Edgar Filing: Regency Energy Partners LP

RGP 12.31.2014 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________________________________

Form 10-K

_____________________________________________________



ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014



¨	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: 001-35262

_____________________________________________________

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

_____________________________________________________



Delaware		16-1731691
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

2001 Bryan Street Suite 3700, Dallas, Texas		75201
(Address of principal executive offices)		(Zip Code)

(214) 750-1771

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report): None

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



Title of Each Class		Name of Each Exchange on Which Registered
Common Units of Limited Partner Interests		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 ý No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No ý

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 ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such file). Yes ý No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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 small reporting company” in Rule 12b-2 of the Exchange Act. ý Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer (Do not check if a smaller reporting company) ¨ Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

As of June 30, 2014, the aggregate market value of the registrant’s common units held by non-affiliates of the registrant was $9.66 billion based on the closing sale price on such date as reported on the New York Stock Exchange.

The issuer had 410,927,131 common units and 6,274,483 Class F units outstanding as of February 19, 2015.

DOCUMENTS INCORPORATED BY REFERENCE

None

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REGENCY ENERGY PARTNERS LP

ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2014

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		Page

PART I
Item 1	Business	1
Item 1A	Risk Factors	20
Item 1B	Unresolved Staff Comments	44
Item 2	Properties	44
Item 3	Legal Proceedings	44
Item 4	Mine Safety Disclosures	44

PART II
Item 5	Market for Registrant’s Common Units, Related Unitholders Matters and Issuer Purchases of Equity Securities	44
Item 6	Selected Financial Data	47
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	55
Item 7A	Quantitative and Qualitative Disclosure about Market Risk	75
Item 8	Financial Statements and Supplementary Data	76
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	76
Item 9A	Controls and Procedures	76
Item 9B	Other Information	77

PART III
Item 10	Directors, Executive Officers and Corporate Governance	78
Item 11	Executive Compensation	83
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	95
Item 13	Certain Relationships and Related Transactions, and Director Independence	97
Item 14	Principal Accountant Fees and Services	99

PART IV
Item 15	Exhibit and Financial Statement Schedules	99

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Introductory Statement

References in this report to the “Partnership,” “we,” “our,” “us” and similar terms refer to Regency Energy Partners LP and its subsidiaries. We use the following definitions in this annual report on Form 10-K:



Name		Definition or Description
/d		Per day
2018 Notes		$600 million of 6.875% senior notes with original maturity on December 1, 2018
AOCI		Accumulated Other Comprehensive Income (Loss)
Aqua - PVR		Aqua - PVR Water Services, LLC
ARO		Asset Retirement Obligation
APM		Anadarko Pecos Midstream LLC
Barclays		Barclays Capital Inc.
Bbls		Barrels
bps		Basis points
Bcf		One billion cubic feet
Citi		Citigroup Global Markets Inc.
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act
CFTC		Commodity Futures Trading Commission
CM		Chesapeake West Texas Processing, L.L.C.
Coal Handling		Coal Handling Solutions LLC, Kingsport Handling LLC, and Kingsport Services LLC, now known as Materials Handling Solutions LLC
CWA		Clean Water Act
DHS		U.S. Department of Homeland Security
DOT		U.S. Department of Transportation
DNR		Louisiana Department of Natural Resources, Office of Conservation
Eagle Rock		Eagle Rock Energy Partners, L.P.
EFS Haynesville		EFS Haynesville, LLC, a wholly-owned subsidiary of GECC
EIA		Energy Information Administration
ELG		Edwards Lime Gathering LLC and its wholly-owned subsidiaries, ELG Oil LLC and ELG Utility LLC
EPA		Environmental Protection Agency
EPD		Enterprise Products Partners L.P.
ERISA		Employee Retirement Income Security Act of 1974
ETC		Energy Transfer Company, the name assumed by La Grange Acquisition, L.P. for conducting business and shared services, a wholly-owned subsidiary of ETP
ETE		Energy Transfer Equity, L.P.
ETE Common Holdings		ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE
ETE GP		ETE GP Acquirer LLC
ETP		Energy Transfer Partners, L.P.
ETP GP		Energy Transfer Partners GP, LP
Exchange Act		Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FASB ASC		FASB Accounting Standards Codification
FERC		Federal Energy Regulatory Commission
Finance Corp.		Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership
GAAP		Accounting principles generally accepted in the United States of America

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Name		Definition or Description
General Partner		Regency GP LP, the general partner of the Partnership, or Regency GP LLC, the general partner of Regency GP LP, which effectively manages the business and affairs of the Partnership through its board of directors and Regency Employees Management LLC
Grey Ranch		Grey Ranch Plant LP, a former joint venture of the Partnership
Gulf States		Gulf States Transmission LLC, a wholly-owned subsidiary of the Partnership
HLPSA		Hazardous Liquid Pipeline Safety Act
Holdco		ETP Holdco Corporation
Hoover		Hoover Energy Partners, LP
HPC		RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP
ICA		Interstate Commerce Act
IDRs		Incentive Distribution Rights
IRC		Internal Revenue Code
IRS		Internal Revenue Service
KMP		Kinder Morgan Energy Partners, L.P.
LDH		LDH Energy Asset Holdings LLC
LIBOR		London Interbank Offered Rate
Lone Star		Lone Star NGL LLC
LTIP		Long-Term Incentive Plan
MBbls		One thousand barrels
MEP		Midcontinent Express Pipeline LLC
Mi Vida JV		Mi Vida JV LLC
MLP		Master Limited Partnership
MMBtu		One million BTUs. BTU is a unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
MMcf		One million cubic feet
NGA		Natural Gas Act of 1938
NGLs		Natural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline
NGPA		Natural Gas Policy Act of 1978
NGPSA		Natural Gas Pipeline Safety Act of 1968, as amended
NMED		New Mexico Environmental Development
NPDES		National Pollutant Discharge Elimination System
NYMEX		New York Mercantile Exchange
NYSE		New York Stock Exchange
ORS		Ohio River System LLC
OSHA		Occupational Safety and Health Act
PADEP		Pennsylvania Department of Environmental Protection
Partnership		Regency Energy Partners LP
PEPL		Panhandle Eastern Pipe Line Company, LP
PEPL Holdings		PEPL Holdings, LLC, a former wholly-owned subsidiary of Southern Union that merged into PEPL
PVR		PVR Partners, L.P.
Ranch JV		Ranch Westex JV LLC
Regency Western		Regency Western G&P LLC, a wholly-owned subsidiary of the Partnership
RCRA		Resource Conservation and Recovery Act
RGS		Regency Gas Services, LP, a wholly-owned subsidiary of the Partnership
RIGS		Regency Intrastate Gas System
SEC		Securities and Exchange Commission

iii

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Name		Definition or Description
Securities Act		Securities Act of 1933, as amended
Senior Notes		The collective of 2019 Notes, 2020 Notes, 2020 PVR Notes, 2021 Notes, 2021 PVR Notes, 2022 Notes, October 2022 Notes, 2023 4.5% Notes and 2023 5.5% Notes
Series A Preferred Units		Series A convertible redeemable preferred units
Services Co.		ETE Services Company, LLC
Southern Union		Southern Union Company
SUGS		Southern Union Gas Services
SUN		Sunoco LP (formerly known as Susser, L.P.)
Sweeny JV		Sweeny Gathering, L.P.
SXL		Sunoco Logistics Partners L.P.
TCEQ		Texas Commission on Environmental Quality
TRRC		Texas Railroad Commission
U.S.		United States
Wells Fargo		Wells Fargo Securities, LLC
WTI		West Texas Intermediate Crude

Cautionary Statement about Forward-Looking Statements

Certain matters discussed in this report include “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we cannot give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions, including without limitation the following:

•volatility in the price of oil, natural gas, condensate, NGLs and coal;


•	unexpected difficulties in integrating any significant acquisitions into our operations;


•	declines in the credit markets and the availability of credit for us as well as for producers connected to our pipelines and our gathering and processing facilities, and for our customers of our contract services business;


•	the level of creditworthiness of, and performance by, our counterparties and customers;


•	our access to capital to fund organic growth projects and acquisitions, and our ability to obtain debt or equity financing on satisfactory terms;


•	our use of derivative financial instruments to hedge commodity risks;


•	the amount of collateral required to be posted from time-to-time in our transactions;


•	changes in commodity prices, interest rates and demand for our services;


•	changes in laws and regulations or enforcement practices impacting the midstream sector of the natural gas industry, oil industry and the coal mining industry, including those that relate to climate change and environmental protection and safety, including with respect to emissions levels applicable to coal-burning power generators and permissible levels of mining runoff;


•	the adoption of new laws, or the promulgation of new regulations, at the federal, state or local level that promote use and development of renewable energy or limit use or development of fossil fuels;


•	weather and other natural phenomena;


•	industry changes including the impact of consolidation and changes in competition;


•	regulation of transportation rates on our natural gas, NGL, and oil pipelines;


•	our ability to obtain indemnification related to cleanup liabilities and to clean up any hazardous materials release on satisfactory terms;

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•	our ability to obtain required approvals for construction or modernization of our facilities and the timing of production from such facilities;


•	the effect of accounting pronouncements issued periodically by accounting standard setting boards;


•	the extent to which the amount and quality of actual production of our coal differs from estimated recoverable coal reserves;


•	the experience and financial condition of our coal lessees, including our lessees’ ability to satisfy their royalty, environmental, reclamation and other obligations to us and others;


•	operating risks, including unanticipated geological problems, incidental to our Gathering and Processing segment and Natural Resources segment;


•	the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves and obtain favorable contracts for such production;


•	delays in anticipated start-up dates of new development in our Gathering and Processing segment and our lessees’ mining operations and related coal infrastructure projects, including the timing of receipt of necessary governmental permits by us or our lessees; and


•	uncertainties relating to the effects of regulatory guidance on permitting under the Clean Water Act and the outcome of current and future litigation regarding mine permitting.

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may differ materially from those anticipated, estimated, projected or expected.

Other factors that could cause our actual results to differ from our projected results are discussed in Item 1A of this annual report.

Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

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PART I

Item 1. Business

Pending Merger with ETP. On January 25, 2015, we and ETP entered into a definitive merger agreement, as amended on February 18, 2015 (the “Merger Agreement”) pursuant to which the Partnership will merge with a wholly-owned subsidiary of ETP, with the Partnership continuing as the surviving entity and becoming a wholly-owned subsidiary of ETP (the "Merger"). At the effective time of the Merger (the "Effective Time"), each Partnership common unit and Class F unit will be converted into the right to receive 0.4066 ETP common units, plus a number of additional ETP common units equal to $0.32 per Partnership unit divided by the lesser of (i) the volume weighted average price of ETP common units for the five trading days ending on the third trading day immediately preceding the Effective Time and (ii) the closing price of ETP common units on the third trading day immediately preceding the Effective Time, rounded to the nearest ten thousandth of a unit. Each Series A Preferred Unit will be converted into the right to receive a preferred unit representing a limited partner interest in ETP, a new class of units in ETP to be established at the Effective Time. Early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, for the Merger was granted by the United States Federal Trade Commission on February 24, 2015. The transaction is expected to close in the second quarter of 2015 and is subject to other customary closing conditions including approval by the Partnership’s unitholders. Additional information regarding the proposed Merger and the terms and conditions of the Merger Agreement are set forth in our Current Reports on Form 8-K, filed with the SEC on January 26, 2015 and February 18, 2015.

OVERVIEW

We are a growth-oriented publicly-traded Delaware limited partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude, and/or condensate, a lighter oil) received from producers; the gathering and disposing of salt water; natural gas and NGL marketing and trading; and the management of coal and natural resource properties in the United States. We focus on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, Avalon and Granite Wash shales. Our assets are primarily located in Texas, Louisiana, Arkansas, West Virginia, Pennsylvania, Ohio, California, Mississippi, Alabama, New Mexico and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma.

We divide our operations into six business segments:

•

Gathering and Processing. We provide “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems, the gathering of oil (crude and/or condensate, a lighter oil) received from producers, the gathering and disposing of salt water, and natural gas and NGL marketing and trading. This segment also includes our 60% membership interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in south Texas, our 33.33% membership interest in Ranch JV, which processes natural gas delivered from NGL-rich shale formations in west Texas, our 50% interest in Sweeny JV, which operates a natural gas gathering facility in south Texas, our 51% membership interest in Aqua - PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, our 75% membership interest in ORS, which will operate a natural gas gathering system in the Utica shale in Ohio, and our 50% interest in Mi Vida JV, which will operate a cryogenic processing plant and related facilities in west Texas.

•

Natural Gas Transportation. We own a 49.99% general partner interest in HPC, which owns RIGS, a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in MEP, which owns a 500-mile interstate natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama. This segment also includes Gulf States, which owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.


•	NGL Services. We own a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including NGL pipelines, storage, fractionation and processing facilities located in Texas, New Mexico, Mississippi and Louisiana.


•	Contract Services. We own and operate a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. We also own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management.


•	Natural Resources. We are involved in the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber,

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leasing coal-related infrastructure facilities, and collecting oil and gas royalties. This segment also included our 50% interest in Coal Handling, which owns and operates end-user coal handling facilities. We purchased the remaining interest in these companies effective December 31, 2014.


•	Corporate. The Corporate segment comprises our corporate assets.

The following map depicts the geographic areas of our operations as of December 31, 2014:

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ORGANIZATIONAL STRUCTURE

The chart below depicts our general organizational and ownership structure as of December 31, 2014:

⁽¹⁾ Includes our 75% interest in ORS and our 60% interest in ELG.

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INDUSTRY OVERVIEW

General. The midstream natural gas industry is the link between exploration and production of raw natural gas and the delivery of its components to end-user markets. It consists of natural gas gathering, compression, dehydration, processing, amine treating, fractionation and transportation as well as the gathering and handling of oil produced at the wellhead (crude and/or condensate, a lighter oil). Raw natural gas produced from the wellhead is gathered and often delivered to a plant located near the production area, where it is treated, dehydrated and/or processed. Natural gas processing involves the separation of raw natural gas into pipeline quality natural gas, principally methane and mixed NGLs. Natural gas treating entails the removal of impurities, such as water, sulfur compounds, carbon dioxide and nitrogen. Pipeline-quality natural gas is delivered by interstate and intrastate pipelines to markets. Mixed NGLs are typically transported via NGL pipelines or by truck to fractionators, which separate the NGLs into their components, such as ethane, propane, normal butane, isobutane and natural gasoline. The NGL components are then sold to end users.

Natural Gas Gathering. A gathering system typically consists of a network of low-pressure, small-diameter pipelines that collect natural gas from the wellhead and transport it to processing or treating plants for processing, treating, and/or dehydration, for redelivery to larger diameter pipelines for further transportation to end-user markets.

Compression. Natural gas compression is a mechanical process in which gas at a lower pressure is boosted, or compressed, to a desired higher pressure, allowing the gas to flow into a higher-pressure, downstream pipeline where it will be transported to end-user markets. Field compression is typically used to lower the gas pressure at entry into the gathering system while maintaining or increasing the exit pressure, providing sufficient pressure to deliver gas into a higher-pressure, downstream pipeline.

Dehydration. Dehydration is the process during which water is removed from the gas; also called Glycol Absorption.

Processing. Natural gas processing is the separation of natural gas into pipeline quality natural gas and a mixed NGL stream through either an absorption, mechanical or cryogenic process. The heavier components which make up the NGL stream are typically ethane, propane, isobutane, normal butane and natural gasoline.

Amine Treating. Natural gas treating entails the removal of impurities such as water, sulfur compounds, carbon dioxide and nitrogen. The amine treating process involves a continuous circulation of a liquid chemical called amine that physically contacts with the natural gas. The gas and amine are separated and the impurities are removed from the amine by heating. The treating plants are sized according to the amine circulation rate in terms of GPM.

Fractionation. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane and natural gasoline. 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. Propane is used both as a petrochemical feedstock in the production of propylene and as a heating fuel, an engine fuel and an industrial fuel. Normal butane is used as a petrochemical feedstock in the production of butadiene (a key ingredient in synthetic rubber) and as a blend stock for motor gasoline. Isobutane is typically fractionated from mixed butane (a stream of normal butane and isobutane in solution), principally for use in enhancing the octane content of motor gasoline. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock, petrochemical feedstock or as a diluent for heavy crude oil to assist in pipeline transportation.

Transportation. Natural gas transportation consists of moving pipeline-quality natural gas from gathering systems, processing or treating plants and other pipelines and delivering it to wholesalers, end users, local distribution companies and other pipelines.

Storage. A place to store natural gas supplies for use at a later time. Storage can be an old gas field, a developed salt dome or a liquefied natural gas tank.

INDUSTRY OUTLOOK

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—General Trends and Outlook”.

GATHERING AND PROCESSING OPERATIONS

General. We operate gathering and processing assets in five geographic regions of the United States: Arklatex (north Louisiana, Arkansas and east Texas), the mid-continent region (north Texas, Kansas, Colorado and Oklahoma), south Texas, Permian, and Eastern (Pennsylvania, West Virginia and Ohio) with a total of 25,684 miles of pipeline across all regions. We contract with producers to gather raw natural gas, NGLs, and oil (crude, and/or condensate, a lighter oil) from individual wells or central receipt points, which may have multiple wells behind them, located near our processing plants, treating facilities and/or gathering systems. Following the execution of a contract, we connect wells and central receipt points to our gathering lines through which the raw natural gas flows to a processing plant, treating facility or directly to interstate or intrastate gas transportation pipelines. At our

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processing plants and treating facilities, we remove impurities from the raw natural gas stream and extract the NGLs. We also perform a producer service function, whereby we purchase natural gas from producers at gathering systems and plants and sell this gas at downstream outlets. In certain regions, we also contract with producers to gather the oil produced with the natural gas and deliver the oil to a tank for transportation by truck or pipeline.

All raw natural gas, NGLs, and oil (crude, and/or condensate, a lighter oil) flowing through our gathering and processing facilities are supplied under gathering and processing contracts having terms ranging from month-to-month to the life of the oil and gas lease. For a description of our contracts, read “-Our Contracts” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The pipeline-quality natural gas remaining after separation of NGLs through processing is either returned to the producer or sold, for our own account or for the account of the producer, at the tailgates of our processing plants for delivery to interstate or intrastate gas transportation pipelines.

The following table sets forth information regarding our gathering systems and processing plants as of December 31, 2014:



Region	Plants	Compression (Horsepower)
Arklatex	9	96,834
South Texas	3	187,723
Permian	10	387,932
Mid-Continent	14	425,394
Eastern	—	112,282
Total	36	1,210,165

Arklatex. Our Arklatex assets gather, compress, treat and dehydrate natural gas in several Parishes of north and west Louisiana and several counties in east Texas. Our assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, and an interstate NGL pipeline.

Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana described in “Natural Gas Transportation Operations,” we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.

