10-K 1 xtex201310-k.htm 10-K XTEX 2013 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, 2013
OR
o
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: 000-50067
CROSSTEX ENERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware
(State of organization)
 
16-1616605
(I.R.S. Employer Identification No.)
2501 CEDAR SPRINGS
DALLAS, TEXAS
(Address of principal executive offices)
 
75201
(Zip Code)
(Registrant's telephone number, including area code)
(214) 953-9500
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of Each Class
 
Name of Exchange on which Registered
Common Units Representing Limited
Partnership Interests
 
The NASDAQ Global Select Market
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None.
Indicate by check mark if registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    No o
Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý
Indicate by check mark whether 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 o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Securities Exchange Act. (Check one):
Large accelerated filer ý
 
Accelerated filer o
 
Non-accelerated filer o
 (Do not check if a
smaller reporting company)
 
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o    No ý
The aggregate market value of the Common Units representing limited partner interests held by non-affiliates of the registrant was approximately $1,263,121,436 on June 30, 2013, based on $20.32 per unit, the closing price of the Common Units as reported on The NASDAQ Global Select Market on such date.
At February 14, 2014, there were 91,534,187 common units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
None.
 
 
 
 
 

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TABLE OF CONTENTS
Item
 
DESCRIPTION
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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CROSSTEX ENERGY, L.P.
PART I
Item 1.    Business
General
Crosstex Energy, L.P. is a publicly traded Delaware limited partnership formed in 2002. Our common units are traded on The NASDAQ Global Select Market under the symbol "XTEX". Our business activities are conducted through our subsidiary, Crosstex Energy Services, L.P., a Delaware limited partnership (the "Operating Partnership"), and the subsidiaries of the Operating Partnership. Our executive offices are located at 2501 Cedar Springs, Dallas, Texas 75201, and our telephone number is (214) 953-9500. Our Internet address is www.crosstexenergy.com. We post the following filings in the "Investors" section of our website as soon as reasonably practicable after they are electronically filed with or furnished to the Securities and Exchange Commission: our annual report on Form 10-K; our quarterly reports on Form 10-Q; our current reports on Form 8-K; and any amendments to those reports or statements filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. All such filings on our website are available free of charge. In this report, the terms "Partnership" and "Registrant," as well as the terms "our," "we," "us" and "its," are sometimes used as abbreviated references to Crosstex Energy, L.P. itself or Crosstex Energy, L.P. together with its consolidated subsidiaries, including the Operating Partnership.
Crosstex Energy GP, LLC, a Delaware limited liability company, is our general partner. Crosstex Energy GP, LLC manages our operations and activities. Crosstex Energy GP, LLC is a wholly owned subsidiary of Crosstex Energy, Inc., or CEI. Crosstex Energy, Inc.'s shares are traded on The NASDAQ Global Select Market under the symbol "XTXI."
The following diagram depicts the organization and ownership of the Partnership as of December 31, 2013.

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The following terms as defined generally are used in the energy industry and in this document:
/d = per day
Bbls = barrels
Bcf = billion cubic feet
Btu = British thermal units
CO2= Carbon dioxide
Gal = gallon
Mcf = thousand cubic feet
MMBtu = million British thermal units
MMcf = million cubic feet
NGL = natural gas liquid and natural gas liquids
Capacity volumes for our facilities are measured based on physical volume and stated in cubic feet (Bcf, Mcf or MMcf). Throughput volumes are measured based on energy content and stated in British thermal units (Btu or MMBtu). A volume capacity of 100 MMcf generally correlates to volume capacity of 100,000 MMBtu. Fractionated volumes are measured based on physical volumes and stated in gallons (Gal). Crude oil, condensate and brine services volumes are measured based on physical volume and stated in barrels (Bbls).
Our Operations
We are a Delaware limited partnership formed on July12, 2002. We primarily focus on providing midstream energy services, including gathering, transmission processing, fractionation and marketing, to producers of natural gas, NGLs, crude oil and condensate. We also provide crude oil, condensate and brine services to producers. Our midstream energy asset network includes approximately 3,600 miles of pipelines, nine natural gas processing plants, four fractionators, 3.1 million barrels of NGL cavern storage, rail terminals, barge terminals, truck terminals and a fleet of approximately 100 trucks. We manage and report our activities primarily according to geography. We have five reportable segments: (1) South Louisiana processing, crude and NGL, or PNGL, which includes our processing and NGL assets in south Louisiana; (2) Louisiana, or LIG, which includes our pipelines and processing plants located in Louisiana; (3) North Texas, or NTX, which includes our activities in the Barnett Shale and the Permian Basin; (4) Ohio River Valley, or ORV, which includes our activities in the Utica and Marcellus Shales; and (5) Corporate Segment, or Corporate, which includes our equity investment in Howard Energy Partners, or HEP, in the Eagle Ford Shale and our general partnership property and expenses. See Note 12 to the consolidated financial statements for financial information about these operating segments.
We connect the wells of natural gas producers in our market areas to our gathering systems, process natural gas for the removal of NGLs, fractionate NGLs into purity products and market those products for a fee, transport natural gas and ultimately provide natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply sources and sell that natural gas to utilities, industrial consumers, other marketers and pipelines. We operate processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems under a variety of fee arrangements. We provide a variety of crude oil and condensate services throughout the ORV which include crude oil and condensate gathering via pipelines, barges, rail and trucks and oilfield brine disposal. We also have crude oil and condensate terminal facilities in south Louisiana that provide access for crude oil and condensate producers to the premium markets in this area. Our gas gathering systems consist of networks of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. Our transmission pipelines primarily receive natural gas from our gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. We also have NGL transmission lines that transport NGLs from east Texas and our south Louisiana processing plants to our fractionators in south Louisiana. Our crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barges that, in exchange for a fee, transport oil from a producer site to an end user. Our processing plants remove NGLs and CO2 from a natural gas stream and our fractionators separate the NGLs into separate NGL products, including ethane, propane, iso-butane, normal butane and natural gasoline.
Our assets include the following:
North Texas Assets (including Permian Basin assets). Our north Texas assets consist of gathering systems with total capacity of approximately 1.1 Bcf/d, processing facilities with a total processing capacity of approximately 315 MMcf/d and a transmission pipeline with a capacity of approximately 375 MMcf/d.
LIG System.  Our LIG system is one of the largest intrastate pipeline systems in Louisiana, consisting of approximately 2,000 miles of mainly transmission pipelines extending from the Haynesville Shale in north Louisiana to onshore production in south central and southeast Louisiana which have approximately 2.0 Bcf/d of

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capacity. The LIG system also includes processing facilities with a total processing capacity of 335 MMcf/d and 10,800 Bbls/d of NGL fractionation capcity.
South Louisiana Processing and NGL Assets.  Our south Louisiana natural gas processing and liquid assets include approximately 1.4 Bcf/d of processing capacity, 83,000 Bbls/d of fractionation capacity, 3.1 million barrels of underground NGL storage, 570 miles of liquids transport lines and a crude oil terminal with a total capacity of 15,600 Bbls/d.
Ohio River Valley Assets.  Our Ohio River Valley assets include a 4,500-barrel-per-hour crude oil and condensate barge loading terminal on the Ohio River, a 20-spot operation crude oil and condensate rail loading terminal on the Ohio Central Railroad network and approximately 200 miles of crude oil and condensate pipelines in Ohio and West Virginia. The assets also include 500,000 barrels of above ground storage and a trucking fleet of approximately 100 vehicles comprised of both semi and straight trucks. We have eight existing brine disposal wells with an injection capacity of approximately 10,000 Bbls/d. We currently hold one additional brine well permit in Ohio.
Our Business Strategy
Our business strategy consists of two overarching objectives, which are to maximize earnings and growth of our existing businesses and enhance the scale and diversification of our assets. As part of enhancing our scale and diversification, we have concentrated on expanding our NGL business, growing a crude oil and condensate business and developing our gas processing and transportation business in rich gas areas. We believe increasing our scale and diversification will strengthen us as a company because we believe it will lead to less reliance on any single geographic area, provide us with a better balance between business driven by crude oil and natural gas, offer us greater opportunities from a broader asset base and provide us with more sustainable fee-based cash flows.
Our strategies include the following:
Maximize earnings and growth of our existing businesses. We intend to leverage our franchise position, infrastructure and customer relationships in our existing areas of operation by expanding our existing systems to meet new or increased demand for our gathering, transmission, processing and marketing services.
Enhance the scale and diversification of our assets. We look to grow and diversify our business through acquiring and/or building assets in new areas that will serve as a platform for future growth with a focus on emerging shale plays and other areas with NGL, crude oil and condensate exposure.
Devon Energy Transaction
On October 21, 2013, the Partnership and the Operating Partnership entered into a Contribution Agreement (the “Contribution Agreement”) with Devon Energy Corporation (“Devon”) and certain of its wholly-owned subsidiaries pursuant to which two of Devon’s subsidiaries would contribute to the Operating Partnership 50% of the outstanding equity interests in EnLink Midstream Holdings, LP (formerly known as Devon Midstream Holdings, L.P.), a wholly-owned subsidiary of Devon referred to herein as “Midstream Holdings,” and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC (formerly known as Devon Midstream Holdings GP, L.L.C.), the general partner of Midstream Holdings (“Midstream Holdings GP” and, together with Midstream Holdings and their subsidiaries, the “Midstream Group Entities”) in exchange for the issuance by the Partnership of 120,542,441 units representing a new class of limited partnership interests in the Partnership (collectively, the “Contribution”) with a value of approximately $2.4 billion based on the volume weighted average closing prices of our common units for the 20 trading days prior to the announcement of the transaction. Upon completion of the Contribution, Devon and its affiliates will own approximately 53% of the limited partner interests in the Partnership, with approximately 39% of the outstanding limited partner interests held by the Partnership's public unitholders and approximately 7% of the outstanding limited partner interests (and the approximate 1% general partner interest) held indirectly by EnLink Midstream (as defined below).
The Midstream Group Entities own Devon’s midstream assets in the Barnett Shale in North Texas, the Cana and Arkoma Woodford Shales in Oklahoma and Devon’s interest in Gulf Coast Fractionators in Mont Belvieu, Texas. These assets consist of natural gas gathering and transportation systems, natural gas processing facilities and NGL fractionation facilities located in Texas and Oklahoma. Midstream Holdings' primary assets consist of three processing facilities with 1.3 Bcf/d of natural gas processing capacity, approximately 3,685 miles of pipelines with aggregate capacity of 2.9 Bcf/d and fractionation facilities with up to 160 MBbls/d of aggregate NGL fractionation capacity.
In connection with the Contribution Agreement, CEI entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Devon and certain of its wholly-owned subsidiaries, EnLink Midstream, LLC (formerly known as New Public Rangers, L.L.C.), a holding company newly formed by Devon (“EnLink Midstream”), Rangers Merger Sub, Inc., a wholly-owned subsidiary of EnLink Midstream (“Rangers Merger Sub”), and Boomer Merger Sub, Inc., a wholly-owned subsidiary of EnLink Midstream

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(“Boomer Merger Sub”), pursuant to which Rangers Merger Sub will merge with and into CEI, and Boomer Merger Sub will merge with and into Acacia Natural Gas Corp I, Inc., a wholly-owned subsidiary of Devon ("New Acacia") (collectively, the “Mergers”), with CEI and New Acacia surviving as wholly-owned subsidiaries of EnLink Midstream. New Acacia owns the remaining 50% limited partner interest in Midstream Holdings. Devon will own the managing member of EnLink Midstream, and EnLink Midstream will indirectly own 100% of our general partner.
The closing of the Contribution is subject to the satisfaction of a number of conditions, including, but not limited to, the closing of the Mergers. The Merger is subject to customary closing conditions, including the approval of the proposal to adopt the merger agreement by the holders of at least 67% of the issued and outstanding shares of CEI's common stock entitled to vote as of the record date for the special meeting. The special meeting is scheduled to take place on March 7, 2014. The Contribution Agreement also contains customary termination provisions and will automatically terminate upon any termination of the Merger Agreement.
Recent Growth Developments
Cajun-Sibon Phases I and II. In Louisiana, we are transforming our business that historically has been focused on processing offshore natural gas to a business that is focused on NGLs with additional opportunities for growth from new onshore supplies of NGLs.  The Louisiana petrochemical market historically has relied on liquids from offshore production; however, the decrease in offshore production and increase in onshore rich gas production have changed the market structure.  Cajun-Sibon Phases I and II will work to bridge the gap between supply, which aggregates in the Mont Belvieu area, and demand, located in the Mississippi River corridor of Louisiana, thereby building a strategic NGL position in this region.
 
We began this transformation by restarting our Eunice fractionator during 2011 at a rate of 15,000 Bbls/d of NGLs. We expanded the Eunice fractionator to a rate of 55,000 Bbls/d with Cajun-Sibon Phase I ("Phase I"). Phase I of our pipeline extension project was completed in November 2013 and connects Mont Belvieu supply lines in east Texas to Eunice, providing a direct link to our fractionators in south Louisiana markets.  The Phase I Eunice fractionator expansion, which also was completed in early November 2013, has increased our interconnected fractionation capacity in Louisiana to approximately 97,000 Bbls/d of raw-make NGLs.
The Phase I expansion added 130-miles of 12-inch diameter pipeline to our existing 440-mile Cajun-Sibon NGL pipeline system, connecting Mont Belvieu to our Eunice fractionator. The pipeline currently has a capacity of 70,000 Bbls/d for raw make NGLs. The Phase I NGL pipeline extension originates from interconnects with major Mont Belvieu supply pipelines and provides connections for NGLs from the Permian Basin, Barnett Shale, Eagle Ford and other areas to our NGL fractionation facilities and key NGL markets in south Louisiana. Phase I is anchored by a five year ethane sales agreement with Williams Olefins, a subsidiary of the Williams Companies and a five year natural gasoline sales agreement with another company. We have entered into contracts of various lengths for all other purity products.
We have commenced construction of Cajun-Sibon Phase II which will further enhance our Louisiana NGL business with significant additions to the Cajun-Sibon Phase I infrastructure including further fractionation expansion. Phase II will include the addition of four pumping stations, totaling 13,400 horsepower, that will facilitate increasing NGL supply capacity from Phase I's 70,000 Bbls/d to 120,000 Bbls/d; the construction of a new 100,000 Bbls/d fractionator at the Plaquemine gas processing plant site; the conversion of our Riverside fractionator to a butane-and-heavier facility; and the construction of 57 miles of NGL pipeline that will originate at the Eunice fractionator and connect to the new Plaquemine fractionator, which will provide optionality to move purity products around the Louisiana-liquids market. We will also construct a 32-mile, 16-inch diameter extension of LIG's Bayou Jack lateral, which will provide gas services to customers in the Mississippi River corridor, replacing the conversion of supply lines that we currently use for liquid service. We expect Phase II will be in service during the second half of 2014.
Phase II is anchored by10-year sales agreements with Dow Hydrocarbons and Resources, or Dow, to deliver up to 40,000 Bbls/d of ethane and 25,000 Bbls/d of propane produced at our new Plaquemine fractionator into Dow's Louisiana pipeline system. We will also deliver 70,000 MMBtu/d of natural gas to Dow's Plaquemine facility.
We believe the Cajun-Sibon project not only represents a tremendous growth step by leveraging our Louisiana assets, but that it also creates a significant platform for continued growth of our NGL business. We believe this project, along with our existing assets, will provide a number of additional opportunities to grow this business, including expanding market optionality and connectivity, upgrading products, expanding rail imports, exporting NGLs and expanding fractionation and product storage capacity.
Bearkat Natural Gas Gathering and Processing System. In the fourth quarter of 2013, we commenced construction of a new natural gas processing complex and rich gas gathering pipeline system in the Permian Basin. The initial construction included treating, processing and gas takeaway solutions for regional producers. The project, which will be fully owned by us, is supported by a 10-year, fee-based contract.

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The new-build processing complex, called Bearkat, will be strategically located near our existing Deadwood joint venture assets in Glasscock County, Texas. The processing plant will have an initial capacity of 60 MMcf/d, increasing the Partnership’s total operated processing capacity in the Permian to approximately 115 MMcf/d. We will also construct a 30-mile high-pressure gathering system upstream of the Bearkat complex to provide additional gathering capacity for producers in Glasscock and Reagan Counties. The entire project is scheduled to be completed in the second half of 2014.
Permian Pipeline Extension Project. In February 2014, the Partnership entered into an agreement to construct a new 35-mile, 12-inch diameter high-pressure pipeline that will provide critical gathering capacity for the aforementioned Bearkat natural gas processing complex. The pipeline will have a capacity of approximately 100 MMcf/d and will provide gas takeaway solutions for constrained producer customers in Howard, Martin and Glasscock counties. Right-of-way acquisition is underway and the pipeline is expected to be operational in the second half of 2014.
Riverside Crude Facility Expansion. In June 2013, we completed the Phase II expansion of our Riverside facility located on the Mississippi River in southern Louisiana. The Riverside facility’s capacity to transload crude oil and condensate from railcars to our barge facility increased to approximately 15,000 Bbls/d of crude oil and condensate. Phase II additions to the Riverside facility include a 100,000 barrel above-ground crude oil and condensate storage tank, a rail spur with a 26-spot crude railcar unloading rack and a crude oil and condensate offloading facility with pumps and metering as well as a truck unloading bay. As part of the Phase II expansion, the Riverside facility was modified so that sour crude can be unloaded in addition to sweet crude.
Our Assets
North Texas Assets (including Permian Basin assets). Our gathering systems in north Texas, or NTG, consist of approximately 715 miles of gathering lines that had an average throughput of approximately 700,000 MMBtu/d for the year ended December 31, 2013. Our processing facilities in north Texas include three gas processing plants with total processing throughput that averaged 382,000 MMBtu/d for the year ended December 31, 2013. Our transmission asset, referred to as the North Texas Pipeline, or NTPL, is a 140-mile pipeline from an area near Fort Worth, Texas to a point near Paris, Texas and related facilities. The NTPL connects production from the Barnett Shale to markets in north Texas accessed by the Natural Gas Pipeline Company of America, LLC, Kinder Morgan, Inc., Houston Pipeline Company, L.P., Atmos Energy Corporation and Gulf Crossing Pipeline Company, LLC. For the year ended December 31, 2013, the average throughput on the NTPL was approximately 342,000 MMBtu/d.
Our north Texas segment also includes our Deadwood natural gas processing plant and our Mesquite Terminal and fractionator that comprise our Permian Basin assets. We have a 50% undivided working interest in the Deadwood processing facility which is located in Glasscock County, Texas. The Deadwood plant is supported by acreage dedication from a major producer in the Permian Basin. The Deadwood processing facility has a total capacity of 58 MMcf/d and total processing throughput that averaged 66,000 MMBtu/d for the year ended December 31, 2013. The Mesquite Terminal is located in Midland County and serves as a terminal for third party raw-make NGLs. We are also transloading crude oil at this facility.
LIG Assets.    The LIG gathering and transmission pipeline system is comprised of a north and south system and had an average throughput of approximately 473,000 MMbtu/d for the year ended December 31, 2013. The southern part of our LIG system has a capacity in excess of 1.5 Bcf/d and approximately 1,125 miles of pipeline. The south system also includes two operating, on-system processing plants, our Plaquemine and Gibson plants, with an average throughput of 255,000 MMBtu/d for the year ended December 31, 2013. The Plaquemine plant also has a fractionation capacity of 10,800 Bbls/d of raw-make NGL products, and total volume for fractionated liquids at Plaquemine averaged approximately 4,800 Bbls/d for the year ended December 31, 2013. The south system has access to both rich and lean gas supplies from onshore production in south central and southeast Louisiana. LIG has a variety of transportation and industrial sales customers in the south, with the majority of its sales being made into the industrial Mississippi River corridor between Baton Rouge and New Orleans.
Our LIG system in the north, comprised of approximately 800 miles of pipeline, serves the natural gas fields south of Shreveport, Louisiana and extends into the Haynesville Shale gas play in north Louisiana. The north Louisiana system has a capacity of 465 MMcf/d and interconnects with interstate pipelines of ANR Pipeline, Columbia Gulf Transmission, Texas Gas Transmission, Trunkline Gas and Tennessee Gas Pipeline. We have a substantial number of firm transportation agreements on the north system with weighted average lives of approximately 4.3 years. Our north Louisiana system is connected to our south Louisiana system and has the capacity to move approximately 145 MMcf/d of gas to our markets in the south.
In August 2012, a slurry-filled sinkhole developed in Assumption Parish near Bayou Corne, Louisiana and in the vicinity of certain of our pipelines and our underground storage reservoir located in Napoleonville, Louisiana. The cause of the slurry is currently under investigation by Louisiana state and local officials. Consequently, we took a section of our 36-inch-diameter natural gas pipeline located near the sinkhole out of service. Service to certain markets, primarily in the Mississippi River area, has been curtailed or interrupted, and we have worked with our customers to secure alternative natural gas supplies so that

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disruptions are minimized. We are currently in the initial phase of constructing the replacement pipeline in our rerouted location and anticipate the re-route to be completed during the first half of 2014. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Changes in Operations During 2013 and 2012" for further information about this matter.
PNGL Assets.    Our south Louisiana natural gas processing and liquids assets include processing and fractionation capabilities, underground storage and approximately 570 miles of liquids transport lines. Total processing throughput averaged 399,000 MMBtu/d and fractionated barrels averaged 27,300 Bbls/d for the year ended December 31, 2013.
NGL Assets.  Our NGL assets include our Eunice fractionation facility, our Riverside fractionation plant, our Cajun-Sibon pipeline system and our Napoleonville storage facility.
Eunice Fractionation Facility.    The Eunice fractionation facility is located in south central Louisiana and was restarted in 2011 to take advantage of the activity around liquids rich shale-plays, including the Eagle Ford, Permian, Granite Wash, Marcellus and Utica plays. The Eunice fractionation facility has a capacity of 55,000 Bbls/d of liquid products, including ethane, propane, iso-butane, normal butane and natural gasoline, and is directly connected to the southeast propane market and pipelines to the Anse La Butte storage facility. The plant fractionated 5,100 Bbls/d of liquids during 2013. Our Plaquemine facility is connected to the PNGL system, which gives us operational flexibility, increased fractionation capacity and the ability to capture new NGL-related business. See "Recent Growth Developments" for a discussion of the Eunice expansion in conjunction with the Cajun-Sibon project.

