Exhibit 99.1
Item 1.    Business
General
EnLink Midstream Partners, LP is a publicly traded Delaware limited partnership formed in 2002. Our common units are traded on the New York Stock Exchange (“NYSE”) under the symbol “ENLK.” Our business activities are conducted through our subsidiary, EnLink Midstream Operating, LP, a Delaware limited partnership (the “Operating Partnership”), and the subsidiaries of the Operating Partnership. Our executive offices are located at 2501 Cedar Springs Rd., Dallas, Texas 75201, and our telephone number is (214) 953-9500. Our Internet address is www.enlink.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 reports 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 EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership.
EnLink Midstream GP, LLC, a Delaware limited liability company, is our general partner (the “General Partner”). Our General Partner manages our operations and activities. Our General Partner is an indirect wholly-owned subsidiary of EnLink Midstream, LLC (“ENLC” or “EnLink Midstream”). ENLC’s units are traded on the NYSE under the symbol “ENLC.” ENLC’s manager is an indirect wholly-owned subsidiary of Devon Energy Corporation (“Devon”).
Effective as of March 7, 2014, the Operating Partnership acquired (the “Acquisition”) 50% of the outstanding equity interests in EnLink Midstream Holdings, LP (“Midstream Holdings”) and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings, in exchange for the issuance by the Partnership of 120,542,441 units representing a new class of limited partnership interests in the Partnership. At the same time, EnLink Midstream, Inc. (“EMI”), the entity that directly owns our General Partner, became a wholly-owned subsidiary of ENLC (together with the Acquisition, the “business combination”). At the conclusion of the business combination, another wholly-owned subsidiary of ENLC, Acacia Natural Gas Corp. I, Inc. (“Acacia”), owned the remaining 50% of the outstanding equity interests in Midstream Holdings. On February 17, 2015, Acacia contributed a 25% interest in Midstream Holdings (the “February Transferred Interests”) to us in exchange for 31.6 million Class D Common Units in the Partnership in a drop down transaction (the "February EMH Drop Down"). On May 27, 2015, the Partnership acquired the remaining 25% limited partner interest in Midstream Holdings (the “ May Transferred Interests” and, together with the February Transferred Interests, the "Transferred Interests") from Acacia in a drop-down transaction in exchange for 36.6 million Class E Common Units in us in a drop down transaction (the "May EMH Drop Down" and, together with the February Drop Down, the "EMH Drop Downs"). After giving effect to the EMH Drop-Downs, the Partnership owns 100% of Midstream Holdings. In this report, the term “Midstream Holdings” is sometimes used to refer to EnLink Midstream Holdings, LP itself or to EnLink Midstream Holdings, LP together with EnLink Midstream Holdings GP, LLC and their subsidiaries. On April 1, 2015, the Partnership acquired the Victoria Express Pipeline and related truck and terminal storage assets ("VEX") from Devon (the "VEX Interests"). See “Recent Growth Developments.”
Midstream Holdings was formerly a wholly-owned subsidiary of Devon Energy Corporation (“Devon”) and it gathers, processes and transports natural gas, primarily for Devon. Midstream Holdings also fractionates natural gas liquids (“NGLs”) into component NGL products. Under the acquisition method of accounting, Midstream Holdings is considered the historical predecessor of our business because Devon obtained control of us through its control of ENLC and through the indirect acquisition of our General Partner.














1






The following diagram depicts the organization and ownership of the Partnership as of December 31, 2014 (does not reflect EMH Drop Downs).





2






             

Definitions
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
Boe = six Mcf of gas per Bbl of oil
Btu = British thermal units
CO2= Carbon dioxide
CPI= Consumer Price Index
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. 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 July 12, 2002. We primarily focus on providing midstream energy services, including gathering, transmission, processing, fractionation, brine services and marketing, to producers of natural gas, NGLs, crude oil and condensate. Our midstream energy asset network includes approximately 8,900 miles of pipelines, 13 natural gas processing plants, seven fractionators, 3.1 million barrels of NGL cavern storage, 11 Bcf of natural gas storage, rail terminals, barge terminals, truck terminals and a fleet of approximately 100 trucks. Our operations are based in the United States and our sales are derived from external domestic customers.
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-based arrangements. We provide a variety of crude oil and condensate services, which include crude oil and condensate gathering via pipelines, barges, rail and trucks, condensate stabilization and 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 transmission lines that transport NGLs from east Texas and from our south Louisiana processing plants to our fractionators in south Louisiana. Additionally, we own an economic interest in an NGL fractionator located at Mont Belvieu, Texas that receives raw mix NGLs from customers, fractionates such raw mix and redelivers the finished products to the customers for a fee. Devon is one of the largest customers of this fractionator. Our crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities 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 are comprised of systems and other assets in which our interest is held through our wholly-owned subsidiaries as well as systems and other assets owned by Midstream Holdings, in which we own a 100% interest as of May 27, 2015, and are located in four primary regions:
•
Texas. Our Texas assets consist of transmission pipelines with a capacity of approximately 1.3 Bcf/d, processing facilities with a total processing capacity of approximately 1.2 Bcf/d and gathering systems with total capacity of approximately 2.8 Bcf/d.

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•
Oklahoma. Our Oklahoma assets consist of processing facilities with a total processing capacity of approximately 550 MMcf/d and gathering systems with total capacity of approximately 605 MMcf/d.
•
Louisiana. Our Louisiana assets consist of transmission pipelines with a capacity of approximately 3.5 Bcf/d, processing facilities with a total processing capacity of approximately 1.7 Bcf/d and gathering systems with total capacity of approximately 510 MMcf/d.
•
Ohio River Valley. Our Ohio River Valley (“ORV”) operations are an integrated network of assets comprised of a 5,000-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 5,000 Bbls/d. Additionally, our ORV operations include five condensate stabilization and natural gas compression stations, including two stations under construction, with combined capacities of 19,000 Bbls/d of condensate stabilization and 580 MMcf/d of natural gas compression.
About Devon
Devon (NYSE: DVN) is a leading independent energy company engaged primarily in the exploration, development and production of crude oil, natural gas and NGLs. Devon’s operations are concentrated in various onshore areas in the U.S. and Canada. Please see Devon’s Annual Report on Form 10-K for the year ended December 31, 2014 for additional information concerning Devon’s business.
Our Business Strategies
Our primary business objectives are to have sustained growth in partnership distributions and to maintain a strong balance sheet. We intend to accomplish these objectives by executing the following strategies:
•
Organic Growth: pursue opportunities around our existing footprint. We expect to grow certain of our systems organically over time by meeting Devon’s and our other customers’ midstream service needs that result from their drilling activity in our areas of operation. We continually evaluate whether to pursue economically attractive organic expansion opportunities in existing or new areas of operation that allow us to leverage our existing infrastructure, operating expertise and customer relationships by constructing and expanding systems to meet new or increased demand for our services.
•
Growing with Devon: We expect our relationship with Devon will continue to provide us with significant business opportunities. Devon is a leading North American E&P company with a focus on five core growth areas: Eagle Ford, Permian Basin, Anadarko Basin, Canadian oil sands and the Barnett Shale.
•
Dropdowns: maximize opportunities provided by Devon’s sponsorship and assets held by ENLC. We plan to execute our growth in part through continued pursuit of accretive drop down opportunities from Devon and ENLC. In the first half of 2015, we acquired the Transferred Interests in Midstream Holdings from ENLC and acquired the Victoria Express Pipeline and related truck terminal and storage assets from Devon (the "VEX Interests") as described in Note (3)-Acquisitions. ENLC and Devon are parties to a first offer agreement pursuant to which ENLC has a right of first offer with respect to Devon’s 50% interest in the Access Pipeline (the “First Offer Agreement”). We are party to a preferential rights agreement with ENLC pursuant to which ENLC granted us a right of first refusal, for a period of 10 years, with respect to Devon’s 50% interest in the Access Pipeline transportation system, to the extent ENLC in the future obtains such interest pursuant to the First Offer Agreement. In addition, if ENLC has the opportunity to exercise its right of first offer for Devon’s interest in the Access Pipeline pursuant to the First Offer Agreement, but determines not to exercise such right, ENLC is required to assign such right to us. We also believe there will continue to be significant opportunities as Devon continues to develop its oil and gas production. However, we cannot be certain that these opportunities will be made available to us, or that we will choose to pursue any such opportunity.
•
Acquisitions: pursue strategic and accretive acquisitions. We pursue strategic and accretive acquisition opportunities within the midstream energy industry, both in new and existing lines of business and geographic areas of operation.
•
Strong Balance Sheet: maintain an investment grade quality financial profile. We intend to maintain appropriate leverage and other key financial metrics in line with other partnerships in our sector that have received investment grade credit ratings. By maintaining an investment grade quality financial profile, we believe that we will be able to pursue strategic acquisitions and large growth projects at a lower cost of capital, which enhances our competitiveness.