In May 2014, we announced the construction of a new 200 MMcf/d cryogenic processing plant and 47-mile, 40,000 bbls/d capacity NGL pipeline, for a combined total of $191 million, which is expected to be completed in mid-2015.

South Texas. Our south Texas assets gather, compress, treat and dehydrate natural gas in Bee, LaSalle, Webb, Karnes, Atascosa, McMullen, Frio and Dimmitt counties. Some of the natural gas produced in this region can have significant quantities of hydrogen sulfide and carbon dioxide that require treating to remove these impurities. The pipeline systems that gather this gas are connected to third-party processing plants and our treating facilities that include an acid gas reinjection wells located in McMullen County, Texas. We also gather oil for producers in the region and deliver it to tanks for further transportation by truck or pipeline.

The natural gas supply for our south Texas gathering systems is derived from a combination of natural gas wells located in mature basins that generally have long lives and predictable gas flow rates, including the Frio, Vicksburg, Miocene, Canyon Sands and Wilcox formations, and the NGLs-rich and oil-rich Eagle Ford shale formation, which lies directly under our existing south Texas gathering system infrastructure.

We own a 60% interest in ELG with Talisman Energy USA Inc. and Statoil Texas Onshore Properties LP owning the remaining 40% interest. We operate a natural gas gathering, oil pipeline and oil stabilization facilities for the joint venture while our joint venture partners operate a lean gas gathering system in the Edwards Lime natural gas trend that delivers to this system.

Permian. Our Permian Basin gathering system assets offer wellhead-to-market services to producers in the Texas counties of Ward, Winkler, Reeves, Pecos, Crocket, Upton, Crane, Ector, Culberson, Reagan and Andrews counties, as well as into Eddy and Lea counties in New Mexico which surround the Waha Hub, one of Texas’ developing NGLs-rich natural gas market areas. As a result of the proximity of our system to the Waha Hub, the Waha gathering system has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. The NGL market outlets include Lone Star’s NGL pipeline.

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Our Permian assets consist of a network of natural gas and NGL pipelines, six processing and treating plants, two processing plants and two treating plants. These assets offer a broad array of services to producers including field gathering and compression of natural gas; treating, dehydration, sulfur recovery and reinjection and other conditioning; and natural gas processing and marketing of natural gas and NGLs.

In October 2014, we entered into a joint venture with Anadarko Mi Vida LLC (“Anadarko”). Anadarko and Regency each own a 50% membership interest in the new joint venture, Mi Vida JV. We are constructing and will operate a 200 MMcf/d cryogenic processing plant and related facilities, in west Texas, on behalf of Mi Vida JV.

We own a 33.33% membership interest in Ranch JV which processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 100 MMcf/d cryogenic processing plant.

Mid-Continent. Our mid-continent systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western Oklahoma and the Texas Panhandle. These mature basins have continued to provide generally long-lived, predictable production volume. Our mid-continent gathering assets are extensive systems that gather, compress and dehydrate low-pressure gas. We have 14 natural gas producing facilities and approximately 12,995 miles of gathering pipeline.

We operate our mid-continent gathering systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.

We also own the Hugoton gathering system that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.

Eastern. Our eastern region assets are located in Pennsylvania, Ohio, and West Virginia, and gather natural gas from the Marcellus and Utica basins. Our eastern gathering assets include approximately 370 miles of natural gas gathering pipeline, natural gas trunkline pipelines, and fresh water pipelines. Our eastern region assets include the Lycoming, Wyoming, East Lycoming, Bradford, Green, and Preston gathering systems. Our Eastern segment earns revenues primarily from fees charged to producers for natural gas gathering, transportation, compression and other related services.

We also own a 51% membership interest in Aqua - PVR, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.

In August 2014, we entered into a joint venture with American Energy - Midstream, LLC (“AEM”). We and AEM own a 75% and 25% membership interest, respectively, in the new joint venture, ORS. On behalf of ORS, we are constructing and will operate our Ohio Utica River System, (the “ORS System”) which consists of a 52-mile, 36-inch gathering trunkline that will be capable of delivering up to 2.1 bcf/d to Rockies Express Pipeline (“REX”), Texas Eastern Transmission, and potentially others, and the construction of 25,000 horsepower of compression at the REX interconnect. This project will also include the construction of a 12-mile, 30-inch lateral that will initially connect to the tailgate of the Cadiz processing plant and Harrison County wellhead production. Phase I and Phase II are expected to be completed in the second and third quarters of 2015, respectively. Total costs for the ORS System are expected to be approximately $500 million; 75% contributed from us and 25% contributed from AEM. Additionally, we and American Energy - Utica, LLC (“AEU”), an affiliate of AEM, entered into a gathering agreement for gas produced from the Utica Shale in eastern Ohio by AEU.

Logistics and Trading. We conduct natural gas marketing and trading activities through our Logistics and Trading subsidiary. We engage in activities intended to capitalize on favorable price differentials between various receipt and delivery locations.

NATURAL GAS TRANSPORTATION OPERATIONS

RIGS has the capacity to transport up to 2.1 Bcf/d of natural gas. Results of RIGS’s operations are determined primarily by the volumes of natural gas transported and subscribed on its intrastate pipeline system and the level of fees charged to customers or the margins received from purchases and sales of natural gas. RIGS generates revenues and segment margins principally under fee-based transportation contracts. The fixed capacity reservation charges related to RIGS that are not directly dependent on throughput volumes or commodity prices represent 93% of HPC’s margin.

MEP pipeline system, operated by KMP, has the capability to transport up to 1.8 Bcf/d of natural gas, and the pipeline capacity is nearly fully subscribed; Zone 1 is 95% subscribed and Zone 2 is fully subscribed, with long-term binding commitments from creditworthy shippers. Results of MEP’s operations are determined primarily by the volumes of natural gas transported and subscribed on its interstate pipeline system and the level of fees charged to customers. MEP generates revenues and segment margins principally under fee-based transportation contracts. The margin MEP earns is primarily related to fixed capacity

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reservation charges that are not directly dependent on throughput volumes or commodity prices. If a sustained decline in commodity prices should result in a decline in volumes, MEP’s revenues would not be significantly impacted until expiration of the current contracts.

Gulf States is a small interstate pipeline that uses cost-based rates and terms and conditions of service for shippers wishing to secure capacity for interstate transportation service. Rates charged are largely governed by long-term negotiated rate agreements.

NGL SERVICES OPERATIONS

Lone Star owns and operates a NGLs storage, fractionation and transportation business. Lone Star’s storage assets are primarily located in Mont Belvieu, Texas. The West Texas Pipeline, which passes through the Barnett shale, and the Lone Star West Texas Gateway NGL Pipeline, which passes through the Eagle Ford shale, transports NGLs in interstate and intrastate commerce through pipeline systems that originate in the Permian and Delaware basins in west Texas, and terminates at Lone Star’s storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana and Texas, including the Lone Star Fractionator I and Fractionator II, located at Mont Belvieu, which began service in December 2012 and November 2013, respectively. Results of Lone Star’s operations are based upon fee-based revenues and commodity pricing which are determined primarily by volumes stored, processed or transported, the level of fees charged to customers and the value of the commodity in the market at the time of sale. The margin Lone Star earns is primarily related to the volume of NGLs stored, processed and transported.

In May 2013, SXL and Lone Star announced the Mariner South project which will integrate SXL’s existing Nederland Marine Terminal and pipeline from Mont Belvieu, Texas to Nederland, Texas with Lone Star’s Mont Belvieu fractionation and storage facilities, creating a LPG export/import operation in the U.S. Gulf Coast. Mariner South will have an initial capacity of 6 million barrels per month and will be designed to load LPG carriers with an approximate capacity of 550,000 barrels. The Mariner South project is expected to be operational in the first quarter of 2015. The project will utilize Lone Star’s increasing fractionation capacity at Mont Belvieu as well as construction of a new 100,000 barrel per day de-ethanizer to convert propane to international specifications. It also will involve the construction of new refrigerated storage tanks located at the Nederland Terminal to take deliveries into the LPG vessels. The Nederland Terminal will provide 24-hour ship access in the Gulf Coast with a load rate of up to 30,000 barrels per hour. The terminal facility includes existing docks and acreage for future expansion. Long-term, fee-based arrangements have been executed with Shell Trading Company US to move forward with this project, making Shell the anchor customer. The project can be expanded to handle additional volumes of products.

In November 2014, Lone Star announced that it will construct a 533 mile, 24- and 30-inch NGL pipeline from the Permian Basin to Mont Belvieu, Texas, and convert Lone Star’s existing West Texas 12-inch NGL pipeline into crude oil/condensate service. The new pipeline and conversion projects, estimated to cost aggregately between $1.5 billion and $1.8 billion, are expected to be operational by the third quarter of 2016 and the first quarter of 2017, respectively.

CONTRACT SERVICES OPERATIONS

Contract services operations can be divided into contract compression services and contract treating services. The natural gas contract compression services include designing, sourcing, owning, installing, operating, servicing, repairing and maintaining compressors and related equipment for which we guarantee our customers 98% mechanical availability for land installations and 96% mechanical availability for over-water installations. We focus on meeting the complex requirements of field-wide compression applications, as opposed to targeting the compression needs of individual wells within a field. These field-wide applications include compression for natural gas gathering and natural gas processing. We believe that we improve the stability of our cash flow by focusing on field-wide compression applications because such applications generally involve long-term installations of multiple large horsepower compression units. Our contract compression operations are located in Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, New Mexico, Colorado and California.

We own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. Our contract treating services are primarily located in Texas, Louisiana and Arkansas.

NATURAL RESOURCES OPERATIONS

Our Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2014, we owned or controlled approximately 821 million tons of proven and probable coal reserves in Central and Northern Appalachia, properties in eastern Kentucky, Tennessee, southwestern Virginia

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and southern West Virginia; and the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky. During 2004, our coal reserves located in the San Juan basin depleted and our associated coal royalty revenues ceased. The Natural Resources segment held a 50% interest in coal handling companies. In December 2014, we acquired the remaining membership interests in these companies through which we own and operate facilities for industrial customers on a fee basis.

Coal reserves are coal tons that can be economically extracted or produced at the time of determination considering legal, economic and technical limitations. All of the estimates of our coal reserves are classified as proven and probable reserves. Proven and probable coal reserves are defined as follows:

Proven Coal Reserves. Proven coal reserves are reserves for which: (i) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; (ii) grade and/or quality are computed from the results of detailed sampling; and (iii) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined, that the size, shape, depth and mineral content of reserves are well-established.

Probable Coal Reserves. Probable coal reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are more widely spaced or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven coal reserves, is high enough to assume continuity between points of observation.

In areas where geologic conditions indicate potential inconsistencies related to coal reserves, we perform additional exploration to ensure the continuity and mineability of the coal reserves. Consequently, sampling in those areas involves drill holes or channel samples that are spaced closer together than those distances cited above.

Coal reserve estimates are adjusted annually for production, unmineable areas, acquisitions and sales of coal in place. The majority of our coal reserves are high in energy content, low in sulfur and suitable for either the steam or to a lesser extent the metallurgical market.

The amount of coal that a lessee can profitably mine at any given time is subject to several factors and may be substantially different from “proven and probable coal reserves.” Included among the factors that influence profitability are the existing market price, coal quality and operating costs.

We enter into long-term leases with experienced, third-party mine operators, providing them the right to mine our coal reserves in exchange for royalty payments. We actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We do not operate any mines. In 2014, our lessees produced 15.9 million tons of coal (11.3 million tons from March 21, 2014 (the date of acquisition) to December 31, 2014) from our properties and paid us coal royalty revenues of $59.1 million ($44.1 million from March 21, 2014 (the date of acquisition) to December 31, 2014, for an average royalty per ton of $3.71 ($3.91 from March 21, 2014 (the date of acquisition) to December 31, 2014). Approximately 84% of our coal royalty revenues in 2014 were derived from coal mined on our properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of our coal royalty revenues for the respective periods was derived from coal mined on our properties under leases containing fixed royalty rates that escalate annually.

Our lessees mine coal using both underground and surface methods. As of December 31, 2014, our lessees operated 24 surface mines and 24 underground mines. Approximately 57% of the coal produced from our properties in 2014 came from underground mines and 43% came from surface mines. Most of our lessees use the continuous mining method in their underground mines located on our properties. In continuous mining, main airways and transportation entries are developed and remote-controlled continuous miners extract coal from “entries” leaving “pillars” to support the roof. Shuttle cars transport coal to a conveyor belt for transportation to the surface. In several underground mines, our lessees use two continuous miners running at the same time, also known as a supersection, to improve productivity and reduce unit costs.

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The following tables set forth production data for the periods presented and reserve information with respect to each of our properties for the period presented (tons in millions):



	Production for the Years Ended December 31,
Property	2014	2013
Central Appalachia	9.0	10.2
Northern Appalachia	2.7	3.3
Illinois Basin	2.4	2.4
San Juan Basin ⁽¹⁾	1.8	9.2
Total	15.9	25.1

⁽¹⁾Our San Juan reserves were fully depleted in the first quarter of 2014.

The following table sets forth the coal reserves we owned and leased with respect to each of our coal properties as of December 31, 2014 (tons in millions):



Property	Owned	Leased	Total Controlled
Central Appalachia	482.3	141	623.3
Northern Appalachia	16.6	—	16.6
Illinois Basin	150.5	30.7	181.2
Total	649.4	171.7	821.1

The following table sets forth our coal reserve activity for the periods presented and ended (tons in millions):



	2014		2013
Reserves - beginning of year	847.0		871.0
Purchase of coal reserves	—		2.3
Tons mined by lessees	(15.9	)	(25.1	)
Revisions of estimates and other	(10.0	)	(1.2	)
Reserves - end of year	821.1		847.0

Our coal reserve estimates are prepared from geological data assembled and analyzed by our internal geologists and engineers. These estimates are compiled using geological data taken from thousands of drill holes, geophysical logs, adjacent mine workings, outcrop prospect openings and other sources. These estimates also take into account legal, qualitative, technical and economic limitations that may keep coal from being mined. Coal reserve estimates will change from time to time due to mining activities, analysis of new engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods and other factors.

CORPORATE OPERATIONS

Our Corporate segment comprises our corporate offices and management services provided to affiliates.

OUR CONTRACTS

The table below provides margin share by product in percentages for the years ended December 31, 2014 and 2013 for all of our operating segments including our proportional shares in our unconsolidated affiliates:



Margin by Product	2014		2013
Net Fee	75	%	77	%
NGLs	5		8
Gas	10		8
Condensate	10		7
Total	100	%	100	%

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Gathering and Processing Contracts. We contract with producers to gather raw natural gas, NGLs, and oil (crude, and/or condensate, a lighter oil) from individual wells or central receipt points located near our gathering systems and processing plants. Following the execution of a contract with the producer, we connect the producer’s wells or central receipt points to our gathering lines through which the natural gas, NGLs, and oil (crude, and/or condensate, a lighter oil) is delivered to a processing plant owned and operated by us or a third party. We obtain supplies of raw natural gas, NGLs, and oil (crude, and/or condensate, a lighter oil) for our gathering and processing facilities under contracts having terms ranging from month-to-month to life of the lease. We categorize our processing contracts in increasing order of commodity price risk as fee-based, percentage-of-proceeds or keep-whole contracts. The following is a summary of our most common contractual arrangements:

•

Fee-Based Arrangements. Under these arrangements, we are generally paid a fixed cash fee for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. A sustained decline in commodity prices, however, could result in a decline in volumes and, thus, a decrease in our fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments.

•

Percent-of-Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at the wellhead or central receipt points, transport it through our gathering system, process it and sell the processed gas and NGLs at prices based on published index prices. In this type of arrangement, we retain the sales proceeds less amounts remitted to producers and the retained sales proceeds constitute our margin. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under these arrangements, our margins typically cannot be negative. The price paid to producers is based on an agreed percentage of one of the following: (1) the actual sale proceeds; (2) the proceeds based on an index price; or (3) the proceeds from the sale of processed gas or NGLs or both. Under this type of arrangement, our margin correlates directly with the prices of natural gas and NGLs (although there is often a fee-based component to these contracts in addition to the commodity sensitive component).

•

Keep-Whole Arrangements. Under these arrangements, we process raw natural gas to extract NGLs and pay to the producer the full thermal equivalent volume of raw natural gas received from the producer in processed gas or its cash equivalent. We are generally entitled to retain the processed NGLs and to sell them for our account. Accordingly, our margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent value of those NGLs. The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs, but also to the price of natural gas relative to NGL prices. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of our keep-whole contracts include provisions that reduce our commodity price exposure, including (1) embedded discounts to the applicable natural gas index price under which we may reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer; (2) fixed cash fees for ancillary services, such as gathering, treating, and compression; or (3) the ability to bypass processing in unfavorable price environments.

We also contract with producers to gather the oil produced with the natural gas. Some of these contracts are subject to the market based tariff rates and terms of service we establish for the oil pipeline system(s). These arrangements typically include a fee per barrel of oil gathered. Additionally, we perform a producer service function. We purchase natural gas from producers or gas marketers at receipt points or plant tailgates, including points on HPC’s RIGS, and we sell the natural gas to other market participants, often after transporting the gas to delivery points on HPC’s RIGS or other transportation pipeline systems.

Our natural gas sales contracts (physical) are consummated under North American Energy Standards Board or Gas Industry Standards Board contracts with pricing predominately based on Platt’s Gas Daily or inside FERC pricing points. We sell our NGL output to third parties at pricing based on OPIS pricing at Mont Belvieu, Texas or Conway, Kansas delivery points. We have multi-year, firm agreements with third parties for NGL fractionation.

Natural Gas Transportation Contracts. HPC and MEP, through their respective pipeline systems, provide natural gas transportation services pursuant to contracts with natural gas shippers. These contracts are primarily fee-based. HPC’s long-term firm transportation contracts will expire between 2015 and 2022; and MEP’s long-term firm service agreements will expire between 2015 and 2021.

NGL Services Contracts. Lone Star owns and operates 2,025 miles of NGL pipelines, two cryogenic refinery off-gas processing plants, two fractionation facilities with a capacity of 200,000 Bbls/d, and two NGL storage facilities with aggregate working storage capacity of 47 million Bbls. Lone Star also has a non-operating interest in an additional cryogenic processing plant. Revenue is principally generated from fees charged to customers under dedicated contracts, take-or-pay contracts and commodity pricing. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to

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the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Transportation fees are based on tariff rates, which are competitive with regional regulated pipelines.