Riverside Fractionation Plant.    The Riverside fractionator and loading facility is located on the Mississippi River upriver from Geismar, Louisiana. The Riverside plant has a fractionation capacity of approximately 28,000 Bbls/d of liquids delivered by the Cajun-Sibon pipeline system from the Eunice, Pelican and Blue Water processing plants or by truck and rail. The Riverside facility has above-ground storage capacity of approximately 233,000 Bbls. The loading/unloading facility has the capacity to transload 15,000 Bbls/d of crude oil and condensate from rail cars to barges. Total volumes for fractionated liquids at Riverside averaged 22,200 Bbls/d for the year ended December 31, 2013. See "Recent Growth Developments" for discussion of the expansion at Riverside in conjunction with the Cajun-Sibon project.

Cajun-Sibon Pipeline System.    Currently, the Cajun-Sibon pipeline system consists of approximately 570 miles of raw make NGL pipelines ranging in size from 4" to 12" with a current system capacity of approximately 70,000 Bbls/d. The pipelines transport unfractionated NGLs, referred to as raw make, from areas such as the Liberty, Texas interconnects near Mont Belvieu and from our Eunice and Pelican processing plants in south Louisiana to either the Riverside or Eunice fractionators or to third party fractionators when necessary. See "Recent Growth Developments" for information regarding the expansion of this pipeline system.
Napoleonville Storage Facility.    The Napoleonville NGL storage facility is connected to the Riverside facility and has a total capacity of 3.1 million barrels of underground storage comprised of two existing caverns. The caverns are currently operated in propane and butane service, and space is leased to customers for a fee.
Processing Assets.  Our processing assets include our Pelican processing plant, our Eunice processing plant and our Blue Water gas processing plant.
Pelican Processing Plant.    The Pelican processing plant complex is located in Patterson, Louisiana and has a designed capacity of 600 MMcf/d of natural gas. For the year ended December 31, 2013, the plant processed approximately 334,000 MMBtu/d. The Pelican plant is connected with continental shelf and deepwater production and has downstream connections to the ANR Pipeline. This plant has an interconnection with the LIG pipeline so we can process natural gas from the LIG system at our Pelican plant when markets are favorable.
Eunice Processing Plant.    The Eunice processing plant is located in south central Louisiana, has a capacity of 475 MMcf/d and processed approximately 31,000 MMBtu/d for the year ended December 31, 2013. The plant is connected to onshore gas supply as well as continental shelf and deepwater gas production and has downstream connections to the ANR Pipeline, Florida Gas Transmission and Texas Gas Transmission. In August 2013, we shut down the Eunice processing plant

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due to adverse economics driven by low NGL prices and low processing volumes, which we do not see improving in the near future based on forecasted price curves.
Blue Water Gas Processing Plant.    We own a 64.29% interest in the Blue Water gas processing plant and operate the plant. The Blue Water plant is located in Crowley, Louisiana and is connected to the Blue Water pipeline system. The plant has a net capacity to our interest of approximately 300 MMcf/d. The plant is not expected to operate in the future unless fractionation spreads are favorable and volumes are sufficient to run the plant.
Ohio River Valley Assets.    Our Ohio River Valley assets include a 4,500-barrel-per-hour crude oil and condensate barge loading terminal on the Ohio River, a 20-spot crude oil and condensate rail loading terminal on the Ohio Central Railroad network and approximately 200 miles of crude oil and condensate pipelines in Ohio and West Virginia. The assets also include 500,000 barrels of above ground storage and a trucking fleet of approximately 100 vehicles comprised of both semi and straight trucks with a current capacity of 25,000 Bbls/d. Total crude oil and condensate handled averaged approximately 11,000 Bbls/d for the year ended December 31, 2013. We have eight existing brine disposal wells with an injection capacity of approximately 10,000 Bbls/d and an average disposal rate of 7,000 Bbls/d for the year ended December 31, 2013. We currently hold one additional well permit in Ohio.
Investment in Limited Liability Company.    In 2011 and 2012, we made capital contributions totaling $87.3 million to HEP in exchange for an individual ownership interest in HEP. HEP owns midstream assets and provides midstream and construction services to Eagle Ford Shale producers and is continuing to expand its midstream assets in the area. As of December 31, 2013, we owned a 30.6% interest in HEP and accounted for this investment under the equity method of accounting. In December 2013, Alinda Capital Partners acquired a 59 percent capital interest in HEP from Quanta Capital Solutions and GE Energy Financial Services. We contributed an additional $30.6 million to HEP during the year ended December 31, 2013 to fund our 30.6% share of HEP’s expansion costs.  We also received cash distributions totaling $17.5 million from HEP during the year ended December 31, 2013.  Our investment in HEP is included in our Corporate segment.

Industry Overview
The following diagram illustrates the gathering, processing, fractionation and transmission process.
The midstream industry is the link between the exploration and production of natural gas, crude oil and condensate and the delivery of its components to end-user markets. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas, crude oil and condensate producing wells.

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Natural gas gathering.    The natural gas gathering process follows the drilling of wells into gas-bearing rock formations. After a well has been completed, it is connected to a gathering system. Gathering systems typically consist of a network of small diameter pipelines and, if necessary, compression and treating systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.
Compression.    Gathering systems are operated at pressures that will maximize the total natural gas throughput from all connected wells. Because wells produce gas at progressively lower field pressures as they age, it becomes increasingly difficult to deliver the remaining production in the ground against the higher pressure that exists in the connected gathering system. Natural gas compression is a mechanical process in which a volume of gas at an existing pressure is compressed to a desired higher pressure, allowing gas that no longer naturally flows into a higher-pressure downstream pipeline to be brought to market. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver gas into a higher-pressure downstream pipeline. The remaining natural gas in the ground will not be produced if field compression is not installed because the gas will be unable to overcome the higher gathering system pressure. In contrast, a declining well can continue delivering natural gas if the field compression is installed.
Natural gas processing.    The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of heavier NGLs and contaminants, such as water and CO2, sulfur compounds, nitrogen or helium. Natural gas produced by a well may not be suitable for long-haul pipeline transportation or commercial use and may need to be processed to remove the heavier hydrocarbon components and contaminants. Natural gas in commercial distribution systems mostly consists of methane and ethane, and moisture and other contaminants have been removed so there are negligible amounts of them in the gas stream. Natural gas is processed to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas and to separate those hydrocarbon liquids from the gas that have higher value as NGLs. The removal and separation of individual hydrocarbons through processing is possible due to differences in weight, boiling point, vapor pressure and other physical characteristics. Natural gas processing involves the separation of natural gas into pipeline-quality natural gas and a mixed NGL stream and the removal of contaminants.
NGL fractionation.    NGLs are separated into individual, more valuable components during the fractionation process. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane, natural gasoline and stabilized crude oil and condensate. 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 as a petrochemical feedstock in the production of ethylene and propylene and as a heating fuel, an engine fuel and industrial fuel. Isobutane is used principally to enhance the octane content of motor gasoline. Normal butane is used as a petrochemical feedstock in the production of ethylene and butylene (a key ingredient in synthetic rubber), as a blend stock for motor gasoline and to derive isobutene through isomerization. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock.
Natural gas transmission.    Natural gas transmission pipelines receive natural gas from mainline transmission pipelines, processing plants and gathering systems and deliver it to industrial end-users, utilities and to other pipelines.
Crude oil and condensate transmission.    Crude oil and condensate are transported by pipelines, barges, rail cars and tank trucks. The method of transportation used depends on, among other things, the resources of the transporter, the locations of the production points and the delivery points, cost-efficiency and the quantity of product being transported.
Brine gathering and disposal services.    Typically, shale wells produce significant amounts of water that, in most cases, require disposal. Produced water and frac-flowback is hauled via truck transport or is pumped through pipelines from its origin at the oilfield tank battery or drilling pad to the disposal location. Once the water reaches the delivery disposal location, water is processed and filtered to remove impurities and injection wells place fluids underground for storage and disposal.
Crude oil and condensate terminals.    Crude oil and condensate rail terminals are an integral part of ensuring the movement of new crude oil and condensate production from the developing shale plays in the United States and Canada. In general, the crude oil and condensate rail loading terminals are used to load rail cars and transport the commodity out of developing basins into market rich areas of the country where crude oil and condensate rail unloading terminals are used to unload rail cars and store crude oil and condensate volumes for third parties until the crude oil and condensate is redelivered to premium markets via pipelines, trucks or rail to delivery points.
Balancing Supply and Demand
When we purchase natural gas, crude oil and condensate, we establish a margin normally by selling it for physical delivery to third-party users. We can also use over-the-counter derivative instruments or enter into future delivery obligations under futures contracts on the New York Mercantile Exchange (the "NYMEX") related to our natural gas purchases. Through these transactions, we seek to maintain a position that is balanced between purchases, on the one hand, and sales or future

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delivery obligations, on the other hand. Our policy is not to acquire and hold natural gas futures contracts or derivative products for the purpose of speculating on price changes.
Competition
The business of providing gathering, transmission, processing and marketing services for natural gas, NGLs, crude oil and condensate is highly competitive. We face strong competition in obtaining natural gas, NGLs, crude oil and condensate supplies and in the marketing and transportation of natural gas, NGLs, crude oil and condensate. Our competitors include major integrated and independent exploration and production crude oil and condensate companies, natural gas producers, interstate and intrastate pipelines, other natural gas and crude oil and condensate gatherers and natural gas processors. Competition for natural gas and crude oil supplies is primarily based on geographic location of facilities in relation to production or markets, the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer. Many of our competitors offer more services or have greater financial resources and access to larger natural gas, NGLs, crude oil and condensate supplies than we do. Our competition varies in different geographic areas.
In marketing natural gas and NGLs, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil and gas companies, and local and national natural gas producers, gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly and through affiliates in marketing activities that compete with our marketing operations.
We face strong competition for acquisitions and development of new projects from both established and start-up companies. Competition increases the cost to acquire existing facilities or businesses and results in fewer commitments and lower returns for new pipelines or other development projects. Many of our competitors have greater financial resources or lower cost of capital or are willing to accept lower returns or greater risks. Our competition differs by region and by the nature of the business or the project involved.
Natural Gas, NGL, Crude Oil and Condensate Supply
Our gathering and transmission pipelines have connections with major intrastate and interstate pipelines, which we believe have ample natural gas and NGLs supplies in excess of the volumes required for the operation of these systems. Our Ohio River Valley pipeline, terminals, trucks and storage facilities are strategically located in oil and condensate producing regions. We evaluate well and reservoir data that is either publicly available or furnished by producers or other service providers in connection with the construction and acquisition of our gathering systems and assets to determine the availability of natural gas, NGL, crude oil and condensate supply for our systems and assets and/or obtain a minimum volume commitment from the producer that results in a rate of return on investment. We do not routinely obtain independent evaluations of reserves dedicated to our systems and assets due to the cost and relatively limited benefit of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems and assets or the anticipated life of such producing reserves.
Credit Risk and Significant Customers
We are diligent in attempting to ensure that we issue credit to only credit-worthy customers. However, our purchase and resale of oil, gas and other products exposes us to significant credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to our overall profitability.
During the year ended December 31, 2013, we had only one customer, Dow, which represented greater than 10.0% of our revenue. While this customer represented 12.6% of consolidated revenues, the loss of this customer would not have a material impact on our results of operations because the gross operating margins received from transactions with this customer are not material to our total gross operating margin, and we believe the sales to this customer could be replaced with other buyers at comparable sales prices.
Regulation
Interstate Natural Gas Pipelines Regulation. We do not own any interstate natural gas pipelines, so the Federal Energy Regulatory Commission, or FERC, does not directly regulate our natural gas operations under the National Gas Act, or NGA. However, FERC's regulation of interstate natural gas pipelines influences certain aspects of our business and the market for our products. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce and its authority to regulate those services includes:
the certification and construction of new facilities;
the extension or abandonment of services and facilities;
the maintenance of accounts and records;

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the acquisition and disposition of facilities;
maximum rates payable for certain services; and
the initiation and discontinuation of services.
While we do not own any interstate natural gas pipelines, we do transport gas in interstate commerce. The rates, terms and conditions of service under which we transport natural gas in our pipeline systems in interstate commerce are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, or NGPA. The maximum rates for services provided under Section 311 of the NGPA may not exceed a "fair and equitable rate," as defined in the NGPA. The rates are generally subject to review every three years by FERC or by an appropriate state agency. The inability to obtain approval of rates at acceptable levels could result in refund obligations, the inability to achieve adequate returns on investments in new facilities and the deterrence of future investment or growth of the regulated facilities.
Liquids Pipelines Regulation. We own liquids transportation, storage and other assets in the Ohio River Valley, including certain assets providing common carrier interstate service subject to regulation by FERC under the Interstate Commerce Act, or ICA, the Energy Policy Act of 1992 and related rules and orders. Our Cajun-Sibon NGL pipeline became subject to FERC regulation as a result of our Phase I expansion, which went into operation in November 2013. The expansion is subject to regulation by FERC as a common carrier under the ICA, the Energy Policy Act of 1992 and related rules and orders.
FERC regulation requires that interstate liquids pipeline rates and terms and conditions of service, including rates for transportation of crude oil and NGLs, be filed with FERC and that these rates and terms and conditions of service be "just and reasonable" and not unduly discriminatory or unduly preferential.
Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning in 2010, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 2.65%. This adjustment is subject to review every five years. Under FERC's regulations, liquids pipelines can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-services approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology.
The ICA permits interested persons to challenge proposed new or changed rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months and investigate such rates. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Under certain circumstances, FERC could limit our ability to set rates based on our costs or could order us to reduce our rates and could require the payment of reparations to complaining shippers for up to two years prior to the date of the complaint. FERC also has the authority to change our terms and conditions of service if it determines that they are unjust and unreasonable or unduly discriminatory or preferential.
As we acquire, construct and operate new liquids assets and expand our liquids transportation business segment, the classification and regulation of our liquids transportation services are subject to ongoing assessment and change based on the services we provide and determinations by FERC and the courts. Such changes may subject additional services we provide to regulation by FERC.
Intrastate Natural Gas Pipeline Regulation. Our intrastate natural gas pipeline operations are subject to regulation by various agencies of the states in which they are located. Most states have agencies that possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Some states also have state agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers.
Intrastate NGL Pipeline Regulation. Intrastate NGL and other petroleum pipelines are not generally subject to rate regulation by FERC, but they are subject to regulation by various agencies in the respective states where they are located. While the regulatory regime varies from state to state, state agencies typically require intrastate petroleum pipelines to file their rates with the agencies and permit shippers to challenge existing rates or proposed rate increases.
Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We own a number of natural gas pipelines that we believe meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. State regulation of gathering facilities generally

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includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation.
We are subject to some 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 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 producer or one source of supply over another source of supply.
Sales of Natural Gas and NGLs. The price at which we sell natural gas and NGLs currently are not subject to federal regulation and, for the most part, are not subject to state regulation. Our natural gas and NGL sales are affected by 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. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas and NGL industries, most notably interstate natural gas transmission companies and NGL pipeline companies that remain subject to FERC's jurisdiction. These initiatives also may affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of these regulatory changes on our natural gas and NGL marketing operations, but we do not believe that we will be affected by any such FERC action in a manner that is materially different from the natural gas and NGL marketers with whom we compete.
Environmental Matters
General. Our operations involve processing and pipeline services for delivery of hydrocarbons (natural gas, NGLs, petroleum and fractionates) from point-of-origin at oil and gas wellheads operated by our suppliers to our end-use market customers. Our facilities include natural gas processing and fractionation plants, brine disposal wells, pipelines and associated facilities, fractionation and storage units for NGLs, and transportation and delivery of petroleum. As with all companies in our industrial sector, our operations are subject to stringent and complex federal, state and local laws and regulations relating to release of hazardous substances or solid wastes into the environment or otherwise relating to protection of the environment. Compliance with existing and anticipated environmental laws and regulations increases our overall costs of doing business, including costs of planning, constructing, and operating plants, pipelines, and other facilities, as well as capital cost items necessary to maintain or upgrade equipment and facilities. Similar costs are likely upon changes in laws or regulations and upon any future acquisition of operating assets.
Any failure to comply with applicable environmental laws and regulations, including those relating to equipment failures, and obtaining required governmental approvals, may result in the assessment of administrative, civil or criminal penalties, imposition of investigatory or remedial activities and, in less common circumstances, issuance of temporary or permanent injunctions or construction or operation bans or delays.
The continuing trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases or spills are associated with possible future operations, and we cannot assure you that we will not incur significant costs and liabilities, including those relating to claims for damage to property and persons as a result of any such upsets, releases or spills. In the event of future increases in environmental costs, we may be unable to pass on those cost increases to our customers. A discharge of hazardous substances or solid wastes into the environment could, to the extent losses related to the event are not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and to pay fines or penalties that may be assessed and the cost related to claims made by neighboring landowners and other third parties for personal injury or damage to natural resources or property. We will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly to comply with changing environmental laws and regulations and to minimize costs with respect to more stringent future laws and regulations or more rigorous enforcement of existing laws and regulations.
Hazardous Substances and Waste.    Environmental laws and regulations that relate to the release of hazardous substances or solid wastes into soils, groundwater and surface water and/or include measures to prevent and control pollution may pose the highest potential cost to our industry sector. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous wastes and may require investigatory and corrective actions at facilities where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the federal "Superfund" law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of "hazardous substance" into the environment. Potentially liable persons include the owner or operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that

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have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the Environmental Protection Agency (EPA) and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the potentially 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 wastes released into the environment. Although petroleum, natural gas and NGLs are excluded from CERCLA's definition of a "hazardous substance," in the course of ordinary operations, we may generate wastes that may fall within the definition of a "hazardous substance." In addition, there are other laws and regulations that can create liability for releases of petroleum, natural gas or NGLs. Moreover, we may be responsible under CERCLA or other laws for all or part of the costs required to clean up sites at which such wastes have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA or any analogous federal or state law.
We also generate, and may in the future generate, both hazardous and nonhazardous solid wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, or RCRA, and/or comparable state statutes. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated by us that are currently considered nonhazardous may in the future be designated as "hazardous wastes," resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Changes in applicable laws or regulations may result in an increase in our capital expenditures or plant operating expenses or otherwise impose limits or restrictions on our production and operations.
We currently own or lease, have in the past owned or leased, and in the future may own or lease, properties that have been used over the years for brine disposal operations, crude and condensate transportation, natural gas gathering, treating or processing and for NGL fractionation, transportation or storage. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and other solid wastes may have been disposed of on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whose operations and hydrocarbon and waste management practices we had no control. These properties and wastes disposed thereon may be subject to the Safe Drinking Water Act, CERCLA, RCRA and analogous state laws. Under these laws, we could be required, alone or in participation with others, to remove or remediate previously disposed wastes or property contamination, if present, including groundwater contamination, or to take action to prevent future contamination.
Air Emissions.    Our current and future operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and impose various controls together with monitoring and reporting requirements. Pursuant to these laws and regulations, we may be required to obtain environmental agency pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing air emissions, obtain and comply with the terms of air permits, which include various emission and operational limitations, or use specific emission control technologies to limit emissions. We likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with maintaining or obtaining governmental approvals addressing air emission-related issues. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties and may result in the limitation or cessation of construction or operation of certain air emission sources. Although we can give no assurances, we believe such requirements will not have a material adverse effect on our financial condition or operating results, and the requirements are not expected to be more burdensome to us than to any similarly situated company.
On April 17, 2012, the EPA approved final rules under the Clean Air Act that establish new air emission controls for oil and natural gas production, pipelines and processing operations. These rules became effective on October 15, 2012. For new or reworked hydraulically-fractured gas wells, the rules require the control of emissions through flaring or reduced emission (or "green") completions until 2015, when the rules require the use of green completions by all such wells except wildcat (exploratory) and delineation gas wells and low reservoir pressure non-wildcat and non-delineation gas wells. The rules also establish specific new requirements regarding emissions from wet seal and reciprocating compressors at production facilities, gathering systems, boosting facilities and onshore natural gas processing plants, effective October 15, 2012, and from pneumatic controllers and storage vessels at production facilities, gathering systems, boosting facilities and onshore natural gas processing plants, effective October 15, 2013. In addition, the rules revise existing requirements for volatile organic compound emissions from equipment leaks at onshore natural gas processing plants by lowering the leak definition for valves from 10,000 parts per million to 500 parts per million and requiring the monitoring of connectors, pumps, pressure relief devices and open-ended lines, effective October 15, 2012. These rules may therefore require a number of modifications to our and our suppliers' and customers' operations, including the installation of new equipment to control emissions.