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Our Competitive Strengths
We believe that we are well-positioned to execute our business strategies and to achieve our business objectives due to the following competitive strengths:
•
Devon’s sponsorship. We expect our relationship with Devon will continue to provide us with significant business opportunities. Devon is one of the largest independent oil and gas producers in North America. Devon has a significant interest in promoting the success of our business, due to its approximate 70% ownership interest in ENLC and approximate 49% ownership interest in us as of December 31, 2014.
•
Strategically-located assets. Our assets are strategically located in strategic producing regions with the potential for increasing throughput volume and cash flow generation. Our assets are in areas consistent with Devon's strategic focus. Our asset portfolio includes gathering, transmission, fractionation, processing and stabilization systems that are located in areas in which producer activity is focused on crude oil, condensate and NGLs as well as natural gas. We have developed or are in the process of developing platforms in these areas through organic development and acquisitions.
•
Stable cash flows. Approximately 95% of our cash flows were derived from fee-based services with no direct commodity exposure during 2014. Midstream Holdings has entered into 10-year, fixed-fee gathering and processing agreements with a subsidiary of Devon pursuant to which Midstream Holdings or its subsidiary provide gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon to Midstream Holdings’ gathering and processing systems in the Barnett and Cana-Woodford Shales. These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering lands within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. These agreements also include five-year minimum volume commitments and annual rate escalators. Please read “—Midstream Holdings’ Contractual Relationship with Devon.” We will continue to focus on contract structures that reduce volatility and support long-term stability of cash flows.
•
Integrated midstream services. We span the energy value chain by providing natural gas, NGL, crude oil, condensate and water services across a diverse customer base. These services include gathering, compressing, treating, processing, transporting, storing and selling natural gas, producing, fractionating, transporting, storing and selling NGLs, and gathering, transporting, storing and trans-loading crude oil and condensate. We believe our ability to provide all of these services gives us an advantage in competing for new opportunities because we can provide substantially all services that producers, marketers and others require to move natural gas, NGLs, crude oil and condensate from the wellhead to the market on a cost-effective basis.
•
Financial flexibility to pursue expansion and acquisition opportunities. We believe our stable cash flows, strong balance sheet and access to debt and equity capital markets provide us with the financial flexibility to competitively pursue acquisition and expansion opportunities and to execute our strategy across capital market cycles.
•
Experienced management team. We believe our management team has a proven track record of creating value through the development, acquisition, optimization and integration of midstream assets. Our management team has an average of over 20 years of experience in the energy industry. We believe this team provides us with a strong foundation for evaluating growth opportunities and operating our assets in a safe, reliable and efficient manner.
We believe that we will leverage our competitive strengths to successfully implement our strategy; however, our business involves numerous risks and uncertainties that may prevent us from achieving our primary business objective. For a more complete description of the risks associated with our business, please see “Item 1A. Risk Factors” of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2014 (the "2014 Form 10-K") filed with the Securities and Exchange Commission ("SEC") on February 20, 2015.

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Midstream Holdings' Contractual Relationship with Devon
Upon the consummation of the business combination, Midstream Holdings entered into a 10-year transportation contract with Devon for the Acacia transmission system as well as the following additional fee-based agreements with Devon:
 
 
 
Contract
Term
 
Minimum
Gathering
Volume
Commitment
 
Minimum
Processing
Volume
Commitment
 
Minimum
Volume
Commitment
Term
 
Annual
Rate
Contract
 
(Years)
 
(MMcf/d)
 
(MMcf/d)
 
(Years)
 
Escalators
Bridgeport gathering and processing contract (1)
10

 
850

 
650

 
5

 
CPI
East Johnson County gathering contract
10

 
125

 
—

 
5

 
CPI
Northridge gathering and processing contract (2)
10

 
40

 
40

 
5

 
CPI
Cana gathering and processing contract
10

 
330

 
330

 
5

 
CPI
 
 
 
 
 
 
 
 
 
 
 
(1)
The Bridgeport gathering and processing contract includes volume commitments to the Bridgeport processing facility as well as the Bridgeport gathering systems.
(2)
On December 1, 2014, Devon Gas Services (“Gas Services”) assigned its 10-year gathering and processing agreement to Linn Exchange Properties, LLC (“Linn Energy”), which is a subsidiary of Linn Energy, LLC, in connection with Gas Services' divestiture of certain of its southeastern Oklahoma assets. Accordingly, on December 1, 2014, Linn Energy assumed all of Gas Services' obligations under the agreement, which remains in full force and effect. This agreement relates to production dedicated to our Northridge assets in southeastern Oklahoma.
Recent Growth Developments
Organic Growth
Ohio River Valley Condensate Pipeline and Condensate Stabilization Facilities. In August 2014, we announced plans to construct a new 45-mile, eight-inch condensate pipeline and six natural gas compression and condensate stabilization facilities that will service major producer customers in the Utica Shale, including Eclipse Resources. As a component of the project, the Partnership has entered into a long-term, fee-based agreement under which Eclipse Resources will receive compression and stabilization services and has agreed to sell stabilized condensate to us.
The new-build stabilized condensate pipeline will connect to our existing 200-mile pipeline in the ORV, providing producer customers in the region access to premium market outlets through our barge facility on the Ohio River and rail terminal in Ohio. The pipeline, which is expected to be complete in the second half of 2015, is expected to have an initial capacity of approximately 50,000 Bbls/d with potential to expand.
We will also build and operate six natural gas compression and condensate stabilization facilities in Noble, Belmont, and Guernsey counties in Ohio. Upon completion, the facilities will have a combined capacity of approximately 560 MMcf/d of natural gas compression and approximately 41,500 Bbls/d of condensate stabilization. The first two compression and condensate stabilization facilities began operations during the fourth quarter of 2014 and the remaining four facilities are expected to be operational by the end of 2015.
In support of the project, we plan to leverage and expand our existing midstream assets in the region, including increasing condensate storage capacity and handling capabilities at our barge terminal on the Ohio River. We will add approximately 130,000 barrels of above ground storage, bringing our total storage capacity at the barge facility to over 360,000 barrels.
Marathon Petroleum Joint Venture. We have entered into a series of agreements with a subsidiary of Marathon Petroleum Corporation (“Marathon Petroleum”), to create a 50/50 joint venture named Ascension Pipeline Company, LLC. This joint venture will build a new 30-mile NGL pipeline connecting our existing Riverside fractionation and terminal complex to Marathon Petroleum's Garyville refinery located on the Mississippi River. The bolt-on project to our Cajun-Sibon NGL system is supported by long-term, fee-based contracts with Marathon Petroleum. Under the arrangement, we will serve as the construction manager and operator of the pipeline project, which is expected to be operational in the first half of 2017.
Cajun-Sibon Phases I and II. In Louisiana, we have transformed our business that historically has been focused on processing offshore natural gas to a business that is now 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 now 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. 

