EnLink Midstream, LLC (ENLC) 2017年年度報告「NYSE」.pdf

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1、Table of ContentsUNITEDSTATESSECURITIESANDEXCHANGECOMMISSIONWashington,D.C.20549Form10-KANNUALREPORTPURSUANTTOSECTION13or15(d)OFTHESECURITIESEXCHANGEACTOF1934ForthefiscalyearendedDecember31,2017ORTRANSITIONREPORTPURSUANTTOSECTION13OR15(d)OFTHESECURITIESEXCHANGEACTOF1934ForthetransitionperiodfromtoCo

2、mmissionfilenumber:001-36336ENLINKMIDSTREAM,LLC(Exact name of registrant as specified in its charter)Delaware46-4108528(State of organization)(I.R.S.Employer Identification No.)1722RouthSt.,Suite1300 Dallas,Texas75201(Address of principal executive offices)(Zip Code)(214)953-9500(Registrantstelephon

3、enumber,includingareacode)SECURITIESREGISTEREDPURSUANTTOSECTION12(b)OFTHEACT:TitleofEachClass NameofExchangeonwhichRegisteredCommon Units Representing Limited The New York Stock ExchangeLiability Company Interests Securities registered pursuant to Section 12(g)of the Act:None.Indicate by check mark

4、if registrant is a well-known seasoned issuer,as defined in Rule 405 of the Securities Act.Yes xNo Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d)of the Act.Yes No xIndicate by check mark whether registrant(1)has filed all reports required

5、 to be filed by Section 13 or 15(d)of the Securities Exchange Act of 1934 during the preceding 12 months(or forsuch shorter period that the registrant was required to file such reports),and(2)has been subject to such filing requirements for the past 90 days.Yes xNo Indicate by check mark whether the

6、 registrant has submitted electronically and posted on its corporate website,if any,every Interactive Data File required to be submitted and postedpursuant to Rule 405 of Regulation S-T(232.405 of this chapter)during the preceding 12 months(or for such shorter period that the registrant was required

7、 to submit and post such files).Yes xNo Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K(229.405 of this chapter)is not contained herein,and will not be contained,to the best ofthe registrants knowledge,in definitive proxy or information statements inc

8、orporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.xIndicate by check mark whether the registrant is a large accelerated filer,an accelerated filer,a non-accelerated filer,a smaller reporting company,or an emerging growth company.See thedefinitions of“large accel

9、erated filer,”“accelerated filer,”“smaller reporting company,”and“emerging growth company”in Rule 12b-2 of the Securities Exchange Act.(Check one):Large accelerated filer x Accelerated filer Non-accelerated filer(Do not check if a smaller reporting company)Smaller reporting company Emerging growth c

10、ompany If an emerging growth company,indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accountingstandards provided pursuant to Section 13(a)of the Exchange Act.Indicate by check mark whether the registrant

11、is a shell company(as defined in Rule 12b-2 of the Act).Yes No xThe aggregate market value of the common units representing limited liability company interests held by non-affiliates of the registrant was approximately$1.1 billion on June 30,2017,based on$17.60 per unit,the closing price of the comm

12、on units as reported on the New York Stock Exchange on such date.At February 14,2018,there were 180,883,369 common units outstanding.DOCUMENTSINCORPORATEDBYREFERENCE:None.Table of ContentsTABLEOFCONTENTSItem Description Page PARTI 1.BUSINESS 41A.RISK FACTORS 291B.UNRESOLVED STAFF COMMENTS 552.PROPER

13、TIES 553.LEGAL PROCEEDINGS 564.MINE SAFETY DISCLOSURES 56 PARTII 5.MARKET FOR REGISTRANTS COMMON EQUITY,RELATED UNITHOLDER MATTERS AND ISSUERPURCHASES OF EQUITY SECURITIES 576.SELECTED FINANCIAL DATA 587.MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 617A.QUANTI

14、TATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 878.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 919.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIALDISCLOSURE 1449A.CONTROLS AND PROCEDURES 1449B.OTHER INFORMATION 144 PARTIII 10.DIRECTORS,EXECUTIVE OFFICERS AND CORPORATE

15、 GOVERNANCE 14511.EXECUTIVE COMPENSATION 14912.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATEDUNITHOLDER MATTERS 16913.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE 17214.PRINCIPAL ACCOUNTING FEES AND SERVICES 173 PARTIV 15.EXHIBITS AND FINANCIAL

16、 STATEMENT SCHEDULES 1752Table of ContentsDefinitionsThe following terms as defined generally are used in the energy industry and in this document:/d=per dayBbls=barrelsBcf=billion cubic feetCO 2=Carbon dioxideCPI=Consumer Price IndexHP=horsepowerMMBtu=million British thermal unitsMMcf=million cubic

17、 feetNGL=natural gas liquidCapacity volumes for our facilities are measured based on physical volume and stated in cubic feet(“Bcf”,“Mcf”or“MMcf”).Throughput volumes aremeasured based on energy content and stated in British thermal units(“Btu”or“MMBtu”).A volume of capacity of 100 MMcf correlates to

18、 an approximateenergy content of 100,000 MMBtu,although this correlation will vary depending on the composition of natural gas and is typically higher for unprocessed gas,which contains a higher concentration of NGLs.Fractionated volumes are measured based on physical volumes and stated in gallons.C

19、rude oil,condensate andbrine services volumes are measured based on physical volume and stated in barrels(“Bbls”).We define“gross operating margin,”a non-GAAP financial measure,as revenues less cost of sales.We disclose gross operating margin in addition to totalrevenue because it is the primary per

20、formance measure used by our management.We believe gross operating margin is an important measure because,in general,our business is to purchase and resell natural gas,NGLs,condensate and crude oil for a margin and to gather,process,store,transport or market natural gas,NGLs,condensate and crude oil

21、 for a fee.The GAAP measure most directly comparable to gross operating margin is operating income(loss).For more information ongross operating margin,including its limitations as a financial measure,see“Item 7.Managements Discussion and Analysis of Financial Condition and Results ofOperationsNon-GA

22、AP Financial Measures.”3Table of ContentsENLINKMIDSTREAM,LLCPARTIItem1.BusinessGeneralEnLink Midstream,LLC(“ENLC”)is a Delaware limited liability company formed in October 2013.Effective as of March 7,2014,EnLink Midstream,Inc.(“EMI”)merged with and into a subsidiary wholly owned by us,and Acacia Na

23、tural Gas Corp I,Inc.(“Acacia”),formerly a wholly-owned subsidiary of DevonEnergy Corporation(“Devon”),merged with and into another subsidiary wholly owned by us(collectively,the“Mergers”).Pursuant to the Mergers,each of EMIand Acacia became our wholly-owned subsidiaries and we became publicly held.

24、EMI owns common units representing an approximate 5.0%limited partnerinterest in EnLink Midstream Partners,LP(“ENLK”)as of December 31,2017 and also owns EnLink Midstream GP,LLC,the general partner of ENLK(the“General Partner”).At the conclusion of the Mergers in March 2014,Acacia directly owned a 5

25、0%limited partner interest in a limited partnership,formerlywholly owned by Devon,that was renamed EnLink Midstream Holdings,LP(“Midstream Holdings”).Concurrently with the consummation of the Mergers,awholly-owned subsidiary of ENLK acquired the remaining 50%of the outstanding limited partner intere

26、st in Midstream Holdings and all of the outstanding equityinterests in EnLink Midstream Holdings GP,LLC,the general partner of Midstream Holdings(together with the Mergers,the“Business Combination”).In 2015,Acacia contributed the remaining 50%interest in Midstream Holdings to ENLK in exchange for 68

27、.2 million ENLK common units in two separatedrop down transactions,with 25%contributed in February 2015 and 25%contributed in May 2015(the“EMH Drop Downs”).After giving effect to the EMHDrop Downs,ENLK owns 100%of Midstream Holdings.As a result of the EMH Drop Downs,Acacia owned approximately 16.7%o

28、f the limited partner interestsin ENLK as of December 31,2017,which brings ENLCs total ownership,through its wholly-owned subsidiaries,of limited partner interests in ENLK to 21.7%as of December 31,2017.On January 7,2016,EnLink Oklahoma Gas Processing,LP(“EnLink Oklahoma T.O.”)completed its acquisit

29、ion of 100%of the issued and outstandingmembership interests of TOMPC LLC and TOM-STACK,LLC.EnLink Oklahoma T.O.is sometimes used herein to refer to EnLink Oklahoma Gas Processing,LP itself or EnLink Oklahoma Gas Processing,LP,together with its consolidated subsidiaries.As a result of the acquisitio

30、n,ENLK indirectly owns an 83.9%limited partnership interest in EnLink Oklahoma T.O.,and ENLC owns a 16.1%limited partnership interest in EnLink Oklahoma T.O.In addition,EnLink EnergyGP,LLC,the general partner of EnLink Oklahoma T.O.and an indirect subsidiary of ENLK,owns the non-economic general par

31、tnership interest.EnLink Midstream,LLC common units are traded on the New York Stock Exchange(“NYSE”)under the symbol“ENLC.”Our executive offices are locatedat 1722 Routh Street,Suite 1300,Dallas,Texas 75201,and our telephone number is(214)953-9500.Our Internet address is .We post thefollowing filin

32、gs in the“Investors”section of our website as soon as reasonably practicable after they are electronically filed with or furnished to the Securities andExchange Commission(“SEC”):our Annual Reports on Form 10-K;our quarterly reports on Form 10-Q;our current reports on Form 8-K;and any amendments tot

33、hose 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 ourwebsite are available free of charge.In this report,the terms“Company”or“Registrant”as well as the terms“ENLC,”“our,”“we,”and“us,”or like terms,are

34、sometimes used as references toEnLink Midstream,LLC itself or EnLink Midstream,LLC and its consolidated subsidiaries,including ENLK.References in this report to“EnLink MidstreamPartners,LP,”the“Partnership,”“ENLK”or like terms refer to EnLink Midstream Partners,LP itself or EnLink Midstream Partners

35、,LP together with itsconsolidated subsidiaries,including EnLink Midstream Operating,LP.ENLINKMIDSTREAM,LLCOur assets consist of equity interests in ENLK and EnLink Oklahoma T.O.ENLK is a publicly traded limited partnership that primarily focuses on providingmidstream energy services,including:gather