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In October 2012, several challenges to the EPA's April 17, 2012 rules were filed by various parties, including environmental groups and industry associations. In a January 16, 2013 unopposed motion to hold this litigation in abeyance, the EPA indicated that it may reconsider some aspects of the rules. The case remains in abeyance. EPA issued a final rule revising certain aspects of the rules on August 5, 2013 and has indicated that it may reconsider other aspects of the rules. Depending on the outcome of such proceedings, the rules may be further modified or rescinded or the EPA may issue new rules. The costs of compliance with any modified or newly issued rules cannot be predicted. Additionally, on December 11, 2012, seven states submitted a notice of intent to sue the EPA to compel the agency to make a determination as to whether standards of performance limiting methane emissions from the oil and gas sector are appropriate, which was not addressed in the EPA rule that became effective on October 15, 2012. The notice of intent also requested that the EPA issue emission guidelines for the control of methane emissions from existing oil and gas sources. Depending on whether such rules are promulgated and the applicability and restrictions in any promulgated rule, compliance with such rules could result in additional costs, including increased capital expenditures and operating costs for us and for other companies in our industry. While we are not able at this time to estimate such additional costs, as is the case with similarly situated entities in the industry, they could be significant for us. Compliance with such rules, as well as any new state rules, may also make it more difficult for our suppliers and customers to operate, thereby reducing the volume of natural gas transported through our pipelines, which may adversely affect our business.
Climate Change.    In response to concerns suggesting that emissions of certain gases, commonly referred to as "greenhouse gases" (including carbon dioxide and methane), may be contributing to warming of the earth's atmosphere, the EPA is taking steps that would result in the regulation of greenhouse gases as pollutants under the federal Clean Air Act.
In October 2009, the EPA promulgated its Mandatory Reporting Rule for greenhouse gases, which requires the monitoring and reporting of greenhouse gas emissions on an annual basis. All of our facilities operating combustion sources, such as engines or natural gas fractionation facilities, are subject to the greenhouse gas reporting requirements included in the October 2009 final rule. The first annual greenhouse gas emissions inventory for our affected facilities was filed by us in September 2011 and we continue to file the required annual reports. In November 2010 and further in December 2011, the EPA expanded the scope of the Mandatory Reporting Rule to include petroleum and natural gas pipeline systems, which applies the Mandatory Reporting Rule's requirements to, among other sources, fugitive and vented methane emissions from the oil and gas sector, including natural gas transmission compression. Our transmission compression facilities as well as gathering compressor stations with large amine treating capacities are also required to report under this expanded rule. The first reports for these facilities were due in 2012. Although the Mandatory Reporting Rule does not control greenhouse gas emission levels from any facilities, it has still caused us to incur monitoring and reporting costs for emissions that are subject to the rule.
After a series of regulatory actions finalized by the EPA between December 2009 and May 2010, greenhouse gases became pollutants "subject to regulation" under the Clean Air Act's Prevention of Significant Deterioration (PSD) air quality permit program for stationary sources, which in turn triggered permitting requirements under the Clean Air Act's Title V permitting program. In the "Tailoring Rule," the EPA promulgated regulatory thresholds for greenhouse gases that make PSD permitting requirements applicable to only relatively large sources of greenhouse gas emissions. As a result, new and modified stationary sources that emit greenhouse gases over statutory thresholds and the Tailoring Rule's regulatory thresholds must obtain a PSD permit setting forth Best Available Control Technology (BACT) for those emissions. The current Tailoring Rule threshold levels act to limit PSD permitting for greenhouse gases to only relatively large sources of greenhouse gas emissions, but the EPA has indicated that it may tighten the Tailoring Rule thresholds in the future, subjecting additional sources to PSD permitting requirements for greenhouse gases. The EPA has also proposed to regulate greenhouse gas emissions from certain electric generating units through the Clean Air Act's New Source Performance Standards (NSPS) program, and may expand greenhouse gas NSPS requirements to additional source categories in the future. Any new requirements could in the future affect our operations and our ability to obtain air permits for new or modified facilities.
The U.S. Congress has considered but to date has not enacted legislation to mandate reductions of greenhouse gas emissions, and almost half of the states, either individually or through multi-state regional initiatives, have already taken legal measures intended to reduce greenhouse gas emissions, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs.
Because regulation of greenhouse gas emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments in greenhouse gas initiatives may affect us and other companies operating in the oil and gas industry. In addition to these developments, recent judicial decisions have allowed certain tort claims alleging property damage to proceed against greenhouse gas emissions sources, which may increase our litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with greenhouse gas emissions, we cannot predict the financial impact of related developments on us.
Federal or state legislative or regulatory initiatives that regulate or restrict emissions of greenhouse gases in areas in which we conduct business could adversely affect the availability of, or demand for, the products we store, transport and

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process, and, depending on the particular program adopted, could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and/or administer and manage a greenhouse gas emissions program. We may be unable to recover any such lost revenues or increased costs in the rates we charge our customers, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before FERC or state regulatory agencies and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our business, financial position, results of operations and prospects.
Some scientific studies on climate change suggest that adverse weather events may become stronger or more frequent in the future in certain of the areas in which we operate, although the scientific studies are not unanimous. Due to their location, our operations along the Gulf Coast are vulnerable to operational and structural damages resulting from hurricanes and other severe weather systems, while inland operations include areas subject to tornadoes. Our insurance may not cover all associated losses. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.
Hydraulic Fracturing and Wastewater.    The Federal Water Pollution Control Act, also known as the Clean Water Act, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including NGL related wastes, into state waters or waters of the United States. Regulations promulgated pursuant to these laws require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System, or NPDES, and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder and that continued compliance with such existing permit conditions will not have a material effect on our results of operations.
We operate brine disposal wells that are regulated as Class II wells under the federal Safe Drinking Water Act (SDWA). The SDWA imposes requirements on owners and operators of Class II wells through the EPA's Underground Injection Control program, including construction, operating, monitoring and testing, reporting and closure requirements. Our brine disposal wells are also subject to comparable state laws and regulations, which in some cases are more stringent than requirements under the federal SDWA. Compliance with current and future laws and regulations regarding our brine disposal wells may impose substantial costs and restrictions on our brine disposal operations, as well as adversely affect demand for our brine disposal services. State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in minor seismic activity and tremors.  When caused by human activity, such events are called induced seismicity.  In a few instances, operators of injection wells in the vicinity of minor seismic events have reduced injection volumes or suspended operations, often voluntarily.  A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity.  Regulatory agencies are continuing to study possible linkage between injection activity and induced seismicity.  To the extent these studies result in additional regulation of injection wells, such regulations could impose additional regulations, costs and restrictions on our brine disposal operations.
It is common for our customers or suppliers to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is an important and commonly used process in the completion of wells by oil and gas producers. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states and localities have been initiated to require or make more stringent the permitting and other regulatory requirements for hydraulic fracturing operations. There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. In addition, the EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and has initiated plans to promulgate regulations controlling wastewater disposal associated with hydraulic fracturing and shale gas development. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing. Additional regulatory burdens in the future, whether federal, state or local, could increase the cost of or restrict the ability of our customers or suppliers to perform hydraulic fracturing. As a result, any increased federal, state or local regulation could reduce the volumes of natural gas that our customers move through our gathering systems which would materially adversely affect our revenues and results of operations.

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Employee Safety.    We are subject to the requirements of the Occupational Safety and Health Act, referred to as OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard 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. We believe that our operations are in substantial compliance with the OSHA requirements including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
Pipeline Safety Regulations.    Our pipelines are subject to regulation by the U.S. Department of Transportation (DOT). DOT's Pipeline Hazardous Material Safety Administration (PHMSA), acting through the Office of Pipeline Safety (OPS), administers the national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipeline. OPS develops regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of pipeline facilities. The main bodies of safety regulations that cover our operations are set forth at 49 CFR, Parts 192 (covering pipelines that transport natural gas) and 195 (pipelines that transport crude oil, carbon dioxide, NGL and petroleum products). In addition to recordkeeping and reporting requirements, amendments to 49 CFR Part 192 and 195 created the Pipeline Integrity Management in High Consequence Areas (PIM) requiring operators of transmission pipelines to ensure the integrity of their pipelines through hydrostatic pressure testing, the use of in-line inspection tools or through risk-based direct assessment techniques. In January 2012, the President signed into law the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 which increases potential penalties for pipeline safety violations, gives new rulemaking authority to DOT with respect to shut-off valves on transmission pipeline facilities constructed or entirely replaced after the rule is promulgated, requires DOT to revise incident notification guidance and imposes new records requirements on pipeline owners and operators. This legislation also requires DOT to study and report to Congress on other areas of pipeline safety, including expanding the reach of the integrity management regulations beyond high consequences areas, but restricts DOT from promulgating expanded integrity management rules during the review period and for a period following submission of its report to Congress unless the rulemaking is needed to address a present condition that poses a risk to public safety, property or the environment. PHMSA issued a final rule effective October 25, 2013 that implemented aspects of the new legislation. Among other things, the final rule increases the maximum civil penalties for violations of pipeline safety statutes or regulations, broadens PHMSA’s authority to submit information requests, and provides additional detail regarding PHMSA’s corrective action authority. Additionally, PHMSA issued an Advisory Bulletin in May 2012, which advised pipeline operators of anticipated changes in annual reporting requirements and that if they are relying on design, construction, inspection, testing or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipeline. A December 2012 PHMSA Advisory Bulletin provides further clarity on the reporting requirements of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, describing a general requirement that pipeline owners or operators report an exceedance of the maximum allowable operating pressure or allowable build-up for pressure-limiting or control devices within five days of the date that the exceedance occurs. At the state level, several states have passed legislation or promulgated rulemaking dealing with pipeline safety. We believe that our pipeline operations are in substantial compliance with applicable PHMSA and state requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the PHMSA or state requirements will not have a material adverse effect on our results of operations or financial positions.
Bayou Corne Sinkhole Incident.    We own and operate a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of these pipelines and our underground storage reservoirs located in Napoleonville, Louisiana.
Following the formation of the sinkhole, we and other pipeline operators in the area promptly undertook steps to depressurize and shut down our pipelines in the affected area. In particular, we took a section of our 36-inch diameter natural gas pipeline out of service. Our pipeline remains out of service, which has partially interrupted service to certain markets including the Mississippi River, but we worked with our customers to secure alternative natural gas supplies to minimize disruptions. In addition, we have identified a reroute for this pipeline outside of the affected areas. We are currently in the initial phase of constructing the replacement pipeline in our rerouted location and anticipate such construction will be completed during first half of 2014. We also implemented additional inspection and operational measures at our nearby underground facility. The damage to our business, including costs and loss of business has been considerable. For more information regarding the costs associated with this sinkhole, please see "Item 7. Management's Discussion and Analysis of Financial condition and Results of Operations—Liquidity and Capital Resources—Changes in Operations During 2013 and 2012."

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The cause and full consequences of this sinkhole and the conditions giving rise thereto remain uncertain. In addition, any restrictions imposed by governmental agencies could negatively impact our assets. We are assessing the potential for recovering our losses from responsible parties and we are seeking recovery from our insurers. Our insurers, however, have denied our insurance claim for coverage and filed a declaratory judgment asking a court to determine that our insurance policy does not cover this damage. We have sued our insurers for breach of contract due to our insurers' refusal to pay our insurance claim for this damage. We cannot assure you that we will be able to fully recover our losses through insurance recovery or claims against responsible parties.
Office Facilities
We occupy approximately 108,500 square feet of space at our executive offices in Dallas, Texas under a lease expiring in August 2019, approximately 25,100 square feet of office space for our Louisiana operations in Houston, Texas with lease terms expiring in April 2023 and approximately 9,000 square feet of office space in Lafayette, Louisiana with lease terms expiring in January 2023.
Employees
As of December 31, 2013, we (through our subsidiaries) employed approximately 817 full-time employees. Approximately 218 of our employees were general and administrative, engineering, accounting and commercial personnel and the remainder were operational employees. We are not party to any collective bargaining agreements and we have not had any significant labor disputes in the past. We believe that we have good relations with our employees.
Item 1A.    Risk Factors
        The following risk factors and all other information contained in this report should be considered carefully when evaluating us. These risk factors could affect our actual results. Other risks and uncertainties, in addition to those that are described below, may also impair our business operations. If any of the following risks occur, our business, financial condition or results of operations could be affected materially and adversely. In that case, we may be unable to make distributions to our unitholders and the trading price of our common units could decline. These risk factors should be read in conjunction with the other detailed information concerning us set forth in our accompanying financial statements and notes and contained in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" included herein.
Risks Associated with the Contribution and the Mergers
We cannot assure you that we will complete the Contribution or, if completed, that such transaction will be beneficial to us.
We cannot assure you that we will complete the Contribution (as defined in "Item 1. Business - Business Development") or, if completed, that such transaction would achieve the desired benefits. The Contribution would involve numerous risks, including the failure to realize expected profitability or growth and an increase in collateral demands by our counterparties. Additionally, the failure to assimilate the Midstream Group Entities’ assets into our existing assets would adversely affect our financial condition and results of operations. We will also be exposed to risks that are commonly associated with any acquisition, such as unanticipated liabilities and costs, some of which may be material, and diversion of management’s attention. Moreover, the Midstream Group Entities’ operations are subject to similar stringent environmental laws and regulations relating to releases of pollutants into the environment and environmental protection as are our existing pipelines and facilities, and thus our operation of those new assets would cause us to incur increased costs to maintain compliance with such laws and regulations.
If we consummate the Contribution and if any of these risks or unanticipated liabilities or costs were to materialize, any desired benefits of the Contribution may not be fully realized, if at all, and our future financial performance and results of operations could be negatively impacted. Further, the failure to complete the Contribution could negatively impact the market price of our common units and our future business and financial results, and we may experience negative reactions from the financial markets and from our customers and employees.
If we complete the Contribution, we will expand our operations into new geographic areas.
The Contribution would, if ultimately consummated, significantly increase the size and scale of our business and expand the geographic areas in which we operate. Midstream Holdings operates its business in geographic regions in which we do not currently operate, including the Cana and Arkoma Woodford Shales in Oklahoma. In order to operate effectively in these new regions, we will need to understand the local market and regulatory environment and identify and retain certain employees from Devon who are familiar with these markets. If we are not successful in retaining these employees or operating in these new geographic areas, we may not be able to compete effectively in the new markets or fully realize the expected benefits of the Contribution.

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Upon consummation of the Contribution, a significant portion of our operations will be located in the Barnett Shale, making us vulnerable to risks associated with having revenue-producing operations concentrated in a limited number of geographic areas.
If we complete the Contribution, our revenue-producing operations will be geographically concentrated in the Barnett Shale, causing us to be disproportionally exposed to risks associated with regional factors. The concentration of our operations in these regions also increases exposure to unexpected events that may occur in these regions such as natural disasters or labor difficulties. Any one of these events has the potential to have a relatively significant impact on our operations and growth plans, decrease cash flows, increase operating and capital costs and prevent development within originally anticipated time frames. Any of these risks could have a material adverse effect on our financial condition and results of operations.
Upon Consummation of the Contribution, we will be dependent on Devon for substantially all of the natural gas that the Midstream Group Entities gather, process and transport, and a material decline in the volumes of natural gas that the Midstream Group Entities gather, process and transport for Devon would have a material adverse impact on our operating results and cash available for distribution.
The Midstream Group Entities rely on Devon for substantially all of their natural gas supply and do not expect to materially increase volumes from third-party producers in the near term. For the foreseeable future, we expect the profitability of the business of the Midstream Group Entities to remain substantially dependent on the volume of natural gas that Devon provides under commercial agreements to be entered into in connection with the closing of the Contribution. Upon the expiration or termination of these agreements, or in the event that the volume of natural gas purchased under these commercial agreements is reduced, we would be adversely affected unless we were able to make comparably profitable arrangements with other customers.
Pending the completion of the Contribution, our business and operations could be materially adversely affected.
Under the terms of the Contribution Agreement, we are subject to certain restrictions on the conduct of our business prior to completing the transactions which may adversely affect our ability to execute certain of our business strategies, including our ability in certain cases to enter into contracts or incur capital expenditures to grow our business. Such limitations could negatively affect our business and operations prior to the completion of the Contribution. Furthermore, matters relating to the Contribution may require substantial commitments of time and resources by management, which could otherwise have been devoted to other opportunities that may have been beneficial to us.
We will incur substantial transaction-related costs in connection with the Contribution.
We expect to incur a number of non-recurring transaction-related costs associated with completing the Contribution, combining the operations of the Midstream Group Entities with our business and achieving desired synergies. These fees and costs will be substantial. 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, or at all.
The consummation of the Contribution and the Mergers would constitute a change of control of us.
The Partnership’s unitholders will have a reduced ownership and voting interest after the Contribution and will exercise less influence over management. Further, following the consummation of the Mergers, our general partner will be an indirect wholly-owned subsidiary of EnLink Midstream, a new public holding company that will be controlled by Devon. CEI stockholders currently have the right to vote in the election of the CEI board of directors and other matters affecting CEI. When the Mergers occur, each CEI shareholder that receives EnLink Midstream common units will become a unitholder of EnLink Midstream with a percentage ownership of the combined organization that is much smaller than such stockholder’s percentage ownership of CEI. EnLink Midstream unitholders are not entitled to elect the directors of EnLink Midstream’s managing member and have only limited voting rights on matters affecting Enlink Midstream's business and, therefore, limited ability to influence management’s decisions regarding our business. Because of its control of EnLink Midstream and our general partner, as well as due to its significant ownership of us following the Contribution, Devon will have the ability to influence our management, policies and business in a manner that may differ from our past practice.
The closing of the Contribution and the Mergers would trigger a mandatory repurchase offer under the indenture governing our 2018 Notes and, in certain circumstances, our 2022 Notes.
The closing of the Contribution and the Mergers will trigger a mandatory repurchase offer under the indenture governing our 2018 Notes. Completion of the Contribution and the Mergers also could trigger a mandatory repurchase offer under the indenture

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governing our 2022 Notes if, within 90 days of the consummation of the transactions, we experience a rating downgrade of the 2022 Notes by either Moody’s or S&P. If we are unable to fund a repurchase of our 2018 Notes or, if necessary, our 2022 Notes, the counterparties may exercise their rights and remedies under the indentures, which could result in a default under our credit facility. Further, during the pendency of the proposed transactions, a decrease in Devon’s perceived creditworthiness may have an adverse effect on our perceived creditworthiness, possibly resulting in a downgrade of credit ratings, tightening of credit under our credit facility, inability to borrow funds under our new credit facility or increasing our borrowing costs.
Risks Inherent In Our Business
Our substantial indebtedness could limit our flexibility and adversely affect our financial health.
We have a substantial amount of indebtedness. As of December 31, 2013, we had approximately $1.12 billion of indebtedness outstanding primarily comprised of $725.0 million (including $7.8 million of original issue discount) of senior unsecured notes due in 2018 and $250.0 million of senior unsecured notes due in 2022. As of December 31, 2013, there was $155.0 million of borrowing and $59.7 million in outstanding letters of credit under our existing credit facility leaving approximately $420.3 million available for future borrowings and letters of credit based on a borrowing capacity of $635.0 million. However, the financial covenants in our existing credit facility limit the amount of funds that we can borrow. As of December 31, 2013, based on the financial covenants in our existing credit facility, we could borrow approximately $207.1 million of additional funds.
Our substantial indebtedness could limit our flexibility and adversely affect our financial health. For example, it could:
make us more vulnerable to general adverse economic and industry conditions;
require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow for operations and other purposes;
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
place us at a competitive disadvantage compared to competitors that may have proportionately less indebtedness.
In addition, our ability to make scheduled payments or to refinance our obligations depends on our successful financial and operating performance. We cannot assure you that our operating performance will generate sufficient cash flow or that our capital resources will be sufficient for payment of our debt obligations in the future. Our financial and operating performance, cash flow and capital resources depend upon prevailing economic conditions and certain financial, business and other factors, many of which are beyond our control.
If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to sell material assets or operations, obtain additional capital or restructure our debt. In the event that we are required to dispose of material assets or operations or restructure our debt to meet our debt service and other obligations, there cannot be any assurance as to the terms of any such transaction or how quickly any such transaction could be completed, if at all.
We may not be able to access new capital to fund our acquisition and growth strategies which could impair our ability to fund future capital needs and to grow.
Any limitations on our access to capital will impair our ability to execute our growth strategy, complete future acquisitions or future construction projects or other capital expenditures, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations. In addition, if the cost of capital becomes too expensive, our ability to develop or acquire strategic and accretive assets will be limited. Further, our customers may increase collateral requirements from us, including letters of credit which reduce available borrowing capacity, or reduce the business they transact with us to reduce their credit exposure to us.
Due to our lack of asset diversification, adverse developments in our gathering, transmission, processing, crude oil, condensate, natural gas and NGL services businesses would materially impact our financial condition.
We rely exclusively on the revenues generated from our gathering, transmission, processing, crude oil, natural gas and condensate and NGL services businesses and as a result our financial condition depends upon prices of, and continued demand for, natural gas, NGLs and crude oil. Due to our lack of asset diversification, an adverse development in one of these businesses would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