Compression Contracts. We generally enter into a new contract with respect to each distinct application for which we will provide contract compression services. Our compression contracts typically have an initial term between one and five years, after which the contract continues on a month-to-month basis until renewal or cancellation. Our customers generally pay a fixed monthly fee, or, in rare cases, a fee based on the volume of natural gas actually compressed. We are not responsible for acts of force majeure and our customers are generally required to pay our monthly fee for fixed fee contracts, or a minimum fee for throughput contracts, even during periods of limited or disrupted production. We are generally responsible for the costs and expenses associated with operation and maintenance of our compression equipment, such as providing necessary lubricants, although certain fees and expenses are the responsibility of the customers under the terms of their contracts. For example, all fuel gas is provided by our customers without cost to us, and in many cases customers are required to provide all water and electricity. We also are reimbursed by our customers for certain ancillary expenses such as trucking, crane and installation labor costs, depending on the terms agreed to in a particular contract.

Natural Resources Contracts. We earn most of our coal royalty revenues under long-term leases that generally require our lessees to make royalty payments to us based on the higher of a percentage of the gross sales price or a fixed price per ton of coal they sell. The balance of our coal royalty revenues is earned under long-term leases that require the lessees to make royalty payments to us based on fixed royalty rates that escalate annually. A typical lease either expires upon exhaustion of the leased reserves or has a five to ten-year base term, with the lessee having an option to extend the lease for at least five years after the expiration of the base term. Substantially all of our leases require the lessee to pay minimum rental payments to us in monthly or annual installments, even if no mining activities are ongoing. These minimum rentals are recoupable, usually over a period from one to three years from the time of payment, against the production royalties owed to us once coal production commences.

Substantially all of our leases impose obligations on the lessees to diligently mine the leased coal using modern mining techniques, indemnify us for any damages we incur in connection with the lessee’s mining operations, including any damages we may incur due to the lessee’s failure to fulfill reclamation or other environmental obligations, conduct mining operations in compliance with all applicable laws, obtain our written consent prior to assigning the lease and maintain commercially reasonable amounts of general liability and other insurance. Substantially all of the leases grant us the right to review all lessee mining plans and maps, enter the leased premises to examine mine workings and conduct audits of lessees’ compliance with lease terms. In the event of a default by a lessee, substantially all of the leases give us the right to terminate the lease and take possession of the leased premises.

In addition, we earn revenues under coal services contracts, timber contracts and oil and gas leases. Our coal services contracts generally provide that the users of our coal services pay us a fixed fee per ton of coal processed at our facilities. All of our coal services contracts are with lessees of our coal reserves and these contracts generally have terms that run concurrently with the related coal lease. Our timber contracts generally provide that the timber companies pay us a fixed price per thousand board feet of timber harvested from our property. We receive royalties under our oil and gas leases based on a percentage of the revenues the producers receive for the oil and gas they sell. We also earn revenues by providing coal handling services to industrial and utility customers.

COMPETITION

Gathering and Processing. We face strong competition in each region in acquiring new gas supplies. Our competitors in acquiring new gas supplies and in processing new natural gas supplies include major integrated oil companies, major interstate and intrastate pipelines and other natural gas gatherers that gather, process and market natural gas. Competition for natural gas supplies is primarily based on the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer.

Many of our competitors have capital resources and control supplies of natural gas substantially greater than ours. Our major competitors for gathering and related services in each region include:


•	Arklatex: Enable Midstream, DCP Midstream’s PELICO Pipeline, LLC (Pelico), ETP, KMP and Access Midstream Partners, L.P.;


•	South Texas: EPD, DCP Midstream Partners, LP, KMP and ETP;


•	Permian Region: EPD, DCP Midstream Partners LP and Targa Resources Partners LP.;


•	Mid-Continent: DCP Midstream Partners, LP and ONEOK Partners, L.P; and


•	Eastern: Williams Partners LP and MarkWest Energy Partners, L.P.

Natural Gas Transportation. Competitors in natural gas transportation differentiate themselves by the price of transportation, the nature of the markets accessible from a transportation pipeline and the type of service provided. HPC’s major competitors in the

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natural gas transportation business are DCP Midstream Partners, L.P., Enable Gas Transmission, Gulf South Pipeline, L.P., Texas Gas Transmission, LLC, ETP and EPD.

Capacity on the MEP pipeline system is almost fully contracted under long-term firm service agreements, Zone 1 is 95% contracted and Zone 2 is fully contracted. The majority of volume is contracted to producers moving supply from the Barnett shale and Oklahoma supply basins. These agreements provide the pipeline with fixed monthly reservation revenues for the primary term of such contracts. Although there are other pipeline competitors providing transportation from these supply basins, the MEP pipeline system was designed and constructed to realize economies of scale and offers its shippers competitive fuel rates and variable costs to transport gas supplies from these mid-continent supply areas to pipelines serving Eastern markets. MEP’s competitors include Gulf Crossing Pipeline, Enable Gas Transmission and Natural Gas Pipeline Co. of America.

NGL Services. In markets served by its NGL pipelines, Lone Star competes with other pipeline companies and barge, rail and truck fleet operations. Lone Star also faces competition with other fractionation and storage facilities based on fees charged and the ability to receive and distribute the customer’s products. Lone Star’s main competitors include EPD, DCP Midstream Partners, LP and ONEOK Partners, L.P.

Contract Services. Our contract services operation includes contract compression and contract treating. We believe that the superior mechanical availability of our standardized compressor fleet is the primary basis on which we compete and a significant distinguishing factor from our competition. All of our competitors attempt to compete on the basis of price. We believe our pricing is competitive because of the superior mechanical availability we deliver, the quality of our compression units, as well as the technical expertise we provide to our customers. We believe our focus on addressing customers’ more complex natural gas compression needs related primarily to field-wide compression applications differentiates us from many of our competitors who target smaller horsepower projects related to individual wellhead applications. The natural gas contract compression services business is highly competitive. We face competition from large national and multinational companies and, on a regional basis, from numerous smaller companies. Our main competitors in the natural gas contract compression business, based on horsepower, are Exterran Holdings, Inc., Compressor Systems, Inc., USA Compression, Valerus Compression Services LP, and J-W Energy Company.

Natural Resources. The coal industry is intensely competitive primarily as a result of the existence of numerous producers. Our lessees compete with both large and small coal producers in various regions of the United States for domestic and international sales. The industry has undergone significant consolidation which has led to some of the competitors of our lessees having significantly larger financial and operating resources than most of our lessees. Our lessees compete on the basis of coal price at the mine, coal quality (including sulfur content), transportation cost from the mine to the customer and the reliability of supply. Continued domestic demand for our coal and the prices that our lessees obtain are also affected by demand for electricity, demand for metallurgical coal, access to transportation, environmental and government regulations, technological developments and the availability and price of alternative fuel supplies, including nuclear, natural gas, oil and hydroelectric power. Demand for our low sulfur coal and the prices our lessees will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances which permit the high sulfur coal to meet federal Clean Air Act, or CAA, requirements. Continued demand for United States coal exports are also influenced by a number of factors including global economic conditions, weather patterns and political instability.

RISK MANAGEMENT

To manage commodity price and interest rate risks, we have implemented a risk management program under which we seek to:


•	match sales prices of commodities (especially NGLs) with purchases under our contracts;


•	manage our portfolio of contracts to reduce commodity price risk;


•	optimize our portfolio by active monitoring of basis, swing, and fractionation spread exposure; and


•	hedge a portion of our exposure to commodity prices.

As a result of our gathering and processing contract portfolio, we derive a portion of our earnings from a long position in NGLs, natural gas and condensate, resulting from the purchase of natural gas for our account or from the payment of processing charges in kind. This long position is exposed to commodity price fluctuations in the condensate, NGLs and natural gas markets. Operationally, we mitigate this price risk by generally purchasing natural gas and NGLs at prices derived from published indices, rather than at a contractually fixed price and by selling natural gas and NGLs under similar pricing mechanisms. In addition, we optimize the operations of our processing facilities on a daily basis, for example by rejecting ethane in processing when recovery of ethane as an NGL is uneconomical. We hedge this commodity price risk by entering into a series of swap contracts or put option contracts for individual NGLs, natural gas and WTI. Our hedging positions are maintained within limits established by the Audit and Risk Committee of the Board of Directors. Read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for information regarding the status of these contracts.

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As part of our natural gas marketing and trading activities, we enter into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales.

Neither our contract compression business nor our contract treating business has direct exposure to natural gas commodity price risk because we do not take title to the natural gas we compress or treat and because the natural gas we use as fuel for our compressors is supplied by our customers or treating units without cost to us.

REGULATION

Industry Regulation

Intrastate Natural Gas Pipeline Regulation. The Partnership owns intrastate pipelines that are subject to state regulation. In Louisiana, HPC owns RIGS, an intrastate pipeline regulated by the Louisiana Department of Natural Resources, Office of Conservation (DNR). The DNR is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. In Texas, the Partnership owns Regency DeSoto Pipeline LLC (“DeSoto Pipeline”) and other gas utilities. Gas utilities are subject to regulation by the Railroad Commission of Texas (RCT). The RCT has jurisdiction over the rates and terms of service provided by utilities, which must be provided on a non-discriminatory basis to similarly-situated shippers, although most operate under contracts with negotiated rates and terms of service. DeSoto delivers gas to end-use markets, such as commercial and industrial customers and local distribution companies.

RIGS and DeSoto Pipeline transport interstate natural gas for many of their shippers pursuant to Section 311 of the NGPA. To the extent that RIGS and DeSoto Pipeline transport natural gas in interstate service, their rates and terms and conditions of service are subject to the jurisdiction of FERC, including its non-discrimination requirements. FERC has substantial enforcement authority to impose administrative, civil and criminal penalties of up to $1 million per day per violation and to order the disgorgement of unjust profits for non-compliance.

Under Section 311 of the NGPA, rates charged for transportation services must be fair and equitable. FERC approved RIGS’ NGPA Section 311 rates as fair and equitable effective February 1, 2010, under a settlement. As part of the settlement and consistent with FERC policy, RIGS is required to justify its current rates or propose new rates every five years. Accordingly, RIGS made a rate filing on January 30, 2015, justifying the continuation of its current maximum rates. RIGS’ rates are in effect, but subject to refund with interest until FERC has determined that the rates are fair and equitable. FERC approved DeSoto Pipeline’s NGPA Section 311 rates as fair and equitable on May 1, 2012. Consistent with FERC policy, DeSoto Pipeline is required to justify its current rates or propose new rates every five years, or by May 17, 2017.

FERC continually proposes and implements new rules and regulations affecting Section 311 transportation. For example, on October 21, 2010, the FERC issued a Notice of Inquiry regarding the applicability of the FERC’s buy-sell rules to intrastate pipelines that provide Section 311 transportation service, including whether the FERC should impose capacity release requirements on such pipelines that offer firm transportation service. We cannot predict the outcome of this notice of inquiry or other regulatory changes that may be proposed or enacted, but any changes could lead to greater regulatory requirements on intrastate pipelines that provide Section 311 services, including RIGS.

Interstate Natural Gas Pipeline Regulation. FERC also has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the NGA, rates charged for interstate natural gas transmission must be just and reasonable. Gulf States and MEP hold FERC-approved tariffs setting forth cost-based rates and terms and conditions of service for shippers wishing to secure capacity for interstate transportation service. Rates charged on MEP are largely governed by long-term negotiated rate agreements, an arrangement approved by FERC in its July 25, 2008 order granting MEP the certificate of public convenience and necessity to build, own and operate these facilities. MEP and Gulf States are NGA-jurisdictional interstate pipelines subject to FERC’s broad regulatory oversight. FERC’s authority extends to:


•	rates and charges for natural gas transportation and related services;


•	certification and construction of new facilities;


•	construction, extension or abandonment of services and facilities;


•	maintenance of accounts and records;


•	relationships between the pipeline and its energy affiliates;


•	terms and conditions of service;


•	depreciation, depletion and amortization policies;

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•	accounting rules for ratemaking purposes;


•	acquisition and disposition of facilities;


•	initiation and discontinuation of service;


•	prevention of market manipulation in connection with interstate sales, purchase or transportation of natural gas; and


•	information posting requirements.

We also own interstate natural gas pipelines that extend from our processing plants to third party interstate natural gas pipelines. We have sought certificates of public convenience and necessity with waiver of FERC’s reporting and tariff requirements for certain of these pipelines.

FERC regularly conducts audits of interstate pipelines and has multiple means to receive complaints of alleged violations of its rules, including anonymous complaints through a toll-free hotline. Any failure to comply with the laws and regulations for interstate natural gas pipelines could result in the imposition of significant administrative, civil and criminal penalties. FERC has authority to impose civil penalties of up to $1 million per day per violation.

Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from FERC jurisdiction under the NGA. We own a number of natural gas pipelines that we believe meet the traditional tests that FERC has used to establish a pipeline’s status as a gatherer not subject to FERC’s interstate pipeline jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is the subject of substantial, on-going litigation none of which we are currently party to. As a result, the classification and regulation of one or more of our gathering systems may be subject to change based on future determinations by FERC, the courts or the U.S. Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and, in other instances, complaint-based rate regulation. We are subject to state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers that purchase gas to purchase 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. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.

In addition, many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules, ordinances and legislation pertaining to these matters may be considered or adopted from time to time at either the federal, state or local level. We cannot predict what effect, if any, such changes might have on our operations, but we and our competitors could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Regulation of NGL and Oil Transportation. We have and may construct pipelines that transport NGLs or oil in interstate commerce pursuant to a FERC-approved tariff. Additionally, Lone Star has pipelines that transport NGLs in interstate commerce pursuant to a FERC-approved tariff. Under the ICA, the Energy Policy Act of 1992, and rules and orders promulgated thereunder, the transportation tariff is required to be just and reasonable and not unduly discriminatory or confer any undue preference. FERC has established an indexing system of transportation rates for oil, NGLs and other products that allows for an annual inflation based increase in the cost of transporting these liquids to shipper. Any failure on our part to comply with the laws and regulations governing interstate transmission of NGLs or oil could result in the imposition of administrative, civil and criminal penalties and could have a material adverse effect on our results of operations.

Lone Star also has pipelines that transport NGLs in intrastate commerce pursuant to state common carrier regulation. We also have and are constructing pipelines that are subject to state common carrier regulation for the transportation of NGLs, crude oil or condensate. Under state common carrier regulation, pipelines must charge rates that are non-discriminatory and operate pursuant to a tariff.

Sales of Natural Gas and NGLs. Our ability to sell gas in interstate markets is subject to FERC authority and oversight. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which we sell NGLs and oil/condensate is not subject to state or federal regulation. However, with regard to our physical purchases and sales of these energy commodities, our gathering or transportation of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC.

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The prices at which we sell natural gas are affected by many competitive factors, including the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. Additionally, FERC imposed rules requiring wholesale purchasers and sellers of natural gas to report certain aggregated annual volume and other information beginning in 2009. On November 15, 2012, FERC issued a Notice of Inquiry seeking comments on whether reporting should be expanded to include more frequent and detailed information about certain interstate natural gas sales transactions. We cannot predict the outcome of this Notice of Inquiry or other regulatory changes that may be proposed or enacted.

We also have firm and interruptible transportation contracts with interstate pipelines that are subject to FERC regulation. As a shipper on an interstate pipeline, we are subject to FERC requirements related to use of interstate capacity. Any failure on our part to comply with the FERC’s regulations or an interstate pipeline’s tariff could result in the imposition of administrative, civil and criminal penalties and the disgorgement of unjust profits.

Sales of crude oil, natural gas, condensate and NGLs are not currently regulated. Prices of these products are set by the market rather than by regulation.

Anti-Market Manipulation Requirements. Under the Energy Policy Act of 2005, FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of non-interstate pipelines and other natural gas market participants. The CFTC also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to our physical purchases and sales of natural gas, NGLs and crude oil, our gathering (of natural gas) or transportation of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation in connection with the sale, purchase or transportation of natural gas, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, or among others, sellers, royalty owners and taxing authorities.

Anti-Terrorism Regulations. We may be subject to future anti-terrorism requirements of the DHS. The DHS has issued its National Infrastructure Protection Plan calling for broadened efforts to “reduce vulnerability, deter threats, and minimize the consequences of attacks and other incidents” as they relate to pipelines, processing facilities and other infrastructure. The precise parameters of DHS regulations and any related sector-specific requirements are not currently known, and there can be no guarantee that any final anti-terrorism rules that might be applicable to our facilities will not impose costs and administrative burdens on our operations.

Eminent Domain. Gas utilities, common carrier pipelines, intrastate pipelines and interstate pipelines typically have eminent domain authority granted by the state or federal government. These eminent domain rights are often subject to public scrutiny, lawsuits and regulatory and/or legislative review. In 2011, the Texas Supreme Court issued a decision impacting the ability of common carriers to acquire land through the use of eminent domain. Certain components of the decision were clarified in 2012; however, as a result of the decision common carrier pipelines could be required to prove “public use” separately in each condemnation proceeding along the entire route of a pipeline. The decision could impact our ability to acquire right-of-way using condemnation for the construction of new common carrier pipeline projects in the state of Texas. Any new court decisions or changes to eminent domain laws or regulations could alter our ability to acquire pipeline right-of-way utilizing eminent domain.

Local Laws and Regulations. With the rapid expansion of natural gas development in shale plays, local governmental authorities are seeking to impose additional regulatory requirements on natural gas market participants, including producers, gatherers, and pipeline companies, which may result in additional cost burdens and permitting requirements for new and existing facilities.

Environmental Matters

General. Our operations and the operations of our lessees are subject to stringent and complex federal, state and local laws and regulations governing, among other things air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, the cleanup of contamination, permitting and licensing, and employee health and safety. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us or our lessees to incur substantial costs, penalties, fines, criminal sanctions, third party claims for personal injury or property damage, incur expenses to upgrade facilities and programs, or curtail operations. Compliance with existing and anticipated environmental laws and regulations increases our and our lessees’ overall cost of doing business.

In addition, the electric utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which could adversely affect demand. for coal mined by our lessees. However, we do not believe that continued compliance will have a material adverse effect on our business, results of operations and financial condition. We cannot be certain, however, that identification of presently unidentified conditions, more rigorous enforcement by regulatory agencies, enactment of more stringent laws and regulations or other unanticipated events will not arise

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in the future and give rise to material environmental liabilities that could have a material adverse effect on our business, results of operations, and financial condition.

Hazardous Substances and Waste Materials. We are subject to the requirements of environmental laws and regulations related to the release of hazardous substances and waste materials into soils, groundwater and surface water, and that include measures to prevent, minimize or remediate contamination of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed. For example, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state laws, impose joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and persons that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. These persons may be liable for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and comparable laws also authorize the EPA, its state counterparts, and, in some instances, third parties to take actions 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 hazardous substances or other pollutants released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes or other materials that may fall within that definition or that may be subject to other waste disposal laws and regulations.

We also generate both hazardous and nonhazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state laws. From time to time, the EPA has considered the adoption of stricter handling, storage and disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. It is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. Changes in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense. Furthermore, some products used by coal companies in operations generate waste containing hazardous substances. We could be pursued under CERCLA and analogous state laws if our lessees are unable to pay for environmental cleanup costs or other responses to threats to the public. In addition, RCRA and analogous state laws and regulations exclude many mining wastes from the regulatory definition of hazardous wastes. The management and disposal of coal combustion byproducts, or coal combustion residues (“CCR”), are not regulated as hazardous or special wastes, but the EPA did recently finalize regulations that impose technical requirements for landfills and surface impoundments that accept CCR.

