DCP Midstream
Annual Report 2018

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 FORM 10-K (Mark One)ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2018or ¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period from to Commission File Number: 001-32678 DCP MIDSTREAM, LP(Exact name of registrant as specified in its charter) Delaware 03-0567133(State or other jurisdictionof incorporation or organization) (I.R.S. EmployerIdentification No.) 370 17th Street, Suite 2500Denver, Colorado 80202(Address of principal executive offices) (Zip Code)Registrant’s telephone number, including area code: (303) 595-3331Securities registered pursuant to Section 12(b) of the Act:Title of Each Class:Name of Each Exchange on Which Registered:Common Units Representing Limited Partner InterestsNew York Stock ExchangeSecurities registered pursuant to Section 12(g) of the Act:None.Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Exchange Act of 1934, or the Act. Yesý No¨Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ýIndicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Act during the preceding 12 months (or for such shorter period that the registrant wasrequired to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesý No¨Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of regulation S-T (§232.405 of this chapter) during thepreceding 12 months (or for such shorter period that the registrant was required to submit and such files). Yes ý No ¨Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ýIndicate 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 the definitions of “largeaccelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.Large accelerated filerý Accelerated filer¨Non-accelerated filer¨ Smaller reporting company¨Emerging growth company¨ 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 accounting standards providedpursuant to Section 13(a) of the Exchange Act. ¨Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ýThe aggregate market value of common units held by non-affiliates of the registrant on June 30, 2018, was approximately $3,577,813,000. The aggregate market value was computed by reference to the last saleprice of the registrant’s common units on the New York Stock Exchange on June 30, 2018.As of February 20, 2019, there were 143,317,328 common units representing limited partner interests outstanding.DOCUMENTS INCORPORATED BY REFERENCE:NoneDCP MIDSTREAM, LPFORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2018TABLE OF CONTENTS Item Page PART I 1.Business11A.Risk Factors201B.Unresolved Staff Comments462.Properties463.Legal Proceedings474.Mine Safety Disclosures47 PART II 5.Market for Registrant's Common Units, Related Unitholder Matters and Issuer Purchases of Common Units476.Selected Financial Data507.Management's Discussion and Analysis of Financial Condition and Results of Operations517A.Quantitative and Qualitative Disclosures about Market Risk818.Financial Statements and Supplementary Data869.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure1429A.Controls and Procedures1429B.Other Information144 PART III 10.Directors, Executive Officers and Corporate Governance14511.Executive Compensation15112.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters16313.Certain Relationships and Related Transactions, and Director Independence16414.Principal Accountant Fees and Services166 PART IV 15.Exhibits and Financial Statement Schedules16716.Form 10-K Summary220 Signatures221iGLOSSARY OF TERMSThe following is a list of certain industry terms used throughout this report: Bbl barrelBbls/d barrels per dayBcf billion cubic feetBcf/d billion cubic feet per dayBtu British thermal unit, a measurement of energyFractionation the process by which natural gas liquids are separated into individual componentsMBbls thousand barrelsMBbls/d thousand barrels per dayMMBtu million BtusMMBtu/d million Btus per dayMMcf million cubic feetMMcf/d million cubic feet per dayNGLs natural gas liquidsThroughput the volume of product transported or passing through a pipeline or other facility iiCAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTSOur reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are“forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use offorward-looking words, such as “may,” “could,” “should,” “intend,” “assume,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and othersimilar words.All statements that are not statements of historical facts, including, but not limited to, statements regarding our future financial position, business strategy, budgets, projectedcosts and plans and objectives of management for future operations, are forward-looking statements.These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and otherfactors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in Item 1A. "Risk Factors" in this AnnualReport on Form 10-K for the year ended December 31, 2018, including the following risks and uncertainties:•the extent of changes in commodity prices and the demand for our products and services, our ability to effectively limit a portion of the adverse impact of potential changesin commodity prices through derivative financial instruments, and the potential impact of price, and of producers’ access to capital on natural gas drilling, demand for ourservices, and the volume of NGLs and condensate extracted;•the demand for crude oil, residue gas and NGL products;•the level and success of drilling and quality of production volumes around our assets and our ability to connect supplies to our gathering and processing systems, as wellas our residue gas and NGL infrastructure;•new, additions to, and changes in, laws and regulations, particularly with regard to taxes, safety, regulatory and protection of the environment, including, but not limitedto, climate change legislation, regulation of over-the-counter derivatives market and entities, and hydraulic fracturing regulations, or the increased regulation of ourindustry, including mandatory setbacks for oil and gas operations and additional local control over such activities, and their impact on producers and customers served byour systems;•volatility in the price of our common units;•general economic, market and business conditions;•the amount of natural gas we gather, compress, treat, process, transport, store and sell, or the NGLs we produce, fractionate, transport, store and sell, may be reduced ifthe pipelines, storage and fractionation facilities to which we deliver the natural gas or NGLs are capacity constrained and cannot, or will not, accept the natural gas orNGLs or we may be required to find alternative markets and arrangements for our natural gas and NGLs;•our ability to continue the safe and reliable operation of our assets;•our ability to construct and start up facilities on budget and in a timely fashion, which is partially dependent on obtaining required construction, environmental and otherpermits issued by federal, state and municipal governments, or agencies thereof, the availability of specialized contractors and laborers, and the price of and demand formaterials;•our ability to access the debt and equity markets and the resulting cost of capital, which will depend on general market conditions, our financial and operating results,inflation rates, interest rates, our ability to comply with the covenants in our $1.4 billion unsecured revolving credit facility or other credit facilities, and the indenturesgoverning our notes, as well as our ability to maintain our credit ratings;•the creditworthiness of our customers and the counterparties to our transactions;•the amount of collateral we may be required to post from time to time in our transactions;•industry changes, including the impact of bankruptcies, consolidations, alternative energy sources, technological advances, infrastructure constraints and changes incompetition;•our ability to grow through organic growth projects, or acquisitions, and the successful integration and future performance of such assets;•our ability to hire, train, and retain qualified personnel and key management to execute our business strategy;•weather, weather-related conditions and other natural phenomena, including, but not limited to, their potential impact on demand for the commodities we sell and theoperation of company-owned and third party-owned infrastructure;•security threats such as terrorist attacks, and cybersecurity attacks and breaches, against, or otherwise impacting, our facilities and systems; and•our ability to obtain insurance on commercially reasonable terms, if at all, as well as the adequacy of insurance to cover our losses.In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at adifferent time than we have described. The forward-looking statements in this report speak as of the filing date of this report. We undertake no obligation to publicly update or reviseany forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable securities laws.iiiPART IItem 1. BusinessOVERVIEWDCP Midstream, LP (together with its consolidated subsidiaries, “we”, “our”, “us”, the “registrant”, or the “Partnership”) is a Delaware limitedPartnership formed in 2005 by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets.DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC is owned 50% by Phillips 66 and 50% by EnbridgeInc. and its affiliates, or Enbridge.The diagram below depicts our organizational structure as of December 31, 2018.Our operations are organized into two reportable segments: (i) Logistics and Marketing and (ii) Gathering and Processing. Our Logistics and Marketingsegment includes transporting, trading, marketing, and storing natural gas and NGLs, fractionating NGLs, and wholesale propane logistics. Our Gathering andProcessing segment consists of gathering, compressing, treating, and processing natural gas, producing and fractionating NGLs, and recovering condensate.The remainder of our business operations are presented as “Other,” and consist of unallocated corporate costs.1OUR BUSINESS STRATEGYOur primary business objectives are to achieve sustained company profitability, a strong balance sheet and profitable growth, thereby sustaining andultimately growing our cash distribution per unit. We intend to accomplish these objectives by prudently executing the following business strategies:Operational Performance. We believe our operating efficiency and reliability enhance our ability to attract new natural gas supplies by enabling usto offer more competitive terms, services and service flexibility to producers. Our logistics assets and gathering and processing systems consist of high-quality, well-maintained facilities, resulting in low-cost, efficient operations. Our goal is to establish a reputation in the midstream industry as a reliable, safeand low cost supplier of services to our customers. We will continue to pursue new contracts, cost efficiencies and operating improvements of our assetsthrough process and technology improvements. We seek to increase the utilization of our existing facilities by providing additional services to our existingcustomers and by establishing relationships with new customers. In addition, we maximize efficiency by coordinating the completion of new facilities in amanner that is consistent with the expected production that supports them.Organic Growth. We intend to use our strategic asset base in the United States and our position as one of the largest processors of natural gas, and asone of the largest producers and marketers of NGLs in the United States, as a platform for future growth. We plan to grow our business by constructing newNGL and natural gas pipeline infrastructure, expanding existing infrastructure, and constructing new gathering lines and processing facilities.Strategic Partnerships and Acquisitions. We intend to pursue economically attractive and strategic partnership and acquisition opportunities withinthe midstream energy industry, both in new and existing lines of business, and areas of operation.OUR COMPETITIVE STRENGTHSWe are one of the largest processors of natural gas and one of the largest producers and marketers of NGLs in the United States. In 2018, our totalwellhead volume was approximately 4.8 Bcf/d of natural gas and we produced an average of approximately 413 MBbls/d of NGLs. We provide natural gasgathering services to the wellhead, and leverage our strategic footprint to extend the value chain through our integrated NGL and natural gas pipelines andmarketing infrastructure. We believe our ability to provide all of these services gives us an advantage in competing for new supplies of natural gas becausewe can provide substantially all services to move natural gas and NGLs from wellhead to market, and creates value for our customers. We believe that we arewell positioned to execute our business strategies and achieve one of our primary business objectives of sustaining our cash distribution per unit because ofthe following competitive strengths:Integrated Logistics and Marketing Operations. We believe the strategic location of our assets coupled with their geographic diversity and ourreputation for running our business reliably and effectively, presents us with continuing opportunities to provide competitive services to our customers andattract new natural gas production to our gathering and processing operations. We have connected our gathering and processing operations to key marketswith NGL pipelines that we own or operate to offer our customers a competitive, integrated midstream service. We have strategically located NGLtransportation pipelines that provide takeaway capabilities for our gathering and processing operations in the Permian Basin, the Denver-Julesburg Basin(“DJ Basin”), the Midcontinent, East Texas, the Gulf Coast, South Texas, and Central Texas. Our NGL pipelines connect to various natural gas processingplants and transport the NGLs to fractionation facilities, a petrochemical plant, a third party underground NGL storage facility and other markets along theGulf Coast. Our Logistics and Marketing operations also consists of multiple downstream assets including NGL fractionation facilities, an NGL storagefacility and a residue gas storage facility.Strategically Located Gas Gathering and Processing Operations. Our assets are strategically located in areas with the potential for increasing ourwellhead volumes and cash flow generation. We have operations in some of the largest producing regions in the United States: DJ Basin, Permian Basin,Midcontinent, and Eagle Ford. In addition, we operate one of the largest portfolios of natural gas processing plants in the United States. Our gatheringsystems and processing plants are connected to numerous key natural gas pipeline systems that provide producers with access to a variety of natural gasmarket hubs.Stable Cash Flows. Our operations consist of a mix of fee-based and commodity-based services, which together with our commodity hedging program,are intended to generate relatively stable cash flows. Growth in our fee-based earnings will reduce the impact of unhedged margins. Additionally, whilecertain of our gathering and processing contracts subject us to commodity price risk, we have mitigated a portion of our currently anticipated commodityprice risk associated with the equity volumes from our gathering and processing operations with fixed price commodity swaps.2Established Relationships with Oil, Natural Gas and Petrochemical Companies. We have long-term relationships with many of our suppliers andcustomers, and we expect that we will continue to benefit from these relationships.Experienced Management Team. Our senior management team and the board of directors of our General Partner have extensive experience in themidstream industry. We believe our management team has a proven track record of enhancing value through organic growth and the acquisition,optimization and integration of midstream assets.Affiliation with DCP Midstream, LLC and its owners. Our relationship with DCP Midstream, LLC and its owners, Phillips 66 and Enbridge, shouldcontinue to provide us with significant business opportunities. Through our relationship with DCP Midstream, LLC and its owners, we believe our strongcommercial relationships throughout the energy industry, including with major producers of natural gas and NGLs in the United States, will help facilitatethe implementation of our strategies.DCP Midstream, LLC has a significant interest in us through its ownership of an approximately 2% general partner interest, an approximately 36%limited partner interest and all of our incentive distribution rights.3OUR OPERATING SEGMENTSLogistics and Marketing Segment GeneralWe market our NGLs, residue gas and condensate and provide logistics and marketing services to third-party NGL producers and sales customers insignificant NGL production and market centers in the United States. This includes purchasing NGLs on behalf of third-party NGL producers for shipment onour NGL pipelines and resale in key markets.Our NGL services include plant tailgate purchases, transportation, fractionation, flexible pricing options, price risk management and product-in-kindagreements. Our primary NGL operations are located in close proximity to our Gathering and Processing assets in each of the operating regions.Our NGL pipelines transport NGLs from natural gas processing plants to fractionation facilities, a petrochemical plant and a third party undergroundNGL storage facility. Our pipelines provide transportation services to customers primarily on a fee basis. Therefore, the results of operations for this businessare generally dependent upon the volume of product transported and the level of fees charged to customers. The volumes of NGLs transported on ourpipelines are dependent on the level of production of NGLs from processing plants connected to our NGL pipelines. When natural gas prices are high relativeto NGL prices, it is less profitable to recover NGLs from natural gas because of the higher value of natural gas compared to the value of NGLs. As a result, wehave experienced periods, and will likely experience periods in the future, when higher relative natural gas prices reduce the volume of NGLs produced atplants connected to our NGL pipelines.4Our natural gas systems have the ability to deliver gas into numerous downstream transportation pipelines and markets. We sell residue gas on behalf ofour producer customers and residue gas which we earn under our gas supply agreements, supplying the residue gas demands of end-use customers physicallyattached to our pipeline systems and managing excess capacity of our owned storage and transportation assets. End-users include large industrial companies,natural gas distribution companies and electric utilities. We are focused on extracting the highest possible value for the residue gas that results from ourprocessing and transportation operations. We sell the residue gas at market-based prices.Our ownership in various intrastate natural gas pipelines gives us access to market centers/hubs such as Waha, Texas; Katy, Texas and the Houston ShipChannel and are used in our natural gas asset based trading activities.The following is operating data for our Logistics and Marketing segment:Operating Data Year Ended December 31, 2018System ApproximateSystemLength(Miles) Fractionators ApproximateThroughputCapacity(MBbls/d) (a) ApproximateNGL StorageCapacity(MMBbls) ApproximateNatural GasStorageCapacity (Bcf) PipelineThroughput(MBbls/d) (a) FractionatorThroughput(MBbls/d) (a)Sand Hills pipeline 1,400 — 323 — — 270 —Southern Hillspipeline 950 — 128 — — 91 —Front Range pipeline 450 — 50 — — 43 —Texas Expresspipeline 600 — 28 — — 20 —Other pipelines 1,200 — 241 — — 158 —Mont Belvieufractionators — 2 60 — — — 58Storage facilities — — — 8 12 — —Total 4,600 2 830 8 12 582 58(a)Represents total NGL capacity or throughput allocated to our proportionate ownership share.NGL PipelinesDCP Sand Hills Pipeline, LLC, or the Sand Hills pipeline, an interstate NGL pipeline which is owned 66.67% by us and 33.33% by Phillips 66, is acommon carrier pipeline which provides takeaway service from plants in the Permian and the Eagle Ford basins to fractionation facilities along the TexasGulf Coast and at the Mont Belvieu, Texas market hub. We completed the expansion of the Sand Hills pipeline to 485 MBbls/d during the fourth quarter of2018.DCP Southern Hills Pipeline, LLC, or the Southern Hills pipeline, an interstate NGL pipeline which is owned 66.67% by us and 33.33% by Phillips 66,provides takeaway service from the Midcontinent to fractionation facilities at the Mont Belvieu, Texas market hub. We increased the capacity of theSouthern Hills pipeline at the end of the third quarter of 2018 to approximately 190 MBbls/d.Front Range Pipeline LLC, or the Front Range pipeline, an interstate NGL pipeline in which we own a 33.33% interest, originates in the DJ Basin andextends to Skellytown, Texas. The Front Range pipeline connects to our O'Connor, Lucerne 1, Lucerne 2, and Mewbourn plants as well as third party plantsin the DJ Basin. Enterprise Products Partners L.P., or Enterprise, is the operator of the pipeline.Texas Express Pipeline LLC, or the Texas Express pipeline, an intrastate NGL pipeline in which we own a 10% interest, originates near Skellytown inCarson County, Texas, and extends to Enterprise's natural gas liquids fractionation and storage complex at Mont Belvieu, Texas. The pipeline also providesaccess to other third party facilities in the area. Enterprise is the operator of the pipeline.The Southern Hills, Sand Hills, Texas Express, and Front Range pipelines have in place long-term, fee-based transportation agreements, a portion ofwhich are ship-or-pay, with us as well as third party shippers. These NGL pipelines collect fee-based transportation revenue under regulated tariffs.5NGL Fractionation FacilitiesWe own a 12.5% interest in the Enterprise fractionator operated by Enterprise and a 20% interest in the Mont Belvieu 1 fractionator operated byONEOK Partners, both located in Mont Belvieu, Texas. The fractionation facilities separate NGLs received from processing plants into their individualcomponents. These fractionation services are provided on a fee basis. The results of operations for this business are generally dependent upon the volume ofNGLs fractionated and the level of fees charged to customers.Storage FacilitiesOur NGL storage facility, which stores ethane, propane and butane, is located in Marysville, Michigan and has strategic access to the Marcellus, Uticaand Canadian NGLs. Our facility includes 11 underground salt caverns with approximately 8 MMBbls of storage capacity. Our facility serves regionalrefining and petrochemical demand, and helps to balance the seasonality of propane distribution in the Midwestern and Northeastern United States and inSarnia, Canada. We provide services to customers primarily on a fee basis under multi-year storage agreements. The results of operations for this business aregenerally dependent upon the volume stored and the level of fees charged to customers.Our Spindletop natural gas storage facility is located in Texas and plays an important role in our ability to act as a full-service natural gas marketer. Thefacility has capacity for residue gas of approximately 12 Bcf. We may lease a portion of the facility’s capacity to third-party customers, and use the balance tomanage relatively constant natural gas supply volumes with uneven demand levels, provide “backup” service to our customers and support our asset basedtrading activities. Our asset based trading activities are designed to realize margins related to fluctuations in commodity prices, time spreads and basisdifferentials and to maximize the value of our storage facility.Wholesale PropaneWe operate a wholesale propane logistics business in the mid-Atlantic, upper Midwest and Northeastern United States. We purchase large volumes ofpropane supply from fractionation facilities and crude oil refineries, primarily located in the Marcellus/Utica area, Canada and other international sources,and transport these volumes of propane supply by pipeline, rail or ship to our terminals and storage facilities. We primarily sell propane on a wholesale basisto propane distributors under annual sales agreements who in turn resell propane to their customers. Our operations include one owned marine terminal, fiveowned propane rail terminals and one joint venture rail terminal, with access to several open access pipeline terminals.The wholesale propane marketing business is significantly impacted by seasonal and weather-driven demand, particularly in the winter, which canimpact the price and volume of propane sold in the markets we serve.Trading and MarketingOur energy trading operations are exposed to market variables and commodity price risk. We manage commodity price risk related to our natural gasstorage and pipeline assets by engaging in natural gas asset based trading and marketing. We may enter into physical contracts and financial instruments withthe objective of realizing a positive margin from the purchase and sale of commodity-based instruments.Our NGL proprietary trading activity includes trading energy related products and services. We undertake these activities through the use of fixedforward sales and purchases, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. These energy tradingoperations are exposed to market variables and commodity price risk with respect to these products and services, and these operations may enter into physicalcontracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments.We may execute a time spread transaction when the difference between the current price of natural gas (cash or futures) and the futures market price fornatural gas exceeds our cost of storing physical gas in our owned and/or leased storage facilities. The time spread transaction allows us to lock in a marginwhen this market condition exists. A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equalshort gas position at a different point in time.We may execute basis spread transactions when the market price differential between locations on a pipeline asset exceeds our cost of transportingphysical gas through our owned and/or leased pipeline asset. When this market condition exists, we may execute derivative instruments around thisdifferential at the market price. This basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas.6Customers and ContractsWe sell our commodities to a variety of customers ranging from large, multi-national petrochemical and refining companies to small regional retailpropane distributors. Substantially all of our NGL sales are made at market-based prices.CompetitionThe Logistics and Marketing business is highly competitive in our markets and includes interstate and intrastate pipelines, integrated oil and gascompanies that produce, fractionate, transport, store and sell natural gas and NGLs, and underground storage facilities. Competition is often the greatest ingeographic areas experiencing robust drilling by producers and strong petrochemical demand and during periods of high NGL prices relative to naturalgas. Competition is also increased in those geographic areas where our contracts with our customers are shorter term and therefore must be renegotiated on amore frequent basis.Competition in the NGLs marketing area comes from other midstream NGL marketing companies, international producers/traders, chemical companies,refineries and other asset owners. Along with numerous marketing competitors, we offer price risk management and other services. We believe it is importantthat we tailor our services to the end-use customer to remain competitive.Gathering and Processing SegmentGeneralOur Gathering and Processing segment consists of a geographically diverse complement of assets and ownership interests that provide a varied array ofwellhead to market services for our producer customers in Alabama, Colorado, Kansas, Louisiana, Michigan, New Mexico, Oklahoma, Texas and Wyoming.These services include gathering, compressing, treating, and processing natural gas, producing and fractionating NGLs, and recovering condensate. OurGathering and Processing segment’s operations are organized into four regions: North, Permian, Midcontinent and South. Our geographic diversity helps tomitigate our natural gas supply risk in that we are not tied to one natural gas resource type or producing area. We believe our current geographic mix of assetsis an important factor for maintaining and growing overall volumes and cash flow for this segment. Our assets are positioned in certain areas with activedrilling programs and opportunities for organic growth.We provide our producer customers with gathering and processing services that allow them to move their raw (unprocessed) natural gas to market. Rawnatural gas is gathered, compressed and transported through pipelines to our processing facilities. In order for the raw natural gas to be accepted by thedownstream market, we remove water, nitrogen and carbon dioxide and separate NGLs for further processing. Processed natural gas, usually referred to asresidue natural gas, is then recompressed and delivered to natural gas pipelines and end users. The separated NGLs are in a mixed, unfractionated form and aresold and delivered through natural gas liquids pipelines to fractionation facilities for further separation.We own or operate 49 active natural gas processing plants and an interest in one additional plant through our 40% equity interest in DiscoveryProducer Services, LLC, or Discovery. At some of these facilities, we fractionate NGLs into individual components (ethane, propane, butane and naturalgasoline).We receive natural gas from a diverse group of producers under contracts with varying durations, and we receive fees or commodities from theproducers to transport the natural gas from the wellhead to the processing plant. We receive fees or commodities as payment for our natural gas processingservices, depending on the types of contracts we enter into with each supplier. We purchase or take custody of substantially all of our natural gas fromproducers, principally under fee-based or percent-of-proceeds/index processing contracts.We actively seek new producing customers of natural gas on all of our systems to increase throughput volume and to offset natural declines in theproduction from connected wells. We obtain new natural gas supplies in our operating areas by contracting for production from new wells, by connectingnew wells drilled on dedicated acreage and by obtaining natural gas that has been directly received or released from other gathering systems.Our contracts with our producing customers in our Gathering and Processing segment are a mix of non-commodity sensitive fee-based contracts andcommodity sensitive percent-of-proceeds and percent-of-liquids contracts. Percent-of-proceeds contracts are directly related to the price of natural gas, NGLsand condensate and percent-of-liquids contracts are directly related to the price of NGLs and condensate. Additionally, these contracts may include fee-basedcomponents. Generally, the initial term of these purchase agreements is three to five years and in some cases, the life of the lease. As we negotiate newagreements and renegotiate existing agreements, this may result in a change in contract mix period over period.7We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with ourgathering, processing and sales activities, thereby stabilizing our cash flows. Our