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The pipeline expansion and the Eunice fractionation expansion under Phase I were completed and commenced operation in November 2013. Phase II of the Cajun-Sibon expansion, which was completed and commenced operation in September 2014, increased the Cajun-Sibon pipeline capacity by an additional 50,000 Bbls/d to approximately 130,000 Bbls/d and added a new 100,000 Bbl/d fractionator at our Plaquemine gas processing complex. The throughput of the pipeline averaged 109,900 Bbls/d during the fourth quarter of 2014. Our fractionators in south Louisiana averaged approximately 98,300 Bbls/d during the fourth quarter of 2014.
We believe the Cajun-Sibon project represents a tremendous growth step by leveraging our Louisiana assets and also by creating 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 September 2014, we completed construction of a new natural gas processing complex and rich gas gathering pipeline system in the Permian Basin called Bearkat.  The natural gas processing complex includes treating, processing and gas takeaway solutions for regional producers. The project, which is fully owned by us, is supported by a 10-year, fee-based contract.
Bearkat is strategically located near our existing Deadwood joint venture assets in Glasscock County, Texas. The processing plant has an initial capacity of 60 MMcf/d, increasing our total operational processing capacity in the Permian to approximately 115 MMcf/d. We also completed construction of a 30-mile high-pressure gathering system upstream of the Bearkat complex to provide additional gathering capacity for producers in Glasscock and Reagan counties.
During 2014, we constructed a new 35-mile, 12-inch diameter high-pressure pipeline to provide gathering capacity for the Bearkat natural gas processing complex. The pipeline has an initial capacity of approximately 100 MMcf/d and provides gas takeaway solutions for constrained producer customers in Howard, Martin and Glasscock counties. The pipeline commenced operation in the fourth quarter of 2014.
Growing with Devon
West Texas Expansion. We are expanding our natural gas gathering and processing system in the Permian Basin by constructing a new natural gas processing plant and expanding our rich gas gathering system. The new 120 MMcf/d gas processing plant will be strategically located on the north end of our existing midstream assets and will offer additional gas processing capabilities to producer customers in the region, including Devon. Due to the impact from the current commodity environment and a shift in producers’ drilling expectations, we are delaying construction on the processing plant until late 2015. Upon completion, our total operated processing capacity in the region will be approximately 240 MMcf/d.
As a part of the expansion, we are a party to a long-term, fee-based agreement with Devon to provide gathering and processing services for over 18,000 acres under development in Martin County. We constructed multiple low pressure gathering pipelines and a new 23-mile, 12-inch high pressure gathering pipeline that will tie into the Bearkat natural gas gathering system. The new pipelines commenced operation in January 2015.
Drop Downs
Midstream Holdings Drop Down. On February 17, 2015, the Partnership acquired the February Transferred Interests from Acacia in the February EMH Drop Down. As consideration for the February Transferred Interests, the Partnership issued 31.6 million Class D Common Units in the Partnership to Acacia.
On May 27, 2015, the Partnership acquired the May Transferred Interests from Acacia in the May EMH Drop Down. As consideration for the May Transferred Interests, the Partnership issued 36.6 million Class E Common Units in the Partnership to Acacia. After giving effect to the EMH Drop-Downs, the Partnership owns 100% of Midstream Holdings.
VEX Pipeline. On April 1, 2015, the Partnership acquired the VEX Interests from Devon, which are located in the Eagle Ford shale in south Texas. The aggregate consideration paid by the Partnership consisted of $171.0 million in cash, 338,159 common units representing limited partner interests in the Partnership with an aggregate value of approximately $9.0 million and the Partnership’s assumption of up to $40.0 million in certain construction costs related to VEX. The VEX pipeline is a 56-mile multi-grade crude oil pipeline with a current capacity of approximately 50,000 Bbls/d and, following completion of currently-underway expansion projects, will have capacity of approximately 90,000 Bbls/d. Other VEX assets at the destination of the pipeline include an eight-bay truck unloading terminal, 200,000 barrels of above-ground storage, of which 50,000 barrels are under construction, and rights to barge loading docks.
E2 Drop Down. On October 22, 2014, the Partnership acquired from EMI, a wholly-owned subsidiary of ENLC, 100% of the Class A Units and 50% of the Class B Units (collectively, the “E2 Appalachian Units”) in E2 Appalachian Compression, LLC (“E2 Appalachian”), and 93.7% of the Class A Units (the “Energy Services Units” and, together with the E2 Appalachian Units, the “Purchased Units”) in E2 Energy Services, LLC (“Energy Services” and, together with E2 Appalachian, “E2”). The

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total consideration paid by the Partnership to EMI for the Purchased Units included (i) $13.0 million in cash for the Energy Services Units and (ii) $150.0 million in cash and 1,016,322 common units representing limited partner interests in the Partnership for the E2 Appalachian Units. The remaining 50% of the Class B Units in E2 Appalachian are owned by members of the E2 Appalachian management team and are designed to provide such management team members with equity incentives.
E2’s assets include five condensate stabilization and natural gas compression stations with combined capacities of 19,000 Bbls/d of condensate stabilization and 580 MMcf/d of natural gas compression located in the ORV. Currently, three of the five stations are in service and commercial start-up of the two remaining stations is expected in the first half of 2015. The assets are supported by a long-term, fee-based contract with Antero Resources.
Acquisitions
Coronado Midstream. On February 1, 2015, the Partnership entered into an agreement with Reliance Midstream, LLC, a Texas limited liability company (“Reliance”), Windsor Midstream LLC, a Delaware limited liability company (“Windsor”), Wallace Family Partnership, LP, a Texas limited partnership (“Wallace”), and Ted Collins, Jr., an individual residing in Midland, Texas (“Collins” and, collectively with Reliance, Windsor and Wallace, the “Sellers,” and each, a “Seller”), and Reliance, in its capacity as representative of the Sellers, to acquire all of the equity interests in Coronado Midstream Holdings LLC, the parent company of Coronado Midstream LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $600.0 million in cash and equity, subject to certain adjustments.  Coronado operates three cryogenic gas processing plants and a gas gathering system in the North Midland Basin including approximately 270 miles of gathering pipelines, 175 MMcf/d of processing capacity and 35,000 horsepower of compression. The Coronado system is underpinned by long-term contracts, which include the dedication of production from over 190,000 acres.
LPC Crude Oil Marketing. On January 31, 2015, the Partnership, through one of its wholly owned subsidiaries, acquired LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $100.0 million. LPC is an integrated crude oil logistics service provider with operations throughout the Permian Basin. LPC's integrated logistics services are supported by 41 tractor trailers, 13 pipeline injection stations and 67 miles of crude oil gathering pipeline.
Natural Gas Pipeline Assets. On November 1, 2014, we acquired from affiliates of Chevron Corporation certain Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana for $234.0 million, subject to certain adjustments. These natural gas pipeline assets include the following:
•
Bridgeline System: approximately 990 miles of natural gas pipelines in southern Louisiana with a total system capacity of approximately 900 MMcf/d;
•
Sabine Pipeline: approximately 130 miles of natural gas pipelines in Texas and southern Louisiana with a total capacity of approximately 300 MMcf/d;
•
Chandeleur System: approximately 215 miles of offshore Mississippi and Alabama pipelines with a total capacity of approximately 300 MMcf/d;
•
Storage Assets: three caverns located in southern Louisiana with a combined working capacity of approximately 11 Bcf of natural gas, including two near Sorrento, LA with a capacity of approximately 4.0 Bcf and one inactive cavern near Napoleonville, LA with a capacity of approximately 7.0 Bcf; and
•
Henry Hub: ownership and management of the title tracking services offered at the Henry Hub, the delivery location for the New York Mercantile Exchange (the “NYMEX”) natural gas futures contracts. Henry Hub is connected to 13 major interstate and intrastate natural gas pipeline and storage systems.