Air Emissions. Our operations and the operations of our lessees are subject to the Clean Air Act (“CAA”) and comparable state laws and regulations. These laws and regulations govern emissions of air pollutants from, and impose monitoring and reporting requirements on, various industrial sources. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain facilities expected to produce air emissions or to result in the increase of existing air emissions, that we obtain and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to limit emissions. Such laws and regulations also may require our lessees to obtain permits and install emissions control equipment.

The EPA and state agencies are continually proposing new rules and regulations that could impact our existing operations, the operations of our lessees, and the costs and timing of new infrastructure development.

For example, on August 16, 2012 the EPA published final rules that extend New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPs”) to certain exploration and production operations. The rule package includes revised NSPS performance standards to address volatile organic compounds (“VOCs”) and sulfur dioxide emissions at natural gas processing plants, emissions requirements for compressors, pneumatic controllers, dehydrators, storage tanks and other production equipment, revised and more stringent leak detection requirements for natural gas processing plants, and NESHAPs for certain exiting stationary spark ignition reciprocating internal combustion engines. These rules will require a number of modifications to our operations, including the installation of new equipment. We are still evaluating the effect of these rules on our operations, but we expect that they could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.

In addition, some of our operations are located in areas that do not meet the national ambient air quality standards (“NAAQS”) established by the EPA relating to ozone. The EPA has recently proposed revisions to the ozone NAAQS that could make those air quality standards even more stringent. The final rule revising the ozone NAAQS is currently scheduled to be issued in October

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2015, with designations of areas failing to meet the standard scheduled to be made in October 2017. It is possible that a further tightening of the ozone NAAQS could increase pressure on some states in which we operate to seek further reductions from emissions sources that may contribute to ozone formation. Any such action may require us to install additional pollution controls.

The CAA also indirectly impacts our lessees’ coal mining and processing operations by extensively regulating the air emissions of coal-fired electric power generating plants and other end users of coal. There have been a series of recent rulemakings that are focused on emissions from coal-fired electric generating facilities, which will make it more costly to build and operate coal-fired power plants and, depending on the requirements of state implementation plans, are likely to make coal a less attractive fuel alternative in the planning and building of power plants in the future. The air emissions programs that may affect our lessees’ operations directly or indirectly include, but are not limited to: the Cross-State Air Pollution Rule (“CSAPR”), which requires certain Midwestern and Eastern states to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states; the Mercury and Air Toxics Standards (“MATS”) Rule, which requires coal and oil-fired power plants to reduce air toxics emissions; NAAQS, which impose air quality standards for carbon monoxide, nitrogen dioxide, ozone, particulate matter, sulfur dioxide, and lead; and the Acid Rain Program, which regulates emissions of sulfur dioxide and nitrogen oxides from electric generating facilities. Any reduction in coal’s share of power generating capacity could negatively impact our lessees’ ability to sell coal, which could have a material effect on our coal royalty revenues.

Hydraulic Fracturing. Certain of our customers’ natural gas is developed from formations requiring hydraulic fracturing as part of the completion process. Fracturing is a process where water, sand and chemicals are injected under pressure into subsurface formations to stimulate production. While the underground injection of fluids is regulated by the EPA under the Safe Drinking Water Act (“SDWA”), fracturing is excluded from regulation unless the injection fluid is diesel fuel. Furthermore, hydraulic fracturing is primarily regulated by state environmental or similar agencies. Congress has recently considered legislation that would repeal the exclusion under the SDWA, allowing the EPA to more generally regulate fracturing, although the EPA is using its current regulatory authority to do so. For example, the EPA announced its intention to propose regulations under the Clean Water Act to regulate wastewater discharged from hydraulic fracturing and other natural gas production; published an Advanced Notice of Proposed Rulemaking that seeks public comment on plants to initiate a rulemaking under the Toxic Substances Control Act to obtain data regarding the composition of hydraulic fracturing fluids; and implemented regulations that require new or reworked hydraulically fractured wells to use reduced emission (or “green”) completions to reduce emissions of volatile organic compounds. The U.S. Department of the Interior has also published a proposed rule that would updated existing regulation of hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. Compliance with these rules could result in additional costs, including increased capital expenditures and operating costs for our customers. This could reduce production of natural gas and, in turn, adversely affect our revenues and results of operations by decreasing the volumes of natural gas and NGLs that we gather, process and transport.

Climate Change. In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the Earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. Accordingly, the EPA adopted regulations limiting emissions of greenhouse gases from motor vehicles , which then triggered CAA construction and operating permit requirements under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs for certain large stationary sources of greenhouse gasses. Facilities that are required to obtain permits for their greenhouse gas emissions will be required to reduce those emissions according to “best available control technology” standards for greenhouse gases, which are currently being developed on a case-by-case basis. The EPA has also proposed New Source Performance Standards (“NSPS”) for carbon dioxide emissions from existing power plants, and is in the process of finalizing a proposal for new power plants.

In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the United States on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. On November 30, 2010, the EPA revised its greenhouse gas reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. Under the new rules, reporting of greenhouse gas emissions from such facilities, including many of our facilities, is required on an annual basis. In December 2014, the EPA proposed additional amendments to its greenhouse gas reporting rule, which would add reporting requirements for additional facilities, including gathering and boosting systems.

Various pieces of legislation to reduce emissions of, or to create cap and trade programs for, greenhouse gases have been proposed by the U.S. Congress over the past several years, but no proposal has yet passed. More than one-third of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The United States is actively participating in international discussions that are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration. Any new international, federal or state laws or regulations that reduce emissions of greenhouse gases or impose other requirements on

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our operations, the operations of our lessees, and/or the operations of our customers, could have a material adverse impact on our financial results.

One consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations and the operations of our lessees could be adversely affected in various ways, including damage to facilities or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our NGLs and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Clean Water Act. The Clean Water Act (“CWA”) and comparable state laws restrict the discharge of pollutants and other materials into regulated waters. Pursuant to these laws, federal and/or state permits must be obtained to discharge pollutants and other materials into regulated waters, including wetlands. Permits may also be required for the discharge of stormwater runoff. Continued compliance with such existing permit conditions are not expected to have a material adverse effect on our business, financial condition or results of operations. However, in March 2014, the EPA and the U.S. Army Corps of Engineers released a proposed rule to update the definition of waters subject to the CWA. An expansion of this definition to include previously unregulated waters could have a material adverse impact on our operations if it requires us to obtain additional permits or otherwise limits construction activities.

Our coal lessees’ operations are also regulated under the CWA with respect to discharges of pollutants and other materials into regulated waters. The EPA issues permits for the discharge of pollutants into navigable waters while the Army Corps of Engineers issues dredge and fill permits. The CWA authorizes the EPA to review and veto permits issued by the Army Corps. The EPA has exercised its veto power to retroactively rescind a permit issued by the Army Corps of Engineers, which has been upheld by the courts. Any future use of this authority could create uncertainty with regard to our lessees’ continued use of their current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our coal royalty revenues.

Safe Drinking Water Act. The SDWA and its state equivalents affect coal mining operations by imposing requirements on the underground injection of fine coal slurries, fly ash and flue gas scrubber sludge, and by requiring permits to conduct such underground injection activities. In addition to establishing the underground injection control program, the SDWA also imposes regulatory requirements on owners and operators of “public water systems.” This regulatory program could impact our lessees’ reclamation operations where subsidence or other mining-related problems require the provision of drinking water to affected adjacent homeowners.

Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitat. We and our lessees may operate in areas that are currently designated as a habitat for endangered or threatened species, the discovery of previously unidentified endangered species, or the designation of additional species as endangered or threatened, which could cause us to incur additional costs, to develop habitat conservation plans, to become subject to expansion or operating restrictions, or bans in the affected areas.

In March 2014, the U.S. Fish & Wildlife Service listed the lesser prairie chicken as a “threatened” species under the federal Endangered Species Act. This species is predominantly located in the Permian and Midcontinent regions; therefore, we may encounter additional costs and delays in infrastructure development. We are participating, along with other companies in our industry, in a conservation plan for this species, which will allow us to participate in managing conservation efforts.

Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act (“SMCRA”) and similar state laws establish minimum operational, reclamation and closure standards for surface mining and deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following the completion of mining activities. These requirements typically are implemented through mining permits issued at the state level. SMCRA also imposes on mine operators the responsibility of restoring the land to its original state and compensating the landowner for types of damages occurring as a result of mining operations, and requires mine operators to post performance bonds to ensure compliance with any reclamation obligations. Moreover, regulatory authorities may attempt to assign the liabilities of our coal lessees to another entity, such as us, if any of our lessees are not financially capable of fulfilling those obligations on the theory that we “owned” or “controlled” the mine operator. To our knowledge, no such claims have been asserted against us to date. In conjunction with mining the property, our coal lessees are contractually obligated under the terms of their leases to comply with all federal, state and local laws, including SMCRA, with obligations including the reclamation and restoration of the mined areas by grading, shaping and reseeding the soil. Additionally, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all

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current mining operations, the proceeds of which are used to restore mines closed before 1977. The current tax is 28 cents per ton on surface-mined coal and 12 cents per ton on underground-mined coal. States from time to time have increased and may continue to increase their fees and taxes to fund reclamation of orphaned mine sites and abandoned mine drainage control on a statewide basis.

Federal and state laws require bonds to secure our lessees’ obligations to reclaim lands used for mining and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for mining companies to secure new surety bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable. It is possible that surety-bond issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Any failure to maintain, or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on our lessees’ ability to produce coal, which could affect our coal royalties revenues.

Under some circumstances, substantial fines and penalties, including revocation of mining permits and criminal sanctions, may be imposed under the laws described above. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations which have outstanding environmental violations. Although our lessees from time-to-time have been cited for violations in the ordinary course of business, to our knowledge, none of them have had one of their permits suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

To dispose of mining overburden generated from surface mining activities, our lessees often need to obtain government approvals, including CWA Section 404 permits to construct valley fills, stream impoundments, and sediment control ponds. Recently, these Section 404 permits and the Section 404 permitting standard have been the target of increased scrutiny by environmental groups, legislators, the White House, and the EPA which has made it more difficult for miners to obtain, and in some cases maintain, Section 404 permits. In one case, the EPA retroactively rescinded a permit that had been issued. The U.S. Office of Surface Mining and Reclamation (‘OSMRE”) is in the process of evaluating its options to address the impacts of mining on streams, with a view towards releasing a proposed rule. If the OSMRE promulgates a more restrictive rule, any such additional requirements could impact coal mining operations, particularly in Appalachia, including, for example, by reducing locations where coal mining operations can be conducted or by further restricting common spoil disposal practices. Regulations which dramatically increase the costs of compliance or prohibit our lessees from obtaining new permits could reduce coal production and cash flows, and could ultimately have an adverse effect on our royalty revenues.

Employee Health and Safety. Our operations and the operations of our lessees are subject to the requirements of the Occupational Saftey and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of workers. OSHA also requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Furthermore, in 2013, the Occupational Safety and Health Administration published a request for information, seeking public comment on potential changes to its Process Safety Management (“PSM”) Standard and related enforcement policies. The PSM Standard imposes requirements on certain employers in connection with the management of hazards associated with the use of hazardous chemicals.

Mine Health and Safety Laws. The operations of our coal lessees are also subject to stringent health and safety standards that have been imposed by federal legislation since the adoption of the Mine Health and Safety Act, which imposes comprehensive health and safety standards on all mining operations. In addition to federal regulatory programs. The states in which we operate also have programs for mine safety and health regulation and enforcement. As part of the Mine Health and Safety Act, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung or pneumoconiosis and to some beneficiaries of miners who have died from this disease.

In addition, in 2006, the Mine Improvement and New Emergency Response Act (“Miner Act”) was enacted which imposed obligations related to improvements in mine safety practices, increased civil and criminal penalties for non-compliance, created additional mine rescue teams and expanded the scope of federal oversight, inspection and enforcement activities. Pursuant to the Miner Act, the Mine Safety Health Administration (“MSHA”) has promulgated new emergency rules on mine safety and revised its civil penalty assessment regulations, which resulted in an across-the-board increase in penalties from the existing regulations. Since passage of the Miner Act, enforcement scrutiny has also increased, including more inspection hours at mine sites, increased numbers of inspections and increased issuance of the number and the severity of enforcement actions and related penalties. Various states also have enacted their own new laws and regulations addressing many of these same subjects. The Dodd Frank Bill that was enacted by Congress in 2010 now requires mining companies, including coal companies, to include various safety statistics regarding citations, penalties, notices of violation and pending legal actions in periodic reports that are required by the securities laws. These disclosures may lead to the enactment of yet further legislation regarding mine safety.

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Mining accidents in the last several years in West Virginia, Utah, and Kentucky have received national attention and instigated responses at the state and national level that are likely to result in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. More stringent mine safety laws and regulations promulgated by these states and the federal government have included increased sanctions for non-compliance. Other states have proposed or passed similar bills, resolutions or regulations addressing mine safety practices.

EMPLOYEES

As of December 31, 2014, our General Partner employed 1,879 employees, of whom 1,406 were field operating employees and 473 were mid-and senior-level management and staff. None of these employees are represented by a labor union and there are no outstanding collective bargaining agreements to which our General Partner is a party. Our General Partner believes that it has good relations with its employees.

AVAILABLE INFORMATION

We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. From time to time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

We make our SEC filings available to the public, free of charge and as soon as practicable after they are filed with the SEC, through our Internet website located at http://www.regencygasservices.com. Our annual reports are filed on Form 10-K, our quarterly reports are filed on Form 10-Q and current-event reports are filed on Form 8-K; we also file amendments to reports filed or furnished pursuant to Section 13(a) or Section 15(d) of the Exchange Act. References to our website addressed in this report are provided as a convenience and do not constitute, and should not be viewed as, an incorporation by reference of the information contained on, or available through, our website. Therefore, such information should not be considered part of this report.

Item 1A. Risk Factors

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our business, our structure as a limited partnership and our tax treatment could materially impact our future performance and results of operations. We have provided below a list of these risk factors that should be reviewed when considering an investment in our securities. These are not all of the risks we face as there are other factors currently considered immaterial or unknown to us that may impact our future operations.

RISKS INHERENT IN AN INVESTMENT IN US

We may not have sufficient cash from operations to enable us to pay our current quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including reimbursement of fees and expenses of our General Partner.

We may not have sufficient available cash from operating surplus each quarter to pay our Minimum Quarterly Distribution (MQD) in the amount of $0.35 per common unit. The amount of cash we can distribute to our unitholders depends principally on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:


•	prevailing economic conditions;


•	the fees we charge and the margins we realize for our services and sales;


•	the prices of, level of, production of, and demand for natural gas, NGLs and oil (crude, and/or condensate, a lighter oil);


•	the volumes of natural gas, NGLs and oil (crude, and/or condensate, a lighter oil) we gather, process and transport; and


•	the amounts of our operating costs, including reimbursement of fees and expenses of our General Partner.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:


•	our debt service requirements;


•	our obligation to pay distributions on our Series A Preferred Units;


•	fluctuation in our working capital needs;


•	our ability to borrow funds and access capital markets;


•	restrictions contained in our debt agreements;


•	the cost of acquisitions, if any;


•	the amounts of cash reserves established by our General Partner; and

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•	our ability to maintain commodity hedge prices from year to year.

You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, not net income (loss) calculated in accordance with GAAP. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not be able to make cash distributions during periods when we record net income for financial accounting purposes.

Our cash flow is affected by supply and demand for natural gas, NGL products, oil (crude, and/or condensate, a lighter oil) and by natural gas and NGL prices. Natural gas, NGLs, crude oil, and other commodity prices are volatile, and an unfavorable change in these prices could adversely affect our cash flow and operating results.

We are subject to risks due to frequent and often substantial fluctuations in commodity prices. NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices as well as global demand of petrochemical products. In the past, the prices of natural gas, NGLs and crude oil have been extremely volatile, and this volatility could continue. Volatility in crude oil, natural gas and NGL prices can impact our customers’ activity levels and spending for our products and services, as well as our margins under our keep-whole and percentage-of-proceeds natural gas gathering and processing contracts. The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for crude oil, natural gas and NGLs, which fluctuates with changes in market and economic conditions and other factors, including:


•	the impact of weather on the demand for crude oil, natural gas and NGLs;


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


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


•	actions taken by foreign crude oil and gas producing nations;


•	the availability of local transportation systems;


•	the price, availability and marketing of competitive fuels;


•	the demand for electricity;


•	the impact of energy conservation efforts; and


•	the extent of governmental regulation and taxation.

Our natural gas gathering and processing businesses operate under two types of contractual arrangements that expose our cash flows to increases and decreases in the price of natural gas and NGLs: percentage-of-proceeds and keep-whole arrangements. Under percentage-of-proceeds arrangements, we generally purchase natural gas from producers and retain from the sale an agreed percentage of pipeline-quality gas and NGLs resulting from our processing activities (in cash or in-kind) at market prices. Under keep-whole arrangements, we receive the NGLs removed from the natural gas during our processing operations as the fee for providing our services in exchange for replacing the thermal content removed as NGLs with a like thermal content in pipeline-quality gas or its cash equivalent. Under these types of arrangements our revenues and our cash flows increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect our profitability. When natural gas prices are low relative to NGLs prices, it is more profitable for us to process natural gas under keep-whole arrangements. When natural gas prices are high relative to NGLs prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and of the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce the volume of natural gas processed at some of our plants.

Our leverage may limit our ability to borrow additional funds, make distributions, comply with the terms of our indebtedness or capitalize on business opportunities.

Our leverage is significant in relation to our partners’ capital. Our debt to capital ratio, calculated as total debt divided by the sum of total debt and partners’ capital, as of December 31, 2014 was 41%. We will be prohibited from making cash distributions during an event of default under any of our indebtedness, and, in the case of the indentures governing our senior notes, the failure to maintain a prescribed ratio of consolidated cash flows (as defined in such indentures) to interest expense. Various limitations in our credit facility, as well as the indentures governing our senior notes, may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on certain business opportunities. Any refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

Our leverage may adversely affect our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisition, construction or development activities, or otherwise realize fully the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage may also make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.

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Increases in interest rates could adversely impact our common unit price and our ability to issue additional equity in order to finance acquisitions, to reduce debt or for other purposes.

The interest rates on our senior notes are fixed and the loans outstanding under our credit facility bear interest at a floating rate. Interest rates on future credit facilities and senior notes could be significantly higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, the market price for our common units will be affected by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse effect on our unit price and our ability to issue additional equity in order to make acquisitions, to reduce debt or for other purposes.