commodity derivative instruments used for our hedging program are acombination of direct NGL product, crude oil, and natural gas hedges.During 2018, total wellhead volume on our assets was approximately 4.8 Bcf/d, originating from a diversified mix of customers. Our systems each havesignificant customer acreage dedications that we expect will continue to provide opportunities for growth as those customers execute their drilling plans overtime. Our gathering systems also attract new natural gas volumes through numerous smaller acreage dedications and by contracting with undedicatedproducers who are operating in or around our gathering footprint. During 2018, the combined NGL production from our processing facilities wasapproximately 413 MBbls/d and was delivered and sold into various NGL takeaway pipelines.The following is operating data for our Gathering and Processing segment by region:Operating Data Year ended December 31, 2018Regions Plants ApproximateGatheringand TransmissionSystems (Miles) ApproximateNet Nameplate PlantCapacity(MMcf/d) (a) Natural GasWellhead Volume(MMcf/d) (a) NGLProduction(MBbls/d) (a)North 13 4,000 1,390 1,253 94Permian 11 16,500 1,260 901 107Midcontinent 12 29,000 1,765 1,301 109South 13 7,500 2,315 1,314 103Total 49 57,000 6,730 4,769 413(a) Represents total capacity or total volumes allocated to our proportionate ownership share.8North RegionOur North region primarily consists of our DJ Basin system. We have a broad network of gathering and processing facilities in Weld County, Coloradothat provide significant optionality and flexibility.We are constructing a new up to 300 MMcf/d natural gas processing facility, O'Connor 2. The 200 MMcf/d O'Connor 2 processing plant is expected tobe placed into service at the end of the second quarter of 2019 and the up to 100 MMcf/d O'Connor 2 bypass is expected to be in service in the third quarterof 2019. We have secured land and filed permits for our Bighorn natural gas processing program with a capacity of up to 1 Bcf/d, which is expected to beplaced into service in phases with an initial in-service date in the second quarter of 2020. These plants will increase capacity to support the growingprocessing needs of producers in the DJ Basin.Our DJ Basin system delivers to the Mont Belvieu hub in Mont Belvieu, Texas via the Front Range and Texas Express pipelines, owned 33.33% and10% by us, respectively, and to the Conway hub in Bushton, Kansas via our Wattenberg pipeline in our Logistics and Marketing segment. We are addingadditional NGL takeaway for our producer customers through our expansions of the Texas Express and Front Range pipelines, and the extension of ourSouthern Hills pipeline into the DJ Basin via the White Cliffs pipeline.9Permian RegionOur Permian region primarily includes our West Texas system in the Midland Basin and our Southeast New Mexico system in the Delaware Basin.Producers continue to focus drilling activity on the most attractive acreage in the Midland and Delaware Basins. Our gathering and processing assets in thePermian region provide NGL takeaway service via our Sand Hills pipeline, to fractionation facilities along the Gulf Coast and to the Mont Belvieu hub. Weare adding additional gas takeaway in the region through our participation in the construction of the Gulf Coast Express Pipeline, which is owned 25% by us,35% by Kinder Morgan Texas Pipeline, Inc, 25% by Targa Resources Corp, and 15% by Altus Midstream, LP.10Midcontinent RegionOur Midcontinent region primarily includes our Liberal system, Panhandle system, and South Central Oklahoma system. We gather and process rawnatural gas primarily from the Ardmore and Anadarko Basins, including the South Central Oklahoma Oil Province (“SCOOP”) play and the Sooner TrendAnadarko Basin Canadian and Kingfisher (“STACK”) play.Existing production in the western Midcontinent region, which includes our Liberal and Panhandle systems, is typically from mature fields withshallow decline profiles that we expect will provide our plants with a dependable source of raw natural gas over a long term. We believe the infrastructure ofour plants and gathering facilities is uniquely positioned to pursue our consolidation strategy in the western Midcontinent region. Our gathering systemfootprint in the eastern Midcontinent region, which includes our South Central Oklahoma system, serves the SCOOP and STACK plays.Our gathering and processing assets in the Midcontinent region deliver NGLs primarily to the Gulf Coast and Mont Belvieu via our Southern Hillspipeline.11South RegionOur South region primarily includes our Eagle Ford system, East Texas system, and our 40% interest in the Discovery system. We are pursuing costefficiencies and increasing the utilization of our existing assets.Our Eagle Ford system delivers NGLs to the Gulf Coast petrochemical markets and to Mont Belvieu through our Sand Hills pipeline and other thirdparty NGL pipelines. Our East Texas system provides NGL takeaway service through the Panola pipeline, owned 15% by us, and delivers gas primarilythrough its Carthage Hub which delivers residue gas to multiple interstate and intrastate pipelines.The Discovery system is operated by Williams Partners L.P., which owns a 60% interest, and offers a full range of wellhead-to-market services to bothonshore and offshore natural gas producers. The assets are primarily located in the eastern Gulf of Mexico and Louisiana, and have access to downstreampipelines and markets.12CompetitionWe face strong competition in acquiring raw natural gas supplies. Our competitors in obtaining additional gas supplies and in gathering and processingraw natural gas includes major integrated oil and gas companies, interstate and intrastate pipelines, and companies that gather, compress, treat, process,transport, store and/or market natural gas. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periodsof high commodity prices for crude oil, natural gas and/or NGLs. Competition is also increased in those geographic areas where our commercial contractswith our customers are shorter term and therefore must be renegotiated on a more frequent basis.We have no revenue attributable to international activities.REGULATORY AND ENVIRONMENTAL MATTERSSafety and Maintenance RegulationWe are subject to regulation by the United States Department of Transportation, or DOT, under the Hazardous Liquids Pipeline Safety Act of 1979, asamended, or HLPSA, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management ofpipeline facilities. HLPSA applies to interstate and intrastate pipeline facilities and the pipeline transportation of liquid petroleum and petroleum products,including NGLs and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to andcopying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations includepotential fines and penalties for violations. We believe that we are in compliance in all material respects with these HLPSA regulations.We are also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, or NGPSA, and the Pipeline Safety Improvement Act of 2002. TheNGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities while the Pipeline Safety ImprovementAct establishes mandatory inspections for all United States oil and natural gas transportation pipelines in high-consequence areas within 10 years. DOT,through the Pipeline and Hazardous Materials Safety Administration (PHMSA), has developed regulations implementing the Pipeline Safety ImprovementAct that requires pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areaswhere the consequences of potential pipeline accidents pose the greatest risk to people and their property.Pipeline safety legislation enacted in 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, (the Pipeline Safety and JobCreations Act) reauthorized funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safetyrequirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements forexisting pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems,sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incidentnotification, and other pipeline-safety related requirements. New rules proposed by DOT’s PHMSA address many areas of this legislation. Extending theintegrity management requirements to our gathering lines would impose additional obligations on us and could add material cost to our operations.The Pipeline Safety and Job Creation Act requires more stringent oversight of pipelines and increased civil penalties for violations of pipeline safetyrules. The legislation gives PHMSA civil penalty authority up to $213,268 per day per violation, with a maximum of $2,132,679 for any related series ofviolations. Any material penalties or fines under these or other statutes, rules, regulations or orders could have a material adverse impact on our business,financial condition, results of operation and cash flows.We currently estimate we will incur approximately $55 million between 2019 and 2023 to implement integrity management program testing alongcertain segments of our natural gas transmission and NGL pipelines. We believe that we are in compliance in all material respects with the NGPSA and thePipeline Safety Improvement Act of 2002 and the Pipeline Safety and Job Creation Act.States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing intrastate pipeline regulations atleast as stringent as the federal standards. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipateany significant problems in complying with applicable state laws and regulations in those states in which we or the entities in which we own an interestoperate. Our natural gas transmission and regulated gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities incompliance with pipeline safety and pollution control requirements.In addition, we are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whosepurpose is to protect the health and safety of workers, both generally and within the pipeline13industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency, or EPA, community right-to-know regulations underTitle III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerninghazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities andcitizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management and EPA Risk Management Programregulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. TheOSHA regulations apply to any process that involves a chemical at or above specified thresholds, or any process that involves flammable liquid or gas,pressurized tanks, caverns and wells holding or handling these materials in quantities in excess of 10,000 pounds at various locations. Flammable liquidsstored in atmospheric tanks at temperatures below the normal boiling point of the liquids without the benefit of chilling or refrigeration are exempt fromthese standards. The EPA regulations have similar applicability thresholds. We have an internal program of inspection designed to monitor and enforcecompliance with worker safety requirements. We believe that we are in compliance in all material respects with all applicable laws and regulations relating toworker health and safety.Propane RegulationNational Fire Protection Association Codes No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, orcomparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states these laws are administered bystate agencies, and in others they are administered on a municipal level. The transportation of propane by rail is regulated by the Federal RailroadAdministration. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We maintainvarious permits that are necessary to operate our facilities, some of which may be material to our propane operations. We believe that the procedures currentlyin effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in compliance in allmaterial respects with applicable laws and regulations.FERC and State Regulation of OperationsFederal Energy Regulatory Commission ("FERC") regulation of interstate natural gas pipelines, the marketing and sale of natural gas in interstatecommerce and the transportation of NGLs in interstate commerce may affect certain aspects of our business and the market for our products and services.Regulation of gathering systems and intrastate transportation of natural gas and NGLs by state agencies may also affect our business.Interstate Natural Gas Pipeline RegulationOur Cimarron River, Discovery, and Dauphin Island Gathering Partners systems, or portions thereof, are some of our natural gas pipeline assets that aresubject to regulation by FERC, under the Natural Gas Act of 1938, as amended, or NGA. Natural gas companies subject to the NGA may only charge rates thathave been determined to be just and reasonable. In addition, FERC authority over natural gas companies that provide natural gas pipeline transportationservices in interstate commerce includes:•certification and construction of new facilities;•abandonment of services and facilities;•maintenance of accounts and records;•acquisition and disposition of facilities;•initiation and discontinuation of transportation services;•terms and conditions of transportation services and service contracts with customers;•depreciation and amortization policies;•conduct and relationship with certain affiliates; and•various other matters.Generally, the maximum filed recourse rates for an interstate natural gas pipeline's transportation services are based on the pipeline's cost of serviceincluding recovery of and a return on the pipeline’s actual prudent investment cost. Key determinants in the ratemaking process are costs of providingservice, allowed rate of return and volume throughput and contractual capacity commitment assumptions. The allocation of costs to various pipeline servicesand the manner in which rates are designed also can impact a pipeline's profitability. The maximum applicable recourse rates and terms and conditions forservice are set forth in each pipeline’s FERC-approved gas tariff. FERC-regulated natural gas pipelines are permitted to discount their firm and interruptiblerates without further FERC authorization down to the minimum rate or variable cost of performing service, provided they do not “unduly discriminate.”14Tariff changes can only be implemented upon approval by FERC. Two primary methods are available for changing the rates, terms and conditions ofservice of an interstate natural gas pipeline. Under the first method, the pipeline voluntarily seeks a tariff change by making a tariff filing with FERCjustifying the proposed tariff change and providing notice, generally 30 days, to the appropriate parties. If FERC determines, as required by the NGA, that aproposed change is just and reasonable, FERC will accept the proposed change and the pipeline will implement such change in its tariff. However, if FERCdetermines that a proposed change may not be just and reasonable as required by NGA, then FERC may suspend such change for up to five months beyondthe date on which the change would otherwise go into effect and set the matter for an administrative hearing. Subsequent to any suspension period ordered byFERC, the proposed change may be placed into effect by the company, pending final FERC approval. In most cases, a proposed rate increase is placed intoeffect before a final FERC determination on such rate increase, and the proposed increase is collected subject to refund (plus interest). Under the secondmethod, FERC may, on its own motion or based on a complaint, initiate a proceeding to compel the company to change or justify its rates, terms and/orconditions of service. If FERC determines that the existing rates, terms and/or conditions of service are unjust, unreasonable, unduly discriminatory orpreferential, then any rate reduction or change that it orders generally will be effective prospectively from the date of the FERC order requiring this change.The natural gas industry historically has been heavily regulated; therefore, there is no assurance that a more stringent regulatory approach will not bepursued by FERC and Congress, especially in light of potential market power abuse by marketing companies engaged in interstate commerce. In the EnergyPolicy Act of 2005, or EPACT 2005, Congress amended the NGA and Federal Power Act to add anti-fraud and anti-manipulation requirements. EPACT 2005prohibits the use of any “manipulative or deceptive device or contrivance” in connection with the purchase or sale of natural gas, electric energy ortransportation subject to FERC jurisdiction. FERC adopted market manipulation and market behavior rules to implement the authority granted under EPACT2005. These rules, which prohibit fraud and manipulation in wholesale energy markets, are subject to broad interpretation. Given FERC's broad mandategranted in EPACT 2005, if energy prices are high, or exhibit what FERC deems to be "unusual" trading patterns, FERC may investigate energy markets todetermine if behavior unduly impacted or "manipulated" energy prices.In addition, EPACT 2005 gave FERC increased penalty authority for violations of the NGA and FERC's rules and regulations thereunder. FERC mayissue civil penalties of up to $1 million per day per violation, and violators may be subject to criminal penalties of up to $1 million per violation and fiveyears in prison. FERC may also order disgorgement of profits obtained in violation of FERC rules. FERC relies on its enforcement authority in issuing anumber of natural gas enforcement actions. Failure to comply with the NGA and FERC's rules and regulations thereunder could result in the imposition ofcivil penalties and disgorgement of profits.Intrastate Natural Gas Pipeline RegulationIntrastate natural gas pipeline operations are not generally subject to rate regulation by FERC, but they are subject to regulation by various agencies inthe respective states where they are located. While the regulatory regime varies from state to state, state agencies typically require intrastate gas pipelines toprovide service that is not unduly discriminatory and to file and/or seek approval of their rates with the agencies and permit shippers to challenge existingrates or proposed rate increases. For example, our Guadalupe system is an intrastate pipeline regulated as a gas utility by the Railroad Commission of Texas.To the extent that an intrastate pipeline system transports natural gas in interstate commerce, the rates and terms and conditions of such interstatetransportation service are subject to FERC rules and regulations under Section 311 of the Natural Gas Policy Act, or NGPA. Certain of our systems are subjectto FERC jurisdiction under Section 311 of the NGPA for their interstate transportation services. Section 311 regulates, among other things, the provision oftransportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. Under Section 311,rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. Ratesfor service pursuant to Section 311 of the NGPA are generally subject to review and approval by FERC at least once every five years. Additionally, the termsand conditions of service set forth in the intrastate pipeline’s Statement of Operating Conditions are subject to FERC approval. Non-compliance with FERC'srules and regulations established under Section 311 of the NGPA, including failure to observe the service limitations applicable to transportation servicesprovided under Section 311, failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditionsof service established in the pipeline’s FERC-approved Statement of Operating Conditions could result in the imposition of civil and criminal penalties.Among other matters, EPACT 2005 also amended the NGPA to give FERC authority to impose civil penalties for violations of the NGPA up to $1 million forany one violation and violators may be subject to criminal penalties of up to $1 million per violation and five years in prison.15Gathering Pipeline RegulationSection 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We believe that our natural gasgathering facilities meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, thedistinction between FERC-regulated transmission services and federally unregulated gathering services continues to be a current issue in various FERCproceedings with respect to facilities that interconnect gathering and processing plants with nearby interstate pipelines, so the classification and regulation ofour gathering facilities may be subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generallyincludes various safety, environmental, and, in many circumstances, nondiscriminatory take requirements and complaint-based rate regulation.Our purchasing, gathering and intrastate transportation operations are subject to ratable take and common purchaser statutes in the states in which theyoperate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to thegatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply orproducer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another sourceof supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transportnatural gas.Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels where FERC has recognized a jurisdictional exemptionfor the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulatedaffiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers tofile complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Our gatheringoperations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Additionalrules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might haveon our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative andregulatory changes.Sales of Natural GasThe price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation.However, with regard to our interstate purchases and sales of natural gas, and any related hedging activities that we undertake, we are required to observeanti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission, or CFTC. Should we violatethe anti-market manipulation laws and regulations, in additional to civil and criminal penalties, we could be subject to related third party damage claims by,among others, market participants, sellers, royalty owners and taxing authorities.Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access topipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulationsaffecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC jurisdiction.These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatorychanges is to promote competition among the various sectors of the natural gas industry. We cannot predict the ultimate impact of these regulatory changesto our natural gas marketing operations.Interstate NGL Pipeline RegulationCertain of our pipelines, including Sand Hills and Southern Hills, are common carriers that provide interstate NGL transportation services subject toFERC regulation. FERC regulates interstate common carriers under its Oil Pipeline Regulations, the Interstate Commerce Act of 1887, as amended, or ICA,and the Elkins Act of 1903, as amended. FERC requires that common carriers file tariffs containing all the rates, charges and other terms for services providedby such pipelines. The ICA requires that tariffs apply to the interstate movement of NGLs, as is the case with the Sand Hills, Southern Hills, Black Lake,Wattenberg and Front Range pipelines. Pursuant to the ICA, rates must be just, reasonable, and nondiscriminatory, and can be challenged at FERC either byprotest when they are initially filed or increased or by complaint at any time they remain on file with FERC.In October 1992, Congress passed EPACT, which among other things, required FERC to issue rules establishing a simplified and generally applicableratemaking methodology for pipelines regulated by FERC pursuant to the ICA. FERC responded to this mandate by issuing several orders, including OrderNo. 561 that enables common carrier pipelines to charge rates up to their ceiling levels, which are adjusted annually based on an inflation index. Specifically,the indexing methodology16requires a pipeline to adjust the ceiling level for its rates annually by the inflation index established by the FERC. FERC reviews the indexing methodologyevery five years, and in 2015, the indexing methodology for the five years beginning July 1, 2016 was changed to be the Producer Price Index for FinishedGoods plus 1.23%. Rate increases made pursuant to the indexing methodology are subject to protest, but such protests must show that the portion of the rateincrease resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. If the indexingmethodology results in a reduced ceiling level that is lower than a pipeline’s filed rate, the pipeline is required to reduce its rate to comply with the lowerceiling unless doing so would reduce a rate “grandfathered” under EPACT below the grandfathered level. A pipeline must, as a general rule, utilize theindexing methodology to change its rates. FERC, however, retained cost-of-service ratemaking, market-based rates, and settlement as alternatives to theindexing approach, which alternatives may be used in certain specified circumstances. The ceiling levels calculated for our interstate NGL pipelines aretypically increased each year pursuant to the indexing methodology, but may be subject to decrease, which occurred in 2016 and resulted in the decrease inthe tariff rates for many such pipelines.On October 20, 2016, FERC issued an Advance Notice of Proposed Rulemaking, which presented significant changes to the indexing mechanism andreporting requirements of common carriers subject to FERC’s jurisdiction under the ICA. The proposed changes to the indexing methodology, wouldprohibit an increase in a common carrier’s ceiling level and rates if a complaint was filed and the return as reported by the common carrier in two previousannual reports exceeded a predetermined threshold. Additionally, the FERC proposed multiple changes to its annual reporting requirements. We cannotpredict the outcome of the proceeding, but the proposal, if implemented, could adversely impact future rate increases of our common carriers and placeadditional administration and reporting burdens on our business.Intrastate NGL Pipeline RegulationNGL and other common carrier petroleum pipelines that provide intrastate transportation services are subject to regulation by various agencies in therespective states where they are located. While the regulatory regime varies from state to state, state agencies typically require intrastate petroleum pipelinesto file tariffs and their rates with the agencies and permit shippers to challenge existing rates or proposed rate increases. For example, certain of our pipelineshave tariffs filed with the Railroad Commission of Texas for their intrastate NGL transportation services.Environmental MattersGeneralOur operation of pipelines, plants and other facilities for gathering, compressing, treating, processing, transporting, fractionating, storing or sellingnatural gas, NGLs and other products is subject to stringent and complex federal, state and local laws and regulations governing the emission or discharge ofmaterials into the environment or otherwise relating to the protection of the environment.As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws andregulations can restrict or impact our business activities in many ways, such as:•requiring the acquisition of permits or authorizations to conduct regulated activities and imposing obligations in those permits, potentiallyincluding capital expenditures or operational requirements, that reduce or limit impacts to the environment;•restricting the ways that we can handle or dispose of our wastes;•limiting or prohibiting construction or operational activities in sensitive areas such as wetlands, coastal regions or areas inhabited by threatenedand endangered species;•requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operations; and•enjoining, or compelling changes to, the operations of facilities deemed not to be in compliance with environmental regulations or with permitsissued pursuant to such environmental laws and regulations.Failure to comply with these laws and regulations may trigger a variety of administrative, civil, or potentially criminal enforcement measures, includingthe assessment of monetary penalties, the imposition of remedial requirements, potential citizen lawsuits, and the issuance of orders enjoining or affectingfuture operations. Certain environmental statutes impose strict liability or joint and several liability for costs required to clean up and restore sites wherehazardous substances, or in some cases hydrocarbons, have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landownersand other third parties to file claims for property damage or personal injury allegedly caused by the release of substances or other waste products into theenvironment.The overall trend in federal and state environmental programs is to expand regulatory requirements, placing more restrictions and limitations onactivities that may affect the environment. Thus, there can be no assurance as to the amount or17timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currentlyanticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changingenvironmental laws and regulations, participate as applicable in the public process to ensure such new requirements are well founded and reasonable or torevise them if they are not, and to manage the costs of such compliance. We also actively participate in industry groups that help formulate recommendationsfor addressing existing or future regulations.We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business,financial position or results of operations. Below is a discussion of the more significant environmental laws and regulations that relate to our business.Impact of Air Quality Standards and Climate ChangeA number of states have adopted or considered programs to reduce “greenhouse gases,” or GHGs, which can include methane, and, depending on theparticular program or jurisdiction, we could be required to purchase and surrender allowances, either for GHG emissions resulting from our operations (e.g.,compressor units) or from downstream combustion of fuels (e.g., oil or natural gas) that we process, or we may otherwise be required by regulation to takesteps to reduce emissions of GHGs. Also, the EPA has declared that GHGs “endanger” public health and welfare, and is regulating GHG emissions frommobile sources such as cars and trucks. The EPA's 2010 action on the GHG vehicle emission rule triggered regulation of carbon dioxide and other GHGemissions from stationary sources under certain Clean Air Act programs at both the federal and state levels, including the Prevention of SignificantDeterioration (“PSD”) program and Title V permitting. In 2016 EPA proposed a rule to revise the PSD and Title V permitting regulations applicable to GHGsin response to a 2014 U.S. Supreme Court decision and subsequent D.C. Circuit decision striking down its 2011 rules. The proposed revisions required thatmajor sources of non-GHG air pollutants, such as volatile organic compounds or nitrogen oxides, which also emit 100,000 tons per year or more of CO2equivalent (or modifications of these sources that result in an increase of emissions of 75,000 tons per year or more of CO2 equivalent), obtain permitsaddressing emissions of greenhouse gases. The EPA has not acted to finalize this proposed rule. The EPA also has published various rules relating to themandatory reporting of GHG emissions, including mandatory reporting requirements of GHGs from petroleum and natural gas systems. In