36、ing,compressing,treating,processing,transporting,storing and selling natural gas;fractionating,transporting,storing,exporting and selling NGLs;and4Table of Contentsgathering,transporting,stabilizing,storing,trans-loading and selling crude oil and condensate.EnLink Oklahoma T.O.is a partnership held

37、by us and ENLK engaged in the gathering,transmission and processing of natural gas and NGLs.As ofDecember 31,2017,our interests in ENLK consist of the following:88,528,451 common units representing an aggregate 21.7%limited partner interest in ENLK;100.0%ownership interest in the General Partner,whi

38、ch owns a 0.4%general partner interest and all of the incentive distribution rights in ENLK;and16.1%limited partner interest in EnLink Oklahoma T.O.Each of ENLK and EnLink Oklahoma T.O is required by its partnership agreement to distribute all its cash on hand at the end of each quarter,less reserve

39、sestablished by its general partner in its sole discretion to provide for the proper conduct of ENLKs or EnLink Oklahoma T.O.s business,as applicable,or toprovide for future distributions.The incentive distribution rights in ENLK entitle us to receive an increasing percentage of cash distributed by

40、ENLK as certain target distribution levels arereached.Specifically,they entitle us to receive 13.0%of all cash distributed in a quarter after each unit has received$0.25 for that quarter,23.0%of all cashdistributed after each unit has received$0.3125 for that quarter and 48.0%of all cash distributed

41、 after each unit has received$0.375 for that quarter.We intend to pay distributions to our unitholders on a quarterly basis equal to the cash we receive,if any,from distributions from ENLK less reserves forexpenses,future distributions and other uses of cash,including:federal income taxes,which we a

42、re required to pay because we are taxed as a corporation;the expenses of being a public company;other general and administrative expenses;capital calls for our interest in EnLink Oklahoma T.O.to the extent not covered by our borrowings;capital contributions to ENLK upon the issuance by it of additio

43、nal partnership securities in order to maintain the General Partners then-current generalpartner interest,to the extent the board of directors of the General Partner(the“GP Board”)exercises its option to do so;andcash reserves the board of directors of EnLink Midstream Manager,LLC,our managing membe

44、r(the“Managing Member”),believes are prudent tomaintain.Our ability to pay distributions is limited by the Delaware Limited Liability Company Act,which provides that a limited liability company may not paydistributions if,after giving effect to the distribution,the companys liabilities would exceed

45、the fair value of its assets.While our ownership of equity interests inthe General Partner and ENLK are included in our calculation of net assets,the value of these assets may decline to a level where our liabilities would exceed thefair value of our assets if we were to pay distributions,thus prohi

46、biting us from paying distributions under Delaware law.ENLINKMIDSTREAMPARTNERS,LPEnLink Midstream Partners,LP is a publicly traded Delaware limited partnership formed in 2002.ENLKs common units are traded on the NYSE under thesymbol“ENLK.”ENLKs business activities are conducted through its subsidiar

47、y,EnLink Midstream Operating,LP,a Delaware limited partnership(the“Operating Partnership”),and the subsidiaries of the Operating Partnership.EnLink Midstream GP,LLC,a Delaware limited liability company and our wholly-owned subsidiary,is ENLKs general partner.The General Partnermanages ENLKs operatio

48、ns and activities.5Table of ContentsThe following diagram depicts our organization and ownership as of December 31,2017:_(1)The general partner(“GP”)ownership percentage for EnLink Midstream Partners,LP accounts for general partner units,while the limited partner(“LP”)ownershippercentages for EnLink

49、 Midstream Partners,LP account for ENLK common units and Series B Preferred Units(as defined below),which are convertible into ENLKcommon units on a one-for-one basis,subject to certain adjustments.(2)Series C Preferred Units(as defined below)are perpetual preferred units that are not convertible in

50、to ENLK common units,and therefore,are not factored into theEnLink Midstream Partners,LP ownership calculations for the limited partner and general partner ownership percentages presented.OurOperationsWe primarily focus on providing midstream energy services,including:gathering,compressing,treating,

51、processing,transporting,storing and selling natural gas;fractionating,transporting,storing,exporting and selling NGLs;andgathering,transporting,stabilizing,storing,trans-loading and selling crude oil and condensate.Our midstream energy asset network includes approximately 11,000 miles of pipelines,2

52、0 natural gas processing plants with approximately 4.8 Bcf/d ofprocessing capacity,7 fractionators with approximately 260,000 Bbls/d of fractionation capacity,barge and rail terminals,product storage facilities,purchasing andmarketing capabilities,brine disposal wells,a crude6Table of Contentsoil tr

53、ucking fleet,and equity investments in certain joint ventures.Our operations are based in the United States,and our sales are derived primarily from domesticcustomers.We connect the wells of producers in our market areas to our gathering systems,which consist of networks of pipelines that collect na

54、tural gas from pointsnear producing wells and transport it to our processing plants or to larger pipelines for further transmission.We operate processing plants that remove NGLs fromthe natural gas stream that is transported to the processing plants by our own gathering systems or by third-party pip

55、elines.In conjunction with our gathering andprocessing business,we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities,industrialconsumers,other markets and pipelines.Our transmission pipelines receive natural gas from our gatherin

56、g systems and from third-party gathering and transmissionsystems and deliver natural gas to industrial end-users,utilities and other pipelines.Our fractionators separate NGLs into separate purity products,including ethane,propane,iso-butane,normal butane and natural gasoline.Our fractionatorsreceive

57、 NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants,and our fractionatorsalso have the capability to receive NGLs by truck or rail terminals.We also have agreements pursuant to which third parties transport NGLs from our W

58、est Texasand Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators.In addition,we have NGL storage capacity toprovide storage for customers.Our crude oil and condensate business includes gathering and transmission via pipelines,barges,rail and tr

59、ucks,condensate stabilization and brine disposal.We may purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities thatprovide market access.Across our businesses,we primarily earn our fees through various fee-base

60、d contractual arrangements,which include stated fee-only contract arrangements orarrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as ourfee.We earn our net margin under our purchase and resell contr

61、act arrangements primarily as a result of stated service-related fees that are deducted from the priceof the commodities purchased.While our transactions vary in form,the essential element of each transaction is the use of our assets to transport a product orprovide a processed product to an end-use

62、r or other marketer or pipeline at the tailgate of the plant,barge terminal or pipeline.Our assets are included in five primary segments:Texas Segment.The Texas segment includes our natural gas gathering,processing and transmission operations in North Texas and the Midland andDelaware Basins(togethe

63、r,the“Permian Basin”)in West Texas;Oklahoma Segment.The Oklahoma segment includes our natural gas gathering,processing and transmission activities in Cana-Woodford,Arkoma-Woodford,Northern Oklahoma Woodford,Sooner Trend Anadarko Basin Canadian and Kingfisher Counties(“STACK”)and Central NorthernOkla

64、homa Woodford(“CNOW”)shale areas;Louisiana Segment.The Louisiana segment includes our natural gas pipelines,natural gas processing plants,gas and NGL storage facilities,fractionationfacilities and NGL pipelines located in Louisiana;Crude and Condensate Segment.The Crude and Condensate segment includ

65、es our crude oil operations in the Permian Basin and Central Oklahoma,ourOhio River Valley(“ORV”)crude oil,condensate stabilization,natural gas compression and brine disposal activities in the Utica and Marcellus Shalesand our crude oil activities associated with our Victoria Express Pipeline and re

66、lated truck terminal and storage assets(“VEX”)located in the Eagle FordShale;andCorporate Segment.The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove joint venture(“Cedar Cove JV”)inOklahoma,our contractual right to the economic benefits and burdens associated w

67、ith Devons 38.75%ownership interest in Gulf Coast Fractionators(“GCF”)and our general corporate property and expenses.For more information about our segment reporting,see“Item 8.Financial Statements and Supplementary Data Note 16.”7Table of ContentsAboutDevonDevon(NYSE:DVN)is a leading independent e

68、nergy company engaged primarily in the exploration,development and production of crude oil,natural gasand NGLs.Devons operations are concentrated in various onshore areas in the U.S.and Canada.Please see Devons Annual Report on Form 10-K for the yearended December 31,2017(the“Devon Annual Report”)fo

69、r additional information concerning Devons business.The information contained in the Devon AnnualReport is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report that we file with orfurnish to the SEC.OurBusinessStrategiesOur

70、primary business objective is to provide cash flow stability in our business while growing prudently and profitably.We intend to accomplish thisobjective by executing the following strategies:Execute in our core growth areas.We believe our assets are positioned in some of the most economically advan

71、tageous basins in the U.S.,as well as keydemand centers with growing end-use customers.We expect to grow certain of our systems organically over time by meeting our customers midstreamservice needs that result from their drilling activity in our areas of operation or growth in supply needs.We contin

72、ually evaluate economically attractiveorganic expansion opportunities in our areas of operation that allow us to leverage our existing infrastructure,operating expertise and customerrelationships by constructing and expanding systems to meet new or increased demand for our services.Maintain a strong

73、 financial position.We believe that maintaining a conservative and balanced capital structure,appropriate leverage and other keyfinancial metrics will afford us better access to the capital markets at a competitive cost of capital.We also believe a strong financial position provides usthe opportunit

74、y to grow our business in a prudent manner throughout the cycles in our industry.Maintain stable cash flows supported by long-term,fee-based contracts.We will seek to generate cash flows pursuant to long-term,firm contracts withcreditworthy customers.We will continue to pursue opportunities to incre

75、ase the fee-based components of our contract portfolio to minimize our directcommodity price exposure.OurCompetitiveStrengthsWe believe that we are well-positioned to execute our strategies and to achieve our primary business objective due to the following competitive strengths:Devons sponsorship.We

76、 expect our relationship with Devon will continue to provide us with significant business opportunities.Devon is one of thelargest independent oil and gas producers in North America.Devon has a significant interest in promoting the success of our business,due to its 64.0%direct ownership interest in

77、 ENLC and 23.1%direct ownership interest in ENLK as of December 31,2017.Approximately 46.8%of our gross operatingmargin for the year ended December 31,2017 was attributable to commercial contracts with Devon.Strategically-located assets.The majority of our assets are strategically located in economi