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We must continually compete for crude oil, condensate and natural gas supplies, and any decrease in supplies of such commodities could adversely affect our financial condition and results of operations.
In order to maintain or increase throughput levels in our natural gas gathering systems and asset utilization rates at our processing plants and to fulfill our current sales commitments, we must continually contract for new natural gas product. We may not be able to obtain additional contracts for crude oil, condensate, natural gas and NGL supplies. The primary factors affecting our ability to connect new wells to our gathering facilities include our success in contracting for existing supplies that are not committed to other systems and the level of drilling activity near our gathering systems. If we are unable to maintain or increase the volumes on our systems by accessing new supplies to offset the natural decline in reserves, our business and financial results could be materially, adversely affected. In addition, our future growth will depend in part upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our current supplies.
Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil, condensate and natural gas reserves. Prolonged periods of low commodity prices may put downward pressure on future drilling activity which may result in lower volumes. Tax policy changes or additional regulatory restrictions on development could also have a negative impact on drilling activity, reducing supplies of product available to our systems and assets. Additional governmental regulation of, or delays in issuance of permits for, the offshore exploration and production industry may negatively impact current and future volumes from offshore pipelines supplying our processing plants. We have no control over producers and depend on them to maintain sufficient levels of drilling activity. A material decrease in production or in the level of drilling activity in our principal geographic areas for a prolonged period, as a result of depressed commodity prices or otherwise, likely would have a material adverse effect on our results of operations and financial position.
A substantial portion of our assets is connected or dependent on hydrocarbon reserves that will decline over time, and the cash flows associated with those assets will decline accordingly.
A substantial portion of our assets, including our gathering systems, is dedicated to certain hydrocarbon reserves and wells for which the production will naturally decline over time. Accordingly, our cash flows associated with these assets will also decline. If we are unable to access new supplies of hydrocarbons either by connecting additional reserves to our existing assets or by constructing or acquiring new assets that have access to additional hydrocarbon reserves, our cash flows may decline.
Growing our business by constructing new pipelines and processing facilities subjects us to risks that oil, natural gas or NGL supplies will not be available upon completion of the facilities and risks of construction delay and additional costs due to obtaining rights-of-way permits and complying with federal, state and local laws.
One of the ways we intend to grow our business is through the construction of additions to our existing gathering systems and construction of new pipelines and gathering and processing facilities. Generally, we may have only limited natural gas or NGL supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas and NGLs to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
Construction of our major development projects subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our operating results, liquidity and financial position.
We are engaged in the planning and construction of several major development projects, some of which will take a number of months before commercial operation, such as our Cajun-Sibon expansion project and the Bearkat processing facility project. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, complying with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, financial condition, results of operations and liquidity. The construction of pipelines and gathering and processing and fractionation facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and capital position could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.

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We typically do not obtain independent evaluations of hydrocarbon reserves; therefore, volumes we service in the future could be less than we anticipate.
We typically do not obtain independent evaluations of hydrocarbon reserves connected to our gathering systems or that we otherwise service due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves serviced by our assets or the anticipated life of such reserves. If the total reserves or estimated life of the reserves is less than we anticipate and we are unable to secure additional sources, then the volumes transported on our gathering systems or that we otherwise service in the future could be less than anticipated. A decline in the volumes could have a material adverse effect on our results of operations and financial condition.
We may not be successful in balancing our purchases and sales.
We are a party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time the supplies that we have under contract may decline due to reduced drilling or other causes and we may be required to satisfy the sales obligations by buying additional gas or NGLs at prices that may exceed the prices received under the sales commitments. In addition, a producer could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a consumer could purchase more or less than contracted volumes. Any of these actions could cause our purchases and sales not to 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 income.
We have made commitments to purchase natural gas in production areas based on production-area indices and to sell the natural gas into market areas based on market-area indices, pay the costs to transport the natural gas between the two points and capture the difference between the indices as margin. Changes in the index prices relative to each other (also referred to as basis spread) can significantly affect our margins or even result in losses. For example, we are a party to one contract with a term to 2019 to supply approximately 150,000 MMBtu/d of gas. We buy gas for this contract on several different production-area indices on our NTPL and sell the gas into a different market area index. For the year ended December 31, 2013, we have recorded a loss of approximately $18.7 million on this contract, and we currently expect that we will record a loss of approximately $20.0 million to $24.0 million on this contract in 2014. Reduced supplies and narrower basis spreads in recent periods have increased the losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse. For additional information on this contract, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview."
Our profitability is dependent upon prices and market demand for oil, condensate, natural gas and NGLs, which are beyond our control and have been volatile.
We are subject to significant risks due to fluctuations in commodity prices. We are directly exposed to these risks primarily in the gas processing component of our business. For the year ended December 31, 2013, approximately 9% of our total gross operating margin was generated under percent of liquids contracts. Under these contracts we receive a fee in the form of a percentage of the liquids recovered and the producer bears all the cost of the natural gas shrink. Accordingly, our revenues under these contracts are directly impacted by the market price of NGLs.
We also realize processing gross operating margins under processing margin (margin) contracts. For the year ended December 31, 2013 approximately 5.6% of our total gross operating margin was generated under processing margin contracts. We have a number of processing margin contracts for activities at our Plaquemine, Gibson and Pelican processing plants. Under this type of contract, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost ("shrink") and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction or PTR. Our margins from these contracts can be greatly reduced or eliminated during periods of high natural gas prices relative to liquids prices. Although we do not currently have any processing margin contracts for our Blue Water and Eunice plants, we do have the opportunity to process liquids from wet gas flowing on the pipelines connected to these plants, as well as our other processing plants, when market pricing is favorable. Our Eunice and Blue Water plants are not profitable to operate unless market pricing is favorable.
We are also indirectly exposed to commodity prices due to the negative impacts on production and the development of production of oil, condensate, natural gas and NGLs connected to or near our assets and on our margins for transportation between certain market centers. Low prices for these products will reduce the demand for our services and volumes on our systems.
In the past, the prices of oil, condensate, natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, crude oil prices (based on the NYMEX futures daily close prices for the prompt month) in 2013

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ranged from a high of $110.53 per Bbl in September 2013 to a low of $86.68 per Bbl in April 2013. Weighted average NGL prices in 2013 (based on the Oil Price Information Service (OPIS) Napoleonville daily average spot liquids prices) ranged from a high of $1.09 per gallon in September 2013 to a low of $0.84 per gallon in June 2013. Natural gas prices (based on Gas Daily Henry Hub closing prices) during 2013 ranged from a high of $4.52 per MMBtu in December 2013 to a low of $3.08 per MMBtu in January 2013.
The markets and prices for oil, condensate, natural gas and NGLs depend upon factors beyond our control. These factors include the supply and demand for oil, condensate, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:
the impact of weather on the demand for oil and natural gas;
the level of domestic oil, condensate, and natural gas production;
technology, including improved production techniques (particularly with respect to shale development);
the level of domestic industrial and manufacturing activity;
the availability of imported oil, natural gas and NGLs;
international demand for oil and NGLs;
actions taken by foreign oil and gas producing nations;
the availability of local, intrastate and interstate transportation systems;
the availability of downstream NGL fractionation facilities;
the availability and marketing of competitive fuels;
the impact of energy conservation efforts; and
the extent of governmental regulation and taxation, including the regulation of "greenhouse gases."
Changes in commodity prices may also indirectly impact our profitability by influencing drilling activity and well operations, and thus the volume of gas, crude oil and condensate we gather and process. The volatility in commodity prices may cause our gross operating margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes. Moreover, hedges are subject to inherent risks, which we describe in "Item 7A. Quantitative and Qualitative Disclosure about Market Risk." Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income. For a discussion of our risk management activities, please read "Item 7A. Quantitative and Qualitative Disclosure about Market Risk."
We are vulnerable to operational, regulatory and other risks due to our concentration of assets in south Louisiana and the Gulf of Mexico, including the effects of adverse weather conditions such as hurricanes.
Our operations and revenues will be significantly impacted by conditions in south Louisiana and the Gulf of Mexico because we have a significant portion of our assets located in these two areas. Our concentration of activity in Louisiana and the Gulf of Mexico makes us more vulnerable than many of our competitors to the risks associated with these areas, including:
adverse weather conditions, including hurricanes and tropical storms;
delays or decreases in production, the availability of equipment, facilities or services; and
changes in the regulatory environment.
Because a significant portion of our operations could experience the same condition at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other midstream companies that have operations in more diversified geographic areas.
A reduction in demand for NGL products by the petrochemical, refining or other industries or by the fuel markets could materially adversely affect our results of operations and financial condition.
The NGL products we produce have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general or industry specific economic

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conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction industries), increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Our NGL products and the demand for these products are affected as follows:
Ethane.  Ethane is typically supplied as purity ethane or as part of ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream thereby reducing the volume of NGLs delivered for fractionation and marketing.

Propane.  Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of warmer-than-normal weather.
Normal Butane.  Normal butane is used in the production of isobutane, as a refined product blending component, as a fuel gas, and in the production of ethylene and propylene. Changes in the composition of refined products resulting from governmental regulation, changes in feedstocks, products and economics, demand for heating fuel and for ethylene and propylene could adversely affect demand for normal butane.
Isobutane.  Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.
Natural Gasoline.  Natural gasoline is used as a blending component for certain refined products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition resulting from governmental regulation of motor gasoline and in demand for ethylene and propylene could adversely affect demand for natural gasoline.
NGLs and products produced from NGLs also compete with global markets. Any reduced demand for ethane, propane, normal butane, isobutane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect demand for the services we provide as well as NGL prices, which would negatively impact our results of operations and financial condition.
We expect to encounter significant competition in any new geographic areas into which we seek to expand, and our ability to enter such markets may be limited.
If we expand our operations into new geographic areas, we expect to encounter significant competition for natural gas, condensate, NGLs and crude oil supplies and markets. Competitors in these new markets will include companies larger than us, which have both lower cost of capital and greater geographic coverage, as well as smaller companies, which have lower total cost structures. As a result, we may not be able to successfully develop acquired assets and markets located in new geographic areas and our results of operations could be adversely affected.
The terms of our credit facility and indentures may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions.
Our credit agreement governing our existing credit facility and the indentures governing our senior notes contain, and our new credit facility and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest. Our existing debt agreements include covenants that, among other things, restrict our ability to:
incur or guarantee additional indebtedness or issue preferred stock;
pay dividends on our equity securities or redeem, repurchase or retire our equity securities or subordinated indebtedness;
make investments;

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pay dividends or other distributions by our subsidiaries;
engage in transactions with our affiliates;
sell assets, including equity securities of our subsidiaries;
consolidate or merge;
incur liens;
prepay, redeem and repurchase certain debt;
make certain acquisitions;
transfer assets;
enter into sale and lease back transactions;
amend our partnership agreement;
make certain capital expenditures; and
change business activities we conduct.
In addition, our credit facility requires us to satisfy and maintain specified financial ratios and other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.
A breach of any of these covenants could result in an event of default under our credit facility and indentures. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If we are unable to repay the accelerated debt under our existing credit facility, the lenders under our existing credit facility could proceed against the collateral granted to them to secure that indebtedness. We have pledged substantially all of our assets as collateral under our existing credit facility. If indebtedness under our credit facility or indentures is accelerated, there can be no assurance that we will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.
We do not own most of the land on which our pipelines and compression facilities are located, which could disrupt our operations.
We do not own most of the land on which our pipelines and compression facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere and reduce our revenue.
We offer pipeline, truck, rail and barge services. Significant delays, inclement weather or increased costs affecting these transportation methods could materially affect our operations and earnings.
We offer pipeline, truck, rail and barge services. The costs of conducting these services could be negatively affected by factors outside of our control, including rail service interruptions, new laws and regulations, rate increases, tariffs, rising fuel costs or capacity constraints. Inclement weather, including hurricanes, tornadoes, snow, ice and other weather events, can negatively impact our distribution network. In addition, rail, truck or barge accidents involving the transportation of hazardous materials could result in significant claims arising from personal injury, property damage and environmental penalties and remediation.
We could experience increased severity or frequency of trucking accidents and other claims.
Potential liability associated with accidents in the trucking industry is severe and occurrences are unpredictable. A material increase in the frequency or severity of accidents or workers' compensation claims or the unfavorable development of existing claims could be expected to materially adversely affect our results of operations. In the event that accidents occur, we may be unable to obtain desired contractual indemnities, and our insurance may be inadequate in certain cases. The occurrence

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of an event not fully insured or indemnified against, or the failure or inability of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses.
Changes in trucking regulations may increase our costs and negatively impact our results of operations.
Our trucking services are subject to regulation as a motor carrier by the United States Department of Transportation and by various state agencies, whose regulations include certain permit requirements of state highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing and specifications and insurance requirements. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations and affect the economics of the industry by requiring changes in operating practices or by changing the demand for or the cost of providing trucking services. Some of these possible changes include increasingly stringent fuel emission limits, changes in the regulations that govern the amount of time a driver may drive or work in any specific period, limits on vehicle weight and size and other matters, including safety requirements.
If we do not make acquisitions on economically acceptable terms or efficiently and effectively integrate the acquired assets with our asset base, our future growth will be limited.
Our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in cash generated from operations on a per unit basis. If we are unable to make accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors, then our future growth and our ability to increase distributions will be limited.
From time to time, we may evaluate and seek to acquire assets or businesses that we believe complement our existing business and related assets. We may acquire assets or businesses that we plan to use in a manner materially different from their prior owner's use. Any acquisition involves potential risks, including:
the inability to integrate the operations of recently acquired businesses or assets, especially if the assets acquired are in a new business segment or geographic area;
the diversion of management's attention from other business concerns;
the failure to realize expected volumes, revenues, profitability or growth;
the failure to realize any expected synergies and cost savings;
the coordination of geographically disparate organizations, systems and facilities;
the assumption of unknown liabilities;
the loss of customers or key employees from the acquired businesses;
a significant increase in our indebtedness; and
potential environmental or regulatory liabilities and title problems.
Management's assessment of these risks is inexact and may not reveal or resolve all existing or potential problems associated with an acquisition. Realization of any of these risks could adversely affect our operations and cash flows. If we consummate any future acquisition, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.
The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other midstream service providers, and the price of, and demand for, crude oil, condensate, NGLs and natural gas in the markets we serve. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.

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In particular, our ability to renew or replace our existing contracts with industrial end-users and utilities impacts our profitability. For the year ended December 31, 2013, approximately 51% of our sales of gas that was transported using our physical facilities were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities may be reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price.
We depend on certain key customers, and the loss of any of our key customers could adversely affect our financial results.
We derive a significant portion of our revenues from contracts with key customers. To the extent that these and other customers may reduce volumes of natural gas purchased or transported under existing contracts, we would be adversely affected unless we were able to make comparably profitable arrangements with other customers. In addition, certain agreements with key customers provide for minimum volumes of natural gas, NGLs or natural gas services that require the customer to transport, process or purchase until the expiration of the term of the applicable agreement, subject to certain force majeure provisions. Customers may default on their obligations to transport, process or purchase the minimum volumes of natural gas, NGLs or natural gas services required under the applicable agreements.
We are exposed to the credit risk of our customers and counterparties, and a general increase in the nonpayment and nonperformance by our customers could have an adverse effect on our financial condition and results of operations.
Risks of nonpayment and nonperformance by our customers are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by our customers could adversely affect our results of operations and reduce our ability to make distributions to our unitholders.
Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.
A portion of our suppliers' and customers' natural gas production is developed from unconventional sources, such as deep gas shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Hydraulic fracturing activities are generally regulated by state oil and gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has released draft permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where EPA is the permitting authority. In addition, legislation has been proposed, but not passed that would provide for federal regulation of hydraulic fracturing and require disclosure of the chemicals used in the hydraulic-fracturing process. State legislatures and agencies are also enacting legislation and promulgating rules to regulate hydraulic fracturing and require disclosure of hydraulic fracturing chemicals.
There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. In addition, the EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and has initiated plans to promulgate regulations controlling wastewater disposal associated with hydraulic fracturing and shale gas development. In addition to the EPA, other federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. These on-going or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms. President Obama created the Interagency Working Group on Unconventional Natural Gas and Oil by Executive Order on April 13, 2012, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources.
We cannot predict whether any additional legislation or regulations will be enacted and, if so, what the provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process constraints for our suppliers and customers that could reduce the volumes of natural gas that move through our gathering systems which could materially adversely affect our revenue and results of operations.
Transportation on certain of our natural gas pipelines is subject to federal and state rate and service regulation, which could limit the revenues we collect from our customers and adversely affect the cash available for distribution to our

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unitholders. The imposition of regulation on our currently unregulated natural gas pipelines also could increase our operating costs and adversely affect the cash available for distribution to our unitholders.
The rates, terms and conditions of service under which we transport natural gas in our pipeline systems in interstate commerce are subject to FERC regulation under Section 311 of the Natural Gas Policy Act and the rules and regulations promulgated under that statute. Under these regulations, we are required to justify our rates for interstate transportation service on a cost-of-service basis every five years. Our intrastate natural gas pipeline operations are subject to regulation by various agencies of the states in which they are located. Should FERC or any of these state agencies determine that our rates for Section 311 transportation service or intrastate transportation service should be lowered, our business could be adversely affected.
Our natural gas gathering and processing activities generally are exempt from FERC regulation under the Natural Gas Act. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels since FERC has less extensively regulated the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Other state and local regulations also affect our business. We are subject to some ratable take and common purchaser statutes in the states where we operate. 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 to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting 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, and some of the states in which we operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which we operate that have adopted some form of complaint-based regulation, like Texas, generally allow 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.
Transportation on our liquids pipelines is subject to federal rate and service regulation, which could limit the revenues we collect from our customers and adversely affect the cash available for distribution to our unitholders.
Our liquids transportation pipelines in the Ohio River Valley and the Cajun-Sibon NGL pipeline, which went into service in November 2013, are subject to regulation by FERC under the ICA, the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates and terms and conditions of service for interstate service on liquids pipelines be just, reasonable and not unduly discriminatory or preferential. The ICA also requires that such rates and terms and conditions be set forth in tariffs filed with FERC. The ICA permits interested persons to challenge proposed new or changed rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months and investigate such rates. If, upon completion of an investigation, FERC finds that the new or changed rates are unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rates during the term of the investigation. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Under certain circumstances, FERC could limit our ability to set rates based on our costs or could order us to reduce our rates and could require the payment of reparations to complaining shippers for up to two years prior to the date of the complaint. FERC also has the authority to change our terms and conditions of service if it determines that they are unjust and unreasonable or unduly discriminatory or preferential.
As we acquire, construct and operate new liquids assets and expand our liquids transportation business segment, the classification and regulation of our liquids transportation services are subject to ongoing assessment and change based on the services we provide and determinations by FERC and the courts. Such changes may subject additional services we provide to regulation by FERC, which could increase our operating costs, decrease our rates and adversely affect our business.
We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.
The states in which we conduct operations administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968. These standards only apply to certain natural gas gathering lines based on the gathering line's operating pressure and proximity to people. Because of their pressure and location, substantial portions of our gathering facilities are not