Because we distribute all of our available cash to our unitholders, our future growth may be limited.

Since we will distribute all of our available cash to our unitholders, subject to the limitations on restricted payments contained in the indentures governing our senior notes and our credit facility, we will depend on financing provided by commercial banks and other lenders and the issuance of debt and equity securities to finance any significant internal organic growth or acquisitions. If we are unable to obtain adequate financing from these sources, our ability to grow will be limited.

To the extent that we intend to grow internally through construction of new, or modification of existing, facilities, we may not be able to manage that growth effectively, which could decrease our cash flow and adversely affect our results of operations.

A principal focus of our strategy is to continue to grow by expanding our business both internally and through acquisitions. Our ability to grow internally will depend on a number of factors, some of which will be beyond our control. We may not be able to finance planned construction or modifications on satisfactory terms. In general, the construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control. Any project that we undertake may not be completed on schedule, at budgeted cost or at all. Construction may occur over an extended period, and we are not likely to receive a material increase in revenues related to such project until it is completed. Moreover, our revenues may not increase immediately upon the completion of construction because the anticipated growth in production that the project was intended to capture may not materialize, our estimate of the growth in production proves inaccurate or for other reasons. For any of these reasons, newly constructed or modified midstream facilities may not generate our expected investment return and that, in turn, could adversely affect our cash flows and results of operations. In addition, our ability to undertake growth projects in this fashion will depend on our ability to hire, train and retain qualified personnel to manage and operate these facilities when completed.

We may have difficulty financing our planned capital expenditures, including making additional capital contributions to our joint ventures, which could adversely affect our results and growth.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including borrowings under our credit facility and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. If we are not able to obtain adequate financing from the capital markets, our ability to grow and our results of operations could be adversely impacted. To access amounts under our credit facility for joint venture capital expenditures or additional investments, we may need to amend to our credit facility, and we cannot assure you that we can obtain any such amendment.

We may not have the ability to raise funds necessary to finance any change of control offer required under our senior notes and our Series A Preferred Units or to repay our credit facility upon a change of control.

If a change of control (as defined in the indentures governing our senior notes) occurs, we will be required to offer to purchase our outstanding senior notes at 101% of their principal amount plus accrued and unpaid interest. If a purchase offer obligation arises under these indentures, a change of control could also have occurred under our credit facility, which could result in the acceleration of the indebtedness outstanding thereunder. Further, if a change of control (as defined in our partnership agreement) occurs, we will be required, under certain circumstances, to offer to purchase the Series A Preferred Units at 101% of their liquidation value (as defined in our partnership agreement) Any of our future debt agreements may contain similar restrictions and provisions. If a change in control were to occur, we may not have sufficient funds to pay the purchase price of all debt or the Series A Preferred Units that we are required to purchase or repay.

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Our ability to manage and grow our business effectively may be adversely affected if our General Partner is unable to hire or retain key management or operational personnel.

We depend on the continuing efforts of our executive officers. The departure of any of our executive officers could have a significant negative effect on our business, operating results, financial condition, and on our ability to compete effectively in the marketplace. Additionally, employees of our General Partner and its affiliates operate some of our business activities. Our General Partner’s ability to hire, train, and retain qualified personnel will continue to be important and will become more challenging as we grow and if energy industry market conditions remain positive.

When general industry conditions are good, the competition for experienced operational and field technicians increases as other energy and manufacturing companies’ needs for the same personnel increases. Our ability to grow and perhaps even to continue our current level of service to our current customers will be adversely impacted if our General Partner or its affiliates that provide these personnel are unable to successfully hire, train and retain these important personnel.

A downgrade of our credit rating could impact our liquidity, access to capital and our costs of doing business, and maintaining credit ratings is under the control of independent third parties.

Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings. A downgrade of our credit rating might increase our cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our ability to access capital markets could also be limited by a downgrade of our credit rating.

ETE and ETP may sell common units in the public or private markets, and the sale could have an adverse impact on the price of our common units.

As of February 19, 2015, ETE directly owns 26,266,791 of our common units and its subsidiary, ETE Common Holdings, LLC, owns 30,890,565 of our common units, ETP indirectly owns 31,372,419 of our common units and 6,274,483 of our Class F units, which will convert into common units on a one-for-one basis in May 2015. All such common units have correlating demand registration rights pursuant to which we are obligated to register the common units for resale under the Securities Act. The resale of these common units in the public or private markets could have an adverse impact on the price of our common units or on the trading market for them.

An impairment of goodwill and intangible assets could reduce our earnings.

At December 31, 2014, our consolidated balance sheet reflected $1.2 billion of goodwill and $3.4 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires us to test goodwill for impairment on an annual basis or when events or circumstances occur that indicate goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets are impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization. During 2014, we recorded a $370 million goodwill impairment charge related to our Permian reporting unit within the Gathering and Processing segment.

RISKS RELATED TO OUR BUSINESS

Our success depends on our ability to obtain new supplies of natural gas, NGLs, and crude oil. Any decrease in supplies or the price of natural gas, NGLs, or crude oil in our areas of operation could adversely affect our business and operating results.

Our gathering and processing and transportation pipeline systems are dependent on the level of production from natural gas wells that supply our systems and such production will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput volume levels on our gathering and transportation pipeline systems and the asset utilization rates at our natural gas processing plants, we must continually obtain new supplies. The primary factors affecting our ability to obtain new supplies of natural gas and attract new customers to our assets are: the level of successful drilling activity near our systems and our ability to compete with other gathering and processing companies for volumes from successful new wells.

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The level of natural gas drilling activity is dependent on economic and business factors beyond our control. The primary factor that impacts drilling decisions is natural gas prices. A sustained decline in natural gas prices, as has occurred in recent years, could result in a decrease in exploration and development activities in the fields served by our gathering and processing facilities and pipeline transportation systems, which would lead to reduced utilization of these assets. Some producers have indicated that they will focus their exploration and production efforts on geographic areas with oil and NGL-rich natural gas products. Other factors that impact production decisions include producers’ capital budget limitations, the ability of producers to obtain necessary drilling and other governmental permits and regulatory changes.

Because of these factors, even if additional natural gas reserves were discovered in areas served by our assets, producers may choose not to develop those reserves. If we were not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells due to reductions in drilling activity or competition, throughput volumes on our pipelines and the utilization rates of our processing facilities would decline, which could have a material adverse effect on our business, results of operations and financial condition.

Our natural gas contract compression operations significantly depend upon the continued demand for and production of natural gas and crude oil. Demand may be affected by, among other factors, natural gas prices, crude oil prices, weather, demand for energy, and availability of alternative energy sources. Any prolonged, substantial reduction in the demand for natural gas or crude oil would, in all likelihood, depress the level of production activity and result in a decline in the demand for our contract compression services and products. Lower natural gas prices or crude oil prices over the long-term could result in a decline in the production of natural gas or crude oil, respectively, resulting in reduced demand for our natural gas contract compression services. Additionally, production from natural gas sources such as longer-lived tight sands, shales and beds constitute an increasing percentage of our compression services business. Such sources are generally less economically feasible to produce in lower natural gas price environments, and a reduction in demand for natural gas may cause such sources of natural gas to be uneconomic to drill and produce, which could in turn negatively impact the demand for our compression services.

The profitability of certain activities in our NGLs and refined products storage business, our NGLs transportation business and our off-gas processing and fractionating business are largely dependent upon market demand for NGLs and refined products, and competition in the market place, both of which are factors that are beyond our control.

Our NGLs and refined products storage revenues are primarily derived from fixed capacity arrangements between us and our customers. However, a portion of our revenues are derived from fungible storage and throughput arrangements, under which our revenues are more dependent upon demand for storage from our customers. Demand for these services may fluctuate as a result of changes in commodity prices. Our NGLs and refined products storage assets are primarily located in the Mont Belvieu area, which is a significant storage distribution and trading complex with multiple industry participants, any one of which could compete for the business of our existing and potential customers. Any loss of business from existing customers or our inability to attract new customers could have an adverse effect on our results of operations.

Revenues from our NGLs transportation systems are exposed to risks due to fluctuations in demand for transportation as a result of unfavorable commodity prices and competition from nearby pipelines. We receive substantially all of our transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to our transportation system. We may not be able to renew these contracts or execute new customer contracts on favorable terms if NGLs prices decline and demand for our transportation services decreases. Any loss of existing customers due to decreased demand for our services or competition from other transportation service providers could have a negative impact on our revenues and have an adverse effect on our results of operations.

Revenues from our off-gas processing and fractionating system in south Louisiana are exposed to risks due to the low concentration of suppliers near our facilities and the possibility that connected refineries may not provide us with sufficient off-gas for processing at our facilities. The connected refineries may also experience outages due to maintenance issues and severe weather, such as hurricanes. We receive revenues primarily through a percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of our off-gas processing and fractionation revenues are exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for our off-gas processing and fractionation services and could have an adverse effect on our results of operations.

Many of our customers’ drilling activity levels and spending for transportation on our gathering and pipeline systems may be impacted by commodity prices and the credit markets.

Many of our customers finance their drilling activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any combination of a reduction of cash flow resulting from declines in natural gas prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ spending for natural gas or crude oil drilling activity, which could result in lower volumes being transported on our gathering and pipeline systems. A significant reduction in drilling activity could have a material adverse effect on our operations.

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We depend on certain key producers and other customers for a significant portion of our supply of natural gas, contract compression and contract treating revenues. The loss of, or reduction in, any of these key producers or customers could adversely affect our business and operating results.

We rely on a limited number of producers and other customers for a significant portion of our natural gas supplies and our contracts for compression services. These contracts have terms that range from month-to-month to life of lease. As these contracts expire, we will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. We may be unable to obtain new or renewed contracts on favorable terms, if at all. The loss of all or even a portion of the volumes of natural gas supplied by these producers and other customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations and financial condition.

Any reduction in the capacity of, or the allocations to, our shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines, which would adversely affect our revenues and cash flow.

Users of our pipelines are dependent upon connections to and from third-party pipelines to receive and deliver natural gas, NGLs, and oil (crude and/or condensate, a lighter crude). Any reduction in the capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes being transported in our pipelines. Similarly, if additional shippers begin transporting volumes of natural gas, NGLs, and oil (crude and/or condensate, a lighter crude) over interconnecting pipelines, the allocations to existing shippers in these pipelines could be reduced, which could also reduce volumes transported in our pipelines. Any reduction in volumes transported in our pipelines would adversely affect our revenues and cash flow.

The contract compression business within our Contract Services segment depends on particular suppliers and is vulnerable to parts and equipment shortages and price increases, which could have a negative impact on our results of operations.

The principal manufacturers of components for our natural gas compression equipment include Caterpillar, Inc. for engines, Air-X-Changers for coolers, and Ariel Corporation for compressors and frames. Our reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. We also rely primarily on one vendor, SEC Energy Products & Services, L.P., a subsidiary of ETP, to package and assemble our compression units. We do not have long-term contracts with these suppliers or packagers, and a partial or complete loss of certain of these sources could have a negative impact on our results of operations and could damage our customer relationships. In addition, since we expect any increase in component prices for compression equipment or packaging costs will be passed on to us, a significant increase in their pricing could have a negative impact on our results of operations.

The contract treating business within our Contract Services segment depends on particular suppliers and is vulnerable to parts and equipment shortages and price increases, which could have a negative impact on our results of operations.

Our contract treating business’ ability to manufacture new equipment used to provide treating services, and to obtain replacement components, depends on particular suppliers and is sensitive to equipment shortages and price increases. Spitzer Industries, the principal manufacturer and packager of amine plants, determines the cost of our contract treating equipment based primarily on the price and availability of commodities (i.e. steel), components and labor. If a significant increase in the cost of manufacturing were to occur, we could see a reduced rate of return on our capital investments relating to our contract treating business absent offsetting increases in revenue rates.

In accordance with industry practice, we do not obtain independent evaluations of natural gas reserves dedicated to our gathering systems. Accordingly, volumes of natural gas gathered on our gathering systems in the future could be less than we anticipate, which could adversely affect our business and operating results.

We do not obtain independent evaluations of natural gas reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations.

Accordingly, we do not have estimates of total reserves dedicated to our systems or the anticipated lives of such reserves. If the total reserves or estimated lives of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas gathered on our gathering systems in the future could be less than we anticipate. A decline in the volumes of natural gas gathered on our gathering systems could have an adverse effect on our business, results of operations and financial condition.

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In our gathering and processing business, we purchase raw natural gas containing significant quantities of NGLs, process the raw natural gas and sell the processed gas and NGLs. If we are unsuccessful in balancing the purchase of raw natural gas with its component NGLs and our sales of pipeline quality gas and NGLs, our exposure to commodity price risks will increase.

We purchase from producers and other customers a substantial amount of the natural gas that flows through our natural gas gathering and processing systems and our RIGS transportation pipeline for resale to third parties, including natural gas marketers and utilities. We may not be successful in balancing our purchases and sales. In addition, a producer could fail to deliver promised volumes or could deliver volumes in excess of contracted volumes, a purchaser could purchase less than contracted volumes, or the natural gas price differential between the regions in which we operate could vary unexpectedly. Any of these actions could cause our purchases and sales to not be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating results.

We may be unable to integrate successfully the operations of future acquisitions with our operations, and we may not realize all the anticipated benefits of our past and any future acquisitions.

Integration of acquisitions with our business and operations is a complex, time consuming, and costly process. Failure to integrate acquisitions successfully with our business and operations in a timely manner may have a material adverse effect on our business, financial condition, and results of operations. We cannot assure you that we will achieve the desired profitability from past or future acquisitions. In addition, failure to assimilate future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions involve numerous risks, including:


•	operating a significantly larger combined organization and adding operations;


•	difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new business segment or geographic area;


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


•	the loss of significant producers or markets or key employees from the acquired business;


•	the availability of local, intrastate and interstate transportation system;


•	the diversion of management’s attention from other business concerns;


•	the failure to realize expected profitability, growth or synergies and cost savings;


•	properly assessing and managing environmental compliance;


•	coordinating geographically disparate organizations, systems, and facilities; and


•	coordinating or consolidating corporate and administrative functions.

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

If we do not make acquisitions on economically acceptable terms, our future growth could be limited.

Our results of operations and our ability to grow and to increase distributions to unitholders will depend in part on our ability to make acquisitions that are accretive to our distributable cash flow per unit.

We may be unable to make accretive acquisitions for any of the following reasons, among others:


•	because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;


•	because we are unable to raise financing for such acquisitions on economically acceptable terms; or


•	because we are outbid by competitors, some of which are substantially larger than us and have greater financial resources and lower costs of capital then we do.

If we consummate future acquisitions, our capitalization and results of operations may change significantly. As we determine the application of our funds and other resources, unitholders will not have an opportunity to evaluate the economics, financial and other relevant information that we will consider.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in each of our areas of operations. Some of our competitors are large oil, natural gas, gathering and processing and natural gas and NGL pipeline companies that have greater financial resources and access to supplies of natural gas, NGLs, and oil (crude and/or condensate, a lighter crude) than we do. In addition, our customers who are significant producers or consumers of NGLs may develop their own processing facilities in lieu of using ours. Similarly, competitors may establish new connections with pipeline systems that would create additional competition for services that we provide to our customers. Our

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ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors.

The natural gas contract compression business is highly competitive, and there are low barriers to entry for individual projects. In addition, some of our competitors are large national and multinational companies that have greater financial and other resources than we do. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to compete effectively. Some of these competitors may expand or construct newer or more powerful compressor fleets that would create additional competition for us. In addition, our customers that are significant producers of natural gas and crude oil may purchase and operate their own compressor fleets in lieu of using our natural gas contract compression services.

We may also compete with similar enterprises or others for potential future acquisitions. Some of these competitors may have greater financial resources, may have the ability to achieve greater synergies with potential acquisitions, or may have other strategic or other interests in potential acquisitions. This competition may result in our inability to successfully bid for desirable acquisitions or may result in our having to pay higher purchase prices for acquisitions in which we are the successful bidder. As we and other companies in our industry expand, the availability of attractive acquisitions may decline over time, limiting our ability for future growth through acquisitions.

All of these competitive pressures could have a material adverse impact on our business, results of operations, and financial condition.

Our results of operations and cash flow may be adversely affected by risks associated with our hedging activities.

In performing our functions in our gathering and processing segment, we are a seller of natural gas, NGLs, and oil (crude, and/or condensate, a lighter oil) and are exposed to commodity price risk associated with movements in commodity prices. As a result of the volatility of commodity prices and interest rates, we have executed swap contracts or put options settled against natural gas, some NGL products and West Texas Intermediate crude oil market prices. Some of our risks remain unhedged. We continually monitor our hedging and contract portfolio and expect to adjust our hedge position as conditions warrant. For more information about our risk management activities, read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.” Even though our management monitors our hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including any circumstance in which a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect, or our hedging policies and procedures are not followed or do not work as planned.

The implementation of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (“CFTC”), the US Securities and Exchange Commission and other regulators to promulgate rules and regulations implementing the new legislation. While many of the regulations are already in effect, the implementation process is still ongoing, and we cannot yet predict the ultimate effect of the regulations on our business.

In its rulemaking under the Dodd-Frank Act, the CFTC is finalizing its final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these position limits provided that various conditions are satisfied. Once finalized, the position limits rule and its companion rule on aggregation may have an impact on our ability to hedge our exposure to certain enumerated commodities.

The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant.” To further define the term “swap,” the CFTC has issued several interpretations clarifying whether certain forwards with optionality will remain as forwards or would qualify as options on commodities and therefore swaps. Once finalized, this interpretation may have an impact on our ability to enter into certain forwards.

The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). As the CFTC further designates swap contracts as required to be cleared, the utility of an end-user exception will become even more important. Our ability to rely on the end-user exception may change the profitability trades or the efficiency of our hedging.

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In addition, new regulations may require us to comply with margin requirements for our over-the-counter derivative contracts with certain regulated entities, which could adversely affect our liquidity and ability to use derivatives to hedge our risks, although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects.

Under the Dodd-Frank Act, the CFTC is also directed generally to prevent price manipulation and fraud in the following two markets: (a) physical commodities traded in interstate commerce, including physical energy and other commodities, as well as (b) financial instruments, such as futures, options and swaps. Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-market manipulation, anti-fraud and disruptive trading practices regulations that prohibit, among other things, fraud and price manipulation in the physical commodities, futures, options and swaps markets. Should we violate these laws and regulations, we could be subject to CFTC enforcement action and material penalties, and sanctions.

The Dodd-Frank Act also may require the counterparties to our 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 Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our 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. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make our transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more difficult to satisfy our regulatory obligations.

We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders. Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve based credit facilities (resulting from a decline in commodity prices) and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.

We do not control the actions of our joint ventures.