78、cally advantageous regions with the potential for increasingthroughput volume and cash flow generation.Our asset portfolio includes gathering,transmission,fractionation,and processing systems that are locatedin the areas in which producer activity is focused on crude oil,condensate and NGLs,as well

79、as natural gas.We have established platforms in Texas,Oklahoma and Louisiana,and we are focused on growing our operations in Central Oklahoma,the Permian Basin and southern Louisiana through organicdevelopment and acquisitions.S table cash flows.Approximately 94%of our gross operating margin for the

80、 year ended December 31,2017 was generated from fee-based contractarrangements with minimal direct commodity price exposure.In addition,our cash flows are generated across a variety of products,services andgeographic locations and through transactions with a strong portfolio of customers with invest

81、ment-grade credit ratings.We have approximately six yearsremaining on fixed-fee gathering and processing agreements with a subsidiary of Devon pursuant to which we provide gathering,treating,compression,dehydration,stabilization,processing and fractionation services,as applicable,for natural gas del

82、ivered by Devon to our gathering and processing systemsin the Barnett and Cana-Woodford Shales.These agreements provide us with dedication of all of the natural gas owned or controlled by Devon andproduced from or attributable to existing and future wells located on certain oil,natural gas and miner

83、al leases covering lands within the8Table of Contentsacreage dedications,excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon.Theseagreements also include minimum volume commitments(“MVCs”)that will remain in effect up to January 1,2019.Add

84、itionally,our EnLink OklahomaT.O.assets are supported by Devon with acreage dedications and MVCs for gathering and processing on Devons STACK acreage through 2021.Foradditional information,please read“Our Contractual Relationship with Devon.”We will continue to focus on contract structures that redu

85、ce volatility andsupport long-term stability of cash flows.Integrated midstream services.We span the energy value chain by providing natural gas,NGL,crude oil and condensate services across a diversecustomer base.These services include gathering,compressing,treating,processing,transporting,storing a

86、nd selling natural gas,fractionating,transporting,storing,exporting and selling NGLs,and gathering,transporting,stabilizing,storing and trans-loading crude oil and condensate.We believeour ability to provide all of these services gives us an advantage in competing for new opportunities because we ca

87、n provide substantially all services thatproducers,marketers and others require to move natural gas,NGLs,crude oil and condensate from the wellhead to the market on a cost-effective basis.Experienced management team.Our management team has deep experience in the energy industry and has a proven trac

88、k record of creating valuethrough the development,acquisition,optimization and integration of midstream assets.We believe this team provides us with a strong foundation forevaluating growth opportunities and operating our assets in a safe,reliable and efficient manner.We believe that we will leverag

89、e our competitive strengths to successfully implement our strategy;however,our business involves numerous risks anduncertainties that may prevent us from achieving our primary business objectives.For a more complete description of the risks associated with our business,pleasesee“Item 1A.Risk Factors

90、.”OurContractualRelationshipwithDevonThe following table includes our long-term,fixed-fee contracts with Devon:Contract RemainingContractTerm(Years)YearContractEnteredInto GatheringMVC(MMcf/d)ProcessingMVC(MMcf/d)RemainingMVCTerm(Years)AnnualRateEscalatorsBridgeport gathering and processing contract

91、 6 2014 850 650 1 CPIJohnson County gathering contract 6 2014 125 1 CPICana gathering and processing contract 6 2014 330 330 1 CPIEnLink Oklahoma T.O.gathering and processing contract(1)12 2016 Varies Varies 3 (1)The gathering MVCs and processing MVCs under this contract escalate on a quarterly basi

92、s over the life of the five-year commitment,beginning with an averagecommitment of 37 MMcf/d during 2016 and ending with an average commitment of 230 MMcf/d during 2020.In addition,we entered into to a five-year transportation MVC,which was executed in June 2014 and expires in July 2019,with Devon r

93、elated to VEX.TheMVC under the VEX contract averaged 25,000 Bbls/d during the first year and will average 30,000 Bbls/d for years two through five.RecentGrowthDevelopmentsOrganic GrowthCentral Oklahoma Plants.In 2017,we completed construction of two new cryogenic gas processing plants,which included

94、 the Chisholm II plant completedin April 2017 and the Chisholm III plant completed in December 2017.Each plant provides 200 MMcf/d of processing capacity and is connected to new andexisting gathering pipeline and compression assets in the STACK play in Oklahoma.The new capacity is supported by new a

95、nd existing long-term contracts.In addition,we are constructing an additional 200 MMcf/d gas processing plant,referred to as the“Thunderbird plant”to expand our Central Oklahomaprocessing capacity.We expect to begin operations on the Thunderbird plant during the first quarter of 2019.9Table of Conte

96、ntsIn June 2017,we entered into a long-term,fee-based arrangement with Oneok Partners(“Oneok”)under which Oneok transports NGLs from our Chisholmprocessing facility to the Gulf Coast and our Cajun-Sibon system.The agreement allows us to retain control of volumes and preferentially fill our Cajun-Sib

97、onsystem.Black Coyote Crude Oil Gathering System.In the fourth quarter of 2017,we began construction of a new crude oil gathering system that we refer to as“BlackCoyote,”which will expand our operations in the core of the STACK play in Central Oklahoma.Black Coyote is being built primarily on acreag

98、e dedicated fromDevon,which will be the main shipper on the system.The system is expected to be operational in the first quarter of 2018.Lobo Natural Gas Gathering and Processing Facilities.The Lobo facilities are part of our joint venture(the“Delaware Basin JV”)with an affiliate of NGPNatural Resou

99、rces XI,LP(“NGP”)and are supported by long-term contracts.In the first quarter of 2017,we completed the expansion of a 75-mile gatheringsystem for our Lobo II processing facility.In the second quarter of 2017,we completed the construction of an expansion of the Lobo II processing facility,whichprovi

100、ded an additional 60 MMcf/d of processing capacity to the existing 95 MMcf/d provided by the Lobo processing facilities.Furthermore,we are constructingan additional expansion of the Lobo II processing facility,which will increase capacity by 15 MMcf/d and is expected to be completed during the first

101、 half of 2018.In 2018,we will also expand our gas processing capacity at our Lobo facilities by 200 MMcf/d through the construction of the Lobo III cryogenic gas processingplant,which is expected to be operational around the second half of 2018.Greater Chickadee Crude Oil Gathering System.In March 2

102、017,we completed construction and began operations of a crude oil gathering system in Uptonand Midland counties,Texas in the Permian Basin,which we refer to as“Greater Chickadee.”Greater Chickadee includes over 185 miles of high-and low-pressure pipelines that transport crude oil volumes to several

103、major market outlets and other key hub centers in the Midland,Texas area and is supported by long-term contracts.Greater Chickadee also includes multiple central tank batteries,together with pump,truck injection and storage stations to maximize shipping anddelivery options for our producer customers

104、.Marathon Petroleum Joint Venture.In April 2017,we completed construction and began operating a new NGL pipeline,which is part of our 50/50 jointventure with a subsidiary of Marathon Petroleum Company(“Marathon Petroleum”).This joint venture,Ascension Pipeline Company,LLC(the“Ascension JV”),is a bol

105、t-on project to our Cajun-Sibon NGL system and is supported by long-term,fee-based contracts with Marathon Petroleum.Sale of Non-Core AssetsIn March 2017,we completed the sale of our ownership interest in HEP for net proceeds of$189.7 million.For the year ended December 31,2016,werecorded an impairm

106、ent loss of$20.1 million to reduce the carrying value of our investment to the expected sales price.Upon the sale of HEP in March 2017,werecorded an additional loss of$3.4 million for the year ended December 31,2017 based on the adjusted sales price at closing.Acquisitions,Organic Growth and Asset S

107、ales in 2015 and 2016In January 2015,we acquired 100%of the voting equity interests of LPC Crude Oil Marketing LLC(“LPC”),which has crude oil gathering,transportation and marketing operations in the Permian Basin,for approximately$108.1 million.In March 2015,we acquired 100%of the voting equity inte

108、rests in Coronado Midstream Holdings LLC(“Coronado”),which owns natural gas gatheringand processing facilities in the Permian Basin,for approximately$600.3 million.In April 2015,we acquired VEX,located in the Eagle Ford Shale in South Texas,together with 100%of the voting equity interests(the“VEX in

109、terests”)in certain entities,from Devon in a drop down transaction(the“VEX Drop Down”)for$166.7 million in cash and approximately$9.0 million in ENLKcommon units.Additionally,we assumed$40.0 million in construction costs related to VEX.In October 2015,we acquired 100%of the voting equity interests i

110、n a subsidiary of Matador Resources Company(“Matador”),which has gathering andprocessing operations in the Delaware Basin,for approximately$141.3 million.10Table of ContentsPrior to November 2015,we co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation(“Apache”).