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regulated under that statute. The gathering line exemptions, however, may be revised in the future and place more of our gathering facilities under jurisdiction of the DOT. Nonetheless, our natural gas transmission pipelines are subject to regulation by the DOT. In response to pipeline accidents in other parts of the country, Congress and the DOT, through PHMSA, have passed or are considering heightened pipeline safety requirements that may be applicable to gathering lines. As a result, our pipeline facilities are subject to the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which reauthorized funding for federal safety programs through 2015, increased penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines.
At the state level, several states have passed legislation or promulgated rulemaking addressing pipeline safety. Compliance with pipeline integrity and other pipeline safety regulations issued by DOT or those issued by the Texas Railroad Commission, or TRRC, could result in substantial expenditures for testing, repairs and replacement. TRRC regulations require periodic testing of all intrastate pipelines meeting certain size and location requirements. Our costs relating to compliance with the required testing under the TRRC regulations were approximately at $1.6 million, $1.4 million, and $1.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. We expect the costs for compliance with TRRC and DOT regulations to be approximately $2.1 million during 2014. If our pipelines fail to meet the safety standards mandated by the TRRC or the DOT regulations, then we may be required to repair or replace sections of such pipelines or operate the pipelines at a reduced maximum allowable operating pressure, the cost of which cannot be estimated at this time.
In addition, our liquids transportation pipelines are subject to regulation by the DOT, through PHMSA, pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as amended by the Pipeline Safety Improvement Act of 2002, and reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. PHMSA has adopted regulations requiring hazardous liquid pipeline operators to develop and implement integrity management programs for pipeline segments that, in the event of a leak or rupture, could affect “high consequence areas,” such as high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area.
Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the PHMSA or state requirements will not have a material adverse effect on our results of operations or financial positions. As our operations continue to expand into and around urban or more populated areas, such as the Barnett Shale, we may incur additional expenses to mitigate noise, odor and light that may be emitted in our operations and expenses related to the appearance of our facilities. Municipal and other local or state regulations are imposing various obligations including, among other things, regulating the location of our facilities, imposing limitations on the noise levels of our facilities and requiring certain other improvements that increase the cost of our facilities. We are also subject to claims by neighboring landowners for nuisance related to the construction and operation of our facilities, which could subject us to damages for declines in neighboring property values due to our construction and operation of facilities.
Failure to comply with existing or new environmental laws or regulations or an accidental release of hazardous substances, hydrocarbons or wastes into the environment may cause us to incur significant costs and liabilities.
Many of the operations and activities of our gathering systems, processing plants, fractionators, brine disposal operations and other facilities are subject to significant federal, state and local environmental laws and regulations. The obligations imposed by these laws and regulations include obligations related to air emissions and discharge of pollutants from our facilities and the cleanup of hazardous substances and other wastes that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for treatment or disposal. Various governmental authorities have the power to enforce compliance with these laws and regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Strict, joint and several liability may be incurred under these laws and regulations for the remediation of contaminated areas. Private parties, including the owners of properties near our facilities or upon or through which our gathering systems traverse, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations for releases of contaminants or for personal injury or property damage.
There is inherent risk of the incurrence of significant environmental costs and liabilities in our business due to our handling of natural gas, crude oil and other petroleum substances, our brine disposal operations, air emissions related to our operations, historical industry operations, waste disposal practices and the prior use of natural gas flow meters containing mercury. For example, we operate brine disposal wells in Ohio and West Virginia and may gather brine from surrounding states. These wells are regulated under the federal Safe Drinking Water Act (SDWA) as Class II wells and under state laws. State laws and regulations that govern these operations can be more stringent than the federal SDWA, such as the Ohio Department of Natural Resources rules which took effect October 1, 2012. These rules imposed new, more stringent environmentally responsible standards for the permitting and operating of brine disposal wells, including extensive review of

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geologic data and use of state of the art technology. They apply to new disposal wells and, as applicable, to existing wells. The Ohio Department of Natural Resources also imposes requirements on the transportation and disposal of brine. In addition, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may incur material environmental costs and liabilities. Furthermore, our insurance may not provide sufficient coverage in the event an environmental claim is made against us.
In addition, state and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste waters and an observed increase in minor seismic activity and tremors.  When caused by human activity, such events are called induced seismicity.  Regulatory agencies are continuing to study possible linkage between injection activity and induced seismicity.  To the extent these studies result in additional regulation of injection wells, such regulations could impose additional regulations, costs and restrictions on our brine disposal operations.
Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental laws or regulations, including, for example, legislation relating to the control of greenhouse gas emissions, or changes in existing environmental laws or regulations might adversely affect our products and activities, including processing, storage and transportation, as well as waste management and air emissions. Federal and state agencies could also impose additional safety requirements, any of which could affect our profitability. Changes in laws or regulations could also limit our production or the operation of our assets or adversely affect our ability to comply with applicable legal requirements or the demand for crude oil, brine disposal services or natural gas, which could adversely affect our business and our profitability.
Recently finalized rules under the Clean Air Act imposing more stringent requirements on the oil and gas industry could cause our customers and us to incur increased capital expenditures and operating costs as well as reduce the demand for our services.
On April 17, 2012, the EPA issued final rules under the Clean Air Act that became effective on October 15, 2012. Among other things, these rules require additional emissions controls for natural gas and NGLs production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds ("VOCs") and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require, among other things, the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or "green completions" on all hydraulically fractured wells constructed or refractured after January 1, 2015. Moreover, these rules establish specific requirements regarding emissions from compressors and controllers at natural gas gathering and boosting stations and processing plants together with dehydrators and storage tanks at natural gas processing plants, compressor stations and gathering and boosting stations. The rules also establish new requirements for leak detection and repair of leaks at natural gas processing plants that exceed 500 parts per million in concentration. These regulations could require a number of modifications to our operations and our natural gas exploration and production suppliers' and customers' operations, including the installation of new equipment, which could result in significant costs, including increased capital expenditures and operating costs. The incurrence of such expenditures and costs by our suppliers and customers could result in reduced production by those suppliers and customers and thus translate into reduced demand for our services. The rules are subject to an ongoing legal challenge brought by various parties, including environmental groups and industry, and the EPA has indicated that it may revise the rules. Any such revisions could affect our operations, as well as the operations of our suppliers and customers.
Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for the natural gas and NGL services we provide.
On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings allowed the EPA to proceed with the adoption and implementation of regulations restricting emissions of GHGs under existing provisions of the federal Clean Air Act. Since 2011, the EPA has required stationary sources that emit GHGs above regulatory and statutory thresholds to obtain a Prevention of Significant Deterioration permit. Moreover, on October 30, 2009, the EPA published a "Mandatory Reporting of Greenhouse Gases" final rule that established a comprehensive scheme requiring operators of stationary sources emitting more than established annual thresholds of GHGs to inventory and report their GHG emissions annually on a facility-by-facility basis. The Mandatory Reporting Rule was expanded by a rule promulgated on November 30, 2010 to include owners and operators of onshore oil and natural gas production, processing, transmission, storage and distribution facilities. Reporting emissions from such onshore activities is required on an annual basis. The first reports were due in 2012 for emissions occurring in 2011. Additionally, the EPA has proposed to regulate greenhouse gas emissions from certain electric generating units under the Clean Air Act's New Source Performance Standards ("NSPS") program. The EPA may propose to regulate additional source categories under the NSPS program in the future.

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In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and NGL fractionation plants, to acquire and surrender emission allowances with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur additional costs to reduce emissions of GHGs associated with our operations, could adversely affect our performance of operations in the absence of any permits that may be required to regulate emission of GHGs or could adversely affect demand for the natural gas we gather, process or otherwise handle in connection with our services.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance.
Our operations are subject to the many hazards inherent in the gathering, compressing, processing, transporting, fractionating, disposal and storage of natural gas, NGLs, condensate, crude oil and brine, including:
damage to pipelines, related equipment and surrounding properties caused by hurricanes, floods, fires and other natural disasters and acts of terrorism;
inadvertent damage from construction and farm equipment;
leaks of natural gas, NGLs, crude oil and other hydrocarbons;
induced seismicity;
rail accidents, barge accidents and truck accidents; and
fires and explosions.
These risks could result in substantial losses due to personal injury and/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 related operations. We are not fully insured against all risks incident to our business. In accordance with typical industry practice, we do not have business interruption insurance or any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. We are not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition.
The adoption of derivatives legislation by the United States Congress and promulgation of related regulations could have an adverse effect on our ability to hedge risks associated with our business.
Comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the Commodities Futures Trading Commission ("CFTC") to regulate certain markets for derivative products, including over-the-counter (“OTC”) derivatives. The CFTC has issued several new relevant regulations and other rulemakings are pending at the CFTC, the product of which would be rules that implement the mandates in the new legislation to cause significant portions of derivatives markets to clear through clearinghouses. The legislation and new regulations may also require counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation 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 and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition and our results of operations.
Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income.
Our operations expose us to fluctuations in commodity prices, and our credit facility exposes us to fluctuations in interest rates. We use over-the-counter price and basis swaps with other natural gas merchants and financial institutions. Use of these instruments is intended to reduce our exposure to short-term volatility in commodity prices. As of December 31, 2013, we have hedged only portions of our expected exposures to commodity price risk. In addition, to the extent we hedge our commodity price risk using swap instruments, we will forego the benefits of favorable changes in commodity prices. Although we do not

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currently have any financial instruments to eliminate our exposure to interest rate fluctuations, we may use financial instruments in the future to offset our exposure to interest rate fluctuations.
Even though monitored by management, our hedging activities may fail to protect us and could reduce our earnings and cash flow. Our hedging activity may be ineffective or adversely affect cash flow and earnings because, among other factors:
hedging can be expensive, particularly during periods of volatile prices;
our counterparty in the hedging transaction may default on its obligation to pay or otherwise fail to perform; and
available hedges may not correspond directly with the risks against which we seek protection. For example:
the duration of a hedge may not match the duration of the risk against which we seek protection;

variations in the index we use to price a commodity hedge may not adequately correlate with variations in the index we use to sell the physical commodity (known as basis risk); and

we may not produce or process sufficient volumes to cover swap arrangements we enter into for a given period. If our actual volumes are lower than the volumes we estimated when entering into a swap for the period, we might be forced to satisfy all or a portion of our derivative obligation without the benefit of cash flow from our sale or purchase of the underlying physical commodity, which could adversely affect our liquidity.
Our financial statements may reflect gains or losses arising from exposure to commodity prices for which we are unable to enter into fully effective hedges. In addition, the standards for cash flow hedge accounting are rigorous. Even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective cash flow hedges for accounting purposes. Our earnings could be subject to increased volatility to the extent our derivatives do not continue to qualify as cash flow hedges and, if we assume derivatives as part of an acquisition, to the extent we cannot obtain or choose not to seek cash flow hedge accounting for the derivatives we assume. Please read "Item 7A. Quantitative and Qualitative Disclosures about Market Risk" for a summary of our hedging activities.
Our success depends on key members of our management, the loss or replacement of whom could disrupt our business operations.
We depend on the continued employment and performance of the officers of our general partner and key operational personnel. Our general partner has entered into employment agreements with each of its executive officers. If any of these officers or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any "key man" life insurance for any officers.
A default under CEI’s Subsidiary’s credit facility could have an adverse effect on the price of our common units and could result in a change of control of our general partner.

A subsidiary of CEI, has entered into a credit facility that is initially secured by a first priority lien on 10,700,000 of our common units and that is guaranteed by CEI. A decline in the price of our common units could require CEI to pledge additional common units or to sell common units that it owns (directly or indirectly) in an expedited manner. Although we are not a party to this credit facility, if a default under such credit facility were to occur, the lenders could foreclose on the pledged units and/or CEI may be forced to sell its assets, including its interest in our general partner or the remaining common units owned by it, to fund any repayment obligations. Any such sale of our common units that it owns (directly or indirectly) could have an adverse effect on the market price of our common units. In addition, any sale by CEI of our general partner would allow the new owner of our general partner to replace the board of directors and officers of our general partner with its own choices and to control the decisions taken by the board of directors and officers. Moreover, any change of control of our general partner (i) would permit the lenders under our credit facility to declare all amounts thereunder immediately due and payable and (ii) may permit the holders of the two outstanding series of our senior unsecured notes to require us to repurchase such notes. If any such event occurs, we may be required to refinance our debt on unfavorable terms, which could negatively impact our results of operations and our ability to make distributions to our unitholders.

The credit and risk profile of CEI could adversely affect our risk profile, which could increase our borrowing costs, hinder our ability to raise capital or impact future credit ratings.

The credit and business risk profiles of CEI may factor into the credit evaluations of us. This is because our general partner can exercise significant influence over our business activities, including cash distribution policy, acquisition strategy

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and business risk profile. Another factor that may be considered in credit evaluations of us is the financial condition of CEI or its subsidiaries, including the degree of their financial leverage and their dependence on cash flow from us to service their indebtedness.

Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect the separateness of us, our general partner, CEI and its subsidiaries, our credit ratings and business risk profile could be adversely affected if the credit ratings and risk profiles of our general partner, CEI or its subsidiaries were viewed as substantially lower or more risky than ours.

Risks Inherent in an Investment in the Partnership
Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves.
Because distributions on our units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter will depend on numerous factors, some of which are beyond our control and the control of our general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.
We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at our current distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
the fees we charge and the margins we realize for our services;
the prices of, levels of production of and demand for oil, natural gas, condensate and NGLs;
the volume of natural gas we gather, compress, process, transport and sell, the volume of NGLs we process or fractionate and sell, the volume of crude oil we handle at our crude terminals, the volume of crude oil we gather, transport, purchase and sell and the volumes of brine we dispose;
the relationship between natural gas and NGL prices;
cash settlements of hedging positions;
the level of competition from other midstream energy companies;
the level of our operating and maintenance and general and administrative costs; and
prevailing economic conditions.
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:
the level of capital expenditures we make;
our ability to make borrowings under our credit facility to pay distributions;
the cost of acquisitions;
our debt service requirements and other liabilities;
fluctuations in our working capital needs;
general and administrative expenses;
restrictions on distributions contained in our debt agreements; and
the amount of cash reserves established by our general partner for the proper conduct of our business.

33


Crosstex Energy, Inc., or CEI, controls our general partner and owned a 15.0% fully diluted limited partner interest in us as of December 31, 2013. Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor its own interests.
As of December 31, 2013, CEI indirectly owned an aggregate fully diluted limited partner interest of approximately 15.0% in us. In addition, CEI owns and controls our general partner. Due to its control of our general partner and the size of its limited partner interest in us, CEI effectively controls all limited partnership decisions, including any decisions related to the removal of our general partner. Conflicts of interest may arise in the future between CEI and its affiliates, including our general partner, on the one hand, and our partnership, on the other hand. As a result of these conflicts our general partner may favor its own interests and those of its affiliates over our interests. These conflicts include, among others, the following situations:
Conflicts Relating to Control
our partnership agreement limits our general partner's liability and reduces its fiduciary duties, while also restricting the remedies available to our unitholders for actions that might, without these limitations, constitute breaches of fiduciary duty by our general partner;
in resolving conflicts of interest, our general partner is allowed to take into account the interests of parties in addition to unitholders, which has the effect of limiting its fiduciary duties to the unitholders;
our general partner's affiliates may engage in limited competition with us;
our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates;
our general partner decides whether to retain separate counsel, accountants or others to perform services for us;
in some instances our general partner may cause us to borrow funds from affiliates of the general partner or from third parties in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions; and
our partnership agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution.
Conflicts Relating to Costs
our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional limited partner interests and reserves;
our general partner determines which costs incurred by it and its affiliates are reimbursable by us; and
our general partner is not restricted 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 with any of these entities on our behalf.
Our unitholders have no right to elect our general partner or the directors of our general partner and have limited ability to remove our general partner.
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 did not elect our general partner or the board of directors of our general partner and have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis.
Furthermore, if unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The general partner generally may not be removed except upon the vote of the holders of 662/3% of the outstanding units voting together as a single class. Affiliates of the general partner controlled approximately 15.0% of all the limited partner units as December 31, 2013.
In addition, unitholders' voting rights are further restricted by the partnership agreement. It provides that any units held by a person that owns 20.0% 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 the board of directors of the general partner, cannot be voted on any matter. In addition, the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

34


As a result of these provisions, it will be more difficult for a third party to acquire our partnership without first negotiating such a purchase with our general partner and, as a result, our unitholders are less likely to receive a takeover premium.
Cost reimbursements due to our general partner may be substantial and will reduce the cash available for distribution to our unitholders.
Prior to making any distributions on the units, we reimburse our general partner and its affiliates, including officers and directors of our general partner, for all expenses they incur on our behalf. The reimbursement of expenses could adversely affect our ability to make distributions to our unitholders. Our general partner has sole discretion to determine the amount of these expenses.
The control of our general partner may be transferred to a third party without unitholder consent.
The general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owner of the general partner from transferring its ownership interest in the general partner to a third party. The new owner of the general partner would then be in a position to replace the board of directors and officers of the general partner with its own choices and to control the decisions taken by the board of directors and officers.
Our general partner's absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to our unitholders.
Our partnership agreement contains provisions that reduce the remedies available to our unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner.
Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. The partnership agreement also restricts the remedies available to our unitholders for actions that would otherwise constitute breaches of our general partner's fiduciary duties. If you own a unit, you will be treated as having consented to the various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary duties under applicable state law.
We may issue additional units without our unitholders' approval, which would dilute our unitholders' ownership interests.
We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. The issuance of additional limited partner interests 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 the common units may decline.
Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80.0% of the 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 the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their units.
Our unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

35


Our unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders to remove or replace our general partner, to approve amendments to our partnership agreement, or to take other action under our partnership agreement constituted participation in the "control" of our business, to the extent that a person who has transacted business with the Partnership reasonably believes, based on our unitholders' conduct, that our unitholders are a general partner. Our general partner generally has unlimited liability for the obligations of the Partnership, such as its debts and environmental liabilities, except for those contractual obligations of the Partnership that are expressly made without recourse to our general partner. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of that section may be liable to the limited partnership for the amount of the distribution for a period of three years from the date of the distribution. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business.
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 entity level taxation by individual states. If the IRS treats us as a corporation or we become subject to entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to you.
The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for federal income tax purposes.
If we were treated as a corporation for federal income tax purposes, we would pay additional tax on our income at corporate rates of up to 35.0% (under the law as of the date of this report) and we would probably pay state income taxes as well. In addition, distributions to unitholders would generally be taxed again as corporate distributions and none of our income, gains, losses, or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to 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 and thus would likely result in a material reduction in the value of the common 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, members of Congress have considered substantive changes to the existing U.S. tax laws that would have affected certain publicly traded partnerships. Although the legislation considered would not have appeared to affect our tax treatment, we are unable to predict whether any such change or other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. At the state level, because of widespread state budget deficits, 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 Texas franchise tax at a maximum effective rate of 1.0% of our gross income apportioned to Texas in the prior year. If federal income tax or material amounts of additional state tax were to be imposed on us, the cash available for distribution to unitholders could be reduced and/or the value of an investment in our common units would be adversely impacted. 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 will be decreased to reflect the impact of that law on us.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the costs of any contest could reduce the cash available for distribution to our unitholders.
We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel's conclusions expressed in this annual report or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with all of our counsel's conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which our common units trade. In addition, our costs of any contest with the IRS will be borne by us and therefore indirectly by our unitholders and our general partner since such costs will reduce the amount of cash available for distribution by us.
Unitholders may be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, they will be required to pay federal income taxes and, in some cases, state and local income

36


taxes on their share of our taxable income even if they do not receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even the tax liability that results from that income.
Tax gain or loss on the disposition of our common units could be different than expected.
Unitholders who sell common units will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of the unitholders' allocable share of total net taxable income decrease the unitholder's tax basis in his or her units, the amount, if any, of such prior excess distributions with respect to the units sold by the unitholder, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than the tax basis in that common unit, even if the price received is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our non-recourse liabilities, a unitholder who sells units may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and foreign 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), pension plans, and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other qualified retirement plans, will be unrelated business 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 federal income tax returns and generally pay tax on their share of our taxable income. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.
We will treat each purchase of common units as having the same tax benefits without regard to the specific units purchased. The IRS may challenge this treatment, which could adversely affect the value of the 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 benefits available to unitholders. It also could affect the timing of these tax benefits 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 the tax returns of unitholders.
The sale or exchange of 50% or more of our capital and profits interests within a 12-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership 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 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year if the termination occurs on a day other than December 31. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder who has adopted a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder's taxable income for the year of termination. Our termination would cause us to be treated as a new partnership for tax purposes for which we must make new tax elections, and we could be subject to penalties if we were to fail to recognize and properly report on our tax return 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 terminated its partnership makes a request for publicly traded partnership technical termination relief and such relief is granted by the IRS then, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception which allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause

37


us to change our business activities, or affect the tax consequences of an investment in our common units. For example, members of Congress have been considering substantive changes to the definition of qualifying income and the treatment of certain types of income earned from profits interests in partnerships. While these specific proposals would not appear to affect our treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will 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 our general partner, which may be unfavorable to such unitholders. Moreover, under our 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 taxable income, gain, loss and deduction between our general partner and certain of 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 taxable gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.
Tax Treatment of Income Earned Through C Corporation Subsidiaries
A material portion of our taxable income is earned through C corporation subsidiaries. Such C corporation subsidiaries are subject to federal income tax on their taxable income at the corporate tax rate, which is currently a maximum of 35%, and will likely pay state (and possibly local) income tax at varying rates, on their taxable income. Any such entity level taxes will reduce the cash available for distribution to our unitholders. Distributions from any such C corporation subsidiary will generally be taxed again to unitholders as dividend income to the extent of current and accumulated earnings and profits of such subsidiary. As of January 1, 2014, the maximum federal income tax rate applicable to such dividend income which is allocable to individuals is 20%. An individual unitholder's share of dividend and interest income from our C corporation subsidiaries would constitute portfolio income that could not be offset by the unitholder's share of our other losses or deductions.
As a result of investing in our common units, you will likely be subject to state and local taxes and return filing or withholding requirements in jurisdictions where you do not live.
In addition to federal income taxes, you will likely be subject to other taxes such as state and local income 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. You will likely be required to file state and local tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and you may be subject to penalties for failure to comply with those requirements. We own property or conduct business in a number of states, most of which currently impose a state income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may do business or own property in other states that impose an income tax. It is our unitholders' responsibility to file all federal, state, local, and foreign tax returns. Under the tax laws of some states where we will conduct business, we may be required to withhold a percentage from amounts to be distributed to a unitholder who is not a resident of that state. Our counsel has not rendered an opinion on the state, local, or foreign tax consequences of owning our common units.
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, and, accordingly, our counsel is unable to opine as to the validity of this method. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying

38


convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method 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. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, 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.
Compliance with and changes in tax law could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.
Item 1B.    Unresolved Staff Comments
We do not have any unresolved staff comments.
Item 2.    Properties
A description of our properties is contained in "Item 1. Business."
Title to Properties
Substantially all of our pipelines 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, property on which our pipeline was built was purchased in fee. Our processing plants are located on land that we lease or own in fee.
We believe that we have satisfactory title to all of our rights-of-way and land assets. Title to these assets may be subject to encumbrances or defects. We believe that none of such encumbrances or defects should materially detract from the value of our assets or from our interest in these assets or should materially interfere with their use in the operation of the business.
Item 3.    Legal Proceedings
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we may be a defendant in various legal proceedings and litigation arising in the ordinary course of business, including litigation on disputes related to contracts, property use or damage and personal injury. Additionally, as we continue to expand operations into more urban, populated areas, such as the Barnett Shale, we may see an increase in claims brought by area landowners, such as nuisance claims and other claims based on property rights. Except as otherwise set forth herein, we do not believe that any pending or threatened claim or dispute is material to our financial results on our operations. We maintain insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. However, we cannot 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.