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Our Assets
Our assets consist of gathering systems, transmission pipelines, processing facilities, fractionation facilities, stabilization facilities, storage facilities and ancillary assets. Except as stated otherwise, the following tables provide information about our assets as of and for the year ended December 31, 2014:
 
 
 
 
 
 
 
Year Ended
December 31, 2014
 
Gathering and Transmission Pipelines
 
Approximate
Length
(Miles)
 
Compression (1)
(HP)
 
Estimated
Capacity
(MMcf/d)
 
Average
Throughput
(Thousands of MMBtu/d)
 
Texas Assets:
 
 
 
 
 
 
 
 
 
   Partnership Assets ^
 
895

 
131,834

 
1,715

 
958,300

 
   Midstream Holdings Assets*
 
3,267

 
262,000

 
2,330

 
1,999,600

 
Oklahoma Assets:
 
 
 
 
 
 
 
 
 
   Cana System*
 
340

 
87,499

 
530

 
414,000

 
   Northridge System*
 
140

 
17,895

 
75

 
57,000

 
Louisiana Assets:
 
 
 
 
 
 
 
 
 
   LIG System^ (2)
 
3,320

 
78,648

 
3,975

 
615,000

 
   South Louisiana Assets^
 
600

 
—

 
—

(3)
—

(4)
VEX Assets:
 
 
 
 
 
 
 
 
 
    VEX Assets
 
56

 
—

 
—

(5)
—

(6)
Total
 
8,618

 
577,876

 
8,625

 
4,043,900

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
^
Assets wholly-owned by the Partnership.
 
 
 
*
Assets owned by Midstream Holdings, in which the Partnership held a 50% interest as of December 31, 2014 and 100% interest as of May 27, 2015.
(1)
Includes power generation units.
 
 
 
(2)
Includes natural gas pipelines acquired from Chevron Corporation on November 1, 2014. Average throughput volumes reflect throughput for the period from November 1, 2014 through December 31, 2014.
(3)
Our South Louisiana assets also have estimated capacity for liquid pipeline transportation of approximately 130 MBbls/d.
(4)
Our South Louisiana Cajun-Sibon liquids pipeline, including the Cajun-Sibon II expansion which commenced operations in late September 2014, had an average throughput of 72,900 Bbls/d for the year ended December 31, 2014.
(5)
Our VEX assets have an estimated capacity for crude pipeline transportation of approximately 50 MBbls/d.
(6)
Our VEX crude pipeline, which commenced operations in July 2014, had an average throughput of 19,800 Bbls/d for the period from July 1, 2014 through December 31, 2014.

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Year Ended
December 31, 2014
 
Processing Facilities
 
Processing
Capacity
(MMcf/d)
 
Average
Throughput
(MMBtu/d)
 
Texas Assets
 
 
 
 
 
   Partnership Assets^
 
369

 
357,100

 
   Midstream Holdings Assets*
 
790

 
788,700

 
Oklahoma Assets
 
 
 
 
 
   Cana System*
 
350

 
368,400

 
   Northridge System*
 
200

 
73,400

 
Louisiana Assets
 
 
 
 
 
   LIG Assets^
 
335

 
193,400

 
   South Louisiana Assets^
 
1,375

 
354,000

 
Total
 
3,419

 
2,135,000

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
^
Assets wholly-owned by the Partnership.
 
*
Assets owned by Midstream Holdings, in which the Partnership held a 50% interest as of December 31, 2014 and an 100% interest as of May 27, 2015.

 

Fractionation Facilities
 
Estimated NGL
Fractionation Capacity
(MBbls/d)
 
Average Throughput
(MBbls/d)
 
Texas Assets
 
 
 
 
 
   Partnership Assets^
 
15

 
—

(2
)
   Midstream Holdings Assets*
 
15

 
—

(2
)
Louisiana Assets
 
 
 
 
 
   LIG Assets^
 
11

 
5

 
   South Louisiana Assets^
 
183

 
116

 
Gulf Coast Fractionators (1)
 
56

 
44

 
Total
 
280

 
165

 
 
 
 
 
 
 
 
 
 
^
Assets wholly-owned by the Partnership.
 
*
Assets owned by Midstream Holdings, in which the Partnership held a 50% interest as of December 31, 2014 and an 100% interest as of May 27, 2015.
(1)
Volumes are shown net of Midstream Holdings’ net contractual right to the burdens and benefits of a 38.75% economic interest in Gulf Coast Fractionators held by Devon.
(2)
We are in the process of connecting our Texas fractionation facility to our Deadwood processing plant in the Permian Basin and the Midstream Holdings fractionation facility is connected to our Bridgeport processing plant. These fractionation facilities will provide operational flexibility for the related processing plants, but are not the primary fractionation facilities for the NGLs produced by the processing plants. Under the Partnership’s current contracts, it does not earn fractionation fees for operating these fractionation facilities so throughput volumes through these facilities are not captured on a routine basis and are not significant to its operating margins.

Texas Assets. Our Texas assets consist of systems and other assets in which our interest is held through our wholly-owned subsidiaries as well as systems and other assets owned by Midstream Holdings, in which we own a 100% interest as of May 27, 2015, and include transmission pipelines with a capacity of approximately 1.3 Bcf/d, processing facilities with a total processing capacity of approximately 1.2 Bcf/d and gathering systems with total capacity of approximately 2.8 Bcf/d.

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•
Transmission Systems. Our transmission systems in Texas include approximately 260 miles of pipeline with an aggregate capacity of approximately 1.3 Bcf/d and consist of the following:

•
North Texas Pipeline. Our North Texas Pipeline (“NTPL”) is a 140-mile pipeline extending from an area near Fort Worth, Texas to a point near Paris, Texas and 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. The NTPL has approximately 375 MMcf/d of capacity and 18,960 horsepower of compression and, for the period March 7, 2014 through December 31, 2014, the average throughput on the NTPL was approximately 338,000 MMBtu/d.

•
Acacia transmission system. The Acacia transmission system, which is owned by Midstream Holdings, is a     120-mile pipeline that connects production from the Barnett Shale to markets in north Texas accessed by Atmos Energy, Brazos Electric, Enbridge Energy Partners, Energy Transfer Partners, Enterprise Product Partners and GDF Suez. The Acacia transmission system has approximately 920 MMcf/d of capacity and 17,000 horsepower of compression and, for the year ended December 31, 2014, average throughput was approximately 733,900 MMBtu/d. Devon is the Acacia transmission system’s only customer and has entered into a 10-year fixed-fee transportation agreement that covers transmission services on the Acacia transmission pipeline and includes annual rate escalators.