111、In November2015,we acquired Apaches 50%ownership interest in the Deadwood natural gas processing facility for approximately$40.1 million.We now own100%of the Deadwood processing plant.In 2015,we completed the EMH Drop Downs.In January 2016,ENLK and ENLC acquired an 83.9%and 16.1%interest,respectivel

112、y,in EnLink Oklahoma T.O.for aggregate consideration ofapproximately$1.4 billion.The EnLink Oklahoma T.O.assets serve gathering and processing needs in the growing STACK and CNOW plays in CentralOklahoma and are supported by long-term,fixed-fee contracts with acreage dedications that,at the time of

113、acquisition,had a weighted-average term ofapproximately 15 years.In April 2016,we completed construction of the 100 MMcf/d Riptide processing plant in the Permian Basin.In August 2016,we formed the Delaware Basin JV with NGP to operate and expand our natural gas,natural gas liquids and crude oil mid

114、stream assets inthe Delaware Basin.The Delaware Basin JV is owned 50.1%by us and 49.9%by NGP.In October 2016,we completed construction of the initial phase of the 60 MMcf/d Lobo II processing facilities.In November 2016,we formed the Cedar Cove JV with Kinder Morgan,Inc.,which consists of gathering

115、and compression assets in Blaine County,Oklahoma,located in the heart of the STACK play.The gathering system has a capacity of 25 MMcf/d with over 50,000 gross acres of dedications andties into our existing Oklahoma assets.All gas gathered by the Cedar Cove JV is processed at our Central Oklahoma pr

116、ocessing system.We hold a 30%ownership interest of the Cedar Cove JV,and Kinder Morgan,Inc.holds the remaining 70%ownership interest.In December 2016,we sold the North Texas Pipeline(the“NTPL”),a 140-mile natural gas transportation pipeline,for$84.6 million.We maintaincapacity on the NTPL at competi

117、tive rates and at levels sufficient to support current and expected operations.As a result of the sale,we recorded a loss of$13.4 million for the year ended December 31,2016.11Table of ContentsOurAssetsOur assets consist of gathering systems,transmission pipelines,processing facilities,fractionation

118、 facilities,stabilization facilities,storage facilities andancillary assets.Except as stated otherwise,the following tables provide information about our assets as of and for the year ended December 31,2017:YearEnded December31,2017GatheringandTransmissionPipelines ApproximateLength(Miles)Compressio

119、n(HP)(1)EstimatedCapacity(2)AverageThroughput(3)Gas Pipelines Texas assets:Bridgeport rich and lean gathering systems 2,840 204,000 861 811,000Johnson County gathering system 290 44,000 589 134,300Silver Creek gathering system 720 77,000 522 390,600Acacia transmission system 130 16,600 920 565,700No

120、rth Texas assets 3,980 341,600 2,892 1,901,600MEGA System gathering facilities 700 105,300 393 262,500Lobo gathering system(4)125 15,200 82 98,800Permian Basin assets(4)825 120,500 475 361,300Texas assets 4,805 462,100 3,367 2,262,900 Oklahoma assets:Central Oklahoma gathering system 1,500 203,500 9

121、37 789,000Northridge gathering system 140 14,000 65 40,300Oklahoma assets 1,640 217,500 1,002 829,300 Louisiana assets:Louisiana gas gathering and transmission system 3,215 97,400 3,975 1,995,800Total Gas Pipelines 9,660 777,000 8,344 5,088,000 NGL,Crude Oil and Condensate Pipelines Louisiana assets

122、:Cajun-Sibon pipeline system 770 130,000 119,200Ascension pipeline(5)20 50,000 13,500Louisiana assets 790 180,000 132,700 Crude and condensate assets:Ohio River Valley(6)210 25,650 20,600Victoria Express Pipeline 60 90,000 15,100Permian gathering(7)360 118,500 76,700Total NGL,Crude Oil and Condensat

123、e Pipelines 1,420 414,150 245,100(1)Includes power generation units.(2)Estimated capacity for gas pipelines is MMcf/d.A volume capacity of 100 MMcf/d correlates to an approximate energy content of 100,000 MMBtu/d.Estimated capacityfor liquids and crude and condensate pipelines is Bbls/d.(3)Average t

124、hroughput for gas pipelines is MMBtu/d.Average throughput for NGL,crude and condensate pipelines is Bbls/d.(4)Includes gross mileage,compression,capacity and throughput for the Delaware Basin JV,which is owned 50.1%by us.Estimated capacity on our Lobo gathering systemincludes only the Delaware Basin

125、 JVs compression capacity and does not include gas compressed by third parties on our system.(5)Includes gross mileage,capacity and throughput for the Ascension JV,which is owned 50%by us.(6)Estimated capacity is comprised of trucking capacity only.(7)Estimated capacity is comprised of 68,500 Bbls/d

126、 of pipeline capacity and 50,000 Bbls/d of trucking capacity.12Table of Contents YearEnded December31,2017ProcessingFacilities ProcessingCapacity(MMcf/d)AverageThroughput(MMBtu/d)Texas assets:Bridgeport processing facility 800 605,500Silver Creek processing system 280 193,600North Texas assets 1,080

127、 799,100MEGA system processing facilities 408 291,100Lobo processing facilities 155 94,200Permian Basin assets 563 385,300Texas assets 1,643 1,184,400 Oklahoma Assets:Central Oklahoma processing facilities 1,005 759,500Northridge processing facility 200 50,800Oklahoma assets 1,205 810,300 Louisiana

128、assets:Louisiana gas processing facilities 1,903 453,300Total Processing Facilities 4,751 2,448,000 YearEnded December31,2017FractionationFacilities EstimatedNGLFractionationCapacity(MBbls/d)AverageThroughput(Bbls/d)Louisiana assets:Plaquemine fractionation facility(1)110 59.9Plaquemine processing p

129、lant 11 4.0Eunice fractionation facility 55 43.1Riverside fractionation facility(1)30.4Louisiana assets 176 137.4 Texas assets:Bridgeport processing facility(2)15 Mesquite terminal(2)15 Texas assets 30 Gulf Coast Fractionators(3)56 38.9Total Fractionation Facilities 262 176.3(1)The Plaquemine fracti

130、onation facility produces purity ethane and propane for sale to markets via pipeline,while butane and heavier products are sent to the Riversidefractionation facility for further processing.The Plaquemine fractionation facility and the Riverside fractionation facility have an aggregate fractionation

131、 capacity of 110MBbls/d.(2)We have two fractionation facilities with capacity of 15 MBbls/d each.Our Mesquite terminal in the Permian Basin and our Bridgeport processing plant in North Texasprovide operational flexibility for the related processing plants but are not the primary fractionation facili

132、ties for the NGLs produced by the processing plants.Under ourcurrent contracts,we do not earn fractionation fees for operating these facilities,so throughput volumes through these facilities are not captured on a routine basis and arenot significant to our gross operating margins.(3)Volumes shown re

133、flect only our contractual right to the benefits and burdens of a 38.75%economic interest in Gulf Coast Fractionators held by Devon.13Table of ContentsStorageAssets EstimatedStorageCapacity(1)Gas storage:Belle Rose gas storage facility 11.9Sorrento gas storage facility 7.3Total gas storage 19.2 NGL

134、storage:Napoleonville NGL storage facility 4.7 Crude oil storage:ORV storage 0.5VEX storage 0.2Total crude oil storage 0.7(1)Estimated capacity for gas storage is Bcf,and includes linefill capacity necessary to operate storage facilities.Estimated capacity for NGL and crude oil storage is MMBbls.Tex

135、as Assets.Our Texas assets include transmission pipelines,processing facilities and gathering systems in the Barnett Shale in North Texas and the PermianBasin in West Texas.Acacia Transmission System.The Acacia transmission system is a pipeline that connects production from the Barnett Shale to mark

136、ets in North Texasaccessed by Atmos Energy,Brazos Electric,Enbridge Energy Partners,Energy Transfer Partners,Enterprise Product Partners and GDF Suez.Devon isthe Acacia transmission systems only customer with approximately six years remaining on a fixed-fee transportation agreement that covers trans

137、missionservices and includes annual rate escalators.Processing and Fractionation Facilities.Our processing facilities in Texas include 10 gas processing plants and consist of the following:North Texas Assets.Our North Texas processing systems include the following:Bridgeport processing facility.Our

138、Bridgeport natural gas processing facility,located in Wise County,Texas,approximately 40 milesnorthwest of Fort Worth,Texas,is one of the largest processing plants in the U.S.with seven cryogenic turboexpander plants.Devon isthe Bridgeport facilitys largest customer,providing substantially all of th

139、e natural gas processed for the year ended December 31,2017.We currently have approximately six years remaining on a fixed-fee processing agreement with Devon pursuant to which weprovide processing services for natural gas delivered by Devon to the Bridgeport processing facility.This contractual arr

140、angementincludes an MVC from Devon of 650 MMcf/d of natural gas delivered to the Bridgeport processing facility that will remain in effect upto January 1,2019.Silver Creek processing system.Our Silver Creek processing system,located in Weatherford,Azle and Fort Worth,Texas,includesthree processing p

141、lants:the Azle plant,the Silver Creek plant and the Goforth plant,which account for 50 MMcf/d,200 MMcf/d and 30MMcf/d of processing capacity,respectively.Permian Basin Assets.Our Permian Basin processing facilities consist of the following:MEGA system processing facilities.Our Permian Basin processi

142、ng plants are located in Midland,Martin,and Glasscock counties,Texas and operate as a connected system.These assets consist of the Bearkat processing facility with a capacity of 75 MMcf/d,theDeadwood processing facility with a capacity of 58 MMcf/d,the Midmar processing facilities with a capacity of

143、 175 MMcf/d and theRiptide processing facility with a capacity of 100 MMcf/d(collectively,the“Midland Energy Gathering Area”or“MEGA system”).14Table of ContentsLobo processing facilities.Our Lobo natural gas processing facilities are located in Loving County,Texas and include two processingplants,th

144、e Lobo I plant and the Lobo II plant,which account for 35 MMcf/d and 120 MMcf/d of processing capacity,respectively.TheLobo processing facilities and the connected gathering system are owned by the Delaware Basin JV.Gathering Systems.Our gathering systems in Texas are connected to our North Texas or

145、 Permian Basin processing assets.North Texas Assets.Our North Texas gathering systems include the following:Bridgeport rich gathering system.A substantial majority of the natural gas gathered on the Bridgeport rich gas gathering system isdelivered to the Bridgeport processing facility.Devon is the l

146、argest customer on the Bridgeport rich gathering system contributingsubstantially all of the natural gas gathered for the year ended December 31,2017.As described above,we currently haveapproximately six years remaining on a fixed-fee gathering agreement with Devon pursuant to which we provide gathe

147、ring services onthe Bridgeport system.The agreement includes an MVC from Devon that will remain in effect up to January 1,2019,with a combined850 MMcf/d of natural gas to be delivered for gathering into the Bridgeport rich and Bridgeport lean gathering systems.Bridgeport lean gathering system.Natura

148、l gas gathered on the Bridgeport lean gathering system is all attributable to Devon and isdelivered to the Acacia transmission system and to intrastate pipelines without processing.As described above,we are party to a fixed-fee gathering and processing agreement with Devon that covers gathering serv

149、ices on the Bridgeport system.Johnson County gathering system.Natural gas gathered on this system is primarily attributable to Devon and is delivered to intrastatepipelines without processing.We currently have approximately six years remaining on a fixed-fee gathering agreement pursuant towhich we p

150、rovide gathering services on the Johnson County gathering system.This contractual arrangement includes an MVC fromDevon that will remain in effect up to January 1,2019,with 125 MMcf/d of natural gas to be delivered for gathering into the JohnsonCounty gathering system.Silver Creek gathering system.O

151、ur Silver Creek gathering system is located primarily in Hood,Parker and Johnson counties,Texas,and connects to the Silver Creek processing system.Permian Basin assets.Our Permian Basin gathering systems include the following:MEGA system gathering facilities.This gathering system in the Permian Basi

152、n serves as an interconnected system of pipelines andcompressors to deliver gas from wellheads in the Permian Basin to the MEGA system processing facilities.Lobo gathering system.The rich natural gas gathering system consists of gathering pipeline and compression assets in the DelawareBasin primaril

153、y in Texas,with a minor portion in New Mexico.The Lobo gathering system is owned by the Delaware Basin JV.Oklahoma Assets.Our Oklahoma assets consist of processing facilities and gathering systems in southern and Central Oklahoma.Oklahoma processing system.Our processing facilities include the follo

154、wing:Central Oklahoma processing facilities.The Central Oklahoma plants include the Chisholm plants,the Battle Ridge plant and the Canaprocessing facilities(collectively,the“Central Oklahoma processing system”),which account for 520 MMcf/d,85 MMcf/d and 400 MMcf/d ofprocessing capacity,respectively.