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At times, our gas-utility and common carrier subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain. As a result, we (or our subsidiaries) are party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by our gas utility subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value, if any, of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, we do not expect that awards in these matters will have a material adverse impact on our consolidated results of operations or financial condition.
From time to time, owners of property located near our processing facilities or compression facilities file lawsuits against us. These suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas. In January 2012, a plaintiff in one of these lawsuits was awarded a judgment of $2.0 million. We have appealed the matter and have posted a bond to secure the judgment pending its resolution. We have accrued a $2.0 million liability related to this matter. Although it is not possible to predict the ultimate outcomes of these matters, we do not expect that awards in these matters will have a material adverse impact on our consolidated results of operations or financial condition.
Item 4.    Mine Safety Disclosures
Not applicable.

PART II
Item 5.    Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Our common units are listed on The NASDAQ Global Select Market under the symbol "XTEX". On February 19, 2014, the closing market price for the common units was $29.94 per unit and there were approximately 26,763 record holders and beneficial owners (held in street name) of our common units. For equity compensation plan information, see discussion under "Item. 12 Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters—Equity Compensation Plan Information."
The following table shows (i) the high and low closing sales prices per common unit, as reported by The NASDAQ Global Select Market and (ii) the amount of our quarterly distributions for the periods indicated.

 
 
Range
 
Cash Distribution
Declared Per Unit(a)
 
 
High
 
Low
 
2013:
 
 
 
 
 
 
Quarter Ended December 31
 
$
29.50

 
$
19.29

 
$
0.36

Quarter Ended September 30
 
22.05

 
18.22

 
0.34

Quarter Ended June 30
 
21.89

 
17.63

 
0.33

Quarter Ended March 31
 
18.58

 
14.70

 
0.33

2012:
 
 
 
 
 
 
Quarter Ended December 31
 
$
16.40

 
$
13.51

 
$
0.33

Quarter Ended September 30
 
17.01

 
13.91

 
0.33

Quarter Ended June 30
 
18.00

 
14.58

 
0.33

Quarter Ended March 31
 
17.27

 
16.40

 
0.33

_______________________________________________________________________________

(a)
For each quarter in which a distribution was paid, an identical cash distribution was paid on all outstanding preferred units for first three quarters of 2012, and a distribution based on the same distribution rate was paid through the issuance of additional preferred units ("paid-in-kind") on all outstanding preferred units for the fourth quarter of 2012 and all of 2013.

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Unless restricted by the terms of our credit facility, within 45 days after the end of each quarter, we will distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. Our available cash consists generally of all cash on hand at the end of the fiscal quarter, less reserves that our general partner determines are necessary to:
provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments or other agreements; or
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;
plus all cash on hand for the quarter resulting from working capital borrowings made after the end of the quarter on the date of determination of available cash.
The indentures governing our senior unsecured notes provide the ability to pay distributions if a minimum fixed charged coverage ratio is met and also provide baskets to make payments if such minimum is not met.
Our ability to distribute available cash is contractually restricted by the terms of our existing credit facility. Our credit facility contains covenants requiring us to maintain certain financial ratios. Under our existing credit facility, we are prohibited from making any distributions if the distribution would cause an event of default, or an event of default is existing, under our credit facility. Please read "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation—Description of Indebtedness."
Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt or, as necessary, reserves to comply with the terms of any of our agreements or obligations. Our distributions are made to our general partner based on its ownership interest with the remaining interest to unitholders, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved. Incentive distributions to our general partner increase to 13.0%, 23.0% and 48.0% based on incremental distribution thresholds as set forth in our partnership agreement.
On January 19, 2010, we issued approximately $125.0 million of Series A Convertible Preferred Units (the "preferred units") to an affiliate of Blackstone/GSO Capital Solutions under exemption Section 4(2) of the Securities Act of 1933, as amended (the "Securities Act"). The preferred units were convertible into common units on a one-for-one basis, subject to certain adjustments in the event of certain dilutive issuances of common units. Holders of the preferred units were entitled to receive quarterly cash distributions with a value equal to the greater of $0.2125 per unit or the amount of the quarterly distribution per unit paid to common unitholders. Such distributions were paid in cash during 2010 through the second quarter of 2012.
Beginning in the third quarter of 2012 through the fourth quarter of 2013, the quarterly distributions on the preferred units were paid-in-kind resulting in the issuance of 2,389,250 additional preferred units with the last distribution paid-in-kind on February 12, 2014. All future quarterly preferred unit quarterly distributions will be paid in cash.
We had the right to force conversion of the preferred units if (i) the daily volume weighted average trading price of the common units is greater than $12.75 per unit for 20 out of the trailing 30 trading days ending on two trading days before the date on which we deliver notice of such conversion, and (ii) the average trading volume of common units exceeds a specified number of common units (the “trading volume threshold”) for 20 out of the trailing 30 trading days ending on two trading days before the date on which we deliver notice of such conversion. On February 27, 2014, the board of directors of our general partner amended our partnership agreement to reduce the trading volume threshold from 250,000 common units to 215,000, and on that same date we delivered a notice of conversion of all outstanding preferred units.
For a discussion regarding our issuance of our senior unsecured notes, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Indebtedness."

41


Item 6.    Selected Financial Data
The following table sets forth selected historical financial and operating data of Crosstex Energy, L.P. as of and for the dates and periods indicated. Financial and operating data related to the July 2012 acquisition of our ORV assets is included for the years ended December 31, 2013 and 2012. The selected historical financial data are derived from the audited consolidated financial statements of Crosstex Energy, L.P. and should be read together with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

 
 
Crosstex Energy, L.P.
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
2010
 
2009
 
 
(In thousands, except per unit data)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
 
 
Midstream
 
$
1,943,239

 
$
1,791,288

 
$
2,013,942

 
$
1,792,676

 
$
1,583,551

Operating costs and expenses:
 
 
 
 
 
 
 
 
 
 
Purchased gas, NGLs and crude oil
 
1,546,987

 
1,397,530

 
1,638,777

 
1,454,376

 
1,272,329

Operating expenses
 
150,346

 
130,882

 
111,778

 
105,060

 
110,394

General and administrative
 
68,061

 
61,308

 
52,801

 
48,414

 
59,854

(Gain) loss on sale of property
 
(1,055
)
 
(342
)
 
264

 
(13,881
)
 
(666
)
(Gain) loss on derivatives
 
2,304

 
1,006

 
7,776

 
9,100

 
(2,994
)
Impairments
 
72,576

 

 

 
1,311

 
2,894

Depreciation and amortization
 
140,026

 
162,226

 
125,284

 
111,551

 
119,088

Total operating costs and expenses
 
1,979,245

 
1,752,610

 
1,936,680

 
1,715,931

 
1,560,899

Operating income (loss)
 
(36,006
)
 
38,678

 
77,262

 
76,745

 
22,652

Other income (expense):
 
 
 
 
 
 
 
 
 
 
Interest expense, net
 
(76,219
)
 
(86,521
)
 
(79,233
)
 
(87,035
)
 
(95,078
)
Loss on extinguishment of debt
 

 

 

 
(14,713
)
 
(4,669
)
Equity in income of limited liability company
 
46

 
3,250

 

 

 

Other income
 
1,367

 
5,053

 
707

 
295

 
1,400

Total other expense
 
(74,806
)
 
(78,218
)
 
(78,526
)
 
(101,453
)
 
(98,347
)
Loss from continuing operations before non-controlling interest and income taxes
 
(110,812
)
 
(39,540
)
 
(1,264
)
 
(24,708
)
 
(75,695
)
Income tax provision
 
(2,337
)
 
(725
)
 
(1,126
)
 
(1,121
)
 
(1,790
)
Loss from continuing operations, net of tax
 
(113,149
)
 
(40,265
)
 
(2,390
)
 
(25,829
)
 
(77,485
)
Loss from discontinued operations, net of tax
 

 

 

 

 
(1,796
)
Gain from sale of discontinued operations, net of tax
 

 

 

 

 
183,747

Discontinued operations
 

 

 

 

 
181,951


42


 
 
Crosstex Energy, L.P.
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
2010
 
2009
 
 
(In thousands, except per unit data)
Net income (loss)
 
(113,149
)
 
(40,265
)
 
(2,390
)
 
(25,829
)
 
104,466

Less: Net income (loss) from continuing operations attributable to the non-controlling interest
 

 
(163
)
 
(48
)
 
19

 
60

Net income (loss) attributable to Crosstex Energy, L.P. 
 
$
(113,149
)
 
$
(40,102
)
 
$
(2,342
)
 
$
(25,848
)
 
$
104,406

Preferred interest in net income attributable to Crosstex Energy, L.P. 
 
$
35,977

 
$
20,779

 
$
18,088

 
$
13,750

 
$

Beneficial conversion feature attributable to preferred units
 
$

 
$

 
$

 
$
22,279

 
$

General partner interest in net income (loss)
 
$
(2,721
)
 
$
(534
)
 
$
(732
)
 
$
(4,371
)
 
$
(819
)
Limited partners' interest in net income (loss) attributable to Crosstex Energy, L.P. 
 
$
(146,405
)
 
$
(60,347
)
 
$
(19,698
)
 
$
(57,506
)
 
$
105,225

Income (loss) per unit from continuing operations:
 
 
 
 
 
 
 
 
 
 
Basic and diluted common unit
 
$
(1.71
)
 
$
(1.01
)
 
$
(0.38
)
 
$
(1.12
)
 
$
(2.18
)
Senior subordinated unit
 
$

 
$

 
$

 
$

 
$
8.85

Distributions declared per limited partner unit
 
$
1.36

 
$
1.32

 
$
1.23

 
$
0.51

 
$

Balance Sheet Data (end of period):
 
 
 
 
 
 
 
 
 
 
Working capital deficit
 
$
(16,805
)
 
$
(18,323
)
 
$
(22,596
)
 
$
(17,640
)
 
$
(50,320
)
Property and equipment, net
 
1,854,249

 
1,471,248

 
1,241,901

 
1,215,104

 
1,279,060

Total assets
 
2,759,336

 
2,422,589

 
1,955,331

 
1,984,940

 
2,069,181

Long-term debt (including current maturities)
 
1,122,202

 
1,036,305

 
798,409

 
718,570

 
873,702

Capital lease obligations (including current maturities)
 
21,988

 
25,257

 
28,367

 
31,327

 
23,799

Partners' equity including non- controlling interest
 
1,206,692

 
1,009,081

 
900,459

 
976,936

 
893,282

Cash Flow Data:
 
 
 
 
 
 
 
 
 
 
Net cash flow provided by (used in)(1):
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
95,155

 
$
103,896

 
$
143,572

 
$
87,187

 
$
80,978

Investing activities
 
(481,137
)
 
(490,283
)
 
(132,094
)
 
14,638

 
379,874

Financing activities
 
385,915

 
362,368

 
(5,032
)
 
(84,907
)
 
(461,709
)
Non-GAAP Financial Measures:
 
 
 
 
 
 
 
 
 
 
Gross operating margin(2)
 
$
396,252

 
$
393,758

 
$
375,165

 
$
338,300

 
$
311,222

Adjusted EBITDA(3)(4)
 
$
214,876

 
$
214,089

 
$
214,028

 
$
186,880

 
$
158,682

Operating Data:
 
 
 
 
 
 
 
 
 
 
Pipeline throughput (MMBtu/d)
 
1,515,000

 
1,943,000

 
2,037,000

 
1,971,000

 
2,040,000

Natural gas processed (MMBtu/d)
 
1,036,000

 
1,350,000

 
1,325,000

 
1,366,000

 
1,235,000

NGL Fractionation (Gals/d) (5)
 
1,473,000

 
1,359,000

 
1,109,000

 
922,000

 
686,000

Crude Oil Handling (BBls/d)(6)
 
12,000

 
11,800

 

 

 

Brine Disposal (Bbls/d)(6)
 
7,000

 
7,800

 

 

 

_______________________________________________________________________________

(1)
Cash flow data includes cash flows from discontinued operations.
(2)
Gross operating margin is defined as revenue minus cost of purchased gas, NGLs and crude oil.
(3)
Adjusted EBITDA is defined as net income plus interest expense, provision for income taxes and depreciation and amortization expense, impairments, stock-based compensation, loss on extinguishment of debt, (gain) loss on noncash derivatives, transaction costs associated with successful transactions, distribution from limited liability company, non-controlling interest, certain severance and exit expenses and accrued expense of legal judgment under appeal; less (income) loss from discontinued operations, gain (loss) on sale of property and equity in income of limited liability company.
(4)
Adjusted EBITDA for the year ended December 31, 2009 is from continuing operations.


43


(5)
Includes Cajun Sibon NGL volumes, which are transported to our southern Louisiana assets for fractionation.

(6)
Crude oil handling and brine disposal volumes for the year ended December 31, 2012 include a daily average for July 2012 through December 2012, the six-month period these assets were operated by us.
Non-GAAP Financial Measures
We include the following non-GAAP financial measures in this report: adjusted EBITDA and gross operating margin.
We define adjusted EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense, impairments, stock-based compensation, loss on extinguishment of debt, (gain) loss on noncash derivatives, transaction costs associated with successful transactions, distribution from limited liability company, non-controlling interest, certain severance and exit expenses; and accrued legal judgment under appeal; less (income) loss from discontinued operations, gain (loss) on sale of property and equity in income of limited liability company. Our adjusted EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements such as investors, commercial 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 our 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 methods or capital structure; and
the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
Adjusted EBITDA is one of the critical inputs into the financial covenants within our credit facility. The rates we pay for borrowings under our existing credit facility are determined by the ratio of our debt to adjusted EBITDA.
Adjusted EBITDA should not 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. Our adjusted EBITDA may not be comparable to similarly titled measures of other companies because other entities may not calculate adjusted EBITDA operations in the same manner.
Adjusted EBITDA does not include interest expense, income taxes or depreciation 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 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 adjusted EBITDA, to evaluate our overall performance.

44


The following table provides a reconciliation of adjusted EBITDA to net income (loss):
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
2010
 
2009
 
 
(In thousands)
Net income (loss) attributable to Crosstex Energy, L.P. 
 
$
(113,149
)
 
$
(40,102
)
 
$
(2,342
)
 
$
(25,848
)
 
$
104,406

Interest expense
 
76,219

 
86,521

 
79,233

 
87,035

 
95,078

Depreciation and amortization
 
140,026

 
162,226

 
125,284

 
111,551

 
119,088

Impairment
 
72,576

 

 

 
1,311

 
2,894

Equity in income of limited liability company
 
(46
)
 
(3,250
)
 

 

 

Loss on extinguishment of debt
 

 

 

 
14,713

 
4,669

Distribution from limited liability company
 
17,468

 

 

 

 

(Gain) loss on sale of property
 
(1,055
)
 
(342
)
 
264

 
(13,881
)
 
(666
)
Stock-based compensation
 
14,170

 
9,207

 
7,308

 
9,276

 
8,742

Loss from discontinued operations, net of tax
 

 

 

 

 
1,796

Gain on sale of discontinued operations, net of tax
 

 

 

 

 
(183,747
)
Other(a)
 
8,667

 
(171
)
 
4,281

 
2,723

 
6,422

Adjusted EBITDA(b)
 
$
214,876

 
$
214,089

 
$
214,028

 
$
186,880

 
$
158,682

_______________________________________________________________________________

(a)
Includes financial derivatives marked-to-market; income taxes; transaction costs associated with successful transactions; non-controlling interest; certain severance and exit expenses and accrued expense of a legal judgment under appeal (as allowed for adjustment under our credit facility).
(b)
Adjusted EBITDA for the year ended December 31, 2009 is from continuing operations.
We define gross operating margin as revenues minus cost of purchased gas, NGLs and crude oil. We present gross operating margin by segment in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations." We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because our business is generally to purchase and resell natural gas and crude oil for a margin or to gather, process, transport or market natural gas, NGLs and crude oil for a fee. Operating expense is a separate measure used by management to evaluate operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. We do not deduct operating expenses from total revenue in calculating gross operating margin because these expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. As an indicator of our operating performance, gross operating margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our gross operating margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.
The following table provides a reconciliation of gross operating margin to operating income (loss):

 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
2010
 
2009
 
 
(In thousands)
Total gross operating margin
 
$
396,252

 
$
393,758

 
$
375,165

 
$
338,300

 
$
311,222

Add (deduct):
 
 
 
 
 
 
 
 
 
 
Operating expenses
 
(150,346
)
 
(130,882
)
 
(111,778
)
 
(105,060
)
 
(110,394
)
General and administrative expenses
 
(68,061
)
 
(61,308
)
 
(52,801
)
 
(48,414
)
 
(59,854
)
Gain (loss) on sale of property
 
1,055

 
342

 
(264
)
 
13,881

 
666

Gain (loss) on derivatives
 
(2,304
)
 
(1,006
)
 
(7,776
)
 
(9,100
)
 
2,994

Depreciation, amortization and impairments
 
(212,602
)
 
(162,226
)
 
(125,284
)
 
(112,862
)
 
(121,982
)
Operating income (loss)
 
$
(36,006
)
 
$
38,678

 
$
77,262

 
$
76,745

 
$
22,652


45


Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations
        You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the financial statements included in this report.
Overview
We are a Delaware limited partnership formed on July 12, 2002. We primarily focus on providing midstream energy services, including gathering, transmission, processing, and fractionation and marketing to producers of natural gas, natural gas liquids (NGLs), crude oil and condensate. We also provide crude oil, condensate and brine services to producers. Our midstream energy asset network includes approximately 3,600 miles of pipelines, nine natural gas processing plants, four fractionators, 3.1 million barrels of NGL cavern storage, rail terminals, barge terminals, truck terminals and a fleet of approximately 100 trucks. We manage and report our activities primarily according to geography. We have five reportable segments: (1) South Louisiana processing, crude and NGL, or PNGL, which includes our processing and NGL assets in South Louisiana; (2) Louisiana, or LIG, which includes our pipelines and processing plants located in Louisiana; (3) North Texas, or NTX, which includes our activities in the Barnett Shale and the Permian Basin; (4) Ohio River Valley, or ORV, which includes our activities in the Utica and Marcellus Shales; and (5) Corporate Segment, or Corporate, which includes our equity investment in Howard Energy Partners, or HEP, in the Eagle Ford Shale and our general partnership property and expenses.
We manage our operations by focusing on gross operating margin because our business is generally to purchase and resell natural gas, NGLs, crude oil and condensate for a margin or to gather, process, transport or market natural gas, NGLs, crude oil and condensate for a fee. In addition, we earn a volume based fee for brine disposal services. We define gross operating margin as operating revenue minus cost of purchased gas, NGLs, condensate and crude oil. Gross operating margin is a non-generally accepted accounting principle, or non-GAAP, financial measure and is explained in greater detail under "Non-GAAP Financial Measures" under "Item 6. Selected Financial Data."
Our gross operating margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through our pipeline systems, processed at our processing facilities, the volumes of NGLs handled at our fractionation facilities, the volumes of crude oil handled at our crude terminals, the volumes of crude oil gathered, transported, purchased and sold and the volume of brine disposed. We generate revenues from seven primary sources:
purchasing and reselling or transporting natural gas on the pipeline systems we own;
processing natural gas at our processing plants;
fractionating and marketing the recovered NGLs;
providing compression services;
purchasing and reselling crude and condensate;
providing crude oil transportation and terminal services; and
providing brine disposal services.
We generally gather or transport gas owned by others through our facilities for a fee, or we buy natural gas from a producer, plant or shipper at either a fixed discount to a market index or a percentage of the market index, then transport and resell the natural gas at the market index. We attempt to execute all purchases and sales substantially concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the margin we will receive for each natural gas transaction. Our gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. We are also party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time the supplies that we have under contract may decline due to reduced drilling or other causes and we may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In our purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased. However, on occasion we have entered into certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and we capture the difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as our margin. Changes in the basis spread can increase or decrease our margins.