•
Processing and Fractionation Facilities. Our processing facilities in Texas include six gas processing plants with total processing throughput that averaged 1,145,749 MMBtu/d for the year ended December 31, 2014 and our 38.75% interest in GCF and consist of the following:

•
Bridgeport processing facility. Our Bridgeport natural gas processing facility, located in Wise County, Texas, approximately 40 miles northwest of Fort Worth, Texas, is owned by Midstream Holdings and is one of the largest processing plants in the U.S. with seven cryogenic turboexpander plants that have a total of 790 MMcf/d of processing capacity and 15 MBbls/d of NGL fractionation capacity, respectively. For the year ended December 31, 2014, throughput volumes at the Bridgeport processing facility averaged 788,700 MMBtu/d of natural gas. Devon is the Bridgeport facility’s largest customer with approximately 717,700 MMBtu/d of natural gas processed for the year ended December 31, 2014, which represented approximately 91% of the total volumes processed at the facility during such period. In March 2014, Devon and Midstream Holdings entered into a 10-year, fixed-fee processing agreement pursuant to which Midstream Holdings provides processing services for natural gas delivered by Devon to the Bridgeport processing facility. This contractual arrangement includes a five-year minimum volume commitment from Devon of 650 MMcf/d of natural gas delivered to the Bridgeport processing facility as well as annual rate escalators.

•
Silver Creek processing complex. The Partnership’s Silver Creek processing complex, located in Weatherford, Azle and Fort Worth, Texas, includes three processing plants. The Partnership’s Silver Creek plants have a total of 280 MMcf/d of processing capacity, with the Azle Plant, Silver Creek Plant and Goforth Plant accounting for 50 MMcf/d, 200 MMcf/d and 30 MMCf/d of processing capacity, respectively. For the period March 7, 2014 through December 31, 2014, throughput volumes at the Silver Creek processing facility averaged 283,600 MMBtu/d of natural gas.

•
Permian Basin assets. Our Permian Basin assets consist of our Deadwood natural gas processing plant, our Bearkat natural gas processing plant and gathering facilities, and our Mesquite Terminal fractionator. The Partnership has 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 71,000 MMBtu/d for the period March 7, 2014 through December 31, 2014. The Mesquite Terminal, which has 15,000 BBls/d of fractionation capacity, is located in Midland County and serves as a terminal for third-party raw-make NGLs. We are also transloading crude oil and condensate at this facility. The Bearkat facility came online in the third quarter of 2014 and consists of a natural gas processing plant with condensate stabilization. The Bearkat plant has a total capacity of 60MMcf/d, and is supplied from approximately 90 miles of high pressure gathering pipelines and 6 compressor stations. The high pressure gathering system has a capacity of approximately 240 MMcf/d. The Bearkat plant averaged 3,000 MMBtu/d for December 2014 which was the first full month of operations.


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•
Gulf Coast Fractionators. Midstream Holdings is entitled to receive the economic benefits and burdens of the 38.75% interest in Gulf Coast Fractionators held by Devon, with the remaining interests owned 22.50% by Phillips 66 and 38.75% by Targa Resources Partners. Gulf Coast Fractionators owns an NGL fractionator located on the Gulf Coast at Mont Belvieu, Texas. Phillips 66 is the operator of the fractionator. Gulf Coast Fractionators receives raw mix NGLs from customers, fractionates the raw mix and redelivers the finished products to the customers for a fee. The facility has a capacity of approximately 145 MBbls/d. The plant fractionated 44,000 Bbls/d of liquids during 2014.

•
Gathering Systems. Our gathering systems in Texas include approximately 3,902 miles of pipeline with total throughput of approximately 1,886,000 MMBtu/d for the year ended December 31, 2014 and consist of the following:

•
Bridgeport rich gathering system. This rich natural gas gathering system, which is owned by Midstream Holdings, consists of approximately 1,922 miles of pipeline segments with approximately 145,000 horsepower of compression. A substantial majority of the natural gas gathered on the system is delivered to the Bridgeport processing facility. For the year ended December 31, 2014, throughput volumes on the Bridgeport rich gathering system averaged 826,300 MMBtu/d of natural gas. Devon is the largest customer on the Bridgeport rich gathering system with approximately 751,900 MMBtu/d of natural gas gathered for the year ended December 31, 2014, which represented approximately 91% of the total throughput on the system during such period. As described above, Devon and Midstream Holdings have entered into a 10-year, fixed-fee gathering agreement pursuant to which Midstream Holdings provides gathering services on the Bridgeport system, which includes a five-year minimum volume commitment from Devon of a combined 850 MMcf/d of natural gas delivered for gathering into the Bridgeport rich and Bridgeport lean gathering systems.

•
Bridgeport lean gathering system. This lean natural gas gathering system, which is owned by Midstream Holdings, consists of approximately 935 miles of pipeline segments with approximately 59,000 horsepower of compression. Natural gas gathered on this system is delivered to the Acacia transmission system and intrastate pipelines without processing. For the year ended December 31, 2014, throughput volumes on the Bridgeport lean gathering system averaged 245,900 MMBtu/d of natural gas. Devon is the largest customer on the Bridgeport lean gathering system with approximately 228,700 MMBtu/d of natural gas gathered for the year ended December 31, 2014, which represented approximately 93% of the total throughput on the system during such period. As described above, Devon and Midstream Holdings have entered into a 10-year, fixed-fee gathering and processing agreement that covers gathering services on the Bridgeport system.

•
East Johnson County gathering system. This natural gas gathering system, which is owned by Midstream Holdings, consists of approximately 290 miles of pipeline segments. Natural gas gathered on this system is delivered to intrastate pipelines without processing. For the year ended December 31, 2014, throughput volumes on the East Johnson County gathering system averaged 193,500 MMBtu/d of natural gas. Devon is the largest customer on the East Johnson County gathering system with approximately 181,900 MMBtu/d of natural gas gathered for the year ended December 31, 2014, which represented approximately 94% of the total throughput on the system during such period. In March 2014, Devon and Midstream Holdings entered into a 10-year, fixed-fee gathering agreement pursuant to which Midstream Holdings provides gathering services on the East Johnson County gathering system, which includes a five-year minimum volume commitment from Devon of 125 MMcf/d of natural gas delivered for gathering into the East Johnson County gathering system as well as annual rate escalators.

•
Silver Creek gathering systems. Our Silver Creek gathering system includes two gathering systems. Our north Texas gathering system, which we refer to as NTG, consists of approximately 690 miles of gathering lines with approximately 112,900 horsepower of compression and had an average throughput of approximately 608,700 MMBtu/d for the period March 7, 2014 through December 31, 2014. The Denton system consists of approximately 35 miles of gathering lines and had an average throughput of approximately 11,600 MMBtu/d for the period March 7, 2014 through December 31, 2014.

•
Howard Energy Partners (“HEP”). HEP owns and operates over 500 miles of pipeline and a 200 MMcf/d processing plant, serving production from the Eagle Ford, Escondido, Olmos, Pearsall and other formations in south Texas and pursues a growth strategy focused on the needs of south Texas producers. HEP’s system has 145 MMcf/d of amine treating capacity and more than 9,000 horsepower of compression. In addition, HEP has a 10 MBbls/d stabilizer in Live Oak County and a 220 MBbls/d liquids storage terminal near Brownsville, Texas. As of December 31, 2014, we owned a 30.6% interest in HEP and accounted for this investment under the equity method of accounting. We include our equity investment in HEP in our corporate segment. Alinda Capital Partners owns a 59% capital interest in HEP.