October 2015, theEPA amended and expanded greenhouse gas reporting requirements to all segments of the oil and gas sector starting with the 2016 reporting year. In June2016, the EPA published final new source performance standards (“NSPS”) for methane (a greenhouse gas) from new and modified oil and gas sector sources.These regulations expand upon the 2012 EPA rulemaking for oil and gas equipment-specific emissions controls, for example, regulating well headproduction emissions with leak detection and repair requirements, pneumatic controllers and pumps requirements, compressor requirements, and institutingleak detection and repair requirements for natural gas compressor and booster stations for the first time. In June 2017, EPA published a proposed rule to staycertain requirements of the 2016 NSPS rule for two years while it completes reconsideration of certain aspects of the rule and reviews the entire rule, and inOctober 2018 EPA published proposed revisions to the NSPS regulation for methane. In October 2015, the EPA finalized a reduction of the ambient ozonestandard from 75 parts per billion to 70 parts per billion under the Clean Air Act, and in December 2018 EPA published a final rule "Implementation of the2015 National Ambient Air Quality Standards for Ozone: Nonattainment Area State Implementation Plan Requirements." The 2015 Ozone standard is beinglitigated in the U.S. Circuit Court of Appeals for the District of Columbia. The EPA in October 2016 issued Control Techniques Guidelines for emissions ofvolatile organic compounds from oil and gas sector sources that were to be implemented or utilized by states in ozone nonattainment areas, with an expectedco-benefit of reduced methane emissions, and in March 2018 EPA published a proposal to withdraw the Control Techniques Guidelines. The permitting,regulatory compliance and reporting programs, taken as a whole, increase the costs and complexity of oil and gas operations with potential to adverselyaffect the cost of doing business for our customers resulting in reduced demand for our gas processing and transportation services, and which may also requireus to incur certain capital and operating expenditures in the future to meet regulatory requirements or for air pollution control equipment, for example, inconnection with obtaining and maintaining operating permits and approvals for air emissions associated with our facilities and operations.Hazardous Substances and WasteOur operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, or solid or hazardouswastes, or petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste,and may impose strict liability or joint and several liability for the investigation and remediation of areas at a facility where hazardous substances, or in somecases hydrocarbons, may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, asamended, or CERCLA, also known as the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the originalconduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include current and priorowners or operators of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at thesite. Under CERCLA, these persons may be18subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages tonatural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threatsto the public health or the environment and to seek to recover from the responsible parties the costs that the agency incurs. Despite the “petroleum exclusion”of CERCLA Section 101(14), which encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similarstate statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs requiredto clean up sites at which these hazardous substances have been released into the environment.We also generate solid wastes, including hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, asamended, or RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation,storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum and natural gas production wastes are excluded from RCRA’shazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, may in thefuture be designated by the EPA as hazardous wastes and therefore be subject to more rigorous and costly disposal requirements. Any such changes in thelaws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.We currently own or lease properties where petroleum hydrocarbons are being or have been handled for many years. Although we have utilizedoperating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or other wastes may have been disposed of or releasedon or under the properties owned or leased by us, or on or under the other locations where these petroleum hydrocarbons and wastes have been taken fortreatment or disposal. In addition, certain of these properties may have been operated by third parties whose treatment and disposal or release of petroleumhydrocarbons or other wastes was not under our control. These properties and wastes disposed or released thereon may be subject to CERCLA, RCRA andanalogous state laws, or separate state laws that address hydrocarbon releases. Under these laws, we could be required to remove or remediate releases ofhydrocarbon materials, or previously disposed wastes (including wastes disposed of or released by prior owners or operators), or to clean up contaminatedproperty (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts,events or conditions relating to the application of such requirements that could reasonably have a material impact on our financial condition or results ofoperations.WaterThe Federal Water Pollution Control Act of 1972, as amended, also referred to as the Clean Water Act, or CWA, and analogous state laws imposerestrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the CWA and analogous state laws, permits must beobtained to discharge pollutants into state and federal waters. The CWA also requires implementation of spill prevention, control and countermeasure plans,also referred to as "SPCC plans," in connection with on-site storage of threshold quantities of oil or certain other materials. The CWA imposes substantialpotential civil and criminal penalties for non-compliance. State laws for the control of water pollution also provide varying administrative, civil andpotentially criminal penalties and liabilities. In addition, some states maintain groundwater protection programs that require permits for discharges oroperations that may impact groundwater. The EPA has also promulgated regulations that require us to have permits in order to discharge certain storm water.The EPA has entered into agreements with certain states in which we operate whereby the permits are issued and administered by the respective states. Thesepermits may require us to monitor and sample the storm water discharges. We believe that compliance with existing permits and compliance with foreseeablenew permit requirements will not have a material adverse effect on our financial condition or results of operations.The Oil Pollution Act of 1990, or OPA, which is part of the Clean Water Act, addresses prevention, containment and cleanup, and liability associatedwith oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities, including natural gas gathering and processing facilities, terminals,pipelines, and transfer facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages, andcertain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum or other pollutants from our operations could resultin government penalties and civil liability. We are not currently aware of any facts, events or conditions relating to the application of such requirements thatcould reasonably have a material impact on our financial condition or results of operations.Anti-Terrorism MeasuresThe federal Department of Homeland Security regulates the security of chemical and industrial facilities pursuant to regulations known as the ChemicalFacility Anti-Terrorism Standards. These regulations apply to oil and gas facilities, among others, that are deemed to present “high levels of securityrisk.” Pursuant to these regulations, certain of our facilities are required19to comply with certain regulatory provisions, including requirements regarding inspections, audits, recordkeeping, and protection of chemical-terrorismvulnerability information.EmployeesWe do not have any employees. Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which is managed by itsgeneral partner, DCP Midstream GP, LLC, (the "General Partner"), which is 100% owned by DCP Midstream, LLC. As of December 31, 2018, approximately2,650 employees of DCP Services, LLC, a wholly-owned subsidiary of DCP Midstream, LLC, provided support for our operations pursuant to the Servicesand Employee Secondment Agreement between DCP Services, LLC and us (the "Services Agreement"). For additional information, refer to Item 10."Directors, Executive Officers and Corporate Governance” and Item 13. "Certain Relationships and Related Transactions, and Director Independence" in thisAnnual Report on Form 10-K.GeneralWe make certain filings with the Securities and Exchange Commission ("SEC"), including our annual report on Form 10-K, quarterly reports onForm 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports, which are available free of charge through our website,www.dcpmidstream.com, as soon as reasonably practicable after they are filed with the SEC. Our website and the information contained on that site, orconnected to that site, are not incorporated by reference into this report. Also, these filings are available on the internet at www.sec.gov. Our annual reports tounitholders, press releases and recent analyst presentations are also available on our website. We have also posted our code of business ethics on our website.Item 1A. Risk FactorsLimited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject aresimilar to those that would be faced by a corporation engaged in similar businesses. You should consider carefully the following risk factors together withall of the other information included in this Annual Report on Form 10-K for the year ended December 31, 2018 in evaluating an investment in our commonunits.If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially affected. In that case,we might not be able to pay distributions on our units, the trading price of our units could decline and you could lose all or part of your investment.Risks Related to Our Business Our cash flow is affected by natural gas, NGL and crude oil prices.Our business is affected by natural gas, NGL and crude oil prices. In the past, the prices of natural gas, NGLs and crude oil have been volatile, and weexpect this volatility to continue.The level of drilling activity is dependent on economic and business factors beyond our control. Among the factors that impact drilling decisions arecommodity prices, the liquids content of the natural gas production, drilling requirements for producers to hold leases, the cost of finding and producingnatural gas and crude oil and the general condition of the financial markets. Commodity prices experienced volatility during 2018, as illustrated by thefollowing table: Year EndedDecember 31, 2018 December 31, 2018 Daily High Daily Low Commodity: NYMEX Natural Gas ($/MMBtu) $4.84 $2.55 $2.94NGLs ($/Gallon) $0.99 $0.53 $0.55Crude Oil ($/Bbl) $76.41 $42.53 $45.41Market conditions, including commodity prices, may impact our earnings, financial condition and cash flows.The markets and prices for natural gas, NGLs, condensate and crude oil depend upon factors beyond our control and may not always have a closerelationship. These factors include supply of and demand for these commodities, which fluctuate with changes in domestic and export markets and economicconditions and other factors, including:•the level of domestic and offshore production;20•the availability of natural gas, NGLs and crude oil and the demand in the U.S. and globally for these commodities;•a general downturn in economic conditions;•the impact of weather, including abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes,respectively, or extreme weather that may disrupt our operations or related upstream or downstream operations;•actions taken by foreign oil and gas producing and importing nations;•the availability of local, intrastate and interstate transportation systems and condensate and NGL export facilities;•the availability and marketing of competitive fuels; and•the extent of governmental regulation and taxation.The primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. Underpercent-of-proceeds arrangements, we generally purchase natural gas from producers for an agreed percentage of the proceeds from the sale of residue gasand/or NGLs resulting from our processing activities, and then sell the resulting residue gas and NGLs at market prices. Under these types of arrangements,our revenues and our cash flows increase or decrease, whichever is applicable, as the price of natural gas and NGLs fluctuate.The amount of natural gas we gather, compress, treat, process, transport, store and sell, or the NGLs we produce, fractionate, transport, store and sell, maybe reduced if the pipelines, storage and fractionation facilities to which we deliver the natural gas or NGLs are capacity constrained and cannot, or willnot, accept the natural gas or NGLs or we may be required to find alternative markets and arrangements for our natural gas and NGLs.The natural gas we gather, compress, treat, process, transport, sell and store, or the NGLs we produce, fractionate, transport, sell and store, are deliveredinto pipelines for further delivery to end-users, including fractionation facilities. If these pipelines, storage and fractionation facilities cannot, or will not,accept delivery of the gas or NGLs due to capacity constraints or changes in interstate pipeline gas quality specifications, we may be forced to limit or stopthe flow of gas or NGLs through our pipelines and processing, treating, and fractionation facilities. We have long and short-term arrangements with facilitiesto fractionate our NGL production; however, additional fractionation capacity may be limited to the extent current and planned fractionation facilitiesexperience delays in construction, significant mechanical or other problems arise at existing facilities, or such facilities otherwise become unavailable to usdue to unforeseen circumstances. As a result, we may be required to find alternative markets and arrangements for our production and for fractionation, andsuch alternative markets and arrangements may not be available on favorable terms, or at all. Additionally, capacity constraints may impact productionvolumes from our producer customers and/or transportation volumes from our third-party NGL customers if there is insufficient fractionation or storagecapacity to handle all of their projected volumes. Any number of factors beyond our control could cause such interruptions or constraints, including fullyutilized capacity, necessary and scheduled maintenance, or unexpected damage to the pipelines. Because our revenues and net operating margins dependupon (i) the volumes of natural gas we process, gather and transmit, (ii) the throughput of NGLs through our transportation, fractionation and storage facilitiesand (iii) the volume of natural gas we gather and transport, any reduction of volumes could adversely affect our operations and cash flows available fordistribution to our unitholders.Our NGL pipelines could be adversely affected by any decrease in NGL prices relative to the price of natural gas.The profitability of our NGL pipelines is dependent on the level of production of NGLs from processing plants. When natural gas prices are high relativeto NGL prices, it is less profitable to process natural gas because of the higher value of natural gas compared to the value of NGLs and because of theincreased cost (principally that of natural gas as a feedstock and fuel) of separating the NGLs from the natural gas. As a result, we may experience periods inwhich higher natural gas prices relative to NGL prices reduce the volume of natural gas processed at plants connected to our NGL pipelines, as well asreducing the amount of NGL extraction, which would reduce the volumes and gross margins attributable to our NGL pipelines and NGL storage facilities.Our hedging activities and the application of fair value measurements may have a material adverse effect on our earnings, profitability, cash flows,liquidity and financial condition.We are exposed to risks associated with fluctuations in commodity prices. The extent of our commodity price risk is related largely to the effectivenessand scope of our hedging activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly fromthe actual natural gas, NGL and condensate prices that we realize in our operations. To mitigate a portion of our cash flow exposure to fluctuations in theprice of natural gas and NGLs, we have entered into derivative financial instruments relating to the future price of natural gas and NGLs, as well as crude oil.Furthermore, we have entered into derivative transactions related to only a portion of the volume of our expected natural gas supply and production of NGLsand condensate from our processing plants; as a result, we will continue to have direct21commodity price risk to the portion not covered by derivative transactions. Our actual future production may be significantly higher or lower than weestimate at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimate, we will have greatercommodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might beforced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity,reducing our liquidity.We record all of our derivative financial instruments at fair value on our balance sheet primarily using information readily observable within themarketplace. In situations where market observable information is not available, we may use a variety of data points that are market observable, or in certaininstances, develop our own expectation of fair value. We will continue to use market observable information as the basis for our fair value calculations;however, there is no assurance that such information will continue to be available in the future. In such instances, we may be required to exercise a higherlevel of judgment in developing our own expectation of fair value, which may be significantly different from the historical fair values, and may increase thevolatility of our earnings.We will continue to evaluate whether to enter into any new derivative arrangements, but there can be no assurance that we will enter into any newderivative arrangement or that our future derivative arrangements will be on terms similar to our existing derivative arrangements. Additionally, although weenter into derivative instruments to mitigate a portion of our commodity price risk, we also forego the benefits we would otherwise experience if commodityprices were to change in our favor.Our derivative instruments may require us to post collateral based on predetermined collateral thresholds. Depending on the movement in commodityprices, the amount of posted collateral required may increase, reducing our liquidity.Our hedging activities may not be as effective as we intend and may actually increase the volatility of our earnings and cash flows. In addition, eventhough our management monitors our hedging activities, these activities can result in material losses. Such losses could occur under various circumstances,including if a counterparty does not or is unable to perform its obligations under the applicable derivative arrangement, the derivative arrangement isimperfect or ineffective, or our risk management policies and procedures are not properly followed or do not work as planned.We could incur losses due to impairment in the carrying value of our goodwill or long-lived assets.We periodically evaluate goodwill and long-lived assets for impairment. Our impairment analyses for long-lived assets require management to applyjudgment in evaluating whether events and circumstances are present that indicate an impairment may have occurred. If we believe an impairment may haveoccurred judgments are then applied in estimating future cash flows as well as asset fair values, including forecasting useful lives of the assets, assessing theprobability of different outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. To perform the impairment assessment forgoodwill, we primarily use a discounted cash flow analysis, supplemented by a market approach analysis. Key assumptions in the analysis include the use ofan appropriate discount rate, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs.In estimating cash flows, we incorporate current market information (including forecasted volumes and commodity prices), as well as historical and otherfactors. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may beexposed to impairment charges. Adverse changes in our business or the overall operating environment, such as lower commodity prices, may affect ourestimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.A reduction in demand for NGL products by the petrochemical, refining or other industries or by the fuel markets could materially adversely affect ourresults of operations and financial condition. The NGL products we produce have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reductionin demand for NGL products, whether because of general or industry specific economic conditions, new government regulations, global competition, reduceddemand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobileand construction industries), increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGLapplications or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services.22Volumes of natural gas dedicated to our systems in the future may be less than we anticipate.If the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas, then thevolumes of natural gas on our systems in the future could be less than we anticipate.We depend on certain natural gas producer customers for a significant portion of our supply of natural gas and NGLs.We identify as primary natural gas suppliers those suppliers individually representing 10% or more of our total natural gas and NGLs supply. We have nonatural gas supplier representing 10% or more of our total natural gas supply as of December 31, 2018. While some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. The loss of all or even a portion ofthe natural gas and NGL volumes supplied by these customers, as a result of competition or otherwise, could have a material adverse effect on our business.Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of supplies of natural gas andNGLs.Our gathering and transportation pipeline systems are connected to or dependent on the level of production from natural gas and crude wells, from whichproduction will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increasethroughput levels on our gathering and transportation pipeline systems and NGL pipelines and the asset utilization rates at our natural gas processing plants,we must continually obtain new supplies. The primary factors affecting our ability to obtain new supplies of natural gas and NGLs, and to attract newcustomers to our assets include the level of successful drilling activity near these assets, the demand for natural gas, crude oil and NGLs, producers’ desire andability to obtain necessary permits in an efficient manner, natural gas field characteristics and production performance, surface access and infrastructureissues, and our ability to compete for volumes from successful new wells. If we are not able to obtain new supplies of natural gas to replace the natural declinein volumes from existing wells or because of competition, throughput on our pipelines and the utilization rates of our treating and processing facilities woulddecline, which could have a material adverse effect on our business, results of operations, financial position and cash flows, and our ability to make cashdistributions.Third party pipelines and other facilities interconnected to our natural gas and NGL pipelines and facilities may become unavailable to transport, processor produce natural gas and NGLs.We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of ourcustomers. Since we do not own or operate any of these third-party pipelines or other facilities, their continuing operation is not within our control and maybecome unavailable to transport, process or produce natural gas and NGLs. If any of these third parties do not continue operation of these facilities or theybecome unavailable to us, and we are not able to obtain new facilities to transport, process or produce natural gas and NGLs, it could have a material adverseeffect on our business, results of operations, financial position and cash flows, and our ability to make cash distributions.We may not successfully balance our purchases and sales of natural gas.We purchase from producers and other customers a substantial amount of the natural gas that flows through our natural gas gathering, processing andtransportation systems for resale to third parties, including natural gas marketers and end-users. We may not be successful in balancing our purchases andsales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less thancontracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. While we attempt to balance our purchases and sales, if ourpurchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating incomeand cash flows.Our ability to manage and grow our business effectively could be adversely affected if we or DCP Midstream, LLC and its subsidiaries fail to attract andretain key management personnel and skilled employees.We rely on our executive management team to manage our day-to-day affairs and establish and execute our strategic business and operational plans. Thisexecutive management team has significant experience in the midstream energy industry. The loss of any of our executives or the failure to fill new positionscreated by expansion, turnover or retirement could adversely affect our ability to implement our business strategy. In addition, our operations requireengineers, operational and field technicians and other highly skilled employees. Competition for experienced executives and skilled employees is intenseand increases when the demand from other energy companies for such personnel is high. Our ability to execute on our business23strategy and to grow or continue our level of service to our current customers may be impaired and our business may be adversely impacted if we or DCPMidstream, LLC and its subsidiaries are unable to attract, train and retain such personnel, which may have an adverse effect on our results of operations andability to make cash distributions.A downgrade of our credit rating could impact our liquidity, access to capital and our costs of doing business, and independent third parties determine ourcredit ratings outside of our control.A downgrade of our credit rating could increase our cost of borrowing under our Credit Agreement and could require us to post collateral with thirdparties, including our hedging arrangements, which could negatively impact our available liquidity and increase our cost of debt.Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limitedto, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industrysectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold oursecurities, although such credit ratings may affect the market value of our debt instruments. Ratings are subject to revision or withdrawal at any time by theratings agencies.Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.We continue to have the ability to incur additional debt, subject to limitations within our Credit Agreement. Our level of debt could have importantconsequences to us, including the following:•our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impairedor such financing may not be available on favorable terms;•an increased amount of cash flow will be required to make interest payments on our debt;•our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and•our debt level may limit our flexibility in responding to changing business and economic conditions.Our ability to obtain new debt funding or service our existing debt will depend upon, among other things, our future financial and operatingperformance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, in addition to market interestrates. If our operating results are not sufficient to service our current or future indebtedness, we may take actions such as reducing distributions, reducing ordelaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additionalequity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.Restrictions in our debt agreements may limit our ability to make distributions to unitholders and may limit our ability to capitalize on acquisitions andother business opportunities.Our debt agreements contain covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments ordispositions and engage in transactions with affiliates. Furthermore, our Credit Agreement contains covenants requiring us to maintain a certain leverageratio and meet certain other tests. Any subsequent replacement of our debt agreements or any new indebtedness could have similar or greater restrictions. Ifour covenants are not met, whether as a result of reduced production levels of natural gas and NGLs as described above or otherwise, our financial condition,results of operations and ability to make distributions to our unitholders could be materially adversely affected.Changes in interest rates may adversely impact our ability to issue additional equity or incur debt, as well as the ability of exploration and productioncompanies to finance new drilling programs around our systems.Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used byinvestors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positiveor negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could impair our ability to issueadditional equity or incur debt to make acquisitions, for other purposes. Increased interest costs could also inhibit the financing of new capital drillingprograms by exploration and production companies served by our systems.24The outstanding senior notes and junior subordinated notes, or notes, are unsecured obligations of our operating subsidiary, DCP Midstream Operating,LP, or DCP Operating, and are not guaranteed by any of our subsidiaries. As a result, our notes are effectively junior to DCP Operating’s existing andfuture secured debt and to all debt and other liabilities of its subsidiaries.The 2.70% Senior Notes due 2019, 5.35% Senior Notes due 2020, 4.75% Senior Notes due 2021, 4.95% Senior Notes due 2022, 3.875% Senior Notesdue 2023, 5.375% Senior Notes due 2025, 8.125% Senior Notes due 2030, 6.450% Senior Notes due 2036, 6.750% Senior Notes due 2037, and 5.60% SeniorNotes due 2044, or the Senior Notes, are senior unsecured obligations of DCP Operating and rank equally in right of payment with all of its other existing andfuture senior unsecured debt and effectively junior to any of its future secured indebtedness to the extent of the collateral securing such indebtedness. The5.85% Fixed-to-Floating Rate Junior Subordinated Notes due 2043 are junior subordinated obligations of DCP Operating and rank junior in right of paymentwith all of its other existing and future senior unsecured debt. All of our operating assets are owned by our subsidiaries, and none of these subsidiariesguarantee DCP Operating’s obligations with respect to the notes. Creditors of DCP Operating’s subsidiaries may have claims with respect to the assets ofthose subsidiaries that rank effectively senior to the notes. In the event of any distribution or payment of assets of such subsidiaries in any dissolution,winding up, liquidation, reorganization or bankruptcy proceeding, the claims of those creditors would be satisfied prior to making any such distribution orpayment to DCP Operating in respect of its direct or indirect equity interests in such subsidiaries. Consequently, after satisfaction of the claims of suchcreditors, there may be little or no amounts left available to make payments in respect of our notes. As of December 31, 2018, DCP Operating’s subsidiarieshad no debt for borrowed money owing to any unaffiliated third parties, other than the amounts borrowed under our accounts receivable securitizationfacility (the "Securitization Facility"). Such subsidiaries are not prohibited under the indentures governing the notes from incurring indebtedness in thefuture.In addition, because our notes and our guarantees of our notes are unsecured, holders of any secured indebtedness of us would have claims with respectto the assets constituting collateral for such indebtedness that are senior to the claims of the holders of our notes. Currently, we do not have any securedindebtedness, with the exception of our accounts receivable securitization facility. Although our debt agreements place some limitations on our ability tocreate liens securing debt, there are significant exceptions to these limitations that will allow us to secure significant amounts of indebtedness withoutequally and ratably securing the notes. If we incur secured indebtedness and such indebtedness is either accelerated or becomes subject to a bankruptcy,liquidation or reorganization, our assets would be used to satisfy obligations with respect to the indebtedness secured thereby before any payment could bemade on our notes. Consequently, any such secured indebtedness would effectively be senior to our notes and our guarantee of our notes, to the extent of thevalue of the collateral securing the secured indebtedness. In that event, our noteholders may not be able to recover all the principal or interest due under ournotes.Our significant indebtedness and the restrictions in our debt agreements may adversely affect our future financial and operating flexibility.As of December 31, 2018, our consolidated principal indebtedness was $5,326 million. Our significant indebtedness and any additional debt we mayincur in the future may adversely affect our liquidity and therefore our ability to make interest payments on our notes and distributions on our units.Debt service obligations and restrictive covenants in our Credit Agreement, and the indentures governing our notes may adversely affect our ability tofinance future operations, pursue acquisitions and fund other capital needs as well as our ability to make distributions to our unitholders. In addition, thisleverage may make our results of operations more susceptible to adverse economic or operating conditions by limiting our flexibility in planning for, orreacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitorsthat have less debt.If we incur any additional indebtedness, including trade payables, that ranks equally with our notes, the holders of that debt will be entitled to shareratably with the holders of our notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other windingup of us or DCP Operating. This may have the effect of reducing the amount of proceeds paid to our noteholders. If new debt is added to our current debtlevels, the related risks that we now face could intensify.25The adoption of financial reform legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments tohedge risks associated with our business. We hedge a portion of our commodity risk. In its rulemaking under the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Act, theCommodities Futures Trading Commission, or CFTC, adopted regulations to set position limits for certain futures and option contracts in the major energymarkets and for swaps that are their economic equivalents, but these rules were successfully challenged in Federal district court by the Securities IndustryFinancial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. In December 2016, the CFTCreproposed rules that place limits on speculative positions in certain physical commodity futures and options contracts and their "economically equivalent"swaps, including NYMEX Henry Hub Natural Gas and NYMEX Light Sweet Crude Oil contracts, subject to exceptions for certain bona fide hedgingtransactions. The CFTC has sought comment on the position limits rules as reproposed, but since these rules are not yet final, the impact of those provisionson us is uncertain at this time. Under the reproposed rules, we believe our hedging transactions will qualify for the non-financial, commercial end userexception, which exempts derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement, and as a result, we donot expect our hedging activity to be subject to mandatory clearing. The Act may also require us to comply with margin requirements in connection with ourhedging activities, although the application of those provisions to us is uncertain at this time. The Act may also require the counterparties to our derivativeinstruments to spin off some of their hedging activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislationand related regulations could significantly increase the cost of derivatives contracts for our industry (including requirements to post collateral which couldadversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks weencounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties,particularly if we are unable to utilize the commercial end user exception with respect to certain of our hedging transactions. If we reduce our use of hedgingas a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which couldadversely affect our ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the legislation was intended, in part, toreduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments relatedto oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.Any of these consequences could have a material adverse effect on our business, our financial condition, and our results of operations.Future disruptions in the global credit markets may make equity and debt markets less accessible and capital markets more costly, create a shortage in theavailability of credit and lead to credit market volatility, which could disrupt our financing plans and limit our ability to grow.From time to time, public equity markets experience significant declines, and global credit markets experience a shortage in overall liquidity and aresulting disruption in the availability of credit. Future disruptions in the global financial marketplace, including the bankruptcy or restructuring of financialinstitutions, could make equity and debt markets inaccessible, and adversely affect the availability of credit already arranged and the availability and cost ofcredit in the future. We have availability under our Credit Agreement to borrow additional capital, but our ability to borrow under that facility could beimpaired if one or more of our lenders fails to honor its contractual obligation to lend to us. As a publicly traded partnership, these developments could significantly impair our ability to make acquisitions or finance growth projects. Wedistribute all of our available cash, as defined in our amended and restated Partnership Agreement (the "Partnership Agreement"), to our common unitholderson a quarterly basis. We rely upon external financing sources, including the issuance of debt and equity securities and bank borrowings, to fund acquisitionsor expansion capital expenditures or fund routine periodic working capital needs. Any limitations on our access to external capital, including limitationscaused by illiquidity or volatility in the capital markets, may impair our ability to complete future acquisitions and construction projects on favorable terms,if at all. As a result, we may be at a competitive disadvantage as compared to businesses that reinvest all of their available cash to expand ongoing operations,particularly under adverse economic conditions.Volatility in the capital markets may adversely impact our liquidity. The capital markets may experience volatility, which may lead to financial uncertainty. Our access to funds under the Credit Agreement is dependent onthe ability of the lenders that are party to the Credit Agreement to meet their funding obligations. Those lenders may not be able to meet their fundingcommitments if they experience shortages of capital and liquidity. If lenders under the Credit Agreement were to fail to fund their share of the CreditAgreement, our available borrowings could be further reduced. In addition, our borrowing capacity may be further limited by the Credit Agreement’sfinancial covenants. 26A significant downturn in the economy could adversely affect our results of operations, financial position or cash flows. In the event that our results werenegatively impacted, we could require additional borrowings. A deterioration of the capital markets could adversely affect our ability to access funds onreasonable terms in a timely manner.We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.The partnership is a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We do not have significantassets other than equity in our subsidiaries and equity method investments. As a result, our ability to make required payments on our notes depends on theperformance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by,among other things, credit instruments, applicable state business organization laws and other laws and regulations. If our subsidiaries are prevented fromdistributing funds to us, we may be unable to pay all the principal and interest on the notes when due.We may incur significant costs and liabilities resulting from implementing and administering pipeline and asset integrity programs and related repairs.Pursuant to the Pipeline Safety Improvement Act of 2002, PHMSA has adopted regulations requiring pipeline operators to develop integritymanagement programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulationsrequire operators to:•perform ongoing assessments of pipeline integrity;•identify threats to pipeline segments that could impact a high consequence area and assess the risks that such threats pose to pipeline integrity;•collect, integrate, and analyze data regarding threats and risks posed to the pipeline;•repair and remediate the pipeline as necessary; and•implement preventive and mitigating actions.Pipeline safety legislation enacted in 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the Pipeline Safety and JobCreations Act, reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safetyrequirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements forexisting pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems,sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incidentnotification, and other pipeline-safety related requirements. New rules proposed by PHMSA, address many areas of this legislation. Extending the integritymanagement requirements to our gathering lines would impose additional obligations on us and could add material cost to our operations.Although many of our natural gas facilities currently are not subject to pipeline integrity requirements, we may incur significant costs and liabilitiesassociated with repair, remediation, preventative or mitigation measures associated with non-exempt pipelines. Such costs and liabilities might relate torepair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, or new requirements that maybe imposed as a result of the Pipeline Safety and Job Creation Act, as well as lost cash flows resulting from shutting down our pipelines during the pendencyof such repairs. Additionally, we may be affected by the testing, maintenance and repair of pipeline facilities downstream from our own facilities. With theexception of our Wattenberg pipeline, our NGL pipelines are also subject to integrity management and other safety regulations imposed by the TexasRailroad Commission, or TRRC.We currently estimate that we will incur costs of approximately $55 million between 2019 and 2023 to implement pipeline integrity managementprogram testing along certain segments of our natural gas and NGL pipelines. This does not include the costs, if any, of any repair, remediation, preventativeor mitigating actions that may be determined to be necessary as a result of the testing program, or new requirements that may be imposed as a result of thePipeline Safety and Job Creation Act, which costs could be substantial.We currently transport NGLs produced at our processing plants on our owned and third party NGL pipelines. Accordingly, in the event that an owned orthird party NGL pipeline becomes inoperable due to any necessary repairs resulting from integrity testing programs or for any other reason for any significantperiod of time, we would need to transport NGLs by other means.27There can be no assurance that we will be able to enter into alternative transportation arrangements under comparable terms, if at all.Any new or expanded pipeline integrity requirements or the adoption of other asset integrity requirements could also increase our cost of operation andimpair our ability to provide service during the period in which assessments and repairs take place, adversely affecting our business. Further, execution of andcompliance with such integrity programs may cause us to incur greater than expected capital and operating expenditures for repairs and upgrades that arenecessary to ensure the continued safe and reliable operation of our assets.State and local legislative and regulatory initiatives relating to oil and gas operations could adversely affect our third-party customers’ production and,therefore, adversely impact our midstream operations.Certain states in which we operate have adopted or are considering adopting measures that could impose new or more stringent requirements on oil andgas exploration and production activities. For example, the potential for adverse impacts to our business is present where local governments have enactedordinances directly regulating pipeline assets and operations, and private individuals have sponsored and may in the future sponsor citizen initiatives tolimit hydraulic fracturing, increase mandatory setbacks of oil and gas operations from occupied structures, and achieve more restrictive state or local controlover such activities. For instance, in 2018, a majority of Colorado voters defeated a citizen-initiative to impose significant mandatory setbacks for new oiland gas development from occupied structures or vulnerable areas, but the Colorado General Assembly continues to consider a variety of legislative measuresthat would, if enacted, impose more stringent legal and regulatory requirements on oil and gas development.In the event state or local restrictions or prohibitions are adopted in our areas of operations, our customers may incur significant compliance costs or mayexperience delays or curtailment in the pursuit of their exploration, development, or production activities, and possibly be limited or precluded in thedrilling of certain wells altogether. Any adverse impact on our customers’ activities would have a corresponding negative impact on our throughput volumes.In addition, while the general focus of debate is on upstream development activities, certain proposals may, if adopted, directly impact our ability tocompetitively locate, construct, maintain, and operate our own assets. Accordingly, such restrictions or prohibitions could have a material adverse effect onour business, prospects, results of operations, financial condition, cash flows and ability to make distributions to our unitholders.We may incur significant costs and liabilities in the future resulting from a failure to comply with existing or new environmental regulations or anaccidental release of hazardous substances or hydrocarbons into the environment.Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example, (i) thefederal Clean Air Act and comparable state laws and regulations, including federal and state air permits, that impose obligations related to air emissions;(ii) the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state laws that impose requirements for the management,storage and disposal of solid and hazardous waste from our facilities; (iii) the Comprehensive Environmental Response, Compensation, and Liability Act of1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released atproperties currently or previously owned or operated by us or locations to which we have sent waste for disposal; (iv) the Clean Water Act and the OilPollution Act, and comparable state laws that impose requirements on discharges to waters as well as requirements to prevent and respond to releases ofhydrocarbons to waters of the United States and regulated state waters; and (v) state laws that impose requirements on the response to and remediation ofhydrocarbon releases to soil or groundwater and managing related wastes. Failure to comply with these laws and regulations or newly adopted laws orregulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including the assessment of monetary penalties, theimposition of remedial requirements, and the issuance of orders enjoining or affecting future operations. Certain environmental regulations, includingCERCLA and analogous state laws and regulations, impose strict liability and joint and several liability for costs required to clean up and restore sites wherehazardous substances, and in some cases hydrocarbons, have been disposed or otherwise released.There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas, NGLs and otherpetroleum products, air emissions related to our operations, and historical industry operations and waste management and disposal practices. For example, anaccidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims madeby neighboring landowners and other third parties for personal injury and property damage, governmental claims for natural resource damages or imposingfines or penalties for related violations of environmental laws, permits or regulations. In addition, it is possible that stricter laws, regulations or enforcementpolicies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover someor any of these costs from insurance or third-party indemnification.28 A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agenciesmay result in increased regulation of our assets.The majority of our natural gas gathering and intrastate transportation operations are exempt from FERC regulation under the NGA, but FERC regulationstill affects these businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its oil and naturalgas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion,indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines,however there can be no assurance that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affectrights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transportation services and federallyunregulated gathering services has been the subject of regular litigation, so the classification and regulation of some of our gathering facilities and intrastatetransportation pipelines may be subject to change based on any reassessment by us of the jurisdictional status of our facilities or on future determinations byFERC and the courts.In addition, the rates, terms and conditions of some of the transportation services we provide on certain of our pipeline systems are subject to FERCregulation under Section 311 of the NGPA. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess offair and equitable rates are subject to refund with interest.Several of our pipelines are interstate transporters of NGLs and are subject to FERC jurisdiction under the Interstate Commerce Act and the Elkins Act.The base interstate tariff rates for our NGL pipelines are determined either by a FERC cost-of-service proceeding or by agreement with an unaffiliated party,and adjusted annually through the FERC’s indexing methodology. The NGL pipelines may also provide incentive rates, which offer tariff rates below thebase tariff rates for high volume shipments.Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties anddisgorgement of profits. Under EPACT 2005, FERC has civil penalty authority under the NGA to impose penalties of up to $1 million per day for eachviolation and possible criminal penalties of up to $1 million per violation and five years in prison. Under the NGPA, FERC may impose civil penalties of upto $1 million for any one violation and may impose criminal penalties of up to $1 million and five years in prison.Other state and local regulations also affect our business. Our non-proprietary gathering lines are subject to ratable take and common purchaser statutes.Ratable take statutes generally require gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer forhandling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer.These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil or natural gas. Federal lawleaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil andnatural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolvegrievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but maynonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum dailyproduction allowable from gas wells. While our proprietary gathering lines are currently subject to limited state regulation, there is a risk that state laws willchange, which may give producers a stronger basis to challenge the proprietary status of a line, or the rates, terms and conditions of a gathering line providingtransportation service.The interstate tariff rates of certain of our pipelines are subject to review and possible adjustment by federal regulators.FERC, pursuant to the NGA, regulates many aspects of our interstate natural gas pipeline transportation service, including the rates our pipelines arepermitted to charge for such service. Under the NGA, interstate transportation rates must be just and reasonable and not unduly discriminatory. If FERC failsto permit our requested tariff rate increases, or if FERC lowers the tariff rates we are permitted to charge, on its own initiative, or as a result of challengesraised by customers or third parties, our tariff rates may be insufficient to recover the full cost of providing interstate transportation service. In certaincircumstances, FERC also has the power to order refunds.Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties andthe disgorgement of profits. Under EPACT 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1million per day for each violation and possible criminal penalties of up to $1 million per violation and five years in prison. 29The transportation rates for our NGL pipelines that provide interstate transportation services, our interstate natural gas pipelines, and our intrastatepipelines that provide interstate services under Section 311 of the NGPA could be adversely impacted by FERC’s revised income tax allowance policy forpartnership pipelines and the federal law reducing the corporate income tax rate.Effective January 1, 2018, the federal corporate tax rate was reduced to 21%, and in March 2018, FERC issued a revised policy statement disallowing anincome tax allowance in the cost-of-service rates for partnership-owned pipelines. Previously, FERC’s policy generally permitted partnership pipelines torecover an income tax allowance in a cost-of-service proceeding before FERC if the pipeline’s ultimate owners had income tax liability. The maximum cost-based rates for our interstate natural gas pipelines and intrastate pipelines that provide interstate transportation services could be adversely affected in futurerate proceedings as a result of the change in policy and law. For interstate oil and NGL pipelines, FERC has indicated that it will consider the impacts of thetax policy and law changes on an industry-wide basis during the 2020 calendar year through its indexing methodology review. We cannot predict thechanges to the indexing methodology, but the tax policy and law changes could adversely impact the FERC index that is applied to the ceiling rates for ourinterstate NGL pipelines beginning in 2021. Additionally, any new cost-based rates for our pipelines regulated by the FERC will be affected by the newpolicy and tax law.Recently proposed or finalized rules imposing more stringent requirements on the oil and gas industry could cause our customers and us to incur increasedcapital expenditures and operating costs as well as reduce the demand for our services.On August 16, 2012, the EPA issued final regulations under the Clean Air Act that, among other things, require additional emissions controls for naturalgas and natural gas liquids production, including New Source Performance Standards, or NSPS, to address emissions of sulfur dioxide and volatile organiccompounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. Thefinal regulations require, among other things, the reduction of VOC emissions from existing natural gas wells that are re-fractured, as well as newly-drilledand fractured wells through the use of reduced emission completions or “green completions” and well completion combustion devices, such as flaring, as ofJanuary 1, 2015. In addition, these rules establish specific requirements regarding emissions from compressors and controllers at natural gas gathering andboosting stations and processing plants together with emissions reduction requirements for dehydrators and storage tanks at natural gas processing plants,compressor stations and gathering and boosting stations. The rules further establish new requirements for detection and repair of VOC leaks exceeding 500parts per million in concentration at new or modified natural gas processing plants. The EPA made certain revisions to the regulation from 2013 to 2015, andthe regulation is also the subject of Petitions for Review before the U.S. Circuit Court of Appeals for the District of Columbia. In addition, in June 2016, theEPA expanded the NSPS regulations for new or modified sources of VOCs to include methane emissions. Among other things, this regulation imposes leakdetection and repair requirements for VOCs and methane on producer well site equipment and on midstream equipment such as compressor and boosterstations, imposes additional emission reduction requirements on specific pieces of oil and gas equipment, and is a regulatory pre-condition to EPA acting toregulate existing oil and gas methane sources in the future under Section 111(d) of the Clean Air Act. This regulation is the subject of a Petition for Reviewbefore the U.S. Circuit Court of Appeals for the District of Columbia. This regulation is also the subject of review pursuant to the March 28, 2017,Presidential Executive Order on Promoting Energy Independence and Economic Growth, which ordered the EPA Administrator to review this regulation forconsistency with the Executive Order’s policy to review existing regulations impacting natural gas development and, if appropriate, “suspend, revise, orrescind the guidance or publish for notice and comment proposed rules suspending, revising or rescinding those rules.” In response to the Executive Order, inOctober 2018 EPA published proposed revisions to the regulation significantly revising elements of the rule. The EPA separately withdrew the informationrequest that it had issued in November 2016 as part of an effort to develop standards for methane and other emissions from existing sources in the oil andnatural gas industry. The EPA, in October 2015, revised and lowered the ambient air quality standard for ozone in the U.S. under the Clean Air Act, from 75parts per billion to 70 parts per billion, which is likely to result in more, and expanded, ozone non-attainment areas, which in turn will require states to adoptimplementation plans to reduce emissions of ozone-forming pollutants, like VOCs and nitrogen oxides, that are emitted from, among others, the oil and gasindustry. Persistent non-attainment status, such as for ozone, can result in lower major source permitting thresholds (making it more costly and complex tosite and permit major new or modified facilities) and additional control requirements. In October 2016, the EPA also finalized Control Techniques Guidelinesfor VOC emissions from existing oil and natural gas equipment and processes in moderate ozone non-attainment areas. These Control Techniques Guidelinesprovide recommendations for states and local air agencies to consider when determining what emissions control requirements apply to sources in the non-attainment areas. In March 2018, however, the EPA published a request for comments on withdrawing the guidelines in their entirety. Collectively, theseregulations could require modifications to the operations of our exploration and production customers, as well as our operations, including the installation ofnew equipment and new emissions management practices, which could result in significant additional costs, both increased capital expenditures andoperating costs. The incurrence of such expenditures and costs by our customers could also30result in reduced production by those customers and thus translate into reduced demand for our services, which could in turn have an adverse effect on ourbusiness and cash available for distributions.We may incur significant costs in the future associated with proposed climate change regulation and legislation.The United States Congress and some states where we have operations may consider legislation related to greenhouse gas emissions, including methaneemissions, which may compel reductions of such emissions. In addition, there have been international conventions and efforts to establish standards for thereduction of greenhouse gases globally, including the Paris accords in December 2015. The conditions for entry into force of the Paris accords were met onOctober 5, 2016 and the Agreement went into force 30 days later on November 4, 2016. In August 2017, however, the United States notified the UnitedNations Secretary-General that it intends to withdraw from the agreement as soon as it is able to do so, or November 2019, although the United States signedimplementation agreements framed in December 2018 at the U.N. Climate Change Conference in Warsaw, Poland. Legislative proposals have included orcould include limitations, or caps, on the amount of greenhouse gas that can be emitted, as well as a system of emissions allowances. For example, legislationpassed by the U.S. House of Representatives in 2010, which was not taken up by the Senate, would have placed the entire burden of obtaining allowances forthe carbon content of NGLs on the owners of NGLs at the point of fractionation. In June 2013, President Obama announced a climate action plan that targetsmethane emissions from the oil and gas industry as part of a comprehensive interagency methane reduction strategy, and in June 2016, the EPA expanded theNSPS regulations for new or modified sources of VOCs to include methane emissions, which, among other things, imposes leak detection and repairrequirements for VOCs and methane on producer well site equipment and on midstream equipment such as