155、The residue natural gas from the Cana processing facility is delivered to Enable Midstream Partners andONEOK.The unprocessed NGLs from the Chisholm facilities are transported by ONEOK to NGL transmission lines,which then transport theNGLs to our fractionators in Louisiana.Devon is the primary custom

156、er of the Cana processing facilities and has approximately six yearsremaining on a fixed-fee gathering and processing agreement with us pursuant to which we provide processing services for natural gas deliveredby Devon to15Table of Contentsthe Cana processing facility.In addition,contractual arrange

157、ments related to the Central Oklahoma processing system that contain an MVCinclude the following:Our contractual arrangement with Devon includes an MVC that will remain in effect until October 2020.For 2018,the MVC dictatesthat approximately 145 MMcf/d of natural gas will be delivered to the Chishol

158、m plant processing facility.The MVC escalatesquarterly,resulting in approximately 230 MMcf/d to be delivered in 2020.We have another contractual arrangement with Devon that includes an MVC that will remain in effect up to January 1,2019 with 330MMcf/d of natural gas to be delivered to the Cana proce

159、ssing facility.Northridge processing facility.Our Northridge processing plant is located in Hughes County in the Arkoma-Woodford Shale in southeasternOklahoma.The residue natural gas from the Northridge processing facility is delivered to Centerpoint,Enable Midstream Partners and MPLX.Oklahoma gathe

160、ring system.Our Oklahoma gathering systems include the following:Central Oklahoma gathering system.The Central Oklahoma gathering system serves the STACK and CNOW plays.Contractual arrangementsrelated to the Central Oklahoma gathering system that contain an MVC include the following:Our contractual

161、arrangement with Devon includes an MVC that will remain in effect until October 2020.For 2018,the MVC dictatesthat approximately 153 MMcf/d of natural gas will be handled through the Chisholm gathering system.The MVC escalates quarterly,resulting in approximately 230 MMcf/d to be delivered in 2020.W

162、e have another contractual arrangement with Devon that includes an MVC that will remain in effect up to January 1,2019,with 330MMcf/d of natural gas to be handled through the Cana gathering system.Northridge gathering system.Our Northridge gathering system is located in the Arkoma-Woodford Shale in

163、Southeastern Oklahoma.Louisiana Assets.Our Louisiana assets consist of gas and NGL transmission pipelines,processing facilities,gathering systems and gas and NGL storage.Louisiana Gas Pipeline and Processing Systems.The Louisiana gas pipeline system includes gathering and transmission systems,proces

164、sing facilities andunderground gas storage.Gas Transmission and Gathering Systems.Our transmission system consists of a portfolio of large capacity interconnections with the GulfCoast pipeline grid that provides customers with supply access to multiple domestic production basins for redelivery to ma

165、jor industrial marketconsumption located primarily in the Mississippi River Corridor between Baton Rouge and New Orleans.Our natural gas transmission servicesare supplemented by fully integrated,high deliverability salt dome storage capacity strategically located in the natural gas consumption corri

166、dor.In combination with our transmission system,our gathering systems provide a fully integrated wellhead to burner tip value chain that includeslocal gathering,processing and treating services to Louisiana producers.Gas Processing and Storage Facilities.Our processing facilities in Louisiana includ

167、e five gas processing plants,of which three are currentlyoperational.Plaquemine Processing Plant.The Plaquemine processing plant has 225 MMcf/d of processing capacity and is connected to thePlaquemine fractionation facility.Gibson Processing Plant.The Gibson processing plant has 110 MMcf/d of proces

168、sing capacity and is located in Gibson,Louisiana.Theprocessing plant is connected to our Louisiana gathering system.16Table of ContentsPelican Processing Plant.The Pelican processing plant complex is located in Patterson,Louisiana and has a designed capacity of 600MMcf/d of natural gas.The Pelican p

169、rocessing plant is connected with continental shelf and deepwater production and has downstreamconnections to the ANR Pipeline.This plant has an interconnection with the Louisiana gas pipeline system allowing us to processnatural gas from this system at our Pelican processing plant when markets are

170、favorable.Blue Water Gas Processing Plant.We operate and own a 64.29%interest in the Blue Water gas processing plant.The Blue Water gasprocessing plant is located in Crowley,Louisiana and is connected to the Blue Water pipeline system.Our share of the plants capacityis approximately 193 MMcf/d.The p

171、lant is not expected to operate in the future unless fractionation spreads are favorable and volumesare 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 ofnatural gas.In August 2013,we shut down the

172、 Eunice processing plant due to adverse economics driven by low NGL prices and lowprocessing volumes,which we do not see improving in the near term based on forecasted prices.Sabine Pass Processing Plant.The Sabine Pass processing plant is located east of the Sabine River at Johnsons Bayou,Louisiana

173、 andhas a processing capacity of 300 MMcf/d of natural gas.In 2013,we shut down the Sabine Pass processing plant and do not anticipatereopening the plant based on current market conditions.Belle Rose Gas Storage Facility.The Belle Rose storage facility is located in Assumption Parish,Louisiana.This

174、facility was placed in servicein May 2016 and is designed for injecting pipeline quality gas into storage or withdrawing stored gas for delivery by pipeline.Sorrento Gas Storage Facility.The storage facility is located in Assumption Parish,Louisiana.This facility is designed for injecting pipelinequ

175、ality gas into storage or withdrawing stored gas for delivery by pipeline.Louisiana Liquids Pipeline System.Our Louisiana liquids pipeline system includes NGL transport lines,fractionation assets and underground NGLstorage.Cajun-Sibon Pipeline System.The Cajun-Sibon pipeline system transports unfrac

176、tionated NGLs from areas such as the Liberty,Texasinterconnects near Mont Belvieu and from our Gibson and Pelican processing plants in South Louisiana to either the Riverside or Eunicefractionators or to third-party fractionators when necessary.Ascension Pipeline.The Ascension JV is an NGL pipeline

177、that connects our Riverside fractionator to Marathon Petroleums Garyville refineryand is owned 50%by Marathon Petroleum.Fractionation Facilities.There are four fractionation facilities located in Louisiana that are connected to our processing facilities,and to MontBelvieu and other hubs through our

178、Cajun-Sibon pipeline system.Plaquemine Fractionation Facility.The Plaquemine fractionator is located at our Plaquemine gas processing plant complex and isconnected to our Cajun-Sibon pipeline.The Plaquemine fractionation facility produces purity ethane and propane for sale to marketsvia pipeline,whi

179、le butane and heavier products are sent to our Riverside facility for further processing.The Plaquemine fractionator,collectively with the Riverside Fractionation Facility,has an approximate capacity of 110,000 Bbls/d of raw-make NGL products.Plaquemine Gas Processing Plant.In addition to the Plaque

180、mine fractionation facility,the adjacent Plaquemine Gas Processing Plantalso has an on-site fractionator.Eunice Fractionation Facility.The Eunice fractionation facility is located in south central Louisiana.Liquids are delivered to theEunice fractionation facility by the Cajun-Sibon pipeline.The Eun

181、ice fractionation facility is directly connected to the southeastpropane market and to a third-party storage facility.17Table of ContentsRiverside Fractionation Facility.The Riverside fractionator and loading facility is located on the Mississippi River upriver fromGeismar,Louisiana.Liquids are deli

182、vered to the Riverside fractionator by the Cajun-Sibon pipeline system from the Eunice and Pelicanprocessing plants or by third-party truck and rail assets.The loading/unloading facility has the capacity to transload 15,000 Bbls/d ofcrude oil and condensate from rail cars to barges.Napoleonville Sto

183、rage Facility.The Napoleonville NGL storage facility is connected to the Riverside facility and is comprised of two existingcaverns.The caverns are currently operated in butane service,and space is leased to customers for a fee.Crude and Condensate.Our Crude and Condensate assets consist of crude oi

184、l and condensate pipelines,above ground storage and a trucking fleet.Ohio River Valley.Our ORV operations are an integrated network of assets comprised of a 5,000-barrel-per-hour crude oil and condensate bargeloading terminal on the Ohio River,a 20-spot crude oil and condensate rail loading terminal

185、 on the Ohio Central Railroad network,crude oil andcondensate pipelines in Ohio and West Virginia,above ground crude oil storage,a trucking fleet comprised of both semi and straight trucks,trailersfor hauling NGL volumes and seven existing brine disposal wells.Additionally,our ORV operations include

186、 eight condensate stabilization andnatural gas compression stations that are supported by long-term,fee-based contracts with multiple producers.Permian Crude and Condensate.Our Permian Crude and Condensate assets have crude oil gathering,transportation and marketing operations in thePermian Basin.Th

187、ese assets include trucking and crude gathering pipelines acquired in the LPC acquisition and the Greater Chickadee gatheringsystem,which was placed into service in March 2017 and delivers crude oil for customers to Enterprise Product Partners L.P.s crude oil terminal inWest Texas.Greater Chickadee

188、also includes multiple central tank batteries,with pump,truck injection and storage stations to maximize shippingand delivery options for producers.Black Coyote Crude Oil Gathering System.We are expanding our operations in the core of the STACK play in Central Oklahoma with theconstruction of the Bl