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Oklahoma Assets. Our Oklahoma assets consist of processing facilities with a total processing capacity of approximately 550 MMcf/d, gathering systems with total capacity of approximately 605 MMcf/d and a crude oil and condensate stabilization facility. All of the systems and other assets comprising our Oklahoma assets are owned by Midstream Holdings, in which we own a 100% interest as of May 27, 2015.

•
Cana system. Our Cana gathering and processing system is located in the Cana-Woodford Shale in West Central Oklahoma and consists of the following:

•
Cana processing facilities. Our Cana processing facilities include a multi-train 350 MMcf/d cryogenic processing plant and a crude oil and condensate stabilization facility. For the year ended December 31, 2014, throughput volumes at the Cana processing facility averaged 368,400 MMBtu/d. The residue natural gas from the Cana processing facility is delivered to Enable Midstream Partners and ONEOK Partners. Devon is the primary customer of the Cana processing facilities and has entered into a 10-year, fixed-fee gathering and processing agreement with Midstream Holdings pursuant to which Midstream Holdings provides processing services for natural gas delivered by Devon to the Cana processing facility. This contractual arrangement includes a five-year minimum volume commitment from Devon of 330 MMcf/d of natural gas delivered to the processing facility as well as annual rate escalators.

•
Cana gathering system. Our Cana gathering system includes an approximately 340-mile gathering system with approximately 87,500 horsepower of compression. For the year ended December 31, 2014, the Cana system gathered approximately 413,900 MMBtu/d of gas. Devon is the primary customer of the Cana gathering system and, as described above, has entered into a 10-year, fixed-fee gathering agreement with Midstream Holdings pursuant to which Midstream Holdings provides gathering services on the Cana gathering system and that includes a five-year minimum volume commitment from Devon of 330 MMcf/d of natural gas delivered for gathering into the Cana gathering system.

•
Northridge system. Our Northridge gathering and processing system is located in the Arkoma-Woodford Shale in Southeastern Oklahoma and consists of the following:

•
Northridge processing plant. Our Northridge processing plant has 200 MMcf/d of processing capacity. For the year ended December 31, 2014, throughput volumes at the Northridge processing facility averaged 73,400 MMBtu/d. The residue natural gas from the Northridge processing facility is delivered to Centerpoint, Enable Midstream Partners and MarkWest. In August 2014, Linn Energy acquired certain of Devon's southeastern Oklahoma assets and became the largest customer of the Northridge processing facility. In connection with this acquisition Linn Energy assumed Devon's 10-year fixed-fee gathering and processing agreement with Midstream Holdings pursuant to which Midstream Holdings provides processing services for natural gas delivered to the Northridge processing facility. This contractual arrangement includes a five-year minimum volume commitment of 40 MMcf/d of natural gas delivered to the Northridge processing facility as well as annual rate escalators.

•
Northridge gathering system. Our Northridge gathering system includes an approximate 140-mile gathering system with approximately 17,900 horsepower of compression. For the year ended December 31, 2014, the Northridge system gathered 56,900 MMBtu/d of gas. Linn Energy is the only customer on the Northridge gathering system and, as described above, has entered into a 10-year fixed-fee gathering and processing agreement with Midstream Holdings pursuant to which Midstream Holdings provides gathering services on the Northridge gathering system. This contract includes a five-year minimum volume commitment from Linn Energy of 40 MMcf/d of natural gas delivered for gathering into the Northridge gathering system.

Louisiana Assets. Our Louisiana assets consist of transmission pipelines with a capacity of approximately 3.5 Bcf/d, processing facilities with a total processing capacity of approximately 1.7 Bcf/d and gathering systems with total capacity of approximately 510 MMcf/d.

•
LIG Assets. The LIG system includes gathering and transmission systems with total capacity of approximately 4.0 Bcf/d, processing facilities with a total processing capacity of approximately 335 MMcf/d and fractionation facilities with total capacity of 10,800 Bbls/d.

•
The LIG gathering and transmission pipeline system is comprised of the 3,320-mile southern system, which has a capacity in excess of 1.5 Bcf/d and approximately 31,318 horsepower of compression, and the 815-mile

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northern system, which has a capacity of 465 MMcf/d and approximately 47,330 horsepower of compression. 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. In the north, the LIG system serves the natural gas fields south of Shreveport, Louisiana and extends into the Haynesville Shale gas play in north Louisiana. The Partnership’s north Louisiana system is connected to its south Louisiana system and has the capacity to move approximately 145 MMcf/d of gas to our markets in the south. The Partnership’s LIG gathering system had an average throughput of approximately 449,700 MMbtu/d for the period March 7, 2014 through December 31, 2014.

•
The south system also includes two operating, on-system processing plants, the Partnership’s Gibson and Plaquemine plants, with 110 MMcf/d and 225 MMcf/d of processing capacity, respectively. For the period March 7, 2014 through December 31, 2014, throughput volumes on the LIG processing system averaged 193,400 MMBtu/d of natural gas.

•
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 4,500 Bbls/d for the period March 7, 2014 through December 31, 2014.

•
The Gulf Coast gathering and transmission system is comprised of 1,120 miles of onshore systems with a capacity of 1.2 Bcf/d, approximately 37,785 horsepower of compression, underground storage facilities with a storage capacity of 4.2 Bcf of active storage capacity, 7.0 Bcf of inactive storage capacity, and Henry Hub transfer services with a capacity of 2.1 Bcf/d. The onshore system has access to the Gulf Coast and the industrial rich Mississippi River corridor, which is seeing an abundance of new growth in chemical and fertilizer plants. The onshore system had an average throughput of 157,000 MMBtu/d from November 1, 2014 (the date of acquisition) through December 31, 2014. The offshore system is comprised of 215 miles of pipeline with a capacity of 0.3 Bcf/d. The average throughput for the period November 1, 2014 through December 31, 2014 was 8,500 MMBtu/d.

•
South Louisiana NGL and Processing Assets. Our south Louisiana NGL and natural gas processing assets include approximately 600 miles of liquids transport lines, processing and fractionation assets and underground storage.

•
Cajun-Sibon Pipeline System. The Cajun-Sibon pipeline system consists of approximately 600 miles of raw make NGL pipelines with a current system capacity of approximately 130,000 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 the Partnership’s Eunice and Pelican processing plants in south Louisiana to either the Riverside or Eunice fractionators or to third party fractionators when necessary.

•
Processing Facilities. Our processing facilities in south Louisiana include three gas processing plants, of which only one is currently operational, with total processing throughput that averaged 354,000 MMBtu/d for the period March 7, 2014 through December 31, 2014 and two fractionation facilities that averaged 115,500 Bbls/d for the period March 7, 2014 through December 31, 2014.

•
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 period March 7, 2014 through December 31, 2014, the plant processed approximately 336,000 MMBtu/d of natural gas. 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 allowing us to process natural gas from the LIG system at our Pelican plant when markets are favorable.

•
Blue Water Gas Processing Plant. We operate and own a 64.29% interest in the Blue Water gas processing 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 with respect 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.