Our joint ventures have their own governing boards. We exercise some influence over our joint ventures because our approval is required for their most significant decisions, but we do not control the decisions made by these boards. We also cannot control the actions of our joint venture partners, including any nonperformance, default, or bankruptcy of our joint venture partners. In the event that any of our joint venture partners do not observe their obligations, it is possible that the affected joint venture would not be able to operate in accordance with its business plans. As a result, we may be required to increase our level of commitment to the affected joint venture to give effect to such plans. Differences in views among the joint venture parties may result in delayed decisions or in failures to agree on significant matters, which could adversely affect the business and operations of the joint ventures and, in turn, our business and operations.

Further, all of our joint ventures may request that we make additional capital contributions to support their capital expenditure programs. If such capital contributions are required, we may not be able to obtain the financing necessary to satisfy our obligations. In the event that we elect not to participate in future capital contributions, our ownership interest in the joint ventures will be diluted.

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Certain of our assets may become subject to regulation.

Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. Lone Star’s NGL pipeline transports NGLs within the state of Texas and is subject to regulation by the TRRC. This transportation system offers services pursuant to an intrastate transportation tariff on file with the TRRC. Lone Star’s NGL pipeline also commenced the interstate transportation of NGLs in 2013, which is subject to FERC’s jurisdiction under the Interstate Commerce Act and the Energy Policy Act of 1992. Both intrastate and interstate NGL transportation services must be provided in a manner that is just, reasonable, and non-discriminatory. The tariff rates established for interstate services were based on a negotiated agreement; however if FERC’s rate making methodologies were imposed, they may, among other things, delay the use of rates that reflect increased costs and subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect revenues and cash flow related to these assets.

Our interstate gas transportation operations, including Section 311 service performed by our intrastate pipelines, our sales of gas in interstate commerce, and our shipment of gas on interstate pipelines are subject to FERC regulation; failure to comply with applicable regulation, future changes in regulations or policies, or the establishment of more onerous terms and conditions applicable to natural gas transportation service could adversely affect our business.

FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines, such as the pipelines owned by Gulf States and MEP, both of which hold FERC-approved tariffs setting forth cost- based rates, terms and conditions for services to shippers wishing to take interstate transportation service. Under the NGA, rates charged for, and the terms and conditions of service of, interstate natural gas transmission must be just and reasonable, and amounts collected in excess of just and reasonable rates may be subject to refund with interest. In addition, FERC regulates the rates, terms and conditions of service with respect to Section 311 transportation service provided by HPC (through RIGS). FERC has authority to alter its rules, regulations and policies governing service provided by interstate pipelines and intrastate pipelines providing Section 311 services. We cannot give any assurance regarding the likely future regulations under which Gulf States, MEP or HPC will operate their interstate transportation services or the effect such regulation could have on our businesses or results of operations. In addition, FERC also has broad authority to require compliance with its rules and regulations and to prohibit and penalize manipulative behavior that affects markets. Since our gathering and processing businesses sell natural gas in interstate commerce and ship gas on interstate pipelines, these activities are subject to FERC oversight. Any failure on our part to comply with applicable FERC-administered statutes, rules, regulations and orders could result in the imposition of significant administrative, civil and/or criminal penalties or both, as well as increased operational requirements or prohibitions.

As limited partnership entities, neither we nor our regulated natural gas pipelines may be able to include a full tax allowance in calculating our costs-of-service for rate-making purposes.

Under current policy applied under the NGA and Section 311, FERC permits regulated natural gas pipelines to include, in the cost-of-service used as the basis for calculating the pipeline’s regulated rates, a tax allowance reflecting the actual or potential income tax liability on pipeline income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis, and the pipeline is required to demonstrate that such potential income tax liability exists. Although FERC’s policy is generally favorable for pipelines that are organized as, or owned by, tax-pass-through entities, application of the policy in individual rate cases still entails rate risk due to the case-by-case review requirement. The specific terms and application of that policy remain subject to future refinement or change by FERC and the courts. Moreover, we cannot guarantee that this policy will not be altered in the future.

There are uncertainties in the calculation of the return on equity that FERC will authorize a natural gas pipeline to include in its cost-of-service.

An important part of the determination of rates by FERC is the establishment of an authorized return on equity. FERC currently calculates a range of potential returns, based on a discounted cash flow analysis of companies included in a proxy group, and then determines where a pipeline’s risks require it to be placed within this range. FERC policy also currently allows the inclusion of master limited partnerships, or MLPs, in proxy groups used to calculate the appropriate returns on equity under FERC’s discounted cash flow analysis, but FERC limits recognition of certain MLP earnings and allows case-by-case determination by FERC of the appropriateness of any MLP, or indeed any stock corporation, proposed as a member of the pipeline’s proxy group.

A change in the level of regulation or the jurisdictional characterization of some of our assets or business activities by federal, state or local regulatory agencies could affect our operations and revenues.

Our natural gas gathering, processing and intrastate transportation operations are generally exempt from FERC regulation under the NGA, but FERC regulation still affects these businesses and the markets for products derived from these businesses. With the passage of the Energy Policy Act of 2005 (EPACT 2005), FERC has expanded its oversight of natural gas purchasers, natural gas

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sellers, gatherers, intrastate pipelines and shippers on FERC regulated pipelines by imposing new market monitoring and market transparency rules and rules prohibiting manipulative behavior. In addition, EPACT 2005 substantially increased FERC’s penalty authority. In recent years, FERC has adopted rules requiring increased reporting by purchasers and sellers of natural gas and increased transactional reporting requirements for intrastate pipelines. In 2010, FERC also sought formal comments on the applicability of buy-sell prohibitions and capacity release requirements on intrastate pipelines that provide interstate service under NGPA Section 311. We cannot predict the outcome of this proceeding or how FERC will approach future matters such as pipeline rates and rules and policies that may affect purchases or sales of natural gas or rights of access to natural gas transportation capacity.

In addition, the distinction between FERC-regulated natural gas interstate transmission service, on one hand, and intrastate natural gas transmission or federally unregulated natural gas gathering services, on the other hand, is the subject of litigation at FERC and in the courts and of policy discussions at FERC. In such circumstances, the classification and regulation of some of our gathering or our intrastate transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress. Such a change could result in increased regulation by FERC, which could adversely affect our business.

Other state and local regulations also affect our business. Our gathering pipelines are subject to ratable take and common purchaser statutes in states in which we operate. Ratable take statutes generally require gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. Many states in which we operate 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 natural gas gathering access and rate discrimination. Our intrastate NGL, crude oil, and condensate pipelines are subject to state common carrier regulations, which require just and reasonable rates, non-discriminatory service, and the filing of tariffs. Our common carrier pipeline tariffs contemplate additional rights to, or superior terms of service for “anchor shippers”, and if these or any other provisions in our common carrier pipeline tariffs are found to be inconsistent with non-discrimination requirements, then we may be required to modify the rates and/or terms of service in our tariffs and may not be able to provide the level of service contemplated in agreements with “anchor shippers”.

Any new laws, rules, regulations or orders could result in additional compliance costs and/or requirements, which could adversely affect our business. If we fail to comply with any new or existing laws, rules, regulations or orders, we could be subject to administrative, civil and/or criminal penalties, or both, as well as increased operational requirements or prohibitions.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations, the operations of our lessees, and our financial results could be adversely affected.

Our operations and the coal mining operations of our lessees are subject to numerous operational risks including:


•	the inability to acquire necessary permits;


•	changes in governmental regulation;


•	adverse weather conditions and natural disasters;


•	fires and explosions;


•	equipment failures, damage to our our lessees facilities, and unexpected maintenance problems; and


•	leaks or losses of hydrocarbons and other pollutants into the environment.

These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage, and may result in curtailment or suspension of our operations. or the operations of our lessees. We are not insured against all events that might occur. If a significant accident or event occurs that is not insured or fully insured, it could adversely affect our operations, the operations of our lessees, and our financial condition.

If the natural gas that we ship on our pipelines fails to meet the specifications of interconnecting interstate pipelines, those interstate pipelines could curtail shipments of our natural gas.

The markets to which the shippers on our pipelines ship natural gas include interstate pipelines. These interstate pipelines establish specifications for the natural gas that they are willing to accept, which include requirements such as hydrocarbon dew point, temperature and foreign content including water, sulfur, carbon dioxide and hydrogen sulfide. These specifications vary by interstate pipeline. If the total mix of natural gas shipped by the shippers on our pipelines fails to meet the specifications of a particular interstate pipeline, the interstate pipeline may refuse to accept all or a part of the natural gas scheduled for delivery to it. In those circumstances, we may be required to find alternative markets for that gas or to shut-in the producers of the non-conforming gas, potentially reducing our throughput volumes or revenues.

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We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair, or preventative or remedial measures, as well as any future legislative and regulatory initiatives related to pipeline safety.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines and certain gathering lines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:


•	perform ongoing assessments of pipeline integrity;


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


•	improve data collection, integration and analysis;


•	repair and remediate the pipeline as necessary; and


•	implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. We currently estimate that we will incur costs of $3.5 million in 2015 to implement pipeline integrity management program testing along certain segments of our pipeline, as required by existing DOT regulations. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial.

The DOT is continually proposing new pipeline safety rules and issuing pipeline safety advisories that impact our businesses. Additionally, Congress has been engaged in developing more stringent safety laws.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 went into effect on January 3, 2012 and requires more stringent oversight of pipelines and increased civil penalties for violations of pipeline safety rules. The law requires numerous studies and/or the development of rules over the next two years covering the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related rules. The DOT has sought comments on potential rules to implement this legislation. Any resulting regulatory changes could have a material effect on our operations through more stringent and comprehensive safety regulations, increased costs and higher penalties for the violation of those regulations.

We may incur significant costs and liabilities in the future resulting from our or our lessees’ failure to comply with new or existing environmental regulations or releases of hazardous materials into the environment.

Our operations and the operations of our lessees are subject to stringent and complex federal, state and local laws and regulations governing, among other things, employee health and safety, permitting and licensing, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us or our lessees to incur substantial costs, penalties, fines and other criminal sanctions, third party claims for personal injury or property damage, investments to retrofit or upgrade our facilities and programs, or curtailment of operations. Certain federal and state environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released.

The possibility exists that stricter laws, regulations or enforcement policies could significantly increase our an our lessees’ compliance costs and the cost of any remediation that may become necessary. We cannot be certain that identification of presently unidentified conditions, more vigorous enforcement by regulatory agencies, enactment of more stringent laws and regulations, or other unanticipated events will not arise in the future and give rise to material environmental liabilities that could have a material adverse effect on our operations, the operations of our lessees, and financial condition.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas and other hydrocarbon products that we handle in connection with our transportation and midstream services, as well as reduce demand for the coal that our lessees mine, which could adversely affect our coal royalty payments.

In December 2009, the Environmental Protection Agency (“EPA”) published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the Earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that restrict emissions of greenhouse gases under existing provisions of the Clean Air Act (“CAA”). Accordingly, the EPA adopted regulations limiting emissions of greenhouse gases from motor vehicles, which then triggered CAA construction and operating permit requirements under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs for certain large stationary sources of greenhouse gases The EPA has also proposed New Source Performance Standards

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(“NSPS”) for carbon dioxide emissions from existing power plants, and is in the process of finalizing a proposal for new power plants.

In addition, in October 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified greenhouse gas sources on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. In November 2010, the EPA revised its greenhouse gas reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. Under these rules, reporting of greenhouse gas emissions from such facilities, including many of our facilities, is required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In December 2014, the EPA proposed additional amendments to its greenhouse gas reporting rule, which could add reporting requirements for additional facilities, including gathering and boosting systems.

The regulation of emissions of greenhouse gases from our equipment and operations could require us to incur costs to reduce the greenhouse gas emissions from our own operations, and it could also adversely affect demand for our transportation, storage and midstream services. It could also lead our lessees’ customers to curtail their operations, switch to other fuels or other alternatives which may, individually or collectively, reduce demand for our lessees’ coal and thereby decrease revenues. As a result of current laws and proposed laws, regulations and trends, electric generators may switch from coal to other fuels that generate fewer greenhouse gas emissions, possibly reducing demand for coal.

Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new natural gas wells, which could adversely impact our revenues by decreasing the volumes of natural gas that we gather, process and transport.

An increasing percentage of our customers’ natural gas production is being developed from unconventional sources, such as shale formations. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas from shale formations. The process involves the injection of water, sand and and a small percentage of chemicals under pressure into to the formation to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and gas commissions. Some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. In addition, a number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing, and have asserted federal regulatory authority over the process. Moreover, Congress from time to time has proposed legislation to more closely and uniformly regulate hydraulic fracturing at the federal level. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of and natural gas that produce, and could thereby adversely affect our revenues and results of operations.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.

We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies. Many of these rights-of-way are perpetual in duration; others have terms ranging from five to ten years. Many are subject to rights of reversion in the case of non-utilization for periods ranging from one to three years. In addition, some of our processing facilities are located on leased premises. Our loss of these rights, through our inability to renew right-of-way contracts or leases or otherwise, could have a material adverse effect on our business, results of operations and financial condition.

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In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas or NGL supplies to our existing pipelines or to capitalize on other attractive expansion opportunities. If the cost of obtaining new rights-of-way increases, then our cash flows and growth opportunities could be adversely affected. Additionally, certain of our pipelines are gas utilities or common carrier pipelines with the statutory right of eminent domain. A recent Texas Supreme Court decision could severely limit our ability to use eminent domain to acquire right-of-way for common carrier expansion and growth projects, and potentially gas utility projects. Any such limitations could adversely affect our growth opportunities and cash flows.

Some portions of our current gathering infrastructure and other assets have been in use for many decades, which may adversely affect our business.

Some portions of our assets, including some of our gathering infrastructure, have been in use for many decades. The current age and condition of our assets could result in a material adverse impact on our business, financial condition and results of operations if the costs of maintaining our facilities exceed current expectations.

If our coal lessees do not manage their operations well or experience financial difficulties, their production volumes and our coal royalty revenues could decrease.

We depend on our coal lessees to effectively manage their operations on our properties. Our coal lessees make their own business decisions with respect to their operations, including decisions relating to:


•	the method of mining;


•	credit review of their customers;


•	marketing of the coal mined;


•	coal transportation arrangements;


•	negotiations with unions;


•	employee hiring and firing;


•	employee wages, benefits and other compensation;


•	permitting;


•	surety bonding; and


•	mine closure and reclamation.

If our lessees do not manage their operations well, or if they experience financial difficulties, their production could be reduced, which would result in lower coal royalty revenues to us and could have a material adverse effect on our business, results of operations or financial condition.

We could be negatively impacted by any decline in the market demand for coal.

The domestic demand for, and price of, the coal produced from our reserves primarily depend on coal consumption patterns of the domestic electric utility industry. Consumption by the domestic electric utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel sources, such as natural gas, nuclear, hydroelectric power and other renewable energy sources. In addition, during the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for or pricing of coal or impact the length of term of coal sales contracts, adversely impacting demand for the coal that our lessees produce and thereby reducing our coal royalty revenues. Indirect competition from gas-fired plants that are less expensive to construct and easier to permit has the most potential to displace a significant amount of coal-fired generation in the near term, particularly for older, less efficient coal-powered generators.

The demand for U.S. coal exports is dependent upon a number of factors, including the overall demand for electricity in foreign markets, currency exchange rates, ocean freight rates, the demand for foreign-produced steel both in foreign markets and in the U.S. market (which is dependent in part on tariff rates on steel), general economic conditions in foreign countries, technological developments and environmental and other governmental regulations and any other pressures placed on companies that are connected to the emission of greenhouse gases. Historically, global demand for electricity and steel production has decreased during periods of economic downturn. If there is a worsening of foreign and U.S. economic and financial market conditions, and additional tightening of global credit markets, foreign demand for U.S. coal could decline, causing competition among coal producers in the United States to intensify, potentially resulting in additional downward pressure on domestic coal prices and thereby reducing our coal royalty revenues.

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In addition, federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants, which are the ultimate consumers of the coal our lessees produce. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. As a result of these current and proposed laws, regulations and trends, electricity generators may elect to switch to other fuels that generate less of these emissions, possibly further reducing demand for the coal that our lessees produce and thereby reducing our coal royalty revenues.

A substantial or extended decline in coal prices could reduce our coal royalty revenues and the value of our coal reserves.

During 2014, weaker international and domestic economies, low natural gas prices and mild weather have impacted coal markets and market weakness is expected to continue into 2015. A substantial or extended decline in coal prices could have a material adverse effect on our coal lessees’ operations (including mine closures) and on the quantities of coal that may be economically produced from our properties. In addition, because a majority of our coal royalty are derived from coal mined on our properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price, our coal royalty revenues could be reduced by such a decline. Such a decline could also reduce our coal services revenues and the value of our coal reserves. Additionally, volatility in coal prices could make it difficult to estimate with precision the value of our coal reserves. The future state of the global economy, including developments in financial and credit markets and their impact on coal production levels and prices is uncertain. Depending on economic conditions, demand for coal may continue to decline, which could adversely affect production and pricing for coal mined by our lessees, and, consequently, adversely affect the royalty income received by us.

We depend on a limited number of primary operators for a significant portion of our coal royalty revenues and the loss of or reduction in production from any of our major lessees would reduce our coal royalty revenues.

We depend on a limited number of primary operators for a significant portion of our coal royalty revenues. If any of these operators enters bankruptcy or decides to cease operations or significantly reduces its production, our coal royalty revenues would be reduced.

A failure on the part of our lessees to make coal royalty payments could give us the right to terminate the lease, repossess the property or obtain liquidation damages and/or enforce payment obligations under the lease. If we repossessed any of our properties, we would seek to find a replacement lessee. We may not be able to find a replacement lessee and, if we find a replacement lessee, we may not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing lessee could be subject to bankruptcy or other proceedings that could further delay the execution of a new lease or the assignment of the existing lease to another operator. If we enter into a new lease, the replacement operator might not achieve the same levels of production or sell coal at the same price as the lessee it replaced.

Our coal reserves decline as our lessees mine our coal and our inability to acquire additional coal reserves that are economically recoverable may have a material adverse effect on the future profitability of our coal business.

Because our reserves decline as our lessees mine our coal, we have historically expanded our coal operations by adding and developing coal reserves in existing, adjacent and neighboring properties and through acquisitions of additional coal reserves that are economically recoverable to replace the reserves we produce. If we are unable to negotiate purchase contracts to replace or increase our coal reserves on acceptable terms, our coal royalty revenues will decline as our coal reserves are eventually depleted. As of December 31, 2014, we owned or controlled approximately 847 million tons of proven or probable coal reserves located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. We anticipate that these reserves will take over 33 years to deplete, based upon 2014 production volumes. Our current business strategy does not contemplate any additional growth in our coal reserve holdings through acquisitions or investments in our existing market areas. During 2014, our coal reserves located in the San Juan Basin were depleted and the associated royalty revenue ceased.