189、ack Coyote crude oil gathering system.Black Coyote is primarily being built on dedicated acreage from Devon,which will bethe main shipper on the system.The system is expected to be operational in the first quarter of 2018.Victoria Express Pipeline.VEX includes a multi-grade crude oil pipeline with t

190、erminals in Cuero and the Port of Victoria Terminal and bargedocks.The Cuero truck unloading terminal at the origin of the VEX system contains eight unloading bays and above-ground storage capacity forreceipt from and delivery to the VEX pipeline.The VEX pipeline terminates at the Port of Victoria T

191、erminal,which has an eight-bay truck unloadingdock and above-ground storage capacity.The Port of Victoria Terminal delivers to two barge loading docks at the Port of Victoria.We have anagreement with Devon,which includes an MVC of 30,000 Bbls/d,that will remain in effect until July 2019.Corporate.Ou

192、r Corporate assets primarily consist of a contractual right to the benefits and burdens associated with Devons 38.75%ownership interest inGCF and a 30%ownership interest in the Cedar Cove JV.Gulf Coast Fractionators.We are entitled to receive the economic benefits and burdens of the 38.75%interest i

193、n GCF held by Devon,with theremaining interests owned 22.5%by Phillips 66 and 38.75%by Targa Resources Partners.GCF owns an NGL fractionator located on the Gulf Coastat Mont Belvieu,Texas.Phillips 66 is the operator of the fractionator.GCF receives raw mix NGLs from customers,fractionates the raw mi

194、x andredelivers the finished products to the customers for a fee.Cedar Cove JV.On November 9,2016,we formed a joint venture with Kinder Morgan,Inc.consisting of gathering and compression assets in BlaineCounty,Oklahoma,which tie into our existing Oklahoma assets.All gas gathered by the Cedar Cove JV

195、 is processed by our Central Oklahomaprocessing facilities.We own 30%of the Cedar Cove JV.18Table of ContentsIndustryOverviewThe following diagram illustrates the gathering,processing,fractionation,stabilization and transmission process.The midstream industry is the link between the exploration and

196、production of natural gas and crude oil and condensate and the delivery of its components toend-user markets.The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants tonatural gas and crude oil and condensate producin

197、g 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 isconnected to a gathering system.Gathering systems typically consist of a network of small diameter pipelines and,if necessary,compressio

198、n and treating systemsthat 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 producegas

199、at progressively lower field pressures as they age,it becomes increasingly difficult to deliver the remaining production in the ground against the higherpressure that exists in the connected gathering system.Natural gas compression is a mechanical process in which a volume of gas at an existing pres

200、sure iscompressed to a desired higher pressure,allowing gas that no longer naturally flows into a higher-pressure downstream pipeline to be brought to market.Fieldcompression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deli

201、ver 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 toovercome the higher gathering system pressure.A declining well can continue delivering natural gas if field compressi

202、on 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 NGLsand contaminants,such as water and CO 2,sulfur compounds,nitrogen or helium.Natural gas produced by a well may not be suitable for l

203、ong-haul pipelinetransportation or commercial use and may need to be processed to remove the heavier hydrocarbon components and contaminants.Natural gas in commercialdistribution systems mostly consists of methane and ethane,and moisture and other contaminants have been removed so there are negligib

204、le amounts of them inthe gas stream.Natural gas is processed to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas and to separatethose hydrocarbon liquids from the gas that have higher value as NGLs.The removal and separation of individual hydro

205、carbons through processing is possible dueto 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.19Table of Content

206、sNGL fractionation.NGLs are separated into individual,more valuable components during the fractionation process.NGL fractionation facilities separatemixed NGL streams into discrete NGL products:ethane,propane,isobutane,normal butane,natural gasoline and stabilized crude oil and condensate.Ethane isp

207、rimarily 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

208、 fuel.Isobutane is usedprincipally to enhance the octane content of motor gasoline.Normal butane is used as a petrochemical feedstock in the production of ethylene and butylene(a keyingredient in synthetic rubber),as a blend stock for motor gasoline and to derive isobutene through isomerization.Natu

209、ral gasoline,a mixture of pentanes andheavier 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 gatheringsystems and delive

210、r 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 transportationused depends on,among other things,the resources of the transporter,the locations of

211、the production points and the delivery points,cost-efficiency and thequantity of product being transported.Condensate Stabilization.Condensate stabilization is the distillation of the condensate product to remove the lighter end components,which ultimately createsa higher quality condensate product

212、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 andfrac-flowback is hauled via truck transport or is pumped through pipelines from it

213、s origin at the oilfield tank battery or drilling pad to the disposal location.Oncethe water reaches the delivery disposal location,water is processed and filtered to remove impurities and injection wells place fluids underground for storage anddisposal.Storage.Demand for natural gas,NGLs and crude

214、oil fluctuate daily and seasonally,while production and pipeline deliveries are relatively constant in theshort term.Storage of products during periods of low demand helps to ensure that sufficient supplies are available during periods of high demand.Natural gas andNGLs are stored in large volumes i

215、n underground facilities and in smaller volumes in tanks above and below ground,while crude oil is typically stored in tanksabove ground.Crude oil and condensate terminals.Crude oil and condensate rail terminals are an integral part of ensuring the movement of new crude oil and condensateproduction

216、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 railcars and transport the commodity out of developing basins into market rich areas of the country where crude oil and condensate rail unloading terminals

217、are used tounload rail cars and store crude oil and condensate volumes for third parties until the crude oil and condensate is redelivered to premium market delivery points viapipelines,trucks or rail.BalancingSupplyandDemandWhen we purchase natural gas,crude oil and condensate,we establish a margin

218、 normally by selling it for physical delivery to third-party users.We can alsouse over-the-counter derivative instruments or enter into future delivery obligations under futures contracts on the New York Mercantile Exchange(“NYMEX”)related to our natural gas purchases.Through these transactions,we s

219、eek to maintain a position that is balanced between(1)purchases and(2)sales or futuredelivery obligations.Our policy is not to acquire and hold natural gas futures contracts or derivative products for the purpose of speculating on price changes.CompetitionThe business of providing gathering,transmis

220、sion,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,crudeoil and condensate.Our competitors in

221、clude major integrated and independent exploration and production companies,natural gas producers,interstate andintrastate pipelines,other natural gas,NGLs and crude oil and condensate gatherers and natural gas processors.Competition for natural gas and crude oil andcondensate supplies is primarily

222、based on geographic location of facilities in relation to production or markets,the reputation,efficiency and reliability of thegatherer and the pricing arrangements offered by the gatherer.For areas where acreage is not dedicated to us,we will compete with similar enterprises in providingadditional

223、 gathering and processing20Table of Contentsservices 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 andcondensate supplies than we do.Our competition varies in different geographic areas.In marketi

224、ng natural gas,NGLs,crude oil and condensate,we have numerous competitors,including marketing affiliates of interstate pipelines,majorintegrated oil and gas companies,and local and national natural gas producers,gatherers,brokers and marketers of widely varying sizes,financial resources andexperienc

225、e.Local utilities and distributors of natural gas are,in some cases,engaged directly and through affiliates in marketing activities that compete with ourmarketing operations.We face strong competition for acquisitions and development of new projects from both established and start-up companies.Compe

226、tition increases the cost toacquire existing facilities or businesses and results in fewer commitments and lower returns for new pipelines or other development projects.Our competitors mayhave greater financial resources than we possess or may be willing to accept lower returns or greater risks.Our

227、competition differs by region and by the nature ofthe business or the project involved.NaturalGas,NGL,CrudeOilandCondensateSupplyOur gathering and transmission pipelines have connections with major intrastate and interstate pipelines,which we believe have ample natural gas and NGLsupplies in excess

228、of the volumes required for the operation of these systems.We evaluate well and reservoir data that is either publicly available or furnished byproducers or other service providers in connection with the construction and acquisition of our gathering systems and assets to determine the availability o

229、f naturalgas,NGLs,crude oil and condensate supply for our systems and assets and/or obtain an MVC from the producer that results in a rate of return on investment.Wedo not routinely obtain independent evaluations of reserves dedicated to our systems and assets due to the cost and relatively limited

230、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.CreditRiskandSignificantCustomersWe are subject to risk of loss resulting from nonpayment or nonperformance by our customers and o

231、ther counterparties,such as our lenders and hedgingcounterparties.We diligently attempt to ensure that we issue credit to only credit-worthy customers.However,our purchase and resale of crude oil,condensate,NGLs and natural gas exposes us to significant credit risk,as the margin on any sale is gener

232、ally a very small percentage of the total sales price.Therefore,a creditloss can be very large relative to our overall profitability.A substantial portion of our throughput volumes come from customers that have investment-graderatings.However,lower commodity prices in future periods may result in a

233、reduction in our customers liquidity and ability to make payments or perform on theirobligations to us.Some of our customers have filed for bankruptcy protection,and their debts and payments to us are subject to laws governing bankruptcy.For the years ended December 31,2017,2016 and 2015,Devon repre

234、sented 14.4%,18.5%and 16.6%,respectively,of our consolidated revenues,and DowHydrocarbons&Resources LLC(“Dow Hydrocarbons”)represented 11.2%,10.8%and 11.7%,respectively,of our consolidated revenues.No other customerrepresented greater than 10.0%of our revenue.Our operations are dependent on the volu

235、me of natural gas that Devon provides to us under commercialagreements,which constitutes a substantial portion of our natural gas supply.The loss of Devon or Dow Hydrocarbons as a customer could have a material impacton our results of operations if we were not able to sell our products to another cu

236、stomer with similar margins because the gross operating margins received fromtransactions with Devon and Dow Hydrocarbons are material to our total gross operating margin.RegulationNatural Gas Pipeline Regulation.We own interstate natural gas pipelines that are subject to regulation as natural gas c

237、ompanies by the Federal EnergyRegulatory Commission(“FERC”)under the Natural Gas Act(“NGA”).FERC regulates the rates and terms and conditions of service on interstate natural gaspipelines,as well as the certification,construction,modification,expansion and abandonment of facilities.The rates and ter

238、ms and conditions for our interstate pipeline services must be just and reasonable and not unduly preferential or unduly discriminatory,although negotiated or settlement rates may be accepted in certain circumstances.Such rates and terms and conditions are set forth in FERC-approved tariffs.Proposed