•
Eunice Processing Plant. The Eunice processing plant is located in south central Louisiana and has a capacity of 475 MMcf/d of natural gas. In August 2013, we shut down the Eunice processing plant due to

14




adverse economics driven by low NGL prices and low processing volumes, which we do not see improving in the near future based on forecasted prices.

•
Plaquemine Fractionation Facility. The Plaquemine fractionator is located at our Plaquemine gas processing plant complex and is connected to our Cajun-Sibon pipeline. The Plaquemine fractionation facility has a capacity of approximately 100,000 Bbls/d, and produces purity ethane and propane for sale by pipeline to long-term markets with the butane and heavier products sent to our Riverside facility for further processing. The plant commenced operations during September and fractionated 49,700 Bbls/d during the fourth quarter of 2014.

•
Eunice Fractionation Facility. The Eunice fractionation facility is located in south central Louisiana. 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 48,600 Bbls/d of liquids for the period March 7, 2014 through December 31, 2014.

•
Riverside Fractionation Facility. 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 and Pelican processing plants or by third-party truck and rail assets. The Riverside fractionator was converted to a butane-and-heavier facility during 2014 in conjunction with the Cajun-Sibon II project. 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 17,200 Bbls/d for the year ended December 31, 2014. During the periods of full operation at Riverside for 2014 (excluding the 65 days of shut down related to the Cajun-Sibon II project completion), the average throughput was 22,000 Bbls/d.

•
Napoleonville Storage Facility. The Napoleonville NGL storage facility is connected to the Riverside facility and has a total capacity of 3.2 million barrels of underground storage comprised of two existing caverns. The caverns are currently operated in butane service, and space is leased to customers for a fee.

Ohio River Valley Assets. Our ORV operations are an integrated network of assets comprised of a 5,000-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 16,300 Bbls/d for the year ended December 31, 2014. We have eight existing brine disposal wells with an injection capacity of approximately 5,000 Bbls/d and an average disposal rate of 4,700 Bbls/d for the year ended December 31, 2014. Additionally, our ORV operations consist of five condensate stabilization and natural gas compression stations with combined capacities of 19,000 Bbls/d of condensate stabilization and 580 MMcf/d of natural gas compression. Currently, three of the five stations are in service and commercial start-up of the two remaining stations is expected in the first half of 2015. The assets are supported by a long-term, fee-based contract with Antero Resources.
VEX Interests. On April 1, 2015, we acquired the VEX Interests from Devon, which are located in the Eagle Ford shale in south Texas. The VEX pipeline is a 56-mile multi-grade crude oil pipeline with a current capacity of approximately 50,000 Bbls/d and, following completion of currently-underway expansion projects, will have capacity of approximately 90,000 Bbls/d. Other VEX assets at the destination of the pipeline include an eight-bay truck unloading terminal, 200,000 barrels of above-ground storage, of which 50,000 barrels are under construction, and rights to barge loading docks. Also included in the transaction are facilities near the origin of the pipeline that are currently under construction, including an eight-bay truck unloading terminal and 160,000 barrels of above-ground storage. The VEX Interests are included with the Partnership's ORV crude operations for segment reporting for the year ended December 31, 2014.

15




Industry Overview
The following diagram illustrates the gathering, processing, fractionation, stabilization and transmission process.
The midstream industry is the link between the exploration and production of natural gas and 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 and crude oil and condensate producing wells.
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. Also, a declining well can continue delivering natural gas if 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

16




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.
Condensate Stabilization. Condensate stabilization is the distillation of the condensate product to remove the lighter end components, which ultimately creates a higher quality condensate product that is then delivered via truck, rail or pipeline to local markets.
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 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 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 companies, natural gas producers, interstate and intrastate pipelines, other natural gas, NGLs and crude oil and condensate gatherers and natural gas processors. Competition for natural gas and crude oil and condensate 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. As a result of the relationship between Devon and Midstream Holdings, we will not compete for the portion of Devon’s existing operations subject to existing acreage dedication and for which Midstream Holdings will provide midstream services. For areas where acreage is not dedicated to Midstream Holdings, we will compete with similar enterprises in providing additional gathering and processing services in its respective areas of operation, which may offer more services or have strong 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, NGLs, crude oil and condensate, 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

17




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. Our competitors may have greater financial resources than we possess or may be 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 NGL supplies in excess of the volumes required for the operation of these systems. Our ORV pipeline, terminals, trucks and storage facilities are strategically located in crude 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, NGLs, 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 diligently attempt to ensure that we issue credit to only credit-worthy customers. However, our purchase and resale of crude oil, condensate, 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 sales price. Therefore, a credit loss can be very large relative to our overall profitability.
For the year ended December 31, 2014, Devon represented 30.6% of our consolidated revenues and Dow Hydrocarbons & Resources LLC represented 11.0% of our consolidated revenues. No other customer represented greater than 10.0% of our revenue. Midstream Holdings’ operations are dependent on the volume of natural gas that Devon provides to us under commercial agreements, which constitutes a substantial portion of their natural gas supply. For the foreseeable future, we expect our profitability to be substantially dependent on Devon. Further, the loss of Dow Hydrocarbons as a customer could have a material impact on our results of operations if we were not able to sell our products to another customer with similar margins because the gross operating margins received from transactions with this customer are material to our total gross operating margin.
Regulation
Interstate Natural Gas Pipelines Regulation. We own interstate natural gas pipelines that are subject to regulation by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act (“NGA”). Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. FERC regulation extends to such matters as the following:
•
rates, services, and terms and conditions of service;
•
the certification and construction of new facilities;
•
the extension or abandonment of services and facilities;
•
the maintenance of accounts and records;
•
the acquisition and disposition of facilities;
•
maximum rates payable for certain services;
•
the initiation and discontinuation of services;
•
internet posting requirements for available capacity, discounts and other matters;
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pipeline segmentation to allow multiple simultaneous shipments under the same contract;
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capacity release to create a secondary market for transportation services;
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relationships between affiliated companies involved in certain aspects of the natural gas business;
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market manipulation in connection with interstate sales, purchases or transportation of natural gas and NGLs; and
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participation by interstate pipelines in cash management arrangements.

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Natural gas companies are prohibited from charging rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
The rates and terms and conditions for our interstate pipeline services are set forth in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint or by action of FERC under Section 5 of the NGA, and proposed rate increases may be challenged by protest. The outcome of any successful complaint or protest against our rates could have an adverse impact on revenues associated with providing transportation service.
For example, one such matter relates to FERC’s policy regarding allowances for income taxes in determining a regulated entity’s cost of service. FERC allows regulated companies to recover an allowance for income taxes in rates only to the extent the company or its owners, such as our unitholders, are subject to U.S. income tax. This policy affects whom we allow to own our units, and if we are not successful in limiting ownership of our units to persons or entities subject to U.S. income tax, our FERC-regulated rates and revenues for our interstate natural gas pipelines could be adversely affected.
Interstate natural gas pipelines regulated by the FERC are required to comply with numerous regulations related to standards of conduct, market transparency, and market manipulation. The FERC’s standards of conduct regulate the manner in which interstate natural gas pipelines may interact with their marketing affiliates (unless the FERC has granted a waiver of such standards). The FERC’s market oversight and transparency regulations require annual reports of purchases or sales of natural gas meeting certain thresholds and criteria and certain public postings of information on scheduled volumes. FERC’s market manipulation regulations promulgated pursuant to the Energy Policy Act of 2005 (the “EPAct 2005”) make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any statement necessary to make the statements made not misleading; or (3) engage in any act or practice that operates as a fraud or deceit upon any person. The EPAct 2005 also amends the NGA and the Natural Gas Policy Act of 1978 (“NGPA”) to give FERC authority to impose civil penalties for violations of these statutes, up to $1.0 million per day per violation for violations occurring after August 8, 2005. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
We also transport gas in interstate commerce that is subject to FERC jurisdiction under Section 311 of the 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 five 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.
Interstate Liquids Pipelines Regulation. We own liquids transportation, storage and other assets in the ORV, including certain assets providing common carrier interstate service subject to regulation by FERC under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 and related rules and orders. Our Cajun-Sibon NGL pipeline is also subject to FERC regulation 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, condensate 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.

