flow:
Net income attributable to Targa Resources Partners LP	$	233.5		$	174.6	$	204.5
Depreciation and amortization expenses		271.6			197.3		178.2
Deferred income tax expense		0.9			1.7		0.8
Amortization in interest expense		15.5			17.6		12.4
Loss on debt redemptions and amendments		14.7			12.8		-
Change in contingent consideration		(15.3	)