239、 rate increases and changes to our tariffs are subject to FERC approval.Pursuant to FERCs jurisdiction over rates,existing rates may be challenged bycomplaint or by FERC on its own initiative,and proposed new or changed rates may be challenged by protest.If protested,a rate increase may be suspended

240、 for upto five months and collected,subject to refund.If,upon completion of an investigation,FERC finds that21Table of Contentsthe 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 ofthe inv

241、estigation.The rates charged by our FERC regulated natural gas pipelines may also be affected by the ongoing uncertainty regarding FERCs current income taxallowance policy.In July 2016,the United States Court of Appeals for the District of Columbia Circuit issued its opinion in United Airlines,Inc.,

242、et al.v.FERC,finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as alimited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted

243、 cash flow return on equity would notresult in the pipeline double-recovering its investors income taxes.The court vacated FERCs order and remanded to FERC to consider mechanisms fordemonstrating that there is no double recovery as a result of the income tax allowance.On December 15,2016,FERC issued

244、 a Notice of Inquiry seeking commenton how to address any double recovery resulting from its income tax allowance policy.FERC is currently considering whether,and if so,to what extent,pipelinesowned by pass-through entities such as MLPs may include income tax allowance in rates to compensate for the

245、 income tax liability of investors.Interstate natural gas pipelines regulated by FERC are required to comply with numerous regulations related to standards of conduct,market transparency,andmarket manipulation.FERCs standards of conduct regulate the manner in which interstate natural gas pipelines m

246、ay interact with their marketing affiliates.FERCs market oversight and transparency regulations require regulated entities to submit annual reports of threshold purchases or sales of natural gas and publiclypost certain information on scheduled volumes.FERCs market manipulation regulations,promulgat

247、ed pursuant to the Energy Policy Act of 2005(the“EPAct2005”),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 thepurchase or sale of transportation services subject to the jurisdiction of FERC,to(1)us

248、e or employ any device,scheme or artifice to defraud;(2)make any untruestatement of material fact or omit to state a material fact necessary to make the statements made not misleading(in light of the circumstances under which thestatements were made);or(3)engage in any act,practice or course of busi

249、ness that operates(or would operate)as a fraud or deceit upon any person.The EPAct2005 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 upto$1.0 million per day per violation for violations occurring a

250、fter August 8,2005.The maximum penalty authority established by the statute has been adjusted to$1.2 million per day per violation and will continue to be adjusted periodically for inflation.Should we fail to comply with all applicable FERC-administeredstatutes,rules,regulations and orders,we could

251、be subject to substantial penalties and fines.Certain of our intrastate natural gas pipelines also transport gas in interstate commerce and,thus,the rates,terms and conditions of such services are subject toFERC jurisdiction under Section 311 of the NGPA(“Section 311”).Pipelines providing transporta

252、tion service under Section 311 are required to provide serviceson an open and nondiscriminatory basis,and the maximum rates for interstate transportation services provided by such pipelines must be“fair and equitable.”Suchrates are generally subject to review every five years by FERC or by an approp

253、riate state agency.In addition to Section 311 regulation,our intrastate natural gas pipeline operations are subject to regulation by various state agencies.Most state agenciespossess the authority to review and authorize natural gas transportation transactions and the construction,acquisition,abando

254、nment and interconnection of physicalfacilities for intrastate pipelines.State agencies also may regulate transportation rates,service terms and conditions and contract pricing.Liquids Pipeline Regulation.We own certain liquids and crude oil pipelines that are regulated by FERC as common carrier int

255、erstate pipelines under theInterstate Commerce Act(“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,condensateand NGLs,be filed with FE

256、RC and that these rates and terms and conditions of service be“just and reasonable”and not unduly discriminatory or undulypreferential.Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology,under which pipelines increase ordecrease thei

257、r rates in accordance with an index adjustment specified by FERC.This adjustment is subject to review every five years.For the five-year periodbeginning on July 1,2016,FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%.OnOctober

258、20,2016,however,FERC issued an Advance Notice of Proposed Rulemaking indicating that FERC is considering a new policy that would deny proposedindex increases for pipelines under certain circumstances where revenues exceed cost-of-service by a certain percentage or where the proposed index increasese

259、xceed certain annual cost changes reported to FERC.Under current FERC regulations,liquids pipelines can request a rate increase that exceeds the rate obtainedthrough application of the indexing methodology by using a cost-of-service approach,but only after the pipeline establishes that a substantial

260、 divergence existsbetween the actual costs experienced by the pipeline and the rates resulting from application of the indexing22Table of Contentsmethodology.The rates charged by our interstate liquids pipelines may also be affected by the ongoing uncertainty regarding FERCs current income taxallowa

261、nce policy discussed above.The ICA permits interested persons to challenge proposed new or changed rates and authorizes FERC to suspend the effectiveness of such rates for up toseven months and investigate such rates.If,upon completion of an investigation,FERC finds that the new or changed rate is u

262、nlawful,it is authorized to requirethe pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation.FERC may also investigate,upon complaintor on its own motion,rates that are already in effect and may order a carrier to change its rates prospe

263、ctively.Under certain circumstances,FERC could limit ourability to set rates based on our costs or could order us to reduce our rates and pay reparations to complaining shippers for up to two years prior to the date of thecomplaint.FERC also has the authority to change our terms and conditions of se

264、rvice if it determines that they are unjust and unreasonable or undulydiscriminatory or preferential.As we acquire,construct and operate new liquids assets and expand our liquids transportation business,the classification and regulation of our liquidstransportation services,including services that o

265、ur marketing companies provide on our FERC-regulated liquids pipelines,are subject to ongoing assessment andchange based on the services we provide and determinations by FERC and the courts.Such changes may subject additional services we provide to regulation byFERC.Intrastate NGL and other petroleu

266、m pipelines are not generally subject to rate regulation by FERC,but they are subject to regulation by various agencies in therespective states where they are located.While such regulatory regimes vary,state agencies typically require intrastate NGL and petroleum pipelines to file theirrates with th

267、e 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 anumber of natural gas pipelines that we believe meet the traditional

268、 tests FERC has used to establish that a pipeline is a gathering pipeline and therefore not subjectto FERC jurisdiction.The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial,ongoing litigation,however,so the classifica

269、tion and regulation of our gathering facilities are subject to change.Application of FERC jurisdiction to our gatheringfacilities could increase our operating costs,decrease our rates and adversely affect our business.State regulation of gathering facilities generally includes varioussafety,environm

270、ental and,in some circumstances,nondiscriminatory requirements and complaint-based rate regulation.In addition,we are subject to some state ratable take and common purchaser statutes.The ratable take statutes generally require gatherers to take,withoutundue discrimination,natural gas production that

271、 may be tendered to the gatherer for handling.Similarly,common purchaser statutes generally require gatherers topurchase without undue discrimination as to source of supply or producer.These statutes are designed to prohibit discrimination in favor of one producer overanother producer or one source

272、of supply over another source of supply.Natural Gas Storage Regulation.In December 2016,the DOTs Pipeline and Hazardous Materials Safety Administration(“PHMSA”)issued an interim finalrule(“IFR”)that addresses safety issues related to downhole facilities located at both intrastate and interstate unde

273、rground storage facilities.The IFR incorporatesby reference two of the American Petroleum Institutes Recommended Practice standards and mandates certain reporting requirements for operators ofunderground natural gas storage facilities.Under the IFR,all intrastate transportation related underground n

274、atural gas storage facilities will become subject tominimum federal safety standards and be inspected by PHMSA or by a state entity that has chosen to expand its authority to regulate these facilities under acertification filed with PHMSA.The IFR became effective on January 18,2017,with a compliance

275、 deadline of January 18,2018.PHMSA subsequentlydetermined,however,that it will not issue enforcement citations to any operators for violations of provisions of the IFR that had previously been non-mandatoryprovisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year

276、after PHMSA issues a final rule.On October 19,2017,PHMSAformally reopened the comment period on the IFR in response to a petition for reconsideration.This matter remains ongoing and subject to future PHMSAdeterminations.We are in compliance with this IFR.Certain of our field injection and withdrawal

277、 wells and water disposal wells are subject to the jurisdiction of the Railroad Commission of Texas(“TRRC”).TRRC regulations require that we report the volumes of natural gas and water disposal associated with the operations of such wells on a monthly and annual basis,respectively.Results of periodi

278、c mechanical integrity tests must also be reported to the TRRC.In addition,our underground gas storage caverns in Louisiana aresubject to the jurisdiction of the Louisiana Department of Natural Resources(“LDNR”).In recent years,LDNR has put in place more comprehensive regulationsgoverning undergroun

279、d hydrocarbon storage in salt caverns.We also operate brine disposal wells that are regulated as Class II wells under the federal Safe Drinking Water Act(“SDWA”).The SDWA imposesrequirements on owners and operators of Class II wells through the EPAs Underground23Table of ContentsInjection Control pr

280、ogram,including construction,operating,monitoring and testing,reporting and closure requirements.Our brine disposal wells are also subjectto comparable state laws and regulations.For more information,see“Environmental Matters”below.Sales of Natural Gas and NGLs.The prices at which we sell natural ga

281、s and NGLs currently are not subject to federal regulation and,for the most part,are notsubject to state regulation.Our natural gas and NGL sales are,however,affected by the availability,terms,cost and regulation of pipeline transportation.Employee Safety.We are subject to the requirements of the Oc

282、cupational Safety and Health Act(“OSHA”),and comparable state laws that regulate theprotection of the health and safety of workers.In addition,the OSHA hazard communication standard requires that information be maintained about hazardousmaterials used or produced in operations and that this informat

283、ion be provided to employees,state and local government authorities and citizens.We believe thatour operations are in substantial compliance with the OSHA requirements including general industry standards,record keeping requirements,and monitoring ofoccupational exposure to regulated substances.Pipe

284、line Safety Regulations.Our pipelines are subject to regulation by PHMSA pursuant to the Natural Gas Pipeline Safety Act of 1968(“NGPSA”)and thePipeline Safety Improvement Act of 2002(“PSIA”).The NGPSA regulates safety requirements in the design,construction,operation and maintenance of gaspipeline

285、facilities.The PSIA established mandatory inspections for all U.S.crude oil and natural gas transportation pipelines and some gathering lines in high-consequence areas(“HCAs”),which include,among other things,areas of high population density or that serve as sources of drinking water.PHMSA hasdevelo