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As we acquire, construct and operate new liquids assets and expand our liquids transportation business, 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.
The FERC’s anti-manipulation rules apply to non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a “nexus” to jurisdictional transactions. As noted above, the FERC’s civil penalty authority under EPAct 2005 would apply to violations of these rules to the extent applicable to our intrastate natural gas services.
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 NGL and 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 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.
The FERC’s anti-manipulation rules apply to non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a “nexus” to jurisdictional transactions. As noted above, the FERC’s civil penalty authority under EPAct 2005 would apply to violations of these rules to the extent applicable to our natural gas gathering services.
Intrastate Natural Gas Storage Regulation. The storage field’s injection and withdrawal wells used in association with the Acacia system, along with water disposal wells located at the Bridgeport processing facility, are under the jurisdiction of the Texas Railroad Commission (“TRRC”). Regulatory requirements for these wells involve monthly and annual reporting of the natural gas and water disposal volumes associated with the operation of such wells, respectively. Results of periodic mechanical integrity tests run on these wells must also be reported to the TRRC.
Sales of Natural Gas and NGLs. The prices 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, crude oil and condensates) 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, natural gas and NGL storage caverns, 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

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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. As part of the regular evaluation of our operations, we routinely review and update governmental approvals as necessary.
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 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 Solid 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 (“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 a “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 an off-site location, such as a landfill. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek recovery of costs they incur from the potentially responsible classes of persons. 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 solid 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 substances 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 (“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, condensate and natural gas wastes. Moreover, it is possible that some wastes generated by us that are currently exempted from the definition of hazardous waste may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Additionally, the Toxic Substances Control Act (“TSCA”) and analogous state laws impose requirements on the use, storage and disposal of various chemicals and chemical substances. 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 oil 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

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environmental laws and regulations. Nevertheless, some hydrocarbons and other solid wastes may have been disposed of on or under various properties owned, leased or operated 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, TSCA 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.
In addition, the EPA included Wise County in its January 2012 revision to the Dallas-Ft. Worth ozone nonattainment area for the 2008 revised ozone national ambient air quality standard (“NAAQS”). As a result of this designation, new major sources, meaning sources that emit greater than 100 tons/year of nitrogen oxides (“NOx”) and volatile organic compounds (“VOCs”), as well as major modifications of existing facilities resulting in net emissions increases of greater than 40 tons/year of NOx or VOCs, are subject to more stringent new source review (“NSR”) pre-construction permitting requirements than they would be in an area that is in attainment with the 2008 ozone NAAQS. NSR pre-construction permits can take twelve to eighteen months to obtain and require the permit applicant to offset the proposed emission increases with reductions elsewhere at a 1.15 to 1 ratio. Devon, Texas industry trade groups and the State of Texas filed petitions for reconsideration with the EPA and a petition for review in the U.S. D.C. Circuit Court of Appeals challenging the nonattainment designation of Wise County under the 2008 ozone NAAQS. The appeal remains pending.
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 required a number of modifications to our assets and operations.
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. The EPA has since revised certain aspects of the rules 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. We cannot predict the costs of compliance with any modified or newly issued rules. Additionally, the EPA has signaled its intent to regulate emissions of methane and volatile organic compounds from the oil and gas sector as a measure to implement President Obama’s Climate Action Plan. While the EPA has not yet issued a proposed rulemaking, it has released a series of white papers addressing methane reductions from the oil and gas sector. 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 December 2009, the EPA determined that emissions of certain gases, commonly referred to as “greenhouse gases,” present an endangerment to public health and the environment because emissions of such gases are,

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according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted regulations under existing provisions of the federal Clean Air Act, that establish Prevention of Significant Deterioration (“PSD”) pre construction permits, and Title V operating permits for greenhouse gas emissions from certain large stationary sources. Under these regulations, facilities required to obtain PSD permits must meet “best available control technology” standards for their greenhouse gas emissions established by the states or, in some cases, by the EPA on a case by case basis. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities.
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 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. The EPA and the U.S. Army Corps of Engineers recently proposed a rule to clarify the meaning of the term “waters of the United States.” While the practical effects of the proposed rule are ambiguous, many interested parties, including the State of Texas, believe that the proposed rule will expand federal jurisdiction under the Clean Water Act if it is promulgated in its current form as a final rule. Regulations promulgated pursuant to these laws require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System (“NPDES”) permits 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. However, some state regulatory agencies have modified their regulations to account for induced seismicity. For example, TRRC rules allow the TRRC to modify,

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suspend, or terminate a permit based on a determination that the permitted activity is likely to be contributing to seismic activity. 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. The EPA has also issued an advance notice of proposed rulemaking under the Toxic Substances Control Act to gather information regarding the potential regulation of chemical substances and mixtures used in oil and gas exploration and production. 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.
Endangered Species and Migratory Birds. The Endangered Species Act (“ESA”), Migratory Bird Treaty Act (“MBTA”), and similar state and local laws restrict activities that may affect endangered or threatened species or their habitats or migratory birds. Some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, potentially exposing us to liability for impacts on an individual member of a species or to habitat. The Endangered Species Act can also make it more difficult to secure a federal permit for a new pipeline.
Employee Safety. We are subject to the requirements of the Occupational Safety and Health Act (“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 and condensate, 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 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

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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 pipelines. 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 this pipeline 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. As a result of the sinkhole, it was necessary to permanently remove from service a section of our 36-inch diameter natural gas pipeline. We worked with customers to secure alternative natural gas supplies to minimize disruptions while a replacement pipeline was constructed. The replacement pipeline was completed and services resumed in May 2014. We also implemented additional inspection and operational measures at our nearby underground facility. The damage to our business related to the sinkhole, including costs and loss of business, has been considerable.
We are seeking to recover our losses from responsible parties. We have sued Texas Brine Company, LLC (“Texas Brine”), the operator of a failed cavern in the area, and its insurers seeking recovery for this damage. We also filed a claim with our insurers, which our insurers denied. We disputed the denial and sued our insurers, but we have agreed to stay the matter pending resolution of our claims against Texas Brine and its insurers. In August 2014, we received a partial settlement with respect to the Texas Brine claims in the amount of $6.1 million, but additional claims remain outstanding. We cannot give assurance that we will be able to fully recover our losses through insurance recovery or claims against responsible parties. Please read “Item 3. Legal Proceedings.”
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. We also occupy approximately 12,500 square feet, 2,200 square feet and 4,700 square feet at Devon’s Bridgeport, Oklahoma City and Cresson office buildings, respectively, under leases with a wholly-owned subsidiary of Devon which are scheduled to expire in March 2016.
In November 2014, we entered into a new agreement to lease approximately 157,600 square feet of space for our offices in Dallas, Texas with a lease term commencing in June 2016.
Employees
As of December 31, 2014, we (through our subsidiaries) employed approximately 1,152 full-time employees. Approximately 256 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.


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