Our coal lessees could satisfy obligations to their customers with coal from properties other than ours, depriving us of the ability to receive amounts in excess of the minimum coal royalty payments.

We do not control our coal lessees’ business operations. Our lessees’ customer supply contracts do not generally require our lessees to satisfy their obligations to their customers with coal mined from our reserves. Several factors may influence a lessee’s decision to supply its customers with coal mined from properties we do not own or lease, including the royalty rates under the lessee’s lease with us, mining conditions, transportation costs and availability and customer coal quality specifications. If a coal lessee satisfies its obligations to its customers with coal from properties we do not own or lease, production under our lease will decrease, and we will receive lower coal royalty revenues.

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Fluctuations in transportation costs and the availability or reliability of transportation could reduce the production of coal mined from our properties.

Transportation costs represent a significant portion of the total cost of coal for the customers of our lessees. Increases in transportation costs could make coal a less competitive source of energy or could make coal produced by some or all of our lessees less competitive than coal produced from other sources. On the other hand, significant decreases in transportation costs could result in increased competition for our lessees from coal producers in other parts of the country or increased imports from offshore producers.

Our lessees depend upon rail, barge, trucking, overland conveyor and other systems to deliver coal to their customers. Disruption of these transportation services due to weather-related problems, strikes, lockouts, bottlenecks, mechanical failures and other events could temporarily impair the ability of our lessees to supply coal to their customers. Our lessees’ transportation providers may face difficulties in the future and impair the ability of our lessees to supply coal to their customers, thereby resulting in decreased coal royalty revenues to us.

Our lessees’ workforces could become increasingly unionized in the future, which could adversely affect their productivity and thereby reduce our coal royalty revenues.

One of our lessees has one mine operated by unionized employees. This mine was our largest mine on the basis of coal production for the year ended December 31, 2014. All of our lessees have workforces that could become increasingly unionized in the future. If some or all of our lessees’ non-unionized operations were to become unionized, it could adversely affect their productivity due to an increase in the risk of work stoppages. In addition, our lessees’ operations may be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our lessees’ operations. Any further unionization of our lessees’ employees could adversely affect the stability of production from our coal reserves and reduce our coal royalty revenues.

Our coal reserve estimates depend on many assumptions that may be inaccurate, which could materially adversely affect the quantities and value of our coal reserves.

Our estimates of our coal reserves may vary substantially from the actual amounts of coal our coal lessees may be able to economically recover. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may, if incorrect, result in an estimate that varies considerably from actual results.

These factors and assumptions relate to, among other things:


•	geological and mining conditions, which may not be fully identified by available exploration data;


•	the amount of ultimately recoverable coal in the ground;


•	the effects of regulation by governmental agencies; and


•	future coal prices, operating costs, capital expenditures, severance and excise taxes and development and reclamation costs.

Actual production, revenues and expenditures with respect to our coal reserves will likely vary from estimates, and these variations may be material. As a result, you should not place undue reliance on the coal reserve data provided by us.

Terrorist or cyber-attacks, the threat of terrorist or cyber-attacks, hostilities in the Middle East, or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, cyber-attacks and the magnitude of the threat of future terrorist or cyber-attacks on the energy transportation industry in general and on us in particular are not known at this time. Uncertainty surrounding hostilities in the Middle East or other sustained military campaigns may affect us in unpredictable ways, including disruptions of natural gas supplies and markets for natural gas and NGLs and the possibility that

infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist or cyber-attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

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RISKS RELATED TO OUR STRUCTURE

Our General Partner is owned by ETE, which also controls the general partners of ETP and SXL. This may result in conflicts of interest.

ETE owns our General Partner and as a result controls us. ETE owns the general partner of ETP, a publicly traded partnership with which we compete in the natural gas gathering, processing and transportation business. ETE and ETP own the general partner of SXL, who is also in the NGL services business. The directors and officers of our General Partner and its affiliates have fiduciary duties to manage our General Partner in a manner that is beneficial to ETE, its sole owner. At the same time, our General Partner has fiduciary duties to manage us in a manner that is beneficial to our unitholders. Therefore, our General Partner’s duties to us may conflict with the duties of its officers and directors to its sole owner. As a result of these conflicts of interest, our General Partner may favor its own interest or the interests of ETE, ETP, SXL, or their owners or affiliates over the interest of our unitholders.

Such conflicts may arise from, among other things, the following:


•	Decisions by our General Partner regarding the amount and timing of our cash expenditures, borrowings and issuances of additional limited partnership units or other securities can affect the amount of incentive distribution payments on our IDRs that we make to ETE;


•	ETE, ETP, SXL and their affiliates may engage in substantial competition with us;

•

Neither our partnership agreement nor any other agreement requires ETE or its affiliates, including ETP and SXL, to pursue a business strategy that favors us. The directors and officers of the general partners of ETE, ETP and SXL have a fiduciary duty to make decisions in the best interest of ETE’s, ETP’s and SXL’s members, limited partners and unitholders, as applicable, which may be contrary to our best interests;


•	Our General Partner is allowed to take into account the interests of other parties, such as ETE, ETP and SXL and their affiliates, which has the effect of limiting its fiduciary duties to our unitholders;


•	Some of the directors and officers of ETE who provide advice to us also may devote significant time to the business of ETE, ETP and SXL and their affiliates and will be compensated by them for their services;


•	Our partnership agreement limits the liability and reduces the fiduciary duties of our General Partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty;


•	Our General Partner determines the amount and timing of asset purchases and sales and other acquisitions, operating expenditures, capital expenditures, borrowings, repayments of debt, issuances of equity and debt securities and cash reserves, each of which can affect the amount of cash available for distribution to our unitholders;


•	Our General Partner determines which costs, including allocated overhead costs and costs under the services agreement we have with Service Co. and our operating agreement with ETP, incurred by it and its affiliates are reimbursable by us; and


•	Our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements, such as the services agreement we have with Service Co. and operating agreement with ETP, with any of these entities on our behalf.

Specifically, certain conflicts may arise as a result of our pursuing acquisitions or development opportunities that may also be advantageous to ETE, ETP or SXL. If we are limited in our ability to pursue such opportunities, we may not realize any or all of the commercial value of such opportunities. In addition, if ETE, ETP or SXL is allowed access to our information concerning any such opportunity and ETE, ETP or SXL uses this information to pursue the opportunity to our detriment, we may not realize any of the commercial value of this opportunity. In either of these situations, our business, results of operations and the amount of our distributions to our unitholders may be adversely affected. Although we, ETE and ETP have adopted a policy to address these conflicts and to limit the commercially sensitive information that we furnish to ETE, ETP and their affiliates, we cannot assure unitholders that such conflicts will not occur.

Our reimbursement of our General Partner’s expenses will reduce our cash available for distribution to common unitholders.

Prior to making any distribution on our common units, we will reimburse our General Partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by our General Partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us. The reimbursement of expenses incurred by our General Partner and its affiliates could adversely affect our ability to pay cash distributions to our unitholders.

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Our partnership agreement limits our General Partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our General Partner might otherwise be held by state fiduciary duty law. For example, our partnership agreement:

•

permits our General Partner to make a number of decisions in its individual capacity, as opposed to its capacity as our General Partner. This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership;


•	provides that our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;


•	provides that our General Partner may resolve any conflicts of interest involving us and our General Partner and its affiliates, and any resolution of a conflict of interest by our General Partner that is “fair and reasonable” to us will be deemed approved by all partners, including the Unitholders, and will not constitute a breach of the partnership agreement;

•

provides that our General Partner may, but is not required, in connection with its resolution of a conflict of interest, to seek “special approval” of such resolution by appointing a conflicts committee of the General Partner’s board of directors composed of two or more independent directors to consider such conflicts of interest and to recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee shall be conclusively deemed “fair and reasonable” to us;

•

provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of our General Partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by our General Partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and


•	provides that our General Partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

Any unitholder is bound by the provisions in the partnership agreement, including those discussed above.

Unitholders have limited voting rights and are not entitled to elect our General Partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders do not elect our General Partner or its Board of Directors and have no right to elect our General Partner or its Board of Directors on an annual or other continuing basis. The Board of Directors of our General Partner is chosen by the members of our General Partner. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which our common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if unitholders are dissatisfied, they cannot remove our General Partner without its consent.

Our unitholders may be unable to remove our General Partner without its consent because our General Partner and its affiliates own a substantial number of common units and Class F units. A vote of the holders of at least 66.67% of all outstanding units voting together as a single class is required to remove our General Partner. As of February 19, 2015, affiliates of our General Partner owned 21.5% of our outstanding common units.

Our partnership agreement restricts the voting rights of those unitholders owning 20% or more of our common units or Series A Preferred Units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of our General Partner, cannot vote on any matter. Our partnership

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agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of our management.

Control of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the partners of our General Partner from transferring their ownership in our General Partner to a third party. The new partners of our General Partner would then be in a position to replace the Board of Directors and officers of our General Partner with their own choices and to control the decisions taken by the Board of Directors and officers of our General Partner.

We may issue an unlimited number of additional units without unitholders’ approval, which would dilute the ownership interest of existing unitholders.

Our General Partner, without the approval of our unitholders, may cause us to issue an unlimited number of additional common units or other equity securities. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:


•	our unitholders’ proportionate ownership interest in us will decrease;


•	the amount of cash available for distribution on each unit may decrease;


•	the relative voting strength of each previously outstanding unit may be diminished; and


•	the market price of our common units may decline.

Our General Partner may, in its sole discretion, approve the issuance of partnership securities and specify the terms of such partnership securities.

Pursuant to our partnership agreement, our General Partner has the ability, in its sole discretion and without the approval of the Unitholders, to approve the issuance of securities by the Partnership at any time and to specify the terms and conditions of such securities. The securities authorized to be issued may be issued in one or more classes or series, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of partnership securities), as shall be determined by our General Partner, including:


•	the right to share in Partnership’s profits and losses;


•	the right to share in the Partnership’s distributions;


•	the rights upon dissolution and liquidation of the Partnership;


•	whether, and the terms upon which, the Partnership may redeem the securities;


•	whether the securities will be issued, evidenced by certificates and assigned or transferred; and


•	the right, if any, of the security to vote on matters relating to the Partnership, including matters relating to the relative rights, preferences and privileges of such security.

Please see “—We may issue an unlimited number of additional units without unitholders’ approval, which would dilute the ownership interest of existing unitholders.” above.

Our General Partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.

If at any time our General Partner and its affiliates own more than 80% of our common units, our General Partner will have the right, but not the obligation (which it may assign to any of its affiliates or to us) to acquire all, but not less than all, of our common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their common units. As of February 19, 2015, affiliates of our General Partner owned 21.5% of the total number of our outstanding common units.

Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.

Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our General Partner or to take other action under our partnership agreement constituted participation in the “control” of our business.

Our General Partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our General Partner. Our partnership agreement allows the general partner to incur obligations on our behalf that are expressly non-recourse to the general partner. Our General

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Partner has entered into such limited recourse obligations in most instances involving payment liability and intends to do so in the future.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets. Additionally, we are not able to control the amounts of cash that our joint ventures may distribute to us.

We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the partnership interests and the equity in our subsidiaries. As a result, our ability to make required payments on our debt obligations and distributions on our common units depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, our revolving credit facility, the indentures governing our senior notes and applicable state partnership and limited liability company laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount at maturity of our debt obligations, to repurchase our debt obligations upon the occurrence of a change of control or make distributions on our common units, we may be required to adopt one or more alternatives, such as a refinancing of our debt obligations or borrowing funds to make distributions on our common units. We cannot assure unitholders that we would be able to borrow funds to make distributions on our common units.

Additionally, the ability of our joint ventures to make distributions to us may be restricted by, among other things, the terms of each such entity’s partnership or limited liability company agreement, as applicable, and any debt instruments entered into by such entity as well as applicable state partnership or limited liability company laws, as applicable, and other laws and regulations. We do not control the amounts of cash that our joint ventures may distribute to us.

The credit and risk profile of our General Partner and its owners could adversely affect our credit ratings and profile.

The credit and business risk profiles of our General Partner and of ETE as the indirect owner of our General Partner, may be factors in credit evaluations of us as a publicly traded limited partnership due to the significant influence of our General Partner and ETE over our business activities, including our cash distributions, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our General Partner and ETE, including the degree of their financial leverage and their dependence on cash flow from us to service their indebtedness.

ETE has significant indebtedness outstanding and is dependent principally on the cash distributions from its general and limited partner interests in us and ETP to service such indebtedness. Any distributions by us to ETE will be made only after satisfying our then current obligations to our creditors. Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect the separateness of us and our General Partner from the entities that control our General Partner (ETE and its general partner), our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of such entities were viewed as substantially lower or riskier than ours.

TAX RISKS TO OUR UNITHOLDERS

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states or local entities. If the IRS treats us as a corporation or we become subject to a material amount of entity-level taxation for state or local tax purposes, it would substantially reduce the amount of cash available for payment for distributions on our common units.

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

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. At the federal level, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for 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

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of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay a Texas margin tax. Imposition of such a tax on us by Texas, and, if applicable, by any other state, will reduce our cash available for distribution to our common unitholders.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be reduced to reflect the impact of that law on us.

A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to you.

The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our cash available for distribution.

Unitholders may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability that results from that income.

Tax gain or loss on disposition of common units could be more or less than expected.

If a unitholder sells his common units, he will recognize a gain or loss equal to the difference between the amount realized and his tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income he was allocated for a common unit, which decreased his tax basis in that common unit, will, in effect, become taxable income to him if the common unit is sold at a price greater than his tax basis in that common unit, even if the price is less than his original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells his common units, he may incur a tax liability in excess of the amount of cash he receives from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If a unitholder is a tax-exempt entity or a non-U.S. person, he should consult his tax advisor before investing in our common units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax deductions available to a unitholder. It also could affect the timing of these tax deductions or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns.

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We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. However, recently proposed Treasury Regulations provide a safe harbor for publicly traded partnerships pursuant to which a similar monthly convention is allowed. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, if the IRS were to challenge our method of allocating income, gain, loss and deduction between transferors and transferees, or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation and allocation methodologies that may result in a shift of income, gain, loss and deductions between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our General Partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

In addition, for purposes of determining the amount of the unrealized gain or loss to be allocated to the capital accounts of our unitholders and our General Partner, we will reduce the fair market value of our property (to the extent of any unrealized income or gain in our property that has not previously been reflected in the capital accounts) to reflect the incremental share of such fair market value that would be attributable to the holders of our outstanding convertible redeemable preferred units if all of such convertible redeemable preferred units were converted into common units as of such date. Consequently, a holder of common units may be allocated less unrealized gain in connection with an adjustment of the capital accounts than such holder would have been allocated if there were no outstanding convertible redeemable preferred units. Following the conversion of our convertible redeemable preferred units into common units, items of gross income and gain (or gross loss and deduction) will be specially allocated to the holders of such common units to reflect differences between the capital accounts maintained with respect to such convertible redeemable preferred units and the capital accounts maintained with respect to common units. This method of maintaining capital accounts and allocating income, gain, loss and deduction with respect to the convertible redeemable preferred units is intended to comply with proposed Treasury Regulations. However, these proposed Treasury Regulations are not legally binding and are subject to change until final Treasury Regulations are issued. Accordingly, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been reached, multiple sales of the same unit will be counted only once. Although a termination likely will cause our unitholders to realize an increased amount of taxable income as a percentage of the cash distributed to them, we anticipate that the ratio of taxable income to distributions for future years will return to levels commensurate with our prior tax periods. However, any future termination of our partnership could have similar consequences. Additionally, in the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. The position that there was a partnership termination does not affect our classification as a partnership for federal income tax purposes; however, we are treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to prevail that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminates requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

You may be subject to state and local taxes and tax return filing requirements.

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We own assets and do business in Texas, Oklahoma, Kansas, Louisiana, West Virginia, Arkansas, Colorado, Alabama, California, Mississippi, New Mexico, Utah and Pennsylvania. Each of these states, other than Texas, currently imposes a personal income tax as well as an income tax on corporations and other entities. Texas imposes a margin tax on corporations, limited partnerships, limited liability partnerships and limited liability companies. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns required as a result of being a unitholder.

RISKS RELATED TO OUR PROPOSED MERGER WITH ETP

We and ETP are subject to contractual restrictions while the merger is pending, which could materially and adversely affect each party’s business and operations, and, pending the completion of the transaction, our business and operations could be materially and adversely affected.

Under the terms of our merger agreement with ETP, we are subject to certain restrictions on the conduct of our business prior to completing the transaction, which may adversely affect our ability to execute certain of our business strategies without first obtaining consent from ETP, including our ability in certain cases to enter into contracts, incur capital expenditures or grow our business. The merger agreement also restricts our ability to solicit, initiate or encourage alternative acquisition proposals with any third party and may deter a potential acquirer from proposing an alternative transaction or may limit our ability to pursue any such proposal. Such limitations could negatively affect our business and operations prior to the completion of the proposed transaction. Furthermore, the process of planning to integrate two businesses and organizations for the post-merger period can divert management attention and resources and could ultimately have an adverse effect on us.

In connection with the pending merger, it is possible that some customers, suppliers and other persons with whom we have business relationships may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationship with us as a result of the transaction, which could negatively affect our revenues, earnings and cash flows, as well as the market price of our common units, regardless of whether the transaction is completed.

We may have difficulty attracting, motivating and retaining executives and other employees in light of the merger.

Uncertainty about the effect of the merger on our employees may have an adverse effect on us and the combined organization. This uncertainty may impair our ability to attract, retain and motivate personnel until the merger is completed. Employee retention may be particularly challenging during the pendency of the merger, as employees may feel uncertain about their future roles with the combined organization. In addition, we may have to provide additional compensation in order to retain employees. If our employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to become employees

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of the combined organization, the combined organization’s ability to realize the anticipated benefits of the merger could be reduced. Also, if we fail to complete the merger, it may be difficult and expensive to recruit and hire replacements for such employees.

We will incur substantial transaction-related costs in connection with the merger.

We expect to incur a number of non-recurring merger-related costs associated with completing the merger, combining the operations of the two companies, and achieving desired synergies. These fees and costs will be substantial. Non-recurring transaction costs include, but are not limited to, fees paid to legal, financial and accounting advisors, filing fees and printing costs. Additional unanticipated costs may be incurred in the integration of our and ETP’s businesses. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction-related costs over time. Thus, any net benefit may not be achieved in the near term, the long term or at all.

Failure to successfully combine our and ETP’s businesses in the expected time frame may adversely affect the future results of the combined organization, and, consequently, the value of the ETP common units that our unitholders receive as the merger consideration.

The success of the proposed merger will depend, in part, on the ability of ETP to realize the anticipated benefits and synergies from combining our and ETP’s businesses. To realize these anticipated benefits, the businesses must be successfully combined. If the combined organization is not able to achieve these objectives, or is not able to achieve these objectives on a timely basis, the anticipated benefits of the merger may not be realized fully or at all. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the merger.