286、ped regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs,including more frequentinspections and other measures to ensure pipeline safety in HCAs.More recently,the Pipeline Safety,Regulatory Certainty and Job Creation Act of 2011

287、increasedpenalties for safety violations,established additional safety requirements for newly constructed pipelines and required studies of certain safety issues that couldresult in the adoption of new regulatory requirements for existing pipelines,and in June 2016,the President of the United States

288、 signed the Protecting ourInfrastructure of Pipelines and Enhancing Safety Act of 2016(the“PIPES Act”),which reauthorizes PHMSAs oil and gas pipeline programs through 2019.In April 2016,PHMSA published a notice of proposed rulemaking(“NPRM”),addressing natural gas transmission and gathering lines.Th

289、e proposed rulewould,among other things,change existing integrity management requirements,expand assessment and repair requirements to pipelines in“moderate-consequenceareas,”including areas of medium population density,and increase requirements for monitoring and inspection of pipeline segments loc

290、ated outside of HCAs.Furthermore,this NPRM would require that records or other data relied on to determine operating pressures must be traceable,verifiable and complete.Locatingsuch records and,in the absence of any such records,verifying maximum pressures through physical testing or modifying or re

291、placing facilities,could significantlyincrease our costs.Additionally,failure to locate such records or verify maximum pressures could result in the reduction of allowable operating pressures,whichwould reduce available capacity on our pipelines.PHMSA,however,has yet to finalize this rulemaking,and

292、the contents and timing of any final rule are currentlyuncertain.In addition,in January 2017,PHMSA finalized new hazardous liquid pipeline safety regulations that would have extended certain regulatory reportingrequirements to all hazardous liquid gathering(including oil)pipelines.The final rule als

293、o would have required additional event-driven and periodic inspections,required the use of leak detection systems on all hazardous liquid pipelines,modified repair criteria,and required certain pipelines to eventually accommodate in-line inspection tools.The effective date of this final rule is curr

294、ently uncertain due to a regulatory freeze implemented by the Trump administration on January 20,2017.On January 23,2017,PHMSA published in the Federal Register amendments to the pipeline safety regulations to address requirements of the Pipeline Safety,Regulatory Certainty,and Job Creation Act of 2

295、011 and to update and clarify certain regulatory requirements regarding notifications of accidents and incidents.The final rule also adds provisions for cost recovery for design reviews of certain new projects,provides for renewal of existing special permits,and incorporatescertain standards for in-

296、line inspections and stress corrosion cracking assessments.At the state level,several states have passed legislation or promulgated rules dealing with pipeline safety.We believe that our pipeline operations are insubstantial compliance with applicable PHMSA and state requirements;however,due to the

297、possibility of new or amended laws and regulations or reinterpretationof existing laws and regulations,there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on ourfinancial condition,results of operations or cash flows.24Table of Co

298、ntentsOn November 2,2015,PHMSA issued a Notice of Probable Violation and Proposed Compliance Order(the“NOPV”)asserting that we have probableviolations of 49 CFR Part 195 due to the misclassification of a transmission line as a gathering line.Transmission lines are subject to more fulsome pipeline sa

299、fetyregulations than gathering lines.The NOPV proposed a compliance order requiring us to satisfy the Part 195 requirements applicable to transmission lines but didnot propose a penalty.On January 18,2018,we received a letter from PHMSA withdrawing the NOPV and indicating that the case was closed ef

300、fective as ofJanuary 18,2018.EnvironmentalMattersGeneral.Our operations involve processing and pipeline services for delivery of hydrocarbons(natural gas,NGLs,crude oil and condensates)from point-of-origin at crude oil and gas wellheads operated by our suppliers to our end-use market customers.Our f

301、acilities include natural gas processing and fractionationplants,natural gas and NGL storage caverns,brine disposal wells,pipelines and associated facilities,fractionation and storage units for NGLs,and transportationand delivery of hydrocarbons.As with all companies in our industrial sector,our ope

302、rations are subject to stringent and complex federal,state and local laws andregulations relating to the discharge 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 regul

303、ations increases our overall costs of doing business,including costs of planning,constructing,and operating plants,pipelines,and other facilities,as well as capital expenditures necessary to maintain or upgrade equipment and facilities.Similarcosts are likely upon changes in laws or regulations and

304、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 requiredgovernmental approvals and permits,may result in the assessment of administrative,civil or criminal penalties,

305、imposition of investigatory or remedial activitiesand,in certain,less common circumstances,issuance of temporary or permanent injunctions or construction or operation bans or delays.As part of the regularevaluation of our operations,we routinely review and update governmental approvals as necessary.

306、The continuing trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment,and thus there canbe no assurance as to the amount or timing of future expenditures for environmental compliance or remediation,and actual future expenditures

307、may be differentfrom the amounts we currently anticipate.Moreover,risks of process upsets,accidental releases or spills are associated with possible future operations,and wecannot assure you that we will not incur significant costs and liabilities,including those relating to claims for damage to the

308、 environment,property and persons as aresult of any such upsets,releases or spills.We may be unable to pass on current or future environmental costs to our customers.A discharge or release ofhydrocarbons,hazardous substances or solid wastes into the environment could,to the extent losses related to

309、the event are not insured,subject us to substantialexpense,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 claimsmade by neighboring landowners and other third parties for personal injury or damage to n

310、atural resources or property.We attempt to anticipate future regulatoryrequirements that might be imposed and plan accordingly to comply with changing environmental laws and regulations and to minimize costs with respect to morestringent future laws and regulations or more rigorous enforcement of ex

311、isting 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,sediments,groundwater and surface water and/or include measures to prevent and control pollution may pose significant cost

312、s to our industrial sector.These lawsand regulations generally regulate the generation,storage,treatment,transportation and disposal of solid wastes and hazardous substances and may requireinvestigatory and corrective actions at facilities where such waste or substance may have been released or disp

313、osed.For instance,the ComprehensiveEnvironmental Response,Compensation,and Liability Act(“CERCLA”),also known as the federal“Superfund”law,and comparable state laws impose liabilitywithout regard to fault or the legality of the original conduct on certain classes of persons that contributed to a rel

314、ease of a“hazardous substance”into theenvironment.Potentially responsible parties include the owner or operator of the site where a release occurred and companies that disposed or arranged for thedisposal of the hazardous substances found at an off-site location,such as a landfill.Under CERCLA,these

315、 persons may be subject to joint and several liability forthe costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources.CERCLAalso authorizes the U.S.Environmental Protection Agency(“EPA”)and,in some cases,third p

316、arties,to take actions in response to threats to public health or theenvironment and to seek recovery of costs they incur from the potentially responsible classes of persons.It is not uncommon for neighboring landowners and otherthird parties to file claims for personal injury and property damage al

317、legedly caused by hazardous substances or solid wastes released into the environment.Although petroleum,natural gas and NGLs are excluded from CERCLAs definition of a“hazardous substance,”in the course of ordinary operations,we maygenerate wastes that may fall within the definition of a“hazardous su

318、bstance.”In addition,there are other laws and regulations that can create liability for releasesof petroleum,natural gas or NGLs.Moreover,we may be responsible under CERCLA or other laws for all or part of25Table of Contentsthe costs required to clean up sites at which such substances have been disp

319、osed.We have not received any notification that we may be potentially responsible forcleanup costs under CERCLA or any analogous federal,state,or local law.We also generate,and may in the future generate,both hazardous and nonhazardous solid wastes that are subject to requirements of the federal Res

320、ourceConservation and Recovery Act(“RCRA”)and/or comparable state statutes.From time to time,the EPA and state regulatory agencies have considered theadoption of stricter disposal standards for nonhazardous wastes,including crude oil,condensate and natural gas wastes.Moreover,it is possible that som

321、e wastesgenerated by us that are currently exempted from the definition of hazardous waste may in the future lose this exemption and be designated as“hazardous wastes,”resulting in the wastes being subject to more rigorous and costly management and disposal requirements.Additionally,the Toxic Substa

322、nces Control Act(“TSCA”)and analogous state laws impose requirements on the use,storage and disposal of various chemicals and chemical substances.In June 2017,the EPAfinalized three rulemakings to update its implementation of TSCA.Two of the new rules establish the EPAs process and criteria for iden

323、tifying high prioritychemicals for risk evaluation and determining whether these high priority chemicals present an unreasonable risk to health or the environment.The third rulerequires industry reporting of chemicals manufactured or processed in the U.S.over the past 10 years.Changes in applicable

324、laws or regulations may result in anincrease 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 use

325、d over the years for brinedisposal 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

326、 over the years with the passage andimplementation of various environmental laws and regulations.Nevertheless,some hydrocarbons and other solid wastes may have been released on or undervarious properties owned,leased or operated by us during the operating history of those properties.In addition,a nu

327、mber of these properties may have beenoperated by third parties over whose operations and hydrocarbon and waste management practices we had no control.These properties and wastes disposedthereon may be subject to the SWDA,CERCLA,RCRA,TSCA and analogous state laws.Under these laws,we could be require

328、d,alone or in participation withothers,to remove or remediate previously disposed wastes or property contamination,if present,including groundwater contamination,or to take action to preventfuture contamination.Air Emissions.Our current and future operations are subject to the federal Clean Air Act

329、and regulations promulgated thereunder and under comparable statelaws and regulations.These laws and regulations regulate emissions of air pollutants from various industrial sources,including our facilities,and impose variouscontrol,monitoring,and reporting requirements.Pursuant to these laws and re

330、gulations,we may be required to obtain environmental agency pre-approval for theconstruction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing air emissions,obtain and complywith the terms of air permits,which include various emi

331、ssion and operational limitations,or use specific emission control technologies to limit emissions.Welikely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with maintaining or obtaininggovernmental approvals addressing air emissi

332、on-related issues.Failure to comply with applicable air statutes or regulations may lead to the assessment ofadministrative,civil or criminal penalties and may result in the limitation or cessation of construction or operation of certain air emission sources or require us toincur additional capital

333、expenditures.Although we can give no assurances,we believe such requirements will not have a material adverse effect on our financialcondition,results of operations or cash flows,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,the location of our Bridgeport facility,in its January 2012 revision to the