46


One contract (the "Delivery Contract") has a term to 2019 that obligates us to supply approximately 150,000 MMBtu/d of gas. At the time that we entered into the Delivery Contract in 2008, we had dedicated supply sources in the Barnett Shale that exceeded the delivery obligations under the Delivery Contract. Our agreements with these suppliers generally provided that the purchase price for the gas was equal to a portion of our sales price for such gas less certain fees and costs. Accordingly, we were initially able to generate a positive margin under the Delivery Contract. However, since entering into the Delivery Contract, there has been both (1) a reduction in the gas available under our supply contracts and (2) the discovery of other shale reserves, most notably the Haynesville and the Marcellus Shales, which has increased the supplies available to east coast markets and reduced the basis spread between north Texas-area production and the market indices used in the Delivery Contract. Due to these factors, we have had to purchase a portion of the gas necessary to fulfill our obligations under the Delivery Contract at market prices, resulting in negative margins under the Delivery Contract.
We have recorded a loss of approximately $18.7 million during the year ended December 31, 2013 on the Delivery Contract. We currently expect that we will record a loss of approximately $20.0 million to $24.0 million during the year ending December 31, 2014. This estimate is based on forward prices, basis spreads and other market assumptions as of December 31, 2013. These assumptions are subject to change if market conditions change during 2014 and actual results under the Delivery Contract in 2014 could be substantially different from our current estimates, which may result in a greater loss than currently estimated.
We generally gather or transport crude oil owned by others by rail, truck, pipeline and barge facilities for a fee, or we buy crude oil from a producer at a fixed discount to a market index, then transport and resell the crude oil at the market index. We execute all purchases and sales substantially concurrently, thereby establishing the basis for the margin we will receive for each crude oil transaction. Additionally, we provide crude oil, condensate and brine services on a volume basis.
We also realize gross operating margins from our processing services primarily through three different contract arrangements: processing margins (margin), percentage of liquids (POL) or fixed-fee based. Under margin contract arrangements our gross operating margins are higher during periods of high liquid prices relative to natural gas prices. Gross operating margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. Under fixed-fee based contracts our gross operating margins are driven by throughput volume. See "Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk."
Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services and utilities. These costs are normally fairly stable across broad volume ranges and therefore do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas, liquids or crude oil moved through or by the asset.
Our general and administrative expenses are dictated by the terms of our partnership agreement. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, fees, services and other transaction costs related to acquisitions, and all other expenses necessary or appropriate to the conduct of business and allocable to us. Our partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.
Our Business Strategy
Our business strategy consists of two overarching objectives, which are to maximize earnings and growth of our existing businesses and enhance the scale and diversification of our assets.
As part of enhancing our scale and diversification, we have concentrated on expanding our NGL business, growing a crude oil and condensate business and developing our gas processing and transportation business in rich gas areas. We believe increasing our scale and diversification will strengthen us as a company because we believe it will lead to less reliance on any single geographic area, provide us with a better balance between business driven by crude oil and natural gas, offer us greater opportunities from a broader asset base and provide us with more sustainable fee-based cash flows.
Our strategies include the following:
Maximize earnings and growth of our existing businesses. We intend to leverage our franchise position, infrastructure and customer relationships in our existing areas of operation by expanding our existing systems to meet new or increased demand for our gathering, transmission, processing and marketing services.
Enhance the scale and diversification of our assets. We look to grow and diversify our business through acquiring and/or building assets in new areas that will serve as a platform for future growth with a focus on emerging shale plays and other areas with NGL, crude oil and condensate exposure.


47


Devon Energy Transaction
On October 21, 2013, the Partnership and the Operating Partnership entered into a Contribution Agreement (the “Contribution Agreement”) with Devon Energy Corporation (“Devon”) and certain of its wholly-owned subsidiaries pursuant to which two of Devon’s subsidiaries would contribute to the Operating Partnership 50% of the outstanding equity interests in EnLink Midstream Holdings, LP (formerly known as Devon Midstream Holdings, L.P.), a wholly-owned subsidiary of Devon referred to herein as "Midstream Holdings," and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC (formerly known as Devon Midstream Holdings GP, L.L.C.), the general partner of Midstream Holdings (“Midstream Holdings GP” and, together with Midstream Holdings and their subsidiaries, the “Midstream Group Entities”), in exchange for the issuance by the Partnership of 120,542,441 units representing a new class of limited partnership interests in the Partnership (collectively, the “Contribution”) with a value of approximately $2.4 billion based on the volume weighted average closing prices of our common units for the 20 trading days prior to the announcement of the transaction. Upon completion of the Contribution, Devon and its affiliates will own approximately 53% of the limited partner interests in the Partnership, with approximately 39% of the outstanding limited partner interests held by the Partnership's public unitholders and approximately 7% of the outstanding limited partner interests (and the approximate 1% general partner interest) held indirectly by EnLink Midstream (as defined below).
The Midstream Group Entities own Devon’s midstream assets in the Barnett Shale in North Texas, the Cana and Arkoma Woodford Shales in Oklahoma and Devon’s interest in Gulf Coast Fractionators in Mont Belvieu, Texas. These assets consist of natural gas gathering and transportation systems, natural gas processing facilities and NGL fractionation facilities located in Texas and Oklahoma. Midstream Holdings' primary assets consist of three processing facilities with 1.3 Bcf/d of natural gas processing capacity, approximately 3,685 miles of pipelines with aggregate capacity of 2.9 Bcf/d and fractionation facilities with up to 160 MBbls/d of aggregate NGL fractionation capacity.
In connection with the Contribution Agreement, CEI entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Devon and certain of its wholly-owned subsidiaries, EnLink Midstream, LLC (formerly known as New Public Rangers, L.L.C.), a holding company newly formed by Devon (“EnLink Midstream”), Rangers Merger Sub, Inc., a wholly-owned subsidiary of EnLink Midstream (“Rangers Merger Sub”), and Boomer Merger Sub, Inc., a wholly-owned subsidiary of EnLink Midstream (“Boomer Merger Sub”), pursuant to which Rangers Merger Sub will merge with and into CEI, and Boomer Merger Sub will merge with and into Acacia Natural Gas Corp I, Inc., a wholly-owned subsidiary of Devon ("New Acacia") (collectively, the “Mergers”), with CEI and New Acacia surviving as wholly-owned subsidiaries of EnLink Midstream. New Acacia owns the remaining 50% limited partner interest in Midstream Holdings. Devon will own the managing member of EnLink Midstream, and EnLink Midstream will indirectly own 100% of our general partner.
The closing of the Contribution is subject to the satisfaction of a number of conditions, including, but not limited to, the closing of the Mergers. The Merger is subject to customary closing conditions, including the approval of the proposal to adopt the merger agreement by the holders of at least 67% of the issued and outstanding shares of CEI's common stock entitled to vote as of the record date for the special meeting. The special meeting is scheduled to take place on March 7, 2014. The Contribution Agreement also contains customary termination provisions and will automatically terminate upon any termination of the Merger Agreement.
Recent Developments
Cajun-Sibon Phases I and II. In Louisiana, we are transforming our business that historically has been focused on processing offshore natural gas to a business that is focused on NGLs with additional opportunities for growth from new onshore supplies of NGLs.  The Louisiana petrochemical market historically has relied on liquids from offshore production; however, the decrease in offshore production and increase in onshore rich gas production have changed the market structure.  Cajun-Sibon Phases I and II will work to bridge the gap between supply, which aggregates in the Mont Belvieu area, and demand, located in the Mississippi River corridor of Louisiana, thereby building a strategic NGL position in this region.

We began this transformation by restarting our Eunice fractionator during 2011 at a rate of 15,000 Bbls/d of NGLs. We expanded the Eunice fractionator to a rate of 55,000 Bbls/d with Cajun-Sibon Phase I. Phase I of our pipeline extension project was completed in November 2013 and connects Mont Belvieu supply lines in east Texas to Eunice, providing a direct link to our fractionators in south Louisiana markets.  The Phase I Eunice fractionator expansion, which also was completed in early November 2013, has increased our interconnected fractionation capacity in Louisiana to approximately 97,000 Bbls/d of raw-make NGLs.
The Phase I expansion added 130-miles of 12-inch diameter pipeline to our existing 440-mile Cajun-Sibon NGL pipeline system, connecting Mont Belvieu to our Eunice fractionator. The pipeline currently has a capacity of 70,000 Bbls/d for raw make NGLs. The Phase I NGL pipeline extension originates from interconnects with major Mont Belvieu supply pipelines and provides connections for NGLs from the Permian Basin, Barnett Shale, Eagle Ford and other areas to our NGL fractionation facilities and key NGL markets in south Louisiana. Phase I is anchored by a five year ethane sales agreement with Williams

48


Olefins, a subsidiary of the Williams Companies, and a five year natural gasoline sales agreement with another company. We have entered into contracts of various lengths for all other purity products.
We have commenced construction of Cajun-Sibon Phase II which will further enhance our Louisiana NGL business with significant additions to the Cajun-Sibon Phase I infrastructure including further fractionation expansion. Phase II will include the addition of four pumping stations, totaling 13,400 horsepower, that will facilitate increasing NGL supply capacity from Phase I's 70,000 Bbls/d to 120,000 Bbls/d; the construction of a new 100,000 Bbls/d fractionator at the Plaquemine gas processing plant site; the conversion of our Riverside fractionator to a butane-and-heavier facility; and the construction of 57 miles of NGL pipeline that will originate at the Eunice fractionator and connect to the new Plaquemine fractionator, which will provide optionality to move purity products around the Louisiana-liquids market. We will also construct a 32-mile, 16-inch diameter extension of LIG's Bayou Jack lateral, which will provide gas services to customers in the Mississippi River corridor, replacing the conversion of supply lines that we currently use for liquid service. We expect Phase II will be in service during the second half of 2014.
Phase II is anchored by 10-year sales agreements with Dow Hydrocarbons and Resources, or Dow, to deliver up to 40,000 Bbls/d of ethane and 25,000 Bbls/d of propane produced at our new Plaquemine fractionator into Dow's Louisiana pipeline system. We will also deliver 70,000 MMBtu/d of natural gas to Dow's Plaquemine facility.
We believe the Cajun-Sibon project not only represents a tremendous growth step by leveraging our Louisiana assets but that it also creates a significant platform for continued growth of our NGL business. We believe this project, along with our existing assets, will provide a number of additional opportunities to grow this business, including expanding market optionality and connectivity, upgrading products, expanding rail imports, exporting NGLs and expanding fractionation and product storage capacity.
Bearkat Natural Gas Gathering and Processing System. In the fourth quarter of 2013, we commenced construction of a new natural gas processing complex and rich gas gathering pipeline system in the Permian Basin. The initial construction included treating, processing and gas takeaway solutions for regional producers. The project, which will be fully owned by us, is supported by a 10-year, fee-based contract.
The new-build processing complex, called Bearkat, will be strategically located near our existing Deadwood joint venture assets in Glasscock County, Texas. The processing plant will have an initial capacity of 60 MMcf/d, increasing our total operated processing capacity in the Permian to approximately 115 MMcf/d. We will also construct a 30-mile high-pressure gathering system upstream of the Bearkat complex to provide additional gathering capacity for producers in Glasscock and Reagan Counties. The entire project is scheduled to be completed in the second half of 2014.
Permian Pipeline Extension Project. In February 2014, the Partnership entered into an agreement to construct a new 35-mile, 12-inch diameter high-pressure pipeline that will provide critical gathering capacity for the aforementioned Bearkat natural gas processing complex. The pipeline will have a capacity of approximately 100 MMcf/d and will provide gas takeaway solutions for constrained producer customers in Howard, Martin and Glasscock counties. Right-of-way acquisition is underway, and the pipeline is expected to be operational in the second half of 2014.
Riverside Crude Facility Expansion. In June 2013, we completed the Phase II expansion of our Riverside facility located on the Mississippi River in southern Louisiana. The Riverside facility’s capacity to transload crude oil and condensate from railcars to our barge facility increased to approximately 15,000 Bbls/d of crude oil and condensate. Phase II additions to the Riverside facility include a 100,000 barrel above-ground crude oil and condensate storage tank, a rail spur with a 26-spot crude railcar unloading rack and a crude oil and condensate offloading facility with pumps and metering as well as a truck unloading bay. As part of the Phase II expansion, the Riverside facility was modified so that sour crude can be unloaded in addition to sweet crude.

Issuance of Common Units. In January 2013, the Partnership issued 8,625,000 common units representing limited partner interests in the Partnership at a public offering price of $15.15 per common unit for net proceeds of $125.5 million. Concurrently with the public offering in a privately negotiated transaction, the Partnership issued 2,700,000 common units representing limited partner interests in the Partnership at an offering price of $14.55 per unit for net proceeds of $39.3 million. In June 2013, the Partnership issued 8,280,000 common units representing limited partner interests in the Partnership (including 1,080,000 common units issued pursuant to the exercise of the underwriters' option to purchase additional common units) at a public offering price of $20.33 per common unit for net proceeds of $162.0 million. The net proceeds from the common unit offerings were used for capital expenditures for capital projects, including the Cajun-Sibon natural gas liquids pipeline expansion, to repay bank borrowings and for general partnership purposes.

In March 2013, we entered into an Equity Distribution Agreement (the “EDA”) with BMO Capital Markets Corp. (“BMOCM”). Pursuant to the terms of the EDA, we could from time to time through BMOCM, as our sales agent, sell common units representing limited partner interests having an aggregate offering price of up to $75.0 million. Sales of such common

49


units could be made by means of ordinary brokers’ transactions through the facilities of the NASDAQ Global Select Market LLC at market prices, in block transactions or as otherwise agreed by BMOCM and us.

In May 2013, we entered into an Equity Distribution Agreement ("Replacement EDA") with BMOCM. This Replacement EDA replaced the previous EDA. Pursuant to the terms of the Replacement EDA, we could from time to time through BMOCM, as its sales agent, sell common units representing limited partner interests having an aggregate offering price of up to $75.0 million. Sales of such common units could be made by means of ordinary brokers’ transactions through the facilities of the NASDAQ Global Select Market LLC at market prices, in block transactions or as otherwise agreed by BMOCM and us. 

Through December 31, 2013, we sold an aggregate of 1,181,628 common units and 3,348,213 common units under the EDA and Replacement EDA, respectively, generating proceeds of approximately $20.9 million and $72.3 million (net of approximately $0.3 million and $0.9 million of commissions to BMOCM), respectively. We used the net proceeds for general partnership purposes, including working capital, capital expenditures and repayments of indebtedness. We exhausted our capacity under the Replacement EDA on January 3, 2014.
 
Other Developments.  HEP is continuing to expand its midstream assets in the Eagle Ford Shale in south Texas.  We contributed an additional $30.6 million to HEP during the year ended December 31, 2013 to fund our 30.6% share of HEP’s expansion costs. In December 2013, Alinda Capital Partners acquired a 59% capital interest in HEP from Quanta Capital Solutions and GE Energy Financial Services.   We also received cash distributions totaling $17.5 million from HEP during the year ended December 31, 2013

Commodity Price Risk
We are subject to significant risks due to fluctuation in commodity prices. Our exposure to these risks is primarily in the gas processing component of our business. Processing margin and percent of liquids contracts are two types of contracts under which the we process gas and are exposed to commodity price risk. For the year ended December 31, 2013, approximately 9.0% of our processed gas arrangements, based on gross operating margin, were processed under POL contracts. A portion of the volume of inlet gas at our south Louisiana and north Texas processing plants is settled under POL agreements. Under these contracts we receive a fee in the form of a percentage of the liquids recovered and the producer bears all the costs of the natural gas volumes lost ("shrink"). Accordingly, our revenues under these contracts are directly impacted by the market price of NGLs.
We also realize processing gross operating margin under margin contracts and spot purchases. For the year ended December 31, 2013, approximately 5.6% of our processed gas arrangements, based on gross operating margin, was processed under margin contracts and spot purchases. We have a number of margin contracts on our Plaquemine, Gibson, Eunice, Blue Water and Pelican processing plants. Under this type of contract, we pay the producer for the full amount of inlet gas to the plant and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas shrink and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction or PTR.
We are also indirectly exposed to commodity prices due to the negative impacts on production and the development of production of natural gas, NGLs and crude oil connected to or near our assets and on our margins for transportation between certain market centers. Low prices for these products could reduce the demand for our services and volumes on our systems.
In the past, the prices of oil, natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, crude oil prices (based on the NYMEX futures daily close prices for the prompt month) in 2013 ranged from a high of $110.53 per Bbl in September 2013 to a low of $86.68 per Bbl in April 2013. Weighted average NGL prices in 2013 (based on the Oil Price Information Service (OPIS) Napoleonville daily average spot liquids prices) ranged from a high of $1.09 per gallon in September 2013 to a low of $0.84 per gallon in June 2013. Natural gas prices (based on Gas Daily Henry Hub closing prices) during 2013 ranged from a high of $4.52 per MMBtu in December 2013 to a low of $3.08 per MMBtu in January 2013.
Changes in commodity prices may also indirectly impact our profitability by influencing drilling activity and well operations, and thus the volume of gas we gather and process. The volatility in commodity prices may cause our gross operating margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes. For a discussion of our risk management activities, please read "Item 7A. Quantitative and Qualitative Disclosures about Market Risk."

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Results of Operations
Set forth in the table below is certain financial and operating data for the periods indicated, which includes our 2012 acquisition of the ORV assets from date of acquisition and excludes financial and operating data deemed discontinued operations. We manage our operations by focusing on gross operating margin, which we define as revenues minus cost of purchased gas, NGLs and crude oil as reflected in the table below.

 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(Dollars in millions)
LIG Segment
 
 
 
 
 
 
Revenues
 
$
580.3

 
$
786.9

 
$
939.3

Purchased gas and NGLs
 
(495.8
)
 
(678.2
)
 
(809.5
)
Total gross operating margin
 
$
84.5

 
$
108.7

 
$
129.8

NTX Segment
 
 
 
 
 
 
Revenues
 
$
394.0

 
$
365.5

 
$
432.6

Purchased gas and NGLs
 
(229.7
)
 
(180.1
)
 
(262.7
)
Total gross operating margin
 
$
164.3

 
$
185.4

 
$
169.9

PNGL Segment
 
 
 
 
 
 
Revenues
 
$
872.4

 
$
998.2

 
$
910.9

Purchased gas and NGLs
 
(778.0
)
 
(924.2
)
 
(835.4
)
Total gross operating margin
 
$
94.4

 
$
74.0

 
$
75.5

ORV Segment
 
 
 
 
 
 
Revenues
 
$
280.8

 
$
108.0

 
$

Purchased crude oil and condensate
 
(227.7
)
 
(82.3
)
 

Total gross operating margin
 
$
53.1

 
$
25.7

 
$

Corporate
 
 
 
 
 
 
Revenues
 
$
(184.2
)
 
$
(467.3
)
 
$
(268.9
)
Purchased gas, NGLs, condensate and crude oil
 
184.2

 
467.3

 
268.9

Total gross operating margin
 
$

 
$

 
$

Total
 
 
 
 
 
 
Revenues
 
$
1,943.3

 
$
1,791.3

 
$
2,013.9

Purchased gas, NGLs, condensate and crude oil
 
(1,547.0
)
 
(1,397.5
)
 
(1,638.7
)
Total gross operating margin
 
$
396.3

 
$
393.8

 
$
375.2

Midstream Volumes:
 
 
 
 
 
 
LIG
 
 
 
 
 
 
Gathering and Transportation (MMBtu/d)
 
473,000

 
783,000

 
912,000

Processing (MMBtu/d)
 
255,000

 
248,000

 
247,000

NTX
 
 
 
 
 
 
Gathering and Transportation (MMBtu/d)
 
1,042,000

 
1,160,000

 
1,125,000

Processing (MMBtu/d)
 
382,000

 
364,000

 
249,000

PNGL
 
 
 
 
 
 
Processing (MMBtu/d)
 
399,000

 
738,000

 
829,000

NGL Fractionation (Gals/d) (1)
 
1,473,000

 
1,359,000

 
1,109,000

ORV*
 
 
 
 
 
 
Crude Oil Handling (Bbls/d)(2)
 
12,000

 
11,800

 

Brine Disposal (Bbls/d)(2)
 
7,000

 
7,800

 

_______________________________________________________________________________
* Crude oil handling from PNGL is included in ORV reported volumes.
(1) Includes Cajun-Sibon pipeline volumes, which are transported to our southern Louisiana assets for fractionation.