Failure to complete the merger, or significant delays in completing the merger, could negatively affect the trading price of our common units and our future business and financial results.

Completion of the merger is not assured and is subject to risks, including the risks that approval of the merger by our unitholders or governmental agencies is not obtained or that other closing conditions are not satisfied. If the merger is not completed, or if there are significant delays in completing the merger, it could negatively affect the trading price of our common units and our future business and financial results, and we will be subject to several risks, including the following:


•	liability for damages to ETP under the terms and conditions of the merger agreement;


•	negative reactions from the financial markets, including declines in the price of our common units due to the fact that current prices may reflect a market assumption that the merger will be completed;


•	having to pay certain significant costs relating to the merger, including a termination fee of $450 million; and


•	the attention of our management will have been diverted to the merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us.

Lawsuits have been filed against us, our General Partner, our General Partner’s board of directors, ETP, ETP GP. and ETE challenging the merger, and any injunctive relief or adverse judgment for monetary damages could prevent the merger from occurring or could have a material adverse effect on us, ETP or the combined company following the merger.

The Partnership, the General Partner, the directors of the General Partner, ETP, ETP GP, and ETE are named defendants in purported class actions and derivative petitions brought by purported Partnership unitholders in Dallas County, Texas, generally alleging claims of breach of duties under the partnership agreement, breach of the implied covenant of good faith and fair dealing in connection with the merger transactions, and aiding and abetting arising out of the defendants’ pursuit of the merger by way of an allegedly conflicted and unfair process. Similar lawsuits have been filed in the United States District Court for the Northern District of Texas. The plaintiffs in these lawsuits seek to enjoin the defendants from proceeding with or consummating the merger and, to the extent that the merger is implemented before relief is granted, plaintiffs seek to have the merger rescinded. Plaintiffs also seek money damages and attorneys’ fees. One of the conditions to the completion of the merger is that no order, decree, or injunction of any court or agency of competent jurisdiction shall be in effect, and no law shall have been enacted or adopted, that enjoins, prohibits, or makes illegal consummation of any of the transactions contemplated by the merger agreement. A preliminary injunction could delay or jeopardize the completion of the merger, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the merger. An adverse judgment for rescission or for monetary damages could have a material adverse effect on us, ETP or the combined company following the merger.

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Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Substantially all of our pipelines (including those of HPC, MEP, Lone Star, Ranch JV, Aqua - PVR, ORS, Mi Vida JV and Sweeny JV) are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our pipelines were built were purchased in fee. These pipelines are used in our gathering and processing segment, natural gas transportation segment and NGL Services segment.

We believe that we have satisfactory title to all our assets. Record title to some of our assets may continue to be held by prior owners until we have made the appropriate filings in the jurisdictions in which such assets are located. Obligations under our credit facility are secured by substantially all of our assets and are guaranteed by the Partnership. Title to our assets may also be subject to other encumbrances. We believe that none of such encumbrances should materially detract from the value of our properties or our interest in those properties or should materially interfere with our use of them in the operation of our business.

Our executive offices occupy two entire floors and half of another floor in an office building at 2001 Bryan Street, Suite 3700, Dallas, Texas, 75201, under a lease that expires on October 31, 2019. We also maintain regional offices located on leased premises in Louisiana, Texas, Tennessee, and Pennsylvania. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.

For additional information regarding our properties, read “Item 1. Business.”

Item 3. Legal Proceedings

We are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal or governmental proceedings and litigation arising in the ordinary course of business. These claims and lawsuits in aggregate are not expected to have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.

For a description of legal proceedings, see Note 12 in the Notes to our Consolidated Financial Statements.

We maintain insurance policies with insurers in amounts and with coverages and deductibles that we, with the advice of our insurance advisers and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities

Market Price of and Distributions on the Common Units and Related Unitholder Matters

Our common units represent limited partnership interests and were first offered and sold to the public on February 3, 2006. Our common units are listed on the NYSE under the symbol “RGP.” As of February 19, 2015, the number of holders of record of common units was 150, with 320,445,553 units held in street name.

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The following table sets forth, for the periods indicated, the high and low quarterly sales prices per common unit, as reported on the NYSE:



	Price Ranges				Cash Distributions
Period	High		Low		(per common unit)
2014
Fourth Quarter	$	32.86	$	22.07	$	0.5025
Third Quarter	33.57		29.54		0.5025
Second Quarter	32.22		25.67		0.4900
First Quarter	27.91		25.29		0.4800

2013
Fourth Quarter	$	29.52	$	23.86	$	0.4750
Third Quarter	29.35		25.57		0.4700
Second Quarter	27.15		23.70		0.4650
First Quarter	25.66		22.03		0.4600

2012
Fourth Quarter	$	24.35	$	20.58	$	0.4600
Third Quarter	24.46		21.93		0.4600
Second Quarter	25.29		20.61		0.4600
First Quarter	27.40		23.59		0.4600

Class F Units

In connection with the SUGS Acquisition, we issued 6,274,483 Class F units. The Class F units are not entitled to participate in the Partnership’s distributions for twenty-four months post-transaction closing. The Class F units were issued in a private placement conducted in accordance with the exemption from registration requirements of the Securities Act of 1933, as amended, under Section 4(a)(2) thereof. The Class F units will convert into common units on a one-for-one basis in May 2015.

Cash Distribution Policy

We distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below. If we do not have sufficient cash to pay our distributions as well as satisfy our other operational and financial obligations, our General Partner has the ability to reduce or eliminate the distribution paid on our common units so that we may satisfy such obligations, including payments on our debt instruments.

Available cash generally means, for any quarter ending prior to liquidation of the Partnership, all cash on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:


•	provide for the proper conduct of our business;


•	comply with applicable law or any partnership debt instrument or other agreement; or


•	provide funds for distributions to unitholders and the General Partner in respect of any one or more of the next four quarters.

In addition to distributions on its General Partner interest, our General Partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds specified levels. The partnership agreement requires that we make distributions of Available Cash from operating surplus for any quarter after the subordination period in the following manner:


•	first, to all unitholders and to the General Partner, pro rata, until each unitholder receives a minimum quarterly distribution of $0.35 per unit outstanding for that quarter;


•	second, to all unitholders and to the General Partner, pro rata, until each unitholder receives a total of $0.4025 per unit outstanding for that quarter;

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•	third, (i) to the General Partner in accordance with its percentage interest, (ii) 13% to holders of the IDRs, pro rata, and (iii) to all unitholders a percentage equal to 100% less the percentages applicable to the General Partner and holders of the IDRs, until each unitholder receives a total of $0.4375 per unit outstanding for that quarter;


•	fourth, (i) to the General Partner in accordance with its percentage interest, (ii) 23% to holders of the IDRs, pro rata, and (iii) to all unitholders a percentage equal to 100% less the percentages applicable to the General Partner and holders of the IDRs, until each unitholder receives a total of $0.5250 per unit outstanding for that quarter; and


•	thereafter, (i) to the General Partner in accordance with its percentage interest, (ii) 48% to holders of the IDRs, pro rata, and (iii) to all unitholders a percentage equal to 100% less the percentages applicable to the General Partner and holders of the IDRs.

In each case, the amount of the distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.

Under the terms of the agreements governing our debt, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for further discussion regarding the restrictions on distributions.

Recent Sales of Unregistered Securities

None.

Issuer Purchases of Equity Securities

None.

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Item 6. Selected Financial Data

The historical financial information presented below was derived from our audited consolidated financial statements as of and for the periods presented. See “Item 7. Management’s Discussions and Analysis of Financial Condition and Results of Operations” for a discussion of why our results may not be comparable, either from period to period or going forward. All tabular dollar amounts, except per unit data, are in millions.



	Successor															Predecessor
	Year Ended December 31, 2014			Year Ended December 31, 2013			Year Ended December 31, 2012			Year Ended December 31, 2011			Period from Acquisition (May 26, 2010) to December 31, 2010			Period from January 1, 2010 to May 25, 2010
Statement of Operations Data:
Total revenues	$	4,951		$	2,521		$	2,000		$	1,434		$	716		$	505
Total operating costs and expenses	4,968			2,466			1,970			1,394			702			485
Operating (loss) income	(17		)	55			30			40			14			20
Other income and deductions:
Income from unconsolidated affiliates	195			135			105			120			54			16
Interest expense, net	(304		)	(164		)	(122		)	(103		)	(48		)	(35		)
Loss on debt refinancing, net	(25		)	(7		)	(8		)	—			(16		)	(2		)
Other income and deductions, net	12			7			29			17			(8		)	(4		)
(Loss) income from continuing operations before income taxes	$	(139	)	$	26		$	34		$	74		$	(4	)	$	(5	)
Income tax expense (benefit)	3			(1		)	—			—			1			—
(Loss) income from continuing operations	$	(142	)	$	27		$	34		$	74		$	(5	)	$	(5	)
Discontinued operations:
Net loss from operations of east Texas assets	—			—			—			—			(1		)	—
Net (loss) income	$	(142	)	$	27		$	34		$	74		$	(6	)	$	(5	)
Net income attributable to noncontrolling interest	(15		)	(8		)	(2		)	(2		)	—			—
Net (loss) income attributable to Regency Energy Partners LP	$	(157	)	$	19		$	32		$	72		$	(6	)	$	(5	)
Amounts attributable to Series A Preferred Units	4			6			10			8			5			3
General partner’s interest, including IDRs	31			11			9			7			3			1
Beneficial conversion feature for Class F units	7			4			—			—			—			—
Pre-acquisition loss from SUGS allocated to predecessor equity	—			(36		)	(14		)	—			—			—
Limited partners’ interest in net (loss) income	$	(199	)	$	34		$	27		$	57		$	(14	)	$	(9	)

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	Successor												Predecessor
	Year Ended December 31, 2014			Year Ended December 31, 2013		Year Ended December 31, 2012		Year Ended December 31, 2011		Period from Acquisition (May 26, 2010) to December 31, 2010			Period from January 1, 2010 to May 25, 2010
Basic and diluted (loss) income from continuing operations per unit:
Basic (loss) income from continuing operations per common unit	$	(0.57	)	$	0.17	$	0.16	$	0.39	$	(0.09	)	$	(0.10	)
Diluted (loss) income from continuing operations per common unit	(0.57		)	0.17		0.13		0.32		(0.09		)	(0.10		)
Distributions per common unit	1.975			1.87		1.84		1.81		0.89			0.89
Basic and diluted loss on discontinued operations per common unit	—			—		—		—		(0.01		)	—
Basic and diluted net (loss) income per unit:
Basic net (loss) income per common unit	$	(0.57	)	$	0.17	$	0.16	$	0.39	$	(0.10	)	$	(0.10	)
Diluted net (loss) income per common unit	(0.57		)	0.17		0.13		0.32		(0.10		)	(0.10		)
Income per Class F unit due to beneficial conversion feature	1.08			0.72		—		—		—			—



	December 31, 2014		December 31, 2013		December 31, 2012		December 31, 2011		December 31, 2010
Balance Sheet Data:
Property, plant and equipment, net	$	9,217	$	4,418	$	3,686	$	1,886	$	1,660
Total assets	17,103		8,782		8,123		5,568		4,770
Long-term debt (non-current portion only)	6,641		3,310		2,157		1,687		1,141
Series A Preferred Units	33		32		73		71		71
Partners’ capital and noncontrolling interest	9,585		4,916		5,340		3,531		3,294



	Successor															Predecessor
	Year Ended December 31, 2014			Year Ended December 31, 2013			Year Ended December 31, 2012			Year Ended December 31, 2011			Period from Acquisition (May 26, 2010) to December 31, 2010			Period from January 1, 2010 to May 25, 2010
Cash Flow Data:
Net cash flows provided by (used in):
Operating activities	$	719		$	436		$	324		$	254		$	80		$	89
Investing activities	(2,169		)	(1,393		)	(807		)	(955		)	(297		)	(148		)
Financing activities	1,455			923			535			693			203			72
Other Financial Data:
Adjusted total segment margin⁽¹⁾	$	1,399		$	729		$	602		$	417		$	235		$	154
Adjusted EBITDA⁽¹⁾	1,172			608			517			420			218			108
Maintenance capital expenditures	98			48			58			22			7			8


(1)	See “—Non-GAAP Financial Measures” for a reconciliation to its most directly comparable GAAP measure.

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Non-GAAP Financial Measures

We include in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” the following non-GAAP financial measures: EBITDA, adjusted EBITDA, total segment margin, and adjusted total segment margin. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures as calculated and presented in accordance with GAAP.

We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation, depletion and amortization expense, and impairment expense. We define adjusted EBITDA as EBITDA plus or minus the following:


•	non-cash loss (gain) from commodity and embedded derivatives;


•	non-cash unit-based compensation;


•	loss (gain) on asset sales, net;


•	loss on debt refinancing, net;


•	other non-cash (income) expense, net;


•	acquisition costs;


•	our interest in ELG and ORS adjusted EBITDA less EBITDA attributable to ELG and ORS; and


•	our interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates.

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These measures are used as supplemental measures by our management and by external users of our financial statements such as investors, banks, research analysts and others, to assess:


•	financial performance of our assets without regard to financing methods, capital structure or historical cost basis;


•	the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and General Partner;


•	our operating performance and return on capital as compared to those of 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.

Neither EBITDA nor adjusted EBITDA should be considered an alternative to, or more meaningful than net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA and adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA or adjusted EBITDA in the same manner. Adjusted EBITDA is the starting point in determining distributable cash flow, which is an important non-GAAP financial measure for a publicly traded Partnership.

EBITDA and adjusted EBITDA do not include interest expense, income tax expense or depreciation, depletion and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation, depletion and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as EBITDA and adjusted EBITDA, to evaluate our performance.

We define segment margin, generally, as revenues minus cost of sales. We calculate our Gathering and Processing segment margin and Natural Gas Transportation segment margin as revenues generated from operations less the cost of natural gas and NGLs purchased and other costs of sales, including third-party transportation and processing fees. We do not record segment margin for our investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV, Aqua - PVR, Mi Vida JV and Sweeny JV) because we record our ownership percentages of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting. We calculate our Contract Services segment margin as revenues minus direct costs, primarily compressor unit repairs, associated with those revenues. Our Natural Resources segment margin is generally equal to total revenues as there is typically minimal cost of sales associated with the management and leasing of these properties. We calculate total segment margin as the sum of segment margin of our segments less intersegment eliminations. We define adjusted segment margin as segment margin adjusted for non-cash (gains) losses from commodity derivatives, the 40% of ELG margin attributable to the holder of the noncontrolling interest, the 25% ORS margin attributable to the holder of the noncontrolling interest, our 33.33% portion of Ranch JV margin, and our 50% portion of the Mi Vida JV margin. Our adjusted total segment margin equals the sum of our operating segments’ adjusted segment margins or segment margins, as applicable, including intersegment eliminations.

Total segment margin and adjusted total segment margin are included as a supplemental disclosure because they are primary performance measures used by our management as they represent the result of product sales, service fee revenues and product purchases, a key component of our operations. We believe total segment margin and adjusted total segment margin are important measures because they are directly related to our volumes and commodity price changes. Operation and maintenance expense is a separate measure used by management to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operation and maintenance expenses. These expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenue in calculating total segment margin and adjusted total segment margin because we separately evaluate commodity volume and price changes in these margin amounts. As an indicator of our operating performance, total segment margin or adjusted total segment margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our total segment margin and adjusted total segment margin may not be comparable to a similarly titled measure of another company because other entities may not calculate these measures in the same manner.

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	Successor															Predecessor
	Year Ended December 31, 2014			Year Ended December 31, 2013			Year Ended December 31, 2012			Year Ended December 31, 2011			Period from Acquisition (May 26, 2010) to December 31, 2010			Period from January 1, 2010 to May 25, 2010
Reconciliation of “Adjusted EBITDA” to net cash flows provided by operating activities and net (loss) income
Net cash flows provided by operating activities	$	719		$	436		$	324		$	254		$	80		$	89
Add (deduct):
Depreciation, depletion and amortization, including debt issuance cost write-off and amortization and bond premium write-off and amortization	(525		)	(293		)	(259		)	(175		)	(78		)	(51		)
Income from unconsolidated affiliates	195			135			105			120			54			16
Derivative valuation change	93			(6		)	12			21			(33		)	(12		)
Gain (loss) on assets sales, net	1			(2		)	(3		)	2			—			—
Unit-based compensation expenses	(10		)	(7		)	(5		)	(3		)	(2		)	(12		)
Revaluation of unconsolidated affiliate upon acquisition	6			—			—			—			—			—
Goodwill impairment	(370		)	—			—			—			—			—
Trade accounts receivable, accrued revenues and related party receivables	(28		)	96			—			8			—			11
Other current assets and other current liabilities	(34		)	54			(10		)	(11		)	13			(25		)
Trade accounts payable, accrued cost of gas and liquids, related party payables, and deferred revenues	16			(119		)	(18		)	(23		)	15			(9		)
Distributions of earnings received from unconsolidated affiliates	(204		)	(142		)	(121		)	(119		)	(57		)	(12		)
Cash flow changes in other assets and liabilities	(1		)	(125		)	9			—			2			—
Net (loss) income	$	(142	)	$	27		$	34		$	74		$	(6	)	$	(5	)
Add (deduct):
Interest expense, net	304			164			122			103			48			35
Depreciation, depletion and amortization	541			287			252			169			77			46
Income tax expense (benefit)	3			(1		)	—			—			1			—
Goodwill impairment	370			—			—
EBITDA	$	1,076		$	477		$	408		$	346		$	120		$	76

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	Successor															Predecessor
	Year Ended December 31, 2014			Year Ended December 31, 2013			Year Ended December 31, 2012			Year Ended December 31, 2011			Period from Acquisition (May 26, 2010) to December 31, 2010			Period from January 1, 2010 to May 25, 2010
EBITDA	$	1,076		$	477		$	408		$	346		$	120		$	76
Add (deduct):
Partnership’s interest in unconsolidated affiliates adjusted EBITDA ^{(1) (2) (3) (4) (5) (6)}	325			250			222			213			102			21
Income from unconsolidated affiliates	(195		)	(135		)	(105		)	(120		)	(54		)	(16		)
Non-cash (gain) loss from commodity and embedded derivatives	(92		)	3			(19		)	(18		)	31			11
Loss on debt refinancing, net	25			7			8			—			16			2
(Gain) loss on assets sales, net	(1		)	2			3			(2		)	—			—
Other, net	34			4			—			1			3			14
Adjusted EBITDA	$	1,172		$	608		$	517		$	420		$	218		$	108

(1) 100% of HPC’s Adjusted EBITDA is calculated as follows:
Net income	$	67		$	72		$	70		$	109		$	72		$	35
Depreciation and amortization	36			37			36			35			20			12
Interest expense	13			5			2			1