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(2)
Crude oil handling and brine disposal volume for ORV for the year ended December 31, 2012 include a daily average for July 2012 through December 31, 2012, the six-month period these assets were operated by us.

Year ended December 31, 2013 Compared to Year ended December 31, 2012
Gross Operating Margin.    Gross operating margin was $396.3 million for the year ended December 31, 2013 compared to $393.8 million for the year ended December 31, 2012, an increase of $2.5 million. The following provides additional details regarding this change in gross operating margin:
The ORV segment gross operating margin increased $27.4 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, which only included operations for six months in 2012 from the date of acquisition. Gross operating margin increased $27.7 million related to our operation of the ORV assets during the first half on 2013 as compared to 2012. Gross operating margin for the second half of 2013 compared to 2012 remained relatively unchanged.
The PNGL segment had a gross operating margin increase of $20.4 million for the year ended December 31, 2013 compared to the year ended December 31, 2012. Our NGL fractionation and marketing activities contributed $24.1 million of gross operating margin increase due to improved margins from seasonal pricing spreads, and increased margins from truck and rail activity and increased NGL volumes from the November 2013 start-up of the Cajun-Sibon pipeline and the Eunice fractionator. The PNGL segment also includes our crude oil terminal activity in south Louisiana, which contributed $3.6 million of the gross operating margin increase. These increases were offset by a combined gross operating margin decrease of $7.3 million from our south Louisiana processing plants due to a less favorable processing environment, which caused a significant decline in volumes processed through the plants as well as declines in margins earned on those volumes. The Pelican processing plant was the only PNGL plant in service throughout 2013 and is the only plant currently in service.
The NTX segment had a decrease in gross operating margin of $21.1 million for the year ended December 31, 2013 compared to the year ended December 31, 2012. Gross operating margin increased by $3.2 million from our gas processing facilities primarily due to increased throughput on our Permian Basin system. This increase was offset by a decline in our gross operating margin of $24.3 million from our gathering and transmission assets due to a decline in our throughput volumes together with reduced gathering rates under certain contracts, including a contract with a major producer in north Texas.
The LIG segment had a decrease in gross operating margin of $24.2 million for the year ended December 31, 2013 compared to the year ended December 31, 2012. Gross operating margin decreased by $5.6 million from our Gibson and Plaquemine plants and decreased by $3.8 million from gas processed for our account by a third-party processor, in each case, due to a weaker processing environment during 2013 as compared to 2012. Gross operating margins decreased by $14.8 million on the gathering and transmission assets due to sales volumes lost related to the Bayou Corne sinkhole, loss of opportunity sales volumes due to lower processing margins and lower blending and treating volumes for the year ended December 31, 2013 as compared to the year ended December 31, 2012.  Although our north LIG system in the Haynesville Shale had volume declines, most of these volume declines were associated with gas transported under firm transportation agreements so we only realized a slight decrease in our transportation fee income on our north LIG system.
Operating Expenses.    Operating expenses were $150.3 million for the year ended December 31, 2013 compared to $130.9 million for the year ended December 31, 2012, an increase of $19.5 million, or 14.9%. This increase in operating expenses is primarily driven by an increase of $20.0 million related to the direct operating costs of the ORV assets for twelve months during 2013 as compared to only six months during 2012, which was offset by a decrease of $0.7 million at the other segments. The primary contributors to the total increase are as follows:
our labor and benefits expense increased by $11.1 million related to an increase in employee headcount following the acquisition of our ORV assets and project expansion in our PNGL segment;

our rents, leases and vehicle expenses increased $4.3 million primarily related to the acquisition and subsequent operations of our ORV assets; and

our regulatory and tax expenses increased by $3.2 million due to increased ad valorem tax expenses on our ORV and NTX assets.

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General and Administrative Expenses.    General and administrative expenses were $68.1 million for the year ended December 31, 2013 compared to $61.3 million for the year ended December 31, 2012, an increase of $6.8 million, or 11.1%. The increase is primarily a result of the following:

our labor and benefits expense increased by $0.8 million primarily due to an increase in headcount primarily related to the acquisition of our ORV assets and activity related to project expansion in our PNGL segment, partially offset by a decrease in overall bonus expense;

our stock based compensation expense increased by $4.4 million due to an increase in headcount, including $2.0 million attributable to certain bonuses paid in March 2013 in the form of stock and unit awards that immediately vested;

our fees and services expense increased by $0.4 million primarily due to $3.2 million of transaction costs in 2013 related to the proposed business combination with Devon as compared to $2.8 million of transaction costs in 2012;

our rents, leases and vehicle expenses increased by $0.5 million primarily due to an increase in office rent; and

our communication related costs increased by $0.5 million primarily due to network upgrades for our ORV assets.
Loss on Derivatives.    Loss on derivatives was $2.3 million for the year ended December 31, 2013 compared to a loss of $1.0 million for the year ended December 31, 2012. The derivative transaction types contributing to the net (gain) loss are as follows (in millions):
 
 
Years Ended December 31,
 
 
2013
 
2012
(Gain) Loss on Derivatives:
 
Total
 
Realized
 
Total
 
Realized
Basis swaps
 
$
1.0

 
$
1.9

 
$
5.2

 
$
4.6

Processing margin hedges
 
(0.2
)
 
(1.7
)
 
(3.1
)
 
0.5

Liquids Swaps-non designated
 
1.1

 

 
(1.0
)
 

Storage/Inventory Swaps
 
0.4

 
0.4

 
(0.1
)
 
(0.6
)
Net loss on derivatives
 
$
2.3

 
$
0.6

 
$
1.0

 
$
4.5

Depreciation and Amortization. Depreciation and amortization expenses were $140.0 million for the year ended December 31, 2013 compared to $162.2 million for the year ended December 31, 2012, a decrease of $22.2 million, or 13.7%. This decrease includes $27.8 million related to accelerated depreciation and amortization of the Sabine Pass Plant included in 2012, $4.9 million of decreased intangible amortization related to the Eunice processing plant impairment discussed below, and $5.4 million of decreased intangible amortization related to the revision in future estimated throughput volumes attributable to the dedicated acreage purchased with our gathering system in north Texas. These decreases were partially offset by $16.0 million of additional depreciation due to net asset additions, including $6.5 million related to the July 2012 acquisition of the ORV assets for the twelve months in 2013 as compared to six months in 2012, and $9.4 million related primarily to the Cajun Sibon pipeline, which came into service in November 2013.
Impairment. Impairment expense was $72.6 million for the year ended December 31, 2013. No impairment was recorded in 2012. The impairment relates to the termination of customer's contracts associated with Eunice processing plant which was shut down in August 2013 due to poor processing economics.

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Interest Expense. Interest expense was $76.2 million for the year ended December 31, 2013 compared to $86.5 million for the year ended December 31, 2012, a decrease of $10.3 million, or 11.9%. The increases and decreases in our interest bearing obligations are depicted below. Net interest expense consists of the following (in millions):
 
 
Years Ended
December 31,
 
 
2013
 
2012
Senior notes
 
$
82.0

 
$
75.1

Bank credit facility
 
6.2

 
6.5

Capitalized interest (1)
 
(22.3
)
 
(4.0
)
Amortization of debt issue costs and notes discount
 
8.0

 
7.3

Other
 
2.3

 
1.6

Total
 
$
76.2

 
$
86.5

(1) The increase in capitalized interest is primarily related to project expansions in our PNGL segment.
Equity in income of limited liability company. Equity in income of limited liability company was less than $0.1 million for the year ended December 31, 2013 compared to $3.3 million for the year ended December 31, 2012. The decrease of $3.2 million of equity in earnings relates to our investment in HEP.
Other Income. Other income was $1.4 million for the year ended December 31, 2013 compared to $5.1 million for the year ended December 31, 2012. Other income in 2013 primarily relates to a settlement of certain legal liabilities for less than the accrued liability resulting in a $1.0 million gain. Other income in 2012 includes a $3.0 million net gain related to the assignment to a third party of our rights, title and interest in a contract for the construction of a processing plant. In addition, we settled certain liabilities associated with sold assets for less than the accrued liabilities resulting in a $1.3 million gain during 2012.
Income Tax Expense. Income tax expense was $2.3 million for the year ended December 31, 2013 compared to $0.7 million for the year ended December 31, 2012, an increase of $1.5 million. The increase is due to income taxes attributable to the wholly-owned corporate entity that was formed to acquire the ORV assets in July 2012 and is subject to income taxes.
Year ended December 31, 2012 Compared to Year ended December 31, 2011
Gross Operating Margin. Gross operating margin was $393.8 million for the year ended December 31, 2012 compared to $375.2 million for the year ended December 31, 2011, an increase of $18.6 million, or 5.0%. The overall increase was due to the July 2012 acquisition of the ORV assets, increased throughput on our NTX and Permian Basin systems, an increase in NGL fractionation and marketing activity and an increase from our south Louisiana crude oil terminal activity. The following provides additional details regarding this change in gross operating margin:
The ORV segment contributed a total of $25.7 million to our gross operating margin growth for the year ended December 31, 2012. Gross operating margins from crude oil and condensate handling and brine disposal and handling were $17.2 million and $8.5 million, respectively.
The LIG segment had a gross operating margin decline of $21.1 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. The weaker processing environment during 2012 as compared to 2011 contributed to a decrease in gross operating margin for the processing activities during the year ended December 31, 2012. Due to this weaker environment, gross operating margin decreased by $7.7 million at the Plaquemine and Gibson plants and by $9.0 million from gas processed for our account by a third party processor. Gross operating margins decreased by $4.4 million on the gathering and transmission assets due to decreased throughput volumes which includes the impact of Bayou Corne sinkhole discussed more fully under "Liquidity and Capital Resources -Changes in Operations During 2013 and 2012."
The NTX segment had a gross operating margin increase of $15.5 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. An increase in throughput volume on the gathering and transmission assets from two north Texas expansion projects contributed $5.8 million to the gross operating margin improvement. The north Texas processing plants also had a gross operating margin increase of $4.3 million for the comparable periods primarily due to increased supply due to our expansion projects. In addition, the gas processing facilities located in the Permian Basin, which commenced operations in 2012, contributed $9.6 million to gross operating margin. These increases were partially offset by an increase in losses of $4.2 million on the Delivery Contract discussed more fully under "Overview."

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The PNGL segment had a gross operating margin decrease of $1.5 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. Our NGL fractionation and marketing activities contributed a gross operating margin improvement of $11.6 million as a result of the growth and expansion of our NGL fractionation and marketing activities. We increased our NGL fractionation and marketing activities through the restart of the Eunice fractionator in June 2011 and by increasing our truck and rail activity at our Riverside fractionator. These increases were offset by a combined gross operating margin decrease of $18.3 million from our south Louisiana processing plants due to a less favorable processing environment during 2012 as compared to 2011. Our crude oil terminal activity in south Louisiana also contributed a gross operating margin increase of $5.2 million during the year ended December 31, 2012.
Operating Expenses. Operating expenses were $130.9 million for the year ended December 31, 2012 compared to $111.8 million for the year ended December 31, 2011, an increase of $19.1 million, or 17.1%. The increase in operating expenses includes a total increase of $11.9 million related to the direct operating costs of the ORV assets that we purchased in July 2012. The primary contributors to the total increase are as follows:
our labor and benefits expense increased by $9.5 million related to the acquisition of our ORV assets and an increase in employee headcount for activity related to the Permian Basin expansions in the North Texas segment and for growth projects in the PNGL segment;
our materials, supplies and contractor service expenses increased by $5.8 million related to the acquisition of our ORV assets, project expansions in the North Texas and PNGL segments and compressor overhauls;
our rents, leases, vehicle and utility expenses increased $1.8 million due to increases from the acquisition of our ORV assets and project expansions in the North Texas and PNGL segments, which were partially offset by reductions in compressor rental and utilities expenses in the LIG segment;
our training, audit and consulting expenses related to regulatory activity increased by $1.2 million;
our ad valorem tax expense increased by $2.0 million due to project expansions; and
our other expenses decreased by $2.0 million due to the 2011 accrual of a legal judgment under appeal.
General and Administrative Expenses. General and administrative expenses were $61.3 million for the year ended December 31, 2012 compared to $52.8 million for the year ended December 31, 2011, an increase of $8.5 million, or 16.1%. The increase is primarily a result of the following:
our fees and services expense increased by $6.3 million primarily due to $2.8 million of acquisition cost for our ORV assets and $2.2 million for evaluation expenses related to potential acquisitions;
our stock based compensation expense increased by $1.8 million;
our labor and benefits expense decreased by $0.2 million primarily related to a decrease in bonuses substantially offset by an increase in labor and benefit expenses due to an increase in employee headcount; and
our traveling and training expense increased by $0.5 million primarily due to acquisition activities.
Loss on Derivatives. Loss on derivatives was $1.0 million for the year ended December 31, 2012 compared to a loss of $7.8 million for the year ended December 31, 2011. The derivative transaction types contributing to the net (gain) loss are as follows (in millions):
 
 
Years Ended December 31,
 
 
2012
 
2011
(Gain) Loss on Derivatives:
 
Total
 
Realized
 
Total
 
Realized
Basis swaps
 
$
5.2

 
$
4.6

 
$
1.4

 
$
1.3

Processing margin hedges
 
(3.1
)
 
0.5

 
6.6

 
5.7

Liquids Swaps-non designated
 
(1.0
)
 

 

 

Storage/Inventory Swaps
 
(0.1
)
 
(0.6
)
 
(0.3
)
 

Other
 

 

 
0.1

 

Net loss on derivatives
 
$
1.0

 
$
4.5

 
$
7.8

 
$
7.0


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Depreciation and Amortization. Depreciation and amortization expenses were $162.2 million for the year ended December 31, 2012 compared to $125.3 million for the year ended December 31, 2011, an increase of $36.9 million, or 29.5%. The increase includes $24.9 million due to accelerated depreciation related to the Sabine Pass plant, $4.9 million related to depreciation on the ORV assets and $2.8 million related to depreciation on additions in the Permian area. In addition, amortization increased $3.1 million due to intangible amortization related to a downward revision in future estimated throughput volumes attributable to the dedicated acreage purchased with our gathering system in north Texas and a $1.2 million impact due to depreciation on other net asset additions.
Interest Expense. Interest expense was $86.5 million for the year ended December 31, 2012 compared to $79.2 million for the year ended December 31, 2011, an increase of $7.3 million, or 9.2%. Net interest expense consists of the following (in millions):
 
 
Years Ended
December 31,
 
 
2012
 
2011
Senior notes (secured and unsecured)
 
$
75.1

 
$
64.3

Bank credit facility
 
6.5

 
5.5

Capitalized interest
 
(4.0
)
 
(0.9
)
Amortization of debt issue costs an notes discount
 
7.3

 
8.3

Other
 
1.6

 
2.0

Total
 
$
86.5

 
$
79.2

Equity in income of limited liability company. Equity in income of limited liability company was $3.3 million for the year ended December 31, 2012 compared to no equity in income for the year ended December 31, 2011. Equity in income of limited liability company relates to our investment in HEP.
Other Income. Other income was $5.1 million for the year ended December 31, 2012 compared to $0.7 million for the year ended December 31, 2011. Other income in 2012 includes a $3.0 million net gain related to the assignment to a third party of our rights, title and interest in a contract for the construction of a processing plant. In addition, we settled certain liabilities associated with sold assets for less than the accrued liabilities resulting in a $1.3 million gain during 2012.
Critical Accounting Policies
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment to the specific set of circumstances existing in our business. Compliance with the rules necessarily involves reducing a number of very subjective judgments to a quantifiable accounting entry or valuation. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. Our critical accounting policies are discussed below. See Note 2 of the Notes to Consolidated Financial Statements for further details on our accounting policies.
Revenue Recognition and Commodity Risk Management.    We recognize revenue for sales or services at the time the natural gas, NGLs or crude oil is delivered or at the time the service is performed. We generally accrue one month of sales and the related gas, NGL or crude oil purchases and reverse these accruals when the sales and purchases are actually invoiced and recorded in the subsequent months. Actual results could differ from the accrual estimates.
We utilize extensive estimation procedures to determine the sales and cost of gas, NGL or crude oil purchase accruals for each accounting cycle. Accruals are based on estimates of volumes flowing each month from a variety of sources. We use actual measurement data, if it is available, and will use such data as producer/shipper nominations, prior month average daily flows, estimated flow for new production and estimated end-user requirements (all adjusted for the estimated impact of weather patterns) when actual measurement data is not available. Throughout the month or two following production, actual measured sales and transportation volumes are received and invoiced and used in a process referred to as "actualization." Through the actualization process, any estimation differences recorded through the accrual are reflected in the subsequent month's accounting cycle when the accrual is reversed and actual amounts are recorded. Actual volumes purchased, processed or sold may differ from the estimates due to a variety of factors including, but not limited to: actual wellhead production or customer requirements being higher or lower than the amount nominated at the beginning of the month; liquids recoveries being higher or lower than estimated because gas processed through the plants was richer or leaner than estimated; the estimated impact of weather patterns being different from the actual impact on sales and purchases; and pipeline maintenance or allocation causing

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actual deliveries of gas to be different than estimated. We believe that our accrual process for sales and purchases provides a reasonable estimate of such sales and purchases.
We engage in price risk management activities in order to minimize the risk from market fluctuations in the price of natural gas, NGLs, crude oil and condensate. We also manage our price risk related to future physical purchase or sale commitments by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in natural gas and NGL prices.
We use derivatives to hedge against changes in cash flows related to product prices, as opposed to their use for trading purposes. FASB ASC 815 requires that all derivatives and hedging instruments are recognized as assets or liabilities at fair value. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.
We conduct "off-system" gas marketing operations as a service to producers on systems that we do not own. We refer to these activities as part of energy trading activities. In some cases, we earn an agency fee from the producer for arranging the marketing of the producer's natural gas. In other cases, we purchase the natural gas from the producer and enter into a sales contract with another party to sell the natural gas. The revenue and cost of sales for these activities are included in revenue on a net basis in the statement of operations.
We manage our price risk related to future physical purchase or sale commitments for energy trading activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance future commitments and significantly reduce risk related to the movement in natural gas prices. However, we are subject to counter-party risk for both the physical and financial contracts. Our energy trading contracts qualify as derivatives and we use mark-to-market accounting for both physical and financial contracts of the energy trading business. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to energy trading activities are recognized in earnings as gain or loss on derivatives immediately.
Impairment of Long-Lived Assets.    In accordance with FASB ASC 360-10-05, we evaluate the long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value.
When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding the purchase and resale margins on natural gas, volume of gas available to the asset, markets available to the asset, operating expenses, and future natural gas prices and NGL product prices. The amount of availability of gas and crude oil to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas and crude oil prices. Projections of gas and crude oil volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:
changes in general economic conditions in regions in which our markets are located;
the availability and prices of natural gas and crude oil supply;
our ability to negotiate favorable sales agreements;
the risks that natural gas and crude oil exploration and production activities will not occur or be successful;
our dependence on certain significant customers, producers and transporters of natural gas and crude oil; and
competition from other midstream companies, including major energy producers.
Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.
Impairment of Goodwill. Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of July 1 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying

57


amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step process goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. We evaluated our goodwill for impairment on July 1, 2013. Our goodwill impairment analysis performed on that date did not result in an impairment as the fair value of the ORV reporting unit substantially exceeded our carrying value, and subsequent to that date, no event has occurred indicating that the implied fair value of the reporting unit is less than the carrying value of our net assets.
Depreciation Expense and Cost Capitalization.    Our assets consist primarily of natural gas, NGL, condensate and crude oil gathering pipelines, processing plants, transmission pipelines and trucks. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the costs of funds used in construction. Capitalized interest represents the cost of funds used to finance the construction of new facilities and is expensed over the life of the constructed assets through the recording of depreciation expense. We capitalize the costs of renewals and betterments that extend the useful life, while we expense the costs of repairs, replacements and maintenance projects as incurred.
We generally compute depreciation using the straight-line method over the estimated useful life of the assets. Certain assets such as land, NGL line pack, natural gas line pack and crude oil line pack are non-depreciable. The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, we may review depreciation estimates to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values, which would impact future depreciation expense.
Liquidity and Capital Resources
Cash Flows from Operating Activities.    Net cash provided by operating activities was $95.2 million, $103.9 million and $143.6 million for the years ended December 31, 2013, 2012 and 2011, respectively. Operating cash flows and changes in working capital for 2013, 2012 and 2011 were as follows (in millions):
 
 
Years Ended December 31,
 
 
2013