compressor and booster stations, imposesadditional emission reduction requirements on specific pieces of oil and gas equipment, and is a regulatory pre-condition to the EPA acting to regulateexisting oil and gas methane sources in the future under Section 111(d) of the Clean Air Act. Many of the actions taken under the Obama Administrationhave been targeted by the Trump Administration. For instance, in October 2018 the EPA published proposed revisions to the 2016 NSPS regulationsignificantly revising elements of the rule. In March 2018, the EPA published a request for comments on entirely withdrawing the October 2016 ControlTechniques Guidelines for emissions of VOCs from existing oil and gas industry sources in ozone nonattainment areas, which had an expected co-benefit ofreduced methane emissions. Relatedly, the D.C. Circuit Court challenge to the October 2015 EPA regulation reducing the ambient ozone standard from 75parts per billion to 70 parts per billion under the Clean Air Act was put in abeyance temporarily while the EPA reviewed the regulation. The EPA laterindicated it will not revise the rule, and in December 2018 the EPA published a final rule “Implementation of the 2015 National Ambient Air QualityStandards for Ozone: Nonattainment Area State Implementation Plan Requirements.” The 2015 Ozone standard continues to be litigated in the U.S. CircuitCourt of Appeals for the District of Columbia. Separately, in 2011 the EPA issued permitting rules for sources of greenhouse gases; however, in June 2014,the U.S. Supreme Court reversed a D.C. Circuit Court of Appeals decision upholding these rules and struck down the EPA’s greenhouse gas permitting rulesto the extent they impose a requirement to obtain a permit based solely on emissions of greenhouse gases. Under the Court ruling and the EPA's subsequentproposed rules, major sources of other air pollutants, such as VOCs or nitrogen oxides, could still be required to implement process or technology controlsand obtain permits regarding emissions of greenhouse gases. These proposed rules have not been finalized. The EPA has issued rules requiring reporting ofgreenhouse gas, on an annual basis, for certain onshore natural gas and oil production facilities, and in October 2015, the EPA amended and expanded thosegreenhouse gas reporting requirements to all segments of the oil and gas industry effective January 1, 2016. To the extent legislation is enacted or additionalregulations are promulgated that regulate greenhouse gas emissions, it could significantly increase our costs to (i) acquire allowances; (ii) permit new largefacilities; (iii) operate and maintain our facilities; (iv) install new emission controls or institute emission reduction measures; and (v) manage a greenhousegas emissions program. If such legislation becomes law or additional rules are promulgated in the United States or any states in which we have operations andwe are unable to pass these costs through as part of our services, it could have an adverse effect on our business and cash available for distributions.Increased regulation of hydraulic fracturing could result in reductions, delays or increased costs in drilling and completing new oil and natural gas wells,which could adversely impact our revenues by decreasing the volumes of natural gas and natural gas liquids that we gather, process and transport.Certain of our customers' natural gas is developed from formations requiring hydraulic fracturing as part of the completion process. Fracturing is aprocess where water, sand, and chemicals are injected under pressure into subsurface formations to stimulate hydrocarbon production. While the undergroundinjection of fluids is regulated by the EPA under the Safe Drinking Water Act, or SDWA, fracturing is excluded from regulation unless the injection fluid isdiesel fuel. The EPA has published an interpretive memorandum and permitting guidance related to regulation of fracturing fluids using this regulatoryauthority. The EPA has finalized various regulatory programs directed at hydraulic fracturing. For example, in June 2016, the EPA issued regulations underthe federal Clean Water Act to further regulate wastewater discharges from hydraulic fracturing and other natural gas production to publicly-owned treatmentworks. The EPA also expanded, as discussed herein, existing Clean Air Act new source performance standards for new and modified air emissions sources, andfinalized Control Techniques Guidelines31for existing sources in ozone non-attainment areas, to reduce emissions of methane or VOCs from oil and gas sources, including drilling and productionprocesses. States can propose or promulgate regulations or enact initiatives or legislation imposing conditions or restrictions on hydraulic fracturing practicesor oil and gas well development using hydraulic fracturing or horizontal drilling techniques. The adoption of new laws or regulations imposing reportingobligations on, or otherwise limiting or regulating, the hydraulic fracturing process could make it more difficult for our customers to complete oil and naturalgas wells in shale formations and increase their costs of compliance. In addition, the EPA has studied the potential adverse impact that each stage ofhydraulic fracturing may have on the environment; the EPA released a final assessment report of the potential impacts of hydraulic fracturing on drinkingwater resources in December 2016. Several states in which our customers operate have also adopted regulations requiring disclosure of fracturing fluidcomponents or otherwise regulate their use more closely. In Oklahoma, induced seismicity from injection of fluids in wastewater disposal wells has resultedin regulatory limitations on wastewater disposal into such wells. Under a recent settlement agreement, the EPA will decide by March 2019 whether to initiaterulemaking governing the disposal of wastewater from oil and gas development. The implementation of rules relating to hydraulic fracturing could result inincreased expenditures for our exploration and production customers, which could cause them to reduce their production and thereby result in reduceddemand for our services by these customers.On March 28, 2017, President Trump issued Executive Order 13783 entitled “Promoting Energy Independence and Economic Growth.” Executive Order13783 directed executive departments and agencies to review regulations that potentially burden the development or use of domestically produced energyresources and, as appropriate, suspend, revise, or rescind those that unduly burden domestic energy resources development. On March 26, 2015, the federalBureau of Land Management (“BLM”) finalized regulations requiring disclosure of chemicals used in hydraulic fracturing activities upon Native AmericanIndian and other federal lands, and added requirements on the use of hydraulic fracturing techniques and management of produced water on these lands. Therule was never implemented due to court challenges. On December 29, 2017, the BLM rescinded the rule. On November 18, 2016, the BLM finalizedregulations to, among other things, curtail the flaring during the production of natural gas and oil on Native American Indian and other federal lands, whichaffects how hydraulically fractured wells are developed and operated. On December 8, 2017, the BLM finalized a rule suspending or delaying many of theprovisions of the regulation while it reviews the regulation, which action was subsequently enjoined by the U.S. District Court in a challenge brought by twostates and a non-profit organization. On February 22, 2018, the BLM proposed changes to the 2016 regulation, and on September 28, 2018, the BLMfinalized the regulatory action rescinding parts of the rule and revising other parts of the rule. Our customers will continue to be subject to uncertaintyassociated with new regulatory measures as well as new regulatory suspensions, revisions, or rescissions and conflicting state and federal regulatorymandates, which could adversely affect their production and thereby result in reduced demand for our services by these customers.32Construction of new assets is subject to regulatory, environmental, political, legal, economic, civil protest, and other risks that may adversely affect ourfinancial results.The construction of new midstream facilities or additions or modifications to our existing midstream asset systems involves numerous regulatory,environmental, political, legal, and economic uncertainties beyond our control and may require the expenditure of significant amounts of capital. Forexample, public participation in review and permitting processes can introduce uncertainty and additional costs associated with project timing andcompletion. Relatedly, civil protests regarding environmental and social issues, including construction of infrastructure associated with fossil fuels, may leadto increased legislative and regulatory initiatives and review at federal, state, and local levels of government that could prevent or delay the construction ofsuch infrastructure and realization of associated revenues. Construction expenditures may occur over an extended period of time, yet we will not receive anymaterial increases in cash flow until the project is completed and fully operational. Moreover, our cash flow from a project may be delayed or may not meetour expectations. These projects may not be completed on schedule or within budgeted cost, or at all. We may construct facilities to capture anticipatedfuture growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development ofnatural gas and oil reserves, we often do not have access to third party estimates of potential reserves in an area prior to constructing facilities in such area. Tothe extent we rely on estimates of future production in our decision to construct new systems or additions to our systems, such estimates may prove to beinaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, these facilities may not be able toattract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. Theconstruction of new systems or additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructingthese facilities. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on otherattractive expansion opportunities. The construction of new systems or additions to our existing gathering and transportation assets may require us to rely onthird parties downstream of our facilities to have available capacity for our delivered natural gas and NGLs. If such third party facilities are not constructed oroperational at the time that the addition to our facilities is completed, we may experience adverse effects on our results of operations and financial condition.The construction of additional systems may require greater capital investment if the commodity prices of certain supplies such as steel increase. Constructionalso subjects us to risks related to the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation orincreased costs of equipment, materials, labor, or other factors beyond our control that could adversely affect results of operations, financial position or cashflows.We are exposed to the credit risks of our key producer customers, and any material nonpayment or nonperformance by our key producer customers couldreduce our ability to make distributions to our unitholders.We are subject to risks of loss resulting from nonpayment or nonperformance by our producer customer. Any material nonpayment or nonperformance byour key producer customers could reduce our ability to make distributions to our unitholders. Furthermore, some of our producer customers may be highlyleveraged and subject to their own operating and regulatory risks, which could increase the risk that they may default on their obligations to us. Additionally,a decline in the availability of credit to producers in and surrounding our geographic footprint could decrease the level of capital investment and growth thatwould otherwise bring new volumes to our existing assets and facilities.If we do not make acquisitions on economically acceptable terms, our future growth could be limited.Our ability to make acquisitions that are accretive to our cash generated from operations per unit is based upon our ability to identify attractiveacquisition candidates, negotiate acceptable purchase contracts and obtain financing for these acquisitions on economically acceptable terms. Furthermore,even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated fromoperations per unit. Additionally, net assets contributed by DCP Midstream, LLC represent a transfer of net assets between entities under common control,and are recognized at DCP Midstream, LLC’s basis in the net assets transferred. The amount of the purchase price in excess of DCP Midstream, LLC’s basis inthe net assets, if any, is recognized as a reduction to partners’ equity. Conversely, the amount of the purchase price less than DCP Midstream’s basis in the netassets, if any, is recognized as an increase to partners’ equity.Any acquisition involves potential risks, including, among other things:•mistaken assumptions about volumes, future contract terms with customers, revenues and costs, including synergies;•an inability to successfully integrate the businesses we acquire;•the assumption of unknown liabilities;•limitations on rights to indemnity from the seller;•mistaken assumptions about the overall costs of equity or debt;33•the diversion of management’s and employees’ attention from other business concerns;•change in competitive landscape;•unforeseen difficulties operating in new product areas or new geographic areas; and•customer or key employee losses at the acquired businesses.If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have theopportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and otherresources.In addition, any limitations on our access to substantial new capital to finance strategic acquisitions will impair our ability to execute this component ofour growth strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire accretive assets will be limited. We may not be ableto raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of capital include market conditions and offering orborrowing costs such as interest rates or underwriting discounts.We may not be able to grow or effectively manage our growth.Historically, a principal focus of our strategy was to continue to grow the per unit distribution on our units by expanding our business. Our acquisition ofthe DCP Midstream Business in January 2017 ("the Transaction") resulted in significant growth of the Partnership, but also in the loss of certain future dropdown opportunities from DCP Midstream, LLC. Our future growth will depend upon a number of factors, some of which we can control and some of which wecannot. These factors include our ability to:•complete construction projects and consummate accretive acquisitions or joint ventures;•identify businesses engaged in managing, operating or owning pipelines, processing and storage assets or other midstream assets foracquisitions, joint ventures and construction projects;•appropriately identify liabilities associated with acquired businesses or assets;•integrate acquired or constructed businesses or assets successfully with our existing operations and into our operating and financial systems andcontrols;•hire, train and retain qualified personnel to manage and operate our growing business; and•obtain required financing for our existing and new operations at reasonable rates.A deficiency in any of these factors could adversely affect our ability to sustain the level of our cash flows or realize benefits from acquisitions, jointventures or construction projects. In addition, competition from other buyers could reduce our acquisition opportunities. DCP Midstream, LLC and itsaffiliates are not restricted from competing with us. DCP Midstream, LLC and its affiliates may acquire, construct or dispose of midstream or other assets inthe future without any obligation to offer us the opportunity to purchase or construct those assets. Furthermore, in recent years we have grown throughorganic projects, dropdowns and acquisitions. If we fail to properly integrate these assets successfully with our existing operations, if the future performanceof these assets does not meet our expectations, if we did not properly value the assets, or if we did not identify significant liabilities associated with acquiredassets, the anticipated benefits from these transactions may not be fully realized.Acquisitions may not be beneficial to us.Acquisitions involve numerous risks, including:•the failure to realize expected profitability, growth or accretion;•an increase in indebtedness and borrowing costs;•potential environmental or regulatory compliance matters or liabilities;•potential title issues;•the incurrence of unanticipated liabilities and costs; and•the temporary diversion of management’s attention from managing the remainder of our assets to the process of integrating the acquiredbusinesses.Assets recently acquired will also be subject to many of the same risks as our existing assets. If any of these risks or unanticipated liabilities or costswere to materialize, any desired benefits of these acquisitions may not be fully realized, if at all, and our future financial performance and results of operationscould be negatively impacted.34Our assets and operations can be affected by weather, weather-related conditions and other natural phenomena.Our assets and operations can be adversely affected by hurricanes, floods, tornadoes, wind, lightning, cold weather and other natural phenomena, whichcould impact our results of operations and make it more difficult for us to realize historic rates of return. Although we carry insurance on the vast majority ofour assets, insurance may be inadequate to cover our loss and in some instances, we have been unable to obtain insurance on some of our assets oncommercially reasonable terms, if at all. If we incur a significant disruption in our operations or a significant liability for which we were not fully insured, ourfinancial condition, results of operations and ability to make distributions to our unitholders could be materially adversely affected.We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including costreimbursements to our general partner, to enable us to continue to make cash distributions to our unitholders.The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuatefrom quarter to quarter based on, among other things:•the fees we charge and the margins we realize for our services;•the prices of, level of production of, and demand for natural gas, condensate, and NGLs;•the success of our commodity and interest rate hedging programs in mitigating fluctuations in commodity prices and interest rates;•the volume and quality of natural gas we gather, compress, treat, process, transport and sell, and the volume of NGLs we process, transport, selland store;•the operational performance and efficiency of our assets, including our plants and equipment;•the operational performance and efficiency of third party assets that provide services to us;•the relationship between natural gas, NGL and crude oil prices;•the level of competition from other energy companies;•the impact of weather conditions on the demand for natural gas and NGLs;•the level of our operating and maintenance and general and administrative costs; and•prevailing economic conditions.In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control,including:•the level of capital expenditures we make;•the cost and form of payment for acquisitions;•our debt service requirements and other liabilities;•fluctuations in our working capital needs;•our ability to borrow funds and access capital markets at reasonable rates;•restrictions contained in our Credit Agreement and the indentures governing our notes;•the timing of our producers' obligations to make volume deficiency payments to us;•the amount of cash distributions we receive from our equity interests;•the amount of cost reimbursements to our general partner;•the amount of cash reserves established by our general partner; and•new, additions to and changes in laws and regulations.We have partial ownership interests in various joint ventures, which could adversely affect our ability to operate and control these entities. In addition, wemay be unable to control the amount of cash we will receive from the operation of these entities and we could be required to contribute significant cash tofund our share of their operations, which could adversely affect our ability to distribute cash to our unitholders.Our inability, or limited ability, to control the operations and management of joint ventures in which we have a partial ownership interest may mean thatwe will not receive the amount of cash we expect to be distributed to us. In addition, for joint ventures in which we have a minority ownership interest, wewill be unable to control ongoing operational decisions, including the incurrence of capital expenditures that we may be required to fund. Specifically,•we have limited ability to control decisions with respect to the operations of these joint ventures, including decisions with respect to incurrenceof expenses and distributions to us;•these joint ventures may establish reserves for working capital, capital projects, environmental matters and legal proceedings which wouldreduce cash available for distribution to us;•these joint ventures may incur additional indebtedness, and principal and interest made on such indebtedness may reduce cash otherwiseavailable for distribution to us; and35•these joint ventures may require us to make additional capital contributions to fund working capital and capital expenditures, our funding ofwhich could reduce the amount of cash otherwise available for distribution.All of these items could significantly and adversely impact our ability to distribute cash to our unitholders.The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow and not solely on profitability.Profitability may be significantly affected by non-cash items. As a result, we may make cash distributions during periods when we record losses forfinancial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.We do not own all of the land on which our pipelines, facilities and rail terminals are located, which may subject us to increased costs.We may become subject to more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or if such rightsof way lapse or terminate. Certain of our leases contain renewal provisions that allow for our continued use and access of the subject land and, although wereview and renew our leases as a routine business matter, there may be instances where we may not be able to renew our contract leases on commerciallyreasonable terms or may have to commence eminent domain proceedings to establish our right to continue to use the land. We obtain the rights to constructand operate our pipelines, surface sites and rail terminals on land owned by third parties and governmental agencies for a specific period of time.Our business involves many hazards and operational risks, some of which may not be fully covered by insurance.Our operations, and the operations of third parties, are subject to many hazards inherent in the gathering, compressing, treating, processing, storing,transporting and fractionating, as applicable, of natural gas and NGLs, including:•damage to pipelines, plants, terminals, storage facilities and related equipment and surrounding properties caused by hurricanes, tornadoes,floods, fires and other natural disasters and acts of terrorism;•inadvertent damage from construction, farm and utility equipment;•leaks of natural gas, NGLs and other hydrocarbons from our pipelines, plants, terminals, or storage facilities, or losses of natural gas or NGLs as aresult of the malfunction of equipment or facilities;•contaminants in the pipeline system;•fires and explosions; and•other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment andpollution or other environmental damage and may result in curtailment or suspension of our related operations. We are not fully insured against all risksinherent to our business, including offshore wind. We insure our underground pipeline systems against property damage, although coverage on certain of oursmall diameter gathering pipelines is subject to usual and customary sublimits. We are not insured against all environmental accidents that might occur,which may include toxic tort claims, other than those considered to be sudden and accidental. In some instances, certain insurance could become unavailableor available only for reduced amounts of coverage, or may become prohibitively expensive, and we may elect not to carry such a policy.Our increasing dependence on digital technology puts us at risk for a cyber incident that could result in information theft, data corruption, operationaldisruption or financial loss.We are increasingly reliant on digital technology to run our business and operate our assets. Our DCP 2.0 digital transformation includes a focus onincreasing the use of digital technology in all aspects of our business. We use digital technology to conduct certain of our plant operations, to monitorpipelines, compressors, pumps, meters, and other operating assets, to record financial and operating data, and to maintain various information databasesrelating our business. Our service providers are also increasingly reliant on digital technology. Our and their reliance on this technology increasingly puts usat risk for technology system failures, telecommunication, data, and network disruptions, and cyberattacks and other breaches in cybersecurity, which couldsignificantly impair our ability to conduct our business. Our insurance may not provide adequate protection from these risks. Any such events could damageour reputation and lead to financial losses from remedial actions, loss of business, or potential liability. As these cyber-risks continue to evolve and ourdependence on digital technology grows, we may be required to expend significant additional resources to continue to modify or enhance our protectivemeasures and remediate cyber vulnerabilities.36Our business could be negatively impacted by security threats, including cybersecurity threats, terrorist attacks, the threat of terrorist attacks and relateddisruptions.We face a variety of security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systemsunusable. Cybersecurity threats are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and otherelectronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information andcorruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.We face the threat of future terrorist attacks on both our industry in general and on us, including the possibility that infrastructure facilities could bedirect targets of, or indirect casualties of, an act of terror. The increased security measures we have taken as a precaution against possible terrorist attacks haveresulted in increased costs to our business. Any physical damage to facilities or cyber incidents resulting from acts of terrorism may not be covered, orcovered fully, by insurance. We may be required to expend material amounts of capital to repair any facilities, the expenditure of which could adverselyaffect our business and cash flows. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for usto obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in thefinancial markets as a result of terrorism or war could also affect our ability to raise capital.Risks Inherent in an Investment in Our Common UnitsConflicts of interest may exist between our individual unitholders and DCP Midstream, LLC, the owner of our general partner, which has soleresponsibility for conducting our business and managing our operations.DCP Midstream, LLC owns and controls our general partner. Some of our general partner’s directors and all of its executive officers are directors orexecutive officers of DCP Midstream, LLC or its owners. Therefore, conflicts of interest may arise between DCP Midstream, LLC and its affiliates and ourunitholders. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of ourunitholders. These conflicts include, among others, the following situations:•neither our Partnership Agreement nor any other agreement requires DCP Midstream, LLC to pursue a business strategy that favors us. DCPMidstream, LLC’s directors and officers have a fiduciary duty to make these decisions in the best interests of the owners of DCP Midstream,LLC, which may be contrary to our interests;•our general partner is allowed to take into account the interests of parties other than us, such as DCP Midstream, LLC and its affiliates, includingPhillips 66 and Enbridge, in resolving conflicts of interest;•DCP Midstream, LLC and its affiliates, including Phillips 66 and Enbridge, are not limited in their ability to compete with us. Please read “DCPMidstream, LLC and its affiliates are not limited in their ability to compete with us” below;•once certain requirements are met, our general partner may make a determination to receive a quantity of our Class B units in exchange forresetting the target distribution levels related to its incentive distribution rights without the approval of the special committee of our generalpartner or our unitholders;•our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders foractions that, without the limitations, might constitute breaches of fiduciary duty;•our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities andreserves, each of which can affect the amount of cash that is distributed to unitholders;•our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capitalexpenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determinationcan affect the amount of cash that is distributed to our unitholders;•our general partner determines which costs incurred by it and its affiliates are reimbursable by us;•our Partnership Agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us orentering into additional contractual arrangements with any of these entities on our behalf;•our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to beindemnified by us;•our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the commonunits;37•our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and•our general partner decides whether to retain separate counsel, accountants or others to perform services for us.DCP Midstream, LLC and its affiliates are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability toacquire additional assets or businesses, which in turn could adversely affect our results of operations and cash available for distribution to ourunitholders.Neither our Partnership Agreement nor the Services Agreement between us and DCP Midstream, LLC prohibits DCP Midstream, LLC and its affiliates,including Phillips 66 and Enbridge, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, DCP Midstream,LLC and its affiliates, including Phillips 66 and Enbridge, may acquire, construct or dispose of additional midstream or other assets in the future, without anyobligation to offer us the opportunity to purchase or construct any of those assets. Each of these entities is a large, established participant in the midstreamenergy business, and each has significantly greater resources than we have, which factors may make it more difficult for us to compete with these entities withrespect to commercial activities as well as for acquisition candidates. As a result, competition from these entities could adversely impact our results ofoperations and cash available for distribution.Cost reimbursements due to our general partner and its affiliates for services provided, which will be determined by our general partner, will be material.Pursuant to the Services Agreement, DCP Midstream, LLC and its affiliates will receive reimbursement for the payment of operating expenses related toour operations and for the provision of various general and administrative services for our benefit. Payments for these services will be material. In addition,under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for ourcontractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, weare obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions tocause us to make payments of these obligations and liabilities. These factors may reduce the amount of cash otherwise available for distribution to ourunitholders.Our Partnership Agreement limits our general partner’s fiduciary duties to holders of our units.Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our generalpartner have a fiduciary duty to manage our general partner in a manner beneficial to its owner, DCP Midstream, LLC. Our Partnership Agreement containsprovisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our PartnershipAgreement permits our general partner to make a number of decisions either in its individual capacity, as opposed to in its capacity as our general partner orotherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires, and it hasno duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include:•the exercise of its right to reset the target distribution levels of its incentive distribution rights at higher levels and receive, in connection withthis reset, a number of Class B units that are convertible at any time following the first anniversary of the issuance of these Class B units intocommon units;•its limited call right;•its voting rights with respect to the units it owns;•its registration rights; and•its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the Partnership Agreement.By purchasing a unit, a unitholder will agree to become bound by the provisions in the Partnership Agreement, including the provisions discussedabove.Our Partnership Agreement restricts the remedies available to holders of our units for actions taken by our general partner that might otherwise constitutebreaches of fiduciary duty.Our Partnership Agreement contains provisions that restrict the remedies available to our unitholders for actions taken by our general partner that mightotherwise constitute breaches of fiduciary duty. For example, our Partnership Agreement:•provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner solong as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;38•generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the special committee of the board ofdirectors of our general partner and not involving a vote of our unitholders must be on terms no less favorable to us than those generally beingprovided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faithand that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of therelationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and providesthat our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any actsor omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that thegeneral partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted withknowledge that the conduct was criminal.Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our generalpartner’s incentive distribution rights without the approval of the special committee of our general partner or holders of our common units. This may resultin lower distributions to holders of our common units in certain situations.Our general partner currently has the right to reset the initial cash target distribution levels at higher levels based on the distribution at the time of theexercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equalto the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election, or the reset minimum quarterlydistribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterlydistribution amount. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level.In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units. The Class B unitswill be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number ofClass B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributionsto our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right inorder to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without suchconversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected toexperience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units,which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributionsbased on the initial target distribution levels. As a result, in certain situations, a reset election may cause our common unitholders to experience dilution inthe amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection withresetting the target distribution levels related to our general partner incentive distribution rights.Holders of our units have limited voting rights and are not entitled to elect our general partner or its directors.Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore,limited ability to influence management’s decisions regarding our business. Our unitholders do not elect our general partner or its board of directors, andhave no right to elect our general partner or its board of directors on an annual or other continuing basis. The members of the board of directors of our generalpartner are chosen by the owner of our general partner. As a result of these limitations, the price at which the units trade could be diminished because of theabsence or reduction of a takeover premium in the trading price.Our units may experience price volatility.Our unit price has experienced volatility in the past, and volatility in the price of our units may occur in the future as a result of any of the risk factorscontained herein and the risks described in our other public filings with the SEC. For instance, our units may experience price volatility as a result of changesin investor sentiment with respect to our competitors, our business partners and our industry in general, which may be influenced by volatility in prices forNGLs, natural gas and crude oil. In addition, the securities markets have from time to time experienced significant price and volume fluctuations that areunrelated to the operating performance of particular companies but affect the market price of their securities. These market fluctuations may also materiallyand adversely affect the market price of our units.39Even if our unitholders are dissatisfied, they may be unable to remove our general partner without its consent.The unitholders may be unable to remove our general partner without its consent because our general partner and its affiliates own a significantpercentage of our outstanding units. The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove the general partner. Asof December 31, 2018, our general partner and its affiliates owned approximately 36% of our outstanding common units.Our Partnership Agreement restricts the voting rights of our unitholders owning 20% or more of any class of our units.Our unitholders’ voting rights are further restricted by the Partnership Agreement provision providing that any units held by a person that owns 20% ormore of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the priorapproval of the board of directors of our general partner, cannot vote on any matter. Our Partnership Agreement also contains provisions limiting the abilityof our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influencethe manner or direction of management.If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and couldhave a material adverse effect on our business.Our assets include certain equity investments, such as minority ownership interests in joint ventures, which may be deemed to be “investment securities”within the meaning of the Investment Company Act of 1940, as amended (the "Investment Company Act"). In the future, we may acquire additional minority-owned interests in joint ventures that could be deemed "investment securities." If a sufficient amount of our assets are deemed to be “investment securities”within the meaning of the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtainexemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company.Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchaseand sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverageand require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events may have a materialadverse effect on our business.Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes in which case wewould be treated as a corporation for federal income tax purposes, and be subject to federal income tax at the corporate tax rate, which could significantlyreduce the cash available for distributions. Additionally, distributions to our unitholders would be taxed again as corporate distributions and none of ourincome, gains, losses or deductions would flow through to our unitholders.Additionally, as a result of our desire to avoid having to register as an investment company under the Investment Company Act, we may have to forgopotential future acquisitions of interests in companies that may be deemed to be investment securities within the meaning of the Investment Company Act ordispose of our current interests in any of our assets that are deemed to be “investment securities.”Control of our general partner may be transferred to a third party without unitholder consent.Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without theconsent of our unitholders. Furthermore, under our Partnership Agreement the owners of our general partner may pledge, impose a lien or transfer all or aportion of their respective ownership interest in our general partner to a third party. Any new owners of our general partner would then be in a position toreplace the board of directors and officers of the general partner with its own choices and thereby influence the decisions taken by the board of directors andofficers.We may generally issue additional units, including units that are senior to our common units, without our unitholders’ approval, which would dilute ourunitholders’ existing ownership interests.Our Partnership Agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders.The issuance by us of additional common units, preferred units, or other equity securities of equal or senior rank will have the following effects:•our unitholders’ proportionate ownership interest in us will decrease, including a relative dilution of any voting rights;•the amount of cash available for distribution on each unit may decrease;40•the ratio of taxable income to distributions may increase;•the relative voting strength of each previously outstanding unit may be diminished; and•the market price of the common units may decline.We are prohibited from paying distributions on our common units if distributions on our Preferred Units are in arrears.The holders of our 7.375% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”), our 7.875%Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Series B Preferred Units”), and our 7.95% Series C Fixed-to-FloatingRate Cumulative Redeemable Perpetual Preferred Units (“Series C Preferred Units and together with the Series A Preferred Units and the Series B PreferredUnits, the “Preferred Units”) are entitled to certain rights that are senior to the rights of holders of common units, such as rights to distributions and rightsupon liquidation of the Partnership. If we do not pay the required distributions on our Preferred Units, we will be unable to pay distributions on our commonunits. Additionally, because distributions to our Preferred Unitholders are cumulative, we will have to pay all unpaid accumulated preferred distributionsbefore we can pay any distributions to our common unitholders. Also, because distributions to our common unitholders are not cumulative, if we do not paydistributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any priorperiods if we later commence paying distributions on our common units. The preferences and privileges of the Preferred Units could adversely affect themarket price for our common units, or could make it more difficult for us to sell our common units in the future.Our Preferred Units are subordinated to our existing and future debt obligations, and your interests could be diluted by the issuance of additional units,including additional Preferred Units, and by other transactions.The Preferred Units are subordinated to all of our existing and future indebtedness. The payment of principal and interest on our debt reduces cashavailable for distribution to our limited partners, including the holders of Preferred Units. The issuance of additional units on parity with or senior to thePreferred Units (including additional Preferred Units) would dilute the interests of the holders of the Preferred Units, and any issuance of equal or seniorranking securities or additional indebtedness could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Preferred Units.We distribute all of our available cash to our common unitholders and are not required to accumulate cash for the purpose of meeting our futureobligations to holders of the Preferred Units, which may limit the cash available to make distributions on the Preferred Units.Our Partnership Agreement requires us to distribute all of our “available cash” each quarter to our common unitholders. “Available cash” is defined inour Partnership Agreement and described below under “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases ofCommon Units—Distributions of Available Cash—Definition of Available Cash.” As a result, we do not expect to accumulate significant amounts of cash.Depending on the timing and amount of our cash distributions, these distributions could significantly reduce the cash available to us in subsequent periodsto make payments on the Preferred Units.Our general partner including its affiliates may sell units in the public or private markets, which could reduce the market price of our outstanding commonunits.If our general partner or its affiliates holding unregistered common units were to dispose of a substantial portion of these units in the public market,whether in a single transaction or series of transactions, it could reduce the market price of our outstanding common units. In addition, these sales, or thepossibility that these sales may occur, could make it more difficult for us to sell our common units in the future.Our general partner has a limited call right that may require our unitholders to sell their units at an undesirable time or price.If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not theobligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a pricenot less than their then-current market price. As a result, our common unitholders may be required to sell their common units at an undesirable time or priceand may not receive any return on their investment. Our common unitholders may also incur a tax liability upon a sale of their common units.41The liability of holders of limited partner interests may not be limited if a court finds that unitholder action constitutes control of our business.A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of thepartnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in anumber of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearlyestablished in some of the other states in which we do business. Holders of limited partner interests could be liable for any and all of our obligations as if suchholder were a general partner if:•a court or government agency determined that we were conducting business in a state but had not complied with that particular state’spartnership statute; or•the right of holders of limited partner interests to act with other unitholders to remove or replace the general partner, to approve someamendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business.Unitholders may have liability to repay distributions that were wrongfully distributed to them.Under certain circumstances, our unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of theDelaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities toexceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners whoreceived the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for thedistribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to thesubstituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the PartnershipAgreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposesof determining whether a distribution is permitted.Tax Risks to UnitholdersOur tax treatment depends on our status as a partnership for federal income tax purposes, as well as our being subject to minimal entity-level taxation byindividual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, or we become subject to amaterial amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to ourunitholders.The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal incometax purposes. We have not requested, and do not plan to request, a ruling from the IRS regarding our status as a partnership.Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated asa corporation for federal income tax purposes. Although we do not believe based upon our current operations that we will be treated as a corporation, the IRScould disagree with the positions we take or a change in our business (or a change in current law) could cause us to be treated as a corporation for federalincome tax purposes or otherwise subject us to taxation as an entity.If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate,which is currently 21% for taxable years beginning after December 31, 2017, and would likely pay state income tax at varying rates. Distributions to aunitholder would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains,losses, deductions, or credits would flow through to the unitholder. Because a tax would be imposed upon us as a corporation, our cash available fordistribution to a unitholder would be substantially reduced. Therefore, treatment of us as a corporation for federal tax purposes would result in a materialreduction in the anticipated cash flow and after-tax return to a unitholder, likely causing a substantial reduction in the value of our units.The Partnership Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as acorporation or otherwise subjects us to entity level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount andthe target distribution levels will be adjusted to reflect the impact of that law on us.42The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changesand differing interpretations, possibly on a retroactive basis.The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our units, may be modified by administrative,legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be appliedretroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception that allows publicly tradedpartnerships that generate qualifying income to be treated as partnerships (rather than corporations) for federal income tax purposes, affect or cause us tochange our business activities, or affect the tax consequences of an investment in our units. The U.S. Treasury Department issued final regulationsinterpreting the scope of activities that generate qualifying income under Section 7704 of the Internal Revenue Code of 1986, as amended, or the Code. Webelieve that the income we currently treat as qualifying income satisfies the requirements for qualifying income under the final regulations.The Tax Cuts and Jobs Act provides a deduction under Code Section 199A to a non-corporate common unitholder, for taxable years beginning afterDecember 31, 2017 and ending on or before December 31, 2025, equal to 20% of his or her allocable share of our “qualified business income.” For purposesof this deduction, our “qualified business income” is equal to the sum of the net amount of our items of income, gain, deduction and loss to the extent suchitems are included or allowed in the determination of taxable income for the year, excluding, however, certain specified types of passive investment income(such as capital gains and dividends); and any gain recognized upon a disposition of our units to the extent such gain is attributable to certain assets, such asdepreciation recapture and our “inventory items,” and is thus treated as ordinary income under Section 751 of the Code. This law also includes certain newlimitations on the use of losses and other deductions to offset taxable income. Various aspects of this deduction and these limitations may be modified byadministrative, legislative or judicial interpretations at any time, which may or may not be applied retroactively.Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation throughthe imposition of state income, franchise and other forms of taxation, which would reduce the cash available for distribution to our unitholders. For example,we are required to pay the State of Texas a margin tax that is assessed at 0.75% of taxable margin apportioned to Texas. The Partnership Agreement providesthat if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted toreflect the impact of that law on us.Changes in tax laws could adversely affect our performance.We are subject to extensive tax laws and regulations, with respect to federal, state and foreign income taxes and transactional taxes such as excise,sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously beingenacted that could result in increased tax expenditures in the future.If tax authorities contest the tax positions we take, the market for our units may be adversely impacted, and the cost of any contest with a tax authoritywould reduce our cash available for distribution to our unitholders.We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. Tax authorities may adoptpositions that differ from the conclusions of our counsel or from the positions we take, and the tax authority's positions may ultimately be sustained. It maybe necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may notagree with some or all of our counsel’s conclusions or positions we take. Any contest with a tax authority, and the outcome of any such contest, may increasea unitholder’s tax liability and result in adjustment to items unrelated to us and could materially and adversely impact the market for our units and the priceat which they trade. In addition, our costs of any contest with any tax authority will be borne indirectly by our unitholders and our general partner becausesuch costs will reduce our cash available for distribution.For taxable years beginning after December 31, 2017, the procedures for auditing large partnerships and the procedures for assessing and collecting taxesdue (including applicable penalties and interest) as a result of an audit have changed. Unless we are eligible to (and choose to) elect to issue revisedSchedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties andinterest) directly from us in the year in which the audit is completed under the new procedures. If we are required to pay taxes, penalties and interest as theresult of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due forthe taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were notunitholders during the audited taxable year.43Our unitholders may be required to pay taxes on income from us even if the unitholders do not receive any cash distributions from us.Because our unitholders will be treated as partners to whom we will allocate taxable income, which could be different in amount than the cash wedistribute, unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable incomeeven if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or evenequal to the tax liability that results from that income.Certain actions that we may take, such as issuing additional units, may increase the federal income tax liability of unitholders.In the event we issue additional units or engage in certain other transactions in the future, the allocable share of nonrecourse liabilities allocated to theunitholders will be recalculated to take into account our issuance of any additional units. Any reduction in a unitholder’s share of our nonrecourse liabilitieswill be treated as a distribution of cash to that unitholder and will result in a corresponding tax basis reduction in a unitholder’s units. A deemed cashdistribution may, under certain circumstances, result in the recognition of taxable gain by a unitholder, to the extent that the deemed cash distributionexceeds such unitholder’s tax basis in its units.In addition, the federal income tax liability of a unitholder could be increased if we dispose of assets or make a future offering of units and use theproceeds in a manner that does not produce substantial additional deductions, such as to repay indebtedness currently outstanding or to acquire property thatis not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the ratecurrently applicable to our assets.Tax gain or loss on disposition of common units could be more or less than expected.If a unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and theunitholder's tax basis in those common units. Because distributions to a unitholder in excess of the total net taxable income allocated to it for a common unitdecreases its tax basis in that common unit, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxableincome to the unitholder if the common unit is sold at a price greater than their tax basis in that common unit, even if the price is less than their original cost.Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items,including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells itsunits, the unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.Our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year.However, under the Tax Cuts and Jobs Act enacted on December 22, 2017 (the “Tax Cuts and Jobs Act”), for taxable years beginning after December 31,2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposesof this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case oftaxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion that is not required to be capitalized aspart of cost of goods sold.Tax-exempt entities and non-U.S. persons face unique tax issues from owning units that may result in adverse tax consequences to them.Investment in units by tax-exempt entities, such as individual retirement accounts, or IRAs, other retirement plans and non-U.S. persons raises issuesunique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and otherretirement plans, will be unrelated business taxable income, which may be taxable to them. Further, with respect to taxable years beginning after December31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that isengaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately withrespect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning afterDecember 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxableincome from another unrelated trade or business or vice versa.44Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be requiredto file United States federal tax returns and pay tax on their share of our taxable income. Gain recognized from a sale or other disposition of our units by anon-U.S. person will be subject to federal income tax as income effectively connected with a U.S. trade or business. Moreover, the transferee of our units isgenerally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required todeduct and withhold from the transferee amounts that should have been withheld by the transferees but were not withheld. Because the “amount realized”includes a partner's share of the partnership's liabilities, 10% of the amount realized could exceed the total cash purchase price for the units. However, the IRShas suspended the application of this withholding rule to open market transfers of interest in publicly traded partnerships, pending promulgation ofregulations or other guidance that address the amount to be withheld, the reporting necessary to determine such amount and the appropriate party to withholdsuch amounts. It is not clear if or when such regulations or other guidance will be issued.If a unitholder is a tax-exempt entity or a non-U.S. person, the unitholder should consult its tax advisor before investing in our units.We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS maychallenge this treatment, which could adversely affect the value of the common units.Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortizationpositions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect theamount of tax benefits available to the unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common unitsand could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of ourunits on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which couldchange the allocation of items of income, gain, loss and deduction among our unitholders.We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of ourunits on the first day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Treasury Department has adopted finalregulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax itemsamong transferor and transferee unitholders. These regulations do not specifically authorize the proration method we have previously used. If the IRS were tochallenge our proration method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss anddeduction among our unitholders.A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, theunitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may be required torecognize gain or loss from the disposition.Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units,the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and suchunitholder may be required to recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income,gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to thoseunits could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to ashort seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units.We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and theunitholders. The IRS may challenge this treatment, which could adversely affect the value of the units.When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gainor loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the valueof our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may beunfavorable to such unitholders. Moreover, subsequent purchasers of our units may have a greater portion of their adjustment under Section 743(b) of theCode allocated to45our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner andcertain of our unitholders.A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to ourunitholders. It also could affect the amount of gain from our unitholders’ sale of our units and could have a negative impact on the value of our units or resultin audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.Treatment of distributions on our Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders ofPreferred Units than the holders of our common units.The tax treatment of distributions on our Preferred Units is uncertain. We will treat the holders of our Preferred Units as partners for tax purposes and willtreat distributions on our Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of our Preferred Units asordinary income and will not be eligible for the deduction provided for under Code Section 199A. Although a holder of our Preferred Units could recognizetaxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making theguaranteed payment distributions associated with the Preferred Units. Because the guaranteed payment for each unit must accrue as income to a holder duringthe taxable year of the accrual, the guaranteed payments attributable to the period beginning December 15 and ending December 31 will accrue as income tothe holder of record of a Preferred Unit on December 31 for such period, regardless of whether such holder continues to own the Preferred Units at the time theactual distribution is made. Otherwise, the holders of our Preferred Units are generally not anticipated to share in our items of income, gain, loss or deduction,except to the extent necessary to provide, to the extent possible, the Preferred Units with the benefit of the liquidation preference. We will not allocate anyshare of our nonrecourse liabilities to the holders of our Preferred Units. If our Preferred Units were treated as indebtedness for tax purposes, rather than aspartnership interests, distributions on our Preferred Units likely would be treated as payments of interest by us to the holders of our Preferred Units, rather thanas guaranteed payments for the use of capital.A holder of our Preferred Units will be required to recognize gain or loss on a sale of its Preferred Units equal to the difference between the amountrealized by such holder and tax basis in the Preferred Units sold. The amount realized generally will equal the sum of the cash and the fair market value ofother property such holder receives in exchange for such Preferred Units. Subject to general rules requiring a blended basis among multiple partnershipinterests, the tax basis of a Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the holder of thePreferred Unit to acquire such Preferred Unit. Gain or loss recognized by a holder of a Preferred Unit on the sale or exchange of a Preferred Unit held for morethan one year generally will be taxable as long-term capital gain or loss. Because holders of our Preferred Units will generally not be allocated a share of ouritems of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain asordinary income as a result of the recapture rules.Unitholders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our units.In addition to federal income taxes, unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes andestate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the unitholders do notlive in any of those jurisdictions. Unitholders may be required to file foreign, state and local income tax returns and pay state and local income taxes in someor all of these jurisdictions. Further, the unitholder may be subject to penalties for failure to comply with those requirements. As we make acquisitions orexpand our business, we may own assets or do business in additional states that impose a personal income tax or an entity level tax. It is each unitholder’sresponsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local taxconsequences of an investment in our units.Item 1B. Unresolved Staff CommentsNone.46Item 2. PropertiesFor details on our plants, fractionation and storage facilities, propane terminals and pipeline systems, please read Item 1. "Business - Our OperatingSegments”. We believe that our properties are generally in good condition, well maintained and are suitable and adequate to carry on our business at capacityfor the foreseeable future.Our real property falls into two categories: (1) parcels that we own in fee; and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which ourplants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of theland on which our plant sites and major facilities are located are held by us pursuant to ground leases between us, as lessee, and the fee owner of the lands, aslessors. We, or our predecessors, have leased these lands for many years without any material challenge known to us relating to the title to the land uponwhich the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to theunderlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way,permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.Our principal executive offices are located at 370 17th Street, Suite 2500, Denver, Colorado 80202, our telephone number is 303-595-3331 and ourwebsite address is www.dcpmidstream.com.Item 3. Legal ProceedingsWe are not a party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings and commercial disputesthat have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of these matters, taken as a whole, andafter consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect upon ourconsolidated results of operations, financial position or cash flows. For more information, please read “Environmental Matters.”Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, fractionating, or storing naturalgas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner oroperator of these facilities, we must comply with laws and regulations at the federal, state and, in some cases, local levels that relate to worker safety, pipelinesafety, air and water quality, solid and hazardous waste management and disposal, and other environmental matters. The cost of planning, designing,constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and regulations, worker safety standards,and safety standards applicable to our various facilities. In addition, there is increasing focus from (i) regulatory bodies and communities, and throughlitigation, on hydraulic fracturing and the real or perceived environmental or public health impacts of this technique, which indirectly presents some risk toour available supply of natural gas and the resulting supply of NGLs, (ii) regulatory bodies regarding pipeline system safety which could impose additionalregulatory burdens and increase the cost of our operations, (iii) state and federal regulatory officials regarding the emission of greenhouse gases, which couldimpose regulatory burdens and increase the cost of our operations, and (iv) regulatory bodies and communities that could prevent or delay the developmentof fossil fuel energy infrastructure such as pipelines, plants, and other facilities used in our business. Failure to comply with these various health, safety andenvironmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits,which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation.Management believes that, based on currently known information, compliance with these existing laws and regulations will not have a material adverseeffect on our results of operations, financial position or cash flows.Item 4. Mine Safety DisclosuresNot applicable.PART IIItem 5. Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common UnitsMarket InformationOur common units are listed on the New York Stock Exchange ("NYSE") under the symbol "DCP". As of February 20, 2019, there were approximately40 unitholders of record of our common units. This number does not include unitholders whose common units are held in trust by other entities.47Distributions of Available CashGeneral - Our Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash (defined below)to unitholders of record on the applicable record date, as determined by our general partner.Definition of Available Cash - Available Cash, for any quarter, consists of all cash and cash equivalents on the date of determination of available cashfor that quarter:•less the amount of cash reserves established by our general partner to:•provide for the proper conduct of our business, including reserves for future capital expenditures and anticipated credit needs;•comply with applicable law or any debt instrument or other agreement or obligation;•provide funds to make payments on the Preferred Units; or•provide funds for distributions to our common unitholders and to our general partner for any one or more of the next four quarters.•plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cashfor the quarter.Minimum Quarterly Distribution - The Minimum Quarterly Distribution, as set forth in the Partnership Agreement, is $0.35 per unit per quarter, or$1.40 per unit per year. Our current quarterly distribution is $0.78 per unit, or $3.12 per unit annualized. There is no guarantee that we will maintain ourcurrent distribution or pay the Minimum Quarterly Distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked,the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into considerationthe terms of our Partnership Agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - CapitalRequirements - Liquidity and Capital Resources” for a discussion of the restrictions included in our Credit Agreement that may restrict our ability to makedistributions.General Partner Interest and Incentive Distribution Rights - As of December 31, 2018, the General Partner was entitled to a percentage of all quarterlydistributions equal to its General Partner interest of approximately 2% and limited partner interest of 36%. The General Partner has the right, but not theobligation, to contribute a proportionate amount of capital to us to maintain its current General Partner interest. The General Partner’s interest may be reducedif we issue additional units in the future and our General Partner does not contribute a proportionate amount of capital to us to maintain its current GeneralPartner interest.The incentive distribution rights held by our General Partner entitle it to receive an increasing share of Available Cash as pre-defined distributiontargets have been achieved. Currently, our distribution to our General Partner related to its incentive distribution rights is at the highest level. Our GeneralPartner’s incentive distribution rights have not been reduced as a result of our common unit offerings, and will not be reduced if we issue additional units inthe future and the General Partner does not contribute a proportionate amount of capital to us to maintain its current General Partner interest.As part of the Transaction, Phillips 66 and Enbridge agreed, if required, to provide a reduction to incentive distributions payable to our General Partnerunder our Partnership Agreement of up to $100 million annually through 2019 to target an approximate 1.0 times distribution coverage ratio. Under theterms of our amended Partnership Agreement, the amount of incentive distributions paid to our General Partner will be evaluated by our General Partner onboth a quarterly and annual basis and may be reduced each quarter by an amount determined by our General Partner (the “IDR giveback”). If nodetermination is made by our General Partner, the quarterly IDR giveback will be $20 million. The IDR giveback, of up to $100 million annually, will besubject to a true-up at the end of the year by taking our total distributable cash flow (as adjusted under our amended Partnership Agreement) less the totalannual distribution payable to our unitholders, adjusted to target an approximate 1.0 times coverage ratio.Please read the Distributions of Available Cash section in Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statementsand Supplementary Data” for more details about the distribution targets and their impact on the General Partner’s incentive distribution rights.On January 23, 2019, we announced that the board of directors of DCP Midstream GP, LLC declared a quarterly distribution of $0.78 per unit, whichwas paid on February 14, 2019, to unitholders of record on February 4, 2019.48Preferred Units - In October 2018 , we issued 4,400,000 of our Series C Preferred Units representing limited partnership interests (including a partialexercise of the underwriters’ option to purchase additional Series C Preferred Units) at a price of $25 per unit. We used the net proceeds of $106 million fromthe issuance of the Series C Preferred Units for general partnership purposes including funding capital expenditures and the repayment of outstandingindebtedness under the Credit Agreement.Distributions of the Preferred Units are payable out of available cash, accrue and are cumulative from the date of original issuance of the Preferred Units.•Distributions on the Series A Preferred Units are payable semiannually in arrears on June 15th and December 15th of each year.•Distributions on the Series B Preferred Units are payable quarterly in arrears on the 15th day of March, June, September and December of each yearto holders of record as of the close of business on the first business day of the month in which the distribution will be made.•Distributions on the Series C Preferred Units are payable quarterly in arrears on the 15th day of January, April, July and October of each year toholders of record as of the close of business on the first business day of the month in which the distribution will be made.Securities Authorized for Issuance Under Equity Compensation PlansThe information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in Item 12.“Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” contained herein.49Item 6. Selected Financial DataThe following table shows our selected financial data for the periods and as of the dates indicated, which is derived from our consolidated financialstatements. The information contained herein should be read together with, and is qualified in its entirety by reference to, the consolidated financialstatements and the accompanying notes included elsewhere in this Form 10-K.Our operating results incorporate a number of significant estimates and uncertainties. Such matters could cause the data included herein to not beindicative of our future financial condition or results of operations. The table should also be read together with Item 7. “Management’s Discussion andAnalysis of Financial Condition and Results of Operations.”The following table shows our selected financial and operating data for the periods and as of the dates indicated, which is derived from our consolidatedfinancial statements. Year Ended December 31, 2018 2017 2016 2015 2014 (millions, except per unit amounts)Statements of Operations Data: Sales of natural gas, NGLs and condensate$9,374 $7,850 $6,269 $6,779 $13,420Transportation, processing and other489 652 647 532 517Trading and marketing (losses) gains, net(41) (40) (23) 119 88Total operating revenues9,822 8,462 6,893 7,430 14,025Operating costs and expenses: Purchases and related costs8,019 6,885 5,461 5,981 11,828Operating and maintenance expense760 661 670 732 773Depreciation and amortization expense388 379 378 377 348General and administrative expense276 290 292 281 277Asset impairments145 48 — 912 18Other expense (income), net11 11 (65) 10 7(Gain) loss on sale of assets, net— (34) (35) (42) 7Restructuring costs— — 13 11 —Total operating costs and expenses9,599 8,240 6,714 8,262 13,258Operating income (loss)223 222 179 (832) 767Loss on financing activities(19) — — — —Interest expense(269) (289) (321) (320) (287)Earnings from unconsolidated affiliates (a)370 303 282 184 82Income (loss) before income taxes305 236 140 (968) 562Income tax (expense) benefit(3) (2) (46) 102 (11)Net income (loss)302 234 94 (866) 551Net income attributable to noncontrolling interests(4) (5) (6) (5) (4)Net income (loss) attributable to partners298 229 88 (871) 547Net loss (income) attributable to predecessor operations (b)— — 224 1,099 (130)General partner interest in net income(164) (164) (124) (124) (114)Series A preferred limited partners' interest in net income(37) (4) — — —Series B preferred limited partners' interest in net income(8) — — — —Series C preferred limited partners' interest in net income(2) — — — —Net income allocable to limited partners$87 $61 $188 $104 $303Net income per limited partner unit-basic and diluted$0.61 $0.43 $1.64 $0.91 $2.8450 Year Ended December 31, 2018 2017 2016 2015 2014 (millions, except per unit amounts)Balance Sheet Data (at period end): Property, plant and equipment, net$9,135 $8,983 $9,069 $9,428 $9,537Total assets$14,266 $13,878 $13,611 $13,885 $13,628Accounts payable$926 $1,076 $735 $545 $977Long-term debt$4,782 $4,707 $4,907 $5,669 $5,191Partners’ equity$7,268 $7,408 $2,601 $2,772 $2,993Predecessor equity$— $— $4,220 $4,287 $2,189Noncontrolling interests$29 $30 $32 $33 $33Total equity$7,297 $7,438 $6,853 $7,092 $5,215Other Information: Cash distributions declared per unit$3.1200 $3.1200 $3.1200 $3.1200 $3.0525Cash distributions paid per unit$3.1200 $3.1200 $3.1200 $3.1200 $3.0050(a)Includes our proportionate share of the earnings of our unconsolidated affiliates. Earnings include the amortization of the net difference betweenthe carrying amount of the investments and the underlying equity of the entities.(b)Includes net (loss) income attributable to the DCP Midstream Business prior to the date of our acquisition from DCP Midstream, LLC.Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financialcondition and results of operations in conjunction with our consolidated financial statements and notes included elsewhere in this Annual Report on Form10-K.OverviewWe are a Delaware limited partnership formed by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementarymidstream energy assets. Our operations are organized into two reportable segments: (i) Logistics and Marketing and (ii) Gathering and Processing. OurLogistics and Marketing segment includes transporting, trading, marketing and storing natural gas and NGLs, fractionating NGLs and wholesale propanelogistics. Our Gathering and Processing segment consists of gathering, compressing, treating, and processing natural gas, producing and fractionating NGLs,and recovering condensate.General Trends and OutlookWe anticipate our business will continue to be affected by the following key trends. Our expectations are based on assumptions made by us andinformation currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, ouractual results may vary materially from our expected results.Our business is impacted by commodity prices and volumes. We mitigate a significant portion of commodity price risk on an overall Partnership basisby growing our fee based assets and by executing on our hedging program. Various factors impact both commodity prices and volumes, and as indicated inItem 7A. "Quantitative and Qualitative Disclosures about Market Risk", we have sensitivities to certain cash and non-cash changes in commodity prices.In the long-term, our belief is that commodity prices will continue to be at levels which support growth in crude, condensate, natural gas, and NGLproduction. We expect future commodity prices will be influenced by the severity of winter and summer weather, tariffs and other global economicconditions, the level of North American production and drilling activity by exploration and production companies and the balance of trade between importsand exports of liquid natural gas, NGLs and crude oil.Our business is primarily driven by the level of production of natural gas by producers and of NGLs from processing plants connected to our pipelinesand fractionators. These volumes can be affected by, among other things, reduced drilling activity, severe weather disruptions, operational outages andethane rejection.51NGL prices are impacted by the balance of supply and demand from petrochemical and refining industries and export facilities. The petrochemicalindustry has been making significant investment in building, expanding and converting facilities to use lighter NGL-based feedstocks, including ethane intheir chemical plants. As these facilities commence operations, ethane demand is expected to increase which could provide price support for increasedrecovery of ethane at gas processing plants. We believe these new facilities will cause increased demand over time, which should provide support for theincreasing supply of ethane. In addition, export facilities are being expanded and built, which provide support for the increasing supply of NGLs. Althoughthere can be, and has been, volatility in NGL prices, longer term we believe there will be sufficient demand in NGLs to support increasing supply.We hedge commodity prices associated with a portion of our expected natural gas, NGL and condensate equity volumes in our Gathering andProcessing segment. Drilling activity levels vary by geographic area; we will continue to target our strategy in geographic areas where we expect producerdrilling activity.Recent significant NGL supply growth has resulted in industry wide infrastructure constraints at pipeline and fractionation facilities. We believe we arewell positioned to manage through these constraints as a large, integrated midstream company, but growth of our business could be dampened in the nearterm while more industry wide pipeline and fractionation facilities are developed. Although there may be infrastructure constraints in the near term, webelieve our growth projects and other industry wide projects coming on-line over the next two years will help mitigate those constraints. We believe theseprojects being developed will enable us to meet the demand of our customers.We believe our contract structure with our producers provides us with significant protection from credit risk since we generally hold the product, sell itand withhold our fees prior to remittance of payments to the producer. Currently, our top 20 producers account for a majority of the total natural gas that wegather and process and of these top 20 producers, 9 have investment grade credit ratings while the remainder do not.In addition to the U.S. financial markets, many businesses and investors continue to monitor global economic conditions. Uncertainty abroad maycontribute to volatility in domestic financial and commodity markets.We believe we are positioned to withstand current and future commodity price volatility as a result of the following:•Our growing fee-based business represents a significant portion of our margins.•We have positive operating cash flow from our well-positioned and diversified assets.•We have a well-defined and targeted hedging program.•We manage our disciplined capital growth program with a significant focus on fee-based agreements and projects with long term volumeoutlooks.•We believe we have a solid capital structure and balance sheet.•We believe we have access to sufficient capital to fund our growth.During 2019, our strategic objectives will continue to focus on maintaining stable Distributable Cash Flows from our existing assets and executing onopportunities to sustain and ultimately grow our long-term Distributable Cash Flows. We believe the key elements to stable Distributable Cash Flows are thediversity of our asset portfolio, our fee-based business which represents a significant portion of our estimated margins, plus our hedged commodity position,the objective of which is to protect against downside risk in our Distributable Cash Flows.We have engaged in a disciplined growth strategy in recent years focusing on our key areas of operations. Our targeted strategy may take numerousforms such as organic build opportunities within our footprint, joint venture opportunities, and acquisitions. Growth opportunities will be evaluated incooperation with producers and customers based on the expected level of drilling activity in these geographic regions and the impacts of higher costs ofcapital.Some of our growth projects include the following:•Within our Logistics and Marketing Segment, we increased the capacity of the Sand Hills pipeline to 485 MBbls/d during the fourth quarter of2018.52•We increased the capacity of the Southern Hills pipeline at the end of the third quarter to approximately 190 MBbls/d.•We are participating in the Front Range 100 MBls/d and Texas Express 90 MBls/d expansions adding NGL takeaway from the DJ Basin. Bothexpansions are expected to go into service in the third quarter of 2019.•We have a 33% ownership option in the Cheyenne Connector pipeline. The Cheyenne Connector pipeline will have an initial capacity of atleast 600 MMcf/day and is expected to be in service in the fourth quarter of 2019, subject to certain conditions, including required approvalsfrom the Federal Energy Regulatory Commission.•We are adding NGL takeaway to the DJ Basin with our Southern Hills pipeline extension via the White Cliffs Pipeline, with capacity of 90MBls/d, expandable to 120 MBls/d. Expected completion is in the fourth quarter of 2019.•We have a 25% ownership interest in the Gulf Coast Express pipeline, or "GCX". The GCX project is designed to transport approximately 2 Bcf/dof natural gas, and is fully subscribed. The natural gas takeaway pipeline is under construction and is anticipated to be in-service in the fourthquarter of 2019.•We hold an option to acquire a 30% ownership interest in two 150 MBbls/d fractionators to be constructed within Phillips 66's Sweeny Hub,exercisable at the in-service date, which is expected to be in late 2020.•Within our Gathering and Processing Segment, construction of our up to 300 MMcf/d O'Connor 2 facility and associated gatheringinfrastructure, located in the DJ Basin, is progressing. O'Connor 2 is comprised of 200 MMcf/d of processing capacity and up to 100 MMcf/d ofbypass. We expect to place the plant into service in the second quarter of 2019, and the bypass into service in the third quarter of 2019.•We have secured land and filed permits for Bighorn, a natural gas processing facility in the DJ Basin, with capacity of up to 1.0 Bcf/d includingbypass. The Bighorn facility is expected to be placed into service in phases beginning in the second quarter of 2020.We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. Our 2019 plan includes maintenance capital expendituresof between $90 million and $110 million, and expansion capital expenditures of between $600 million and $800 million. Expansion capital expenditures areexpected to include the construction of the O'Connor 2 plant in our DJ Basin as well as the construction of the Gulf Coast Express pipeline, the Front Rangeand Texas Express expansions and the extension of Southern Hills into the DJ Basin via the White Cliffs Pipeline, which are shown as investments inunconsolidated affiliates in our consolidated statements of cash flows.Recent EventsSale of Wholesale Propane BusinessOn January 30, 2019, we entered into a purchase and sale agreement with NGL Energy Partners LP to sell Gas Supply Resources, our wholesale propanebusiness primarily consisting of seven natural gas liquids terminals in the Eastern United States within our Logistics and Marketing segment forapproximately $90 million, subject to customary purchase price adjustments. The transaction is expected to close effective March 1, 2019. We expect torecognize a loss on sale of approximately $8 million, net of goodwill, in the first quarter of 2019.Issuance of Senior NotesOn January 18, 2019, we issued an additional $325 million of additional aggregate principal amount to our existing $500 million 5.375% Senior Notesdue July 2025. The full $825 million 5.375% Senior Notes due July 2025 will be treated as a single series of debt. We received proceeds of $324 million, netof underwriters’ fees, related expenses and issuance premiums, which we expect to use for general partnership purposes including the funding of capitalexpenditures and repayment of outstanding indebtedness under the Credit Agreement. Interest on the notes will be paid semi-annually in arrears on the 15thday of January and July of each year, commencing July 15, 2019.Preferred Units Issuance53In October 2018 , we issued 4,400,000 of our Series C Preferred Units representing limited partnership interests (including a partial exercise of theunderwriters’ option to purchase additional Series C Preferred Units) at a price of $25 per unit. We used the net proceeds of $106 million from the issuance ofthe Series C Preferred Units for general partnership purposes including funding capital expenditures and the repayment of outstanding indebtedness underthe Credit Agreement.Common and Preferred DistributionsOn January 23, 2019, we announced that the board of directors of the General Partner declared a quarterly distribution on our common units of $0.78per common unit. The distribution will be paid on February 14, 2019 to unitholders of record on February 4, 2019.On the same date, the board of directors of the General Partner declared a quarterly distribution on our Series B and Series C Preferred Units of $0.4922and $0.4969 per unit, respectively. The Series B distributions will be paid on March 15, 2019 to unitholders of record on March 1, 2019. The Series Cdistribution will be paid on April 15, 2019 to unitholders of record on April 1, 2019.Factors That May Significantly Affect Our ResultsLogistics and Marketing SegmentOur Logistics and Marketing segment operating results are impacted by, among other things, the throughput volumes of the NGLs we transport on ourNGL pipelines and the volumes of NGLs we fractionate and store. We transport, fractionate and store NGLs primarily on a fee basis. Throughput may benegatively impacted as a result of our customers operating their processing plants in ethane rejection mode, often as a result of low ethane prices relative tonatural gas prices. Factors that impact the supply and demand of NGLs, as described below in our Gathering and Processing segment, may also impact thethroughput and volume for our Logistics and Marketing segment.These contractual arrangements may require our customers to commit a minimum level of volumes to our pipelines and facilities, thereby mitigating ourexposure to volume risk. However, the results of operations for this business segment are generally dependent upon the volume of product transported,fractionated or stored and the level of fees charged to customers. We do not take title to the products transported on our NGL pipelines, fractionated in ourfractionation facilities or stored in our storage facility; rather, the customer retains title and the associated commodity price risk. The volumes of NGLstransported on our pipelines are dependent on the level of production of NGLs from processing plants connected to our NGL pipelines. When natural gasprices are high relative to NGL prices, it is less profitable to process natural gas because of the higher value of natural gas compared to the value of NGLs andbecause of the increased cost of separating the NGLs from the natural gas. As a result, we have experienced periods in the past, in which higher natural gas orlower NGL prices reduce the volume of NGLs extracted at plants connected to our NGL pipelines and, in turn, lower the NGL throughput on our assets.Our results of operations for our Logistics and Marketing segment are also impacted by increases and decreases in the volume, price and basisdifferentials of natural gas associated with our natural gas storage and pipeline assets, as well as our underlying derivatives associated with these assets. Wemanage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activitiesrelated to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads. A timespread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time.Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We mayexecute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock ina margin on our physical purchases and sales of gas, including injections and withdrawals from storage.We manage our wholesale propane margins by selling propane to propane distributors under annual sales agreements negotiated each spring whichspecify floating price terms that provide us a margin in excess of our floating index-based supply costs under our supply purchase arrangements. Ourportfolio of multiple supply sources and storage capabilities allows us to actively manage our propane supply purchases and to lower the aggregate cost ofsupplies. Based on the carrying value of our inventory, timing of inventory transactions and the volatility of the market value of propane, we havehistorically and may continue to periodically recognize non-cash lower of cost or market inventory adjustments. In addition, we may use financialderivatives to manage the value of our propane inventories.54Gathering and Processing SegmentOur results of operations for our Gathering and Processing segment are impacted by (1) the prices of and relationship between commodities such asNGLs, crude oil and natural gas, (2) increases and decreases in the wellhead volume and quality of natural gas that we gather, (3) the associated Btu contentof our system throughput and our related processing volumes, (4) the operating efficiency and reliability of our processing facilities, (5) potential limitationson throughput volumes arising from downstream and infrastructure capacity constraints, and (6) the terms of our processing contract arrangements withproducers. This is not a complete list of factors that may impact our results of operations but, rather, are those we believe are most likely to impact thoseresults.Volume and operating efficiency generally are driven by wellhead production, plant recoveries, operating availability of our facilities, physicalintegrity and our competitive position on a regional basis, and more broadly by demand for natural gas, NGLs and condensate. Historical and current trendsin the price changes of commodities may not be indicative of future trends. Volume and prices are also driven by demand and take-away capacity for residuenatural gas and NGLs.Our processing contract arrangements can have a significant impact on our profitability and cash flow. Our actual contract terms are based upon avariety of factors, including the commodity pricing environment at the time the contract is executed, natural gas quality, geographic location, customerrequirements and competition from other midstream service providers. Our gathering and processing contract mix and, accordingly, our exposure to naturalgas, NGL and condensate prices, may change as a result of producer preferences, impacting our expansion in regions where certain types of contracts are morecommon as well as other market factors. We generate our revenues and our gross margin for our Gathering and Processing segment principally from contractsthat contain a combination of fee based arrangements and percent-of-proceeds/liquids arrangements.Our Gathering and Processing segment operating results are impacted by market conditions causing variability in natural gas, crude oil and NGL prices.The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by drilling activity, which maybe impacted by prevailing commodity prices. The number of active oil and gas drilling rigs in the United States has increased, from 882 on December 31,2017 to 993 on December 31, 2018. Although the prevailing price of residue natural gas has less short-term significance to our operating results than theprice of NGLs, in the long-term, the growth and sustainability of our business depends on commodity prices being at levels sufficient to provide incentivesand capital for producers to explore for and produce natural gas.The prices of NGLs, crude oil and natural gas can be extremely volatile for periods of time, and may not always have a close relationship. Due to ourhedging program, changes in the relationship of the price of NGLs and crude oil may cause our commodity price exposure to vary, which we have attemptedto capture in our commodity price sensitivities in Item 7A in this 2018 Form 10-K, “Quantitative and Qualitative Disclosures about Market Risk.” Our resultsmay also be impacted as a result of non-cash lower of cost or market inventory or imbalance adjustments, which occur when the market value of commoditiesdecline below our carrying value.We face strong competition in acquiring raw natural gas supplies. Our competitors in obtaining additional gas supplies and in gathering and processingraw natural gas includes major integrated oil and gas companies, interstate and intrastate pipelines, and companies that gather, compress, treat, process,transport, store and/or market natural gas. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periodsof high commodity prices for crude oil, natural gas and/or NGLs. Competition is also increased in those geographic areas where our commercial contractswith our customers are shorter term and therefore must be renegotiated on a more frequent basis.WeatherThe economic impact of severe weather may negatively affect the nation’s short-term energy supply and demand, and may result in commodity pricevolatility. Additionally, severe weather may restrict or prevent us from fully utilizing our assets, by damaging our assets, interrupting utilities, and throughpossible NGL and natural gas curtailments downstream of our facilities, which restricts our production. These impacts may linger past the time of the actualweather event. Although we carry insurance on the vast majority of our assets, insurance may be inadequate to cover our loss in some instances, and in certaincircumstances we have been unable to obtain insurance on commercially reasonable terms, if at all.55Capital MarketsVolatility in the capital markets may impact our business in multiple ways, including limiting our producers’ ability to finance their drilling programsand operations and limiting our ability to support or fund our operations and growth. These events may impact our counterparties’ ability to perform undertheir credit or commercial obligations. Where possible, we have obtained additional collateral agreements, letters of credit from highly rated banks, or havemanaged credit lines to mitigate a portion of these risks.Impact of InflationInflation has been relatively low in the United States in recent years. However, the inflation rates impacting our business fluctuate throughout the broadeconomic and energy business cycles. Consequently, our costs for chemicals, utilities, materials and supplies, labor and major equipment purchases mayincrease during periods of general business inflation or periods of relatively high energy commodity prices.OtherThe above factors, including sustained deterioration in commodity prices and volumes, other market declines or a decline in our common unit price,may negatively impact our results of operations, and may increase the likelihood of a non-cash impairment charge or non-cash lower of cost or marketinventory adjustments.How We Evaluate Our OperationsOur management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (1)volumes; (2) gross margin and segment gross margin; (3) operating and maintenance expense, and general and administrative expense; (4) adjusted EBITDA;(5) adjusted segment EBITDA; and (6) Distributable Cash Flow. Gross margin, segment gross margin, adjusted EBITDA, adjusted segment EBITDA, andDistributable Cash Flow are not measures under accounting principles generally accepted in the United States of America ("GAAP"). To the extent permitted,we present certain non-GAAP measures and reconciliations of those measures to their most directly comparable financial measures as calculated andpresented in accordance with GAAP. These non-GAAP measures may not be comparable to a similarly titled measure of another company because otherentities may not calculate these non-GAAP measures in the same manner.Volumes - We view wellhead, throughput and storage volumes as important factors affecting our profitability. We gather and transport some of thenatural gas and NGLs under fee-based transportation contracts. Revenue from these contracts is derived by applying the rates stipulated to the volumestransported. Pipeline throughput volumes from existing wells connected to our pipelines will naturally decline over time as wells deplete. Accordingly, tomaintain or to increase throughput levels on these pipelines and the utilization rate of our natural gas processing plants, we must continually obtain newsupplies of natural gas and NGLs. Our ability to maintain existing supplies of natural gas and NGLs and obtain new supplies are impacted by: (1) the level ofworkovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines; and (2) our ability tocompete for volumes from successful new wells in other areas. The throughput volumes of NGLs and gas on our pipelines are substantially dependent uponthe quantities of NGLs and gas produced at our processing plants, as well as NGLs and gas produced at other processing plants that have pipelineconnections with our NGL and gas pipelines. We regularly monitor producer activity in the areas we serve and in which our pipelines are located, and pursueopportunities to connect new supply to these pipelines. We also monitor our inventory in our NGL and gas storage facilities, as well as overall demand forstorage based on seasonal patterns and other market factors such as weather and overall demand.56Results of OperationsConsolidated OverviewThe following table and discussion is a summary of our consolidated results of operations for the years ended December 31, 2018, 2017 and 2016. Theresults of operations by segment are discussed in further detail following this consolidated overview discussion. Year Ended December 31, Variance 2018 vs. 2017 Variance 2017 vs. 2016 2018 2017 2016 Increase(Decrease) Percent Increase(Decrease) Percent (millions, except operating data)Operating revenues (a): Logistics and Marketing $9,014 $7,757 $6,186 $1,257 16 % $1,571 25 %Gathering and Processing 5,843 5,467 4,490 376 7 % 977 22 %Inter-segment eliminations (5,035) (4,762) (3,783) 273 6 % 979 26 %Total operating revenues 9,822 8,462 6,893 1,360 16 % 1,569 23 %Purchases and related costs Logistics and Marketing (8,789) (7,557) (5,981) 1,232 16 % 1,576 26 %Gathering and Processing (4,265) (4,090) (3,263) 175 4 % 827 25 %Inter-segment eliminations 5,035 4,762 3,783 273 6 % 979 26 %Total purchases (8,019) (6,885) (5,461) 1,134 16 % 1,424 26 %Operating and maintenance expense (760) (661) (670) 99 15 % (9) (1)%Depreciation and amortization expense (388) (379) (378) 9 2 % 1 — %General and administrative expense (276) (290) (292) (14) (5)% (2) (1)%Asset impairments (145) (48) — 97 * 48 *Other (expense) income, net (11) (11) 65 — — % (76) *Gain on sale of assets, net — 34 35 (34) * (1) (3)%Restructuring costs — — (13) — * 13 100 %Loss from financing activities (19) — — 19 * — *Earnings from unconsolidated affiliates (b) 370 303 282 67 22 % 21 7 %Interest expense (269) (289) (321) (20) (7)% (32) (10)%Income tax expense (3) (2) (46) 1 50 % (44) (96)%Net income attributable to noncontrollinginterests (4) (5) (6) (1) (20)% (1) (17)%Net income attributable to partners $298 $229 $88 $69 30 % $141 *Other data: Gross margin (c): Logistics and Marketing $225 $200 $205 $25 13 % $(5) (2)%Gathering and Processing 1,578 1,377 1,227 201 15 % 150 12 %Total gross margin $1,803 $1,577 $1,432 $226 14 % $145 10 % Non-cash commodity derivative mark-to-market $108 $(28) $(139) $136 * $111 *Natural gas wellhead (MMcf/d) (d) 4,769 4,531 5,124 238 5 % (593) (12)%NGL gross production (MBbls/d) (d) 413 375 393 38 10 % (18) (5)%NGL pipelines throughput (MBbls/d) (d) 582 460 420 122 27 % 40 10 %* Percentage change is not meaningful.(a)Operating revenues include the impact of trading and marketing gains (losses), net.(b)Earnings for Discovery, Sand Hills, Southern Hills, Front Range, Mont Belvieu 1 and Texas Express include the amortization of the net differencebetween the carrying amount of the investments and the underlying equity of the entities.(c)Gross margin consists of total operating revenues less purchases and related costs. Segment gross margin for each segment consists of total operatingrevenues for that segment less purchases and related costs for that segment. Please read “Reconciliation of Non-GAAP Measures”.(d)For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the wellhead and throughput volumes and NGLproduction.57Year Ended December 31, 2018 vs. Year Ended December 31, 2017Total Operating Revenues — Total operating revenues increased $1,360 million in 2018 compared to 2017 primarily as a result of the following:•$1,257 million increase for our Logistics and Marketing segment primarily due to higher NGL and crude prices, higher gas and NGL salesvolumes which impacts both sales and purchases, partially offset by lower natural gas prices, unfavorable commodity derivative activity and theimplementation of ASC 606; and•$376 million increase for our Gathering and Processing segment due to higher NGL and crude prices, higher gas and NGL sales volumesimpacting both sales and purchases due to increased drilling activity in our Eagle Ford system and the impact of Hurricane Harvey in 2017 in theSouth region, growth projects primarily related to our DJ Basin system in the North region and increased volumes, improved operationalperformance in our Midcontinent region and favorable commodity derivative activity. These increases were partially offset by lower natural gasprices, the sale of our Douglas gathering system in June 2017 and the implementation of ASC 606;These increases were partially offset by:•$273 million change in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment toour Logistics and Marketing segment, primarily due to higher gas and NGL sales volume, higher commodity prices and the implementation ofASC 606.Total Purchases — Total purchases increased $1,134 million in 2018 compared to 2017 primarily as a result of the following:•$1,232 million increase for our Logistics and Marketing segment for the reasons discussed above.•$175 million increase for our Gathering and Processing segment for the reasons discussed above;These increases were partially offset by:•$273 million change in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment toour Logistics and Marketing segment, primarily due to higher gas and NGL sales volumes and higher commodity prices and the implementationof ASC 606;Operating and Maintenance Expense — Operating and maintenance expense increased in 2018 compared to 2017 primarily as a result of increasedreliability spending, planned maintenance spending associated with anticipated volume growth and costs associated with the ramp-up of our Mewbourn 3plant.General and Administrative Expense — General and administrative expense decreased in 2018 compared to 2017 primarily as a result of lower contractservices.Asset Impairments — Asset impairments in 2018 represent the impairment of property, plant and equipment in our Midcontinent and South regions.Asset impairments in 2017 represent the impairment of property, plant and equipment and intangible assets in our South region.Gain on Sale of Assets, Net — The gain on sale in 2017 represents the sale of our Douglas gathering system.Loss from Financing Activities — Loss from financing activities in 2018 represents a loss on redemption of senior notes.Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2018 compared to 2017 primarily as a result of theexpansion and volume ramp up of the Sand Hills NGL pipeline and higher volumes on the Southern Hills NGL pipeline in our Logistics and Marketingsegment partially offset by a decrease from Discovery in our Gathering and Processing segment primarily due to lower production volumes from two offshorewells.Interest Expense - Interest expense decreased in 2018 compared to 2017 as a result of higher capitalized interest and a lower effective interest rate.Net Income Attributable to Partners — Net income attributable to partners increased in 2018 compared to 2017 for the reasons discussed above.Gross Margin — Gross margin increased $226 million in 2018 compared to 2017 primarily as a result of the following:58•$201 million increase for our Gathering and Processing segment primarily related to increased volumes from increased drilling activity in ourEagle Ford system and the impact of Hurricane Harvey in 2017 in the South region, growth projects primarily related to our DJ Basin system inthe North region, increased volumes and improved operational performance in the Midcontinent region, favorable commodity derivative activityand higher commodity prices. These increases were partially offset by lower volumes in our Permian region due to weather impacting operations,a third-party line strike and operational factors and the sale of our Douglas gathering system in June 2017;•$25 million increase for our Logistics and Marketing segment primarily related to higher gas marketing margins due to favorable commodityspreads primarily associated with Guadalupe and higher NGL marketing margins and transported volumes, partially offset by unfavorablecommodity derivative activity, lower margins on wholesale propane and the expiration of a commercial arrangement.Year Ended December 31, 2017 vs. Year Ended December 31, 2016Total Operating Revenues — Total operating revenues increased $1,569 million in 2017 compared to 2016 primarily as a result of the following:•$1,571 million increase for our Logistics and Marketing segment primarily due to increased commodity prices and favorable commodityderivative activity, partially offset by lower gas and NGL sales volumes and the sale of our Northern Louisiana System;•$977 million increase for our Gathering and Processing segment primarily due to higher commodity prices, higher gas and NGL sales volumesprimarily related to our North region which impacts both sales and purchases, and higher transportation, processing and other, primarily relatedto fee based contract realignment efforts. These increases were partially offset by lower gas and NGL sales volumes in the South, Midcontinentand Permian regions, unfavorable commodity derivative activity and the sale of our Northern Louisiana system and Douglas gathering system;These increases were partially offset by:•$979 million increase in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment toour Logistics and Marketing segment, primarily due to higher commodity prices, partially offset by lower gas and NGL sales volumes.Total Purchases — Total purchases increased $1,424 million in 2017 compared to 2016 primarily as a result of the following:•$1,576 million increase for our Logistics and Marketing segment for the reasons discussed above;•$827 million increase for our Gathering and Processing segment for the reasons discussed above;These increases were partially offset by:•$979 million increase in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment toour Logistics and Marketing segment, primarily due to higher commodity prices, partially offset by lower gas and NGL sales volumes.Operating and Maintenance Expense — Operating and maintenance expense decreased in 2017 compared to 2016 primarily as a result of the sale ofour Northern Louisiana system in July 2016 and Douglas gathering system in June 2017, decreased base operating costs resulting from cost savingsinitiatives, partially offset by increased gathering pipeline remediation spending, planned maintenance spending associated with anticipated volume growthand additional expenses related to Hurricane Harvey.General and Administrative Expense - General and administrative expense decreased in 2017 compared to 2016, primarily due to investment in digitaltransformation, offset by nonrecurring costs in 2016 driven the Transaction.Asset impairments — Asset impairments in 2017 represent the impairment of property, plant and equipment and intangible assets in our South region.59Other (Expense) Income — Other expense in 2017 primarily represents the write-off of property, plant and equipment associated with the expiration of alease. Other income in 2016 primarily represents a producer settlement, net of legal fees, partially offset by the write-off of property, plant and equipment andother long-term assets.Gain on Sale of Assets, net — The gain on sale in 2017 represents the sale of our Douglas gathering system. The gain on sale in 2016 represents the saleof our Northern Louisiana system, partially offset by a loss on sale of non-core assets.Restructuring Costs - Restructuring costs in 2016 related to our headcount reduction in April of 2016.Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2017 compared to 2016 primarily as a result of theexpansion and volume ramp up of the Sand Hills NGL pipeline in our Logistics and Marketing segment partially offset by a decrease from Discovery in ourGathering and Processing segment primarily due to lower production volumes from two offshore wells at Discovery. We expect continued volume declinesfrom these wells to impact future earnings.Interest Expense - Interest expense decreased in 2017 compared to 2016 as a result of lower average outstanding debt balances.Income Tax (Expense) Benefit — Income tax expense decreased in 2017 compared to 2016 primarily due to the conversion of a subsidiary from acorporation to a limited liability company for federal income tax purposes in 2016.Net Income Attributable to Partners — Net income attributable to partners increased in 2017 compared to 2016 for the reasons discussed above.Gross Margin — Gross margin increased $145 million in 2017 compared to 2016 primarily as a result of the following:•$150 million increase for our Gathering and Processing segment primarily related to higher commodity prices, increased volume from growthprojects, higher margins associated with a specific producer arrangement, higher NGL recoveries and a producer settlement in our North region,and contract realignment efforts in our Permian and Midcontinent regions. These increases were partially offset by lower volumes across ourSouth, Midcontinent, and Permian regions due to reduced drilling activity in prior periods, the impact of Hurricane Harvey primarily in theSouth and Permian regions, the sale of our Northern Louisiana system, the sale of our Douglas gathering system and unfavorable commodityderivative activity.These increases were partially offset by:•$5 million decrease for our Logistics and Marketing segment primarily related to lower margins on wholesale propane and the expiration of acontract, the sale of our Northern Louisiana system, lower gas storage margins and lower transportation volumes on certain of our NGLpipelines, partially offset by higher NGL marketing margins, higher gas marketing margins and favorable commodity derivative activity.60Supplemental Information on Unconsolidated AffiliatesThe following table presents financial information related to unconsolidated affiliates:Earnings from investments in unconsolidated affiliates were as follows: Year Ended December 31, 2018 2017 2016 (millions)DCP Sand Hills Pipeline, LLC $223 $148 $110DCP Southern Hills Pipeline, LLC 68 47 44Front Range Pipeline LLC 24 17 19Texas Express Pipeline LLC 19 9 9Mont Belvieu Enterprise Fractionator 10 13 16Mont Belvieu 1 Fractionator 16 6 9Discovery Producer Services LLC 8 61 73Other 2 2 2Total earnings from unconsolidated affiliates $370 $303 $282Distributions received from unconsolidated affiliates were as follows: Year Ended December 31, 2018 2017 2016 (millions)DCP Sand Hills Pipeline, LLC $252 $169 $139DCP Southern Hills Pipeline, LLC 83 62 56Front Range Pipeline LLC 29 17 24Texas Express Pipeline LLC 20 12 11Mont Belvieu Enterprise Fractionator 9 13 18Mont Belvieu 1 Fractionator 15 6 11Discovery Producer Services LLC 30 85 94Other 3 3 3Total distributions from unconsolidated affiliates $441 $367 $35661Results of Operations — Logistics and Marketing SegmentThe results of operations for our Logistics and Marketing segment are as follows: Year Ended December 31, Variance 2018 vs. 2017 Variance 2017 vs. 2016 2018 2017 2016 Increase(Decrease) Percent Increase(Decrease) Percent (millions, except operating data)Operating revenues: Sales of natural gas, NGLs and condensate $9,017 $7,667 $6,094 $1,350 18 % $1,573 26 %Transportation, processing and other 57 64 70 (7) (11)% (6) (9)%Trading and marketing (losses) gains, net (60) 26 22 (86) * 4 18 %Total operating revenues 9,014 7,757 6,186 1,257 16 % 1,571 25 %Purchases and related costs (8,789) (7,557) (5,981) 1,232 16 % 1,576 26 %Operating and maintenance expense (47) (41) (43) 6 15 % (2) (5)%Depreciation and amortization expense (15) (14) (15) 1 7 % (1) (7)%General and administrative expense (12) (11) (9) 1 9 % 2 22 %Other expense, net (4) (11) (5) (7) (64)% 6 *Earnings from unconsolidated affiliates (a) 362 243 209 119 49 % 34 16 %Gain on sale of assets, net — — 16 — — (16) *Segment net income attributable to partners $509 $366 $358 $143 39 % $8 2 %Other data: Segment gross margin (b) $225 $200 $205 $25 13 % $(5) (2)%Non-cash commodity derivative mark-to-market $(4) $(4) $(20) $— * $16 (80)%NGL pipelines throughput (MBbls/d) (c) 582 460 420 122 27 % 40 10 %* Percentage change is not meaningful.(a)Earnings from unconsolidated affiliates for Sand Hills, Southern Hills, Front Range, Mont Belvieu 1 and Texas Express include the amortization ofthe net difference between the carrying amount of our investments and the underlying equity of the entities.(b)Segment gross margin consists of total operating revenues less purchases and related costs. Please read “Reconciliation of Non-GAAP Measures”.(c)For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the throughput volume.Year Ended December 31, 2018 vs. Year Ended December 31, 2017Total Operating Revenues — Total operating revenues increased $1,257 million in 2018 compared to 2017, primarily as a result of the following:•$853 million increase as a result of higher NGL and crude prices, partially offset by lower natural gas prices, which impacted both sales andpurchases, before the impact of derivative activity, and•$497 million increase attributable to higher gas and NGL sales volumes, which impacted both sales and purchases, offset by $149 million due tothe implementation of ASC 606;These increases were partially offset by:62•$86 million decrease as a result of commodity derivative activity attributable to an increase in realized cash settlement losses due to movementsin forward prices of commodities in 2018; and•$7 million decrease in transportation, processing and other primarily related to the expiration of a commercial arrangement in our wholesalepropane business.Purchases and related costs — Purchases and related costs increased $1,232 million in 2018 compared to 2017, primarily as a result of higher NGL and crudeprices and higher gas and NGL sales volumes, partially offset by lower natural gas prices and the implementation of ASC 606.Operating and Maintenance Expense — Operating and maintenance expense increased in 2018 compared to 2017 primarily as a result of increasedreliability spending and planned maintenance spending associated with anticipated volume growth.Other Expense, net — Other expense in 2018 represents the write-off of property plant and equipment and long term inventory valuations. Otherexpense in 2017 represents the write-off of property, plant and equipment associated with the expiration of a lease.Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2018 compared to 2017 primarily as a result of higherthroughput volumes on Sand Hills due to ongoing capacity expansions, higher volumes on the Southern Hills NGL pipeline and accelerated recognition ofrevenues at Texas Express.Segment Gross Margin — Segment gross margin increased $25 million in 2018 compared to 2017, primarily as a result of the following:•$104 million increase in gas marketing margins due to favorable commodity spreads primarily associated with Guadalupe; and•$13 million increase in NGL marketing margins and transported volumes;These increases are partially offset by;•$86 million decrease as a result of commodity derivative activity discussed above, and;•$6 million decrease as a result of lower margins and the expiration of a commercial arrangement in our wholesale propane business, partiallyoffset by higher throughput volumes.NGL Pipelines Throughput — NGL pipelines throughput increased in 2018 compared to 2017 primarily as a result of higher throughput volumes onSand Hills due to ongoing capacity expansions on the Sand Hills pipeline and higher throughput volumes on Southern Hills primarily due to ethanerecovery.Year Ended December 31, 2017 vs. Year Ended December 31, 2016Total Operating Revenues — Total operating revenues increased $1,571 million in 2017 compared to 2016, primarily as a result of the following:•$1,934 million increase as a result of higher commodity prices, which impacted both sales and purchases, before the impact of derivativeactivity; and•$4 million increase as a result of commodity derivative activity attributable to an decrease in unrealized commodity derivative losses of $16million partially offset by a $12 million decrease in realized cash settlement gains due to movements in forward prices of commodities in 2017;These increases were partially offset by:•$325 million decrease attributable to lower gas and NGL sales volumes, which impacted both sales and purchases;•$36 million decrease due to the sale of our Northern Louisiana system; and•$6 million decrease in transportation, processing and other primarily related to lower gas storage margins and lower transportation volumes oncertain of our NGL pipelines.63Purchases and related costs — Purchases and related costs increased $1,576 million in 2017 compared to 2016, primarily as a result of highercommodity prices, partially offset by lower gas and NGL sales volumes.Other Expense — Other expense in 2017 primarily represents the write-off of property, plant and equipment associated with the expiration of a leasewhile other expense in 2016 primarily represents the write-off of property, plant and equipment and other long term assets.Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2017 compared to 2016 primarily as a result of higherthroughput volumes on Sand Hills due to continued NGL production growth from the Permian basin and ongoing capacity expansions, partially offset bylower volumes and planned maintenance on the Mont Belvieu fractionators.Gain on sale of assets, net — The gain on sale in 2016 primarily represents the sale of our Northern Louisiana system.Segment Gross Margin — Segment gross margin decreased $5 million in 2017 compared to 2016, primarily as a result of the following:•$11 million decrease as a result of lower margins and the expiration of a contract in our wholesale propane business;•$8 million decrease as a result of lower gas storage margins and lower transportation volumes on certain of our NGL pipelines; and•$7 million decrease as a result of the sale of our Northern Louisiana system;These decreases are partially offset by;•$9 million increase as a result of higher NGL marketing margins;•$8 million increase as a result of higher gas marketing margins; and•$4 million increase as a result of commodity derivative activity discussed above.NGL Pipelines Throughput — NGL pipelines throughput increased in 2017 compared to 2016 primarily as a result of higher throughput volumes onSand Hills due to continued NGL production growth from the Permian basin and ongoing capacity expansions on the Sand Hills pipeline.64Results of Operations — Gathering and Processing SegmentThe results of operations for our Gathering and Processing segment are as follows: Year Ended December 31, Variance 2018 vs. 2017 Variance2017 vs. 2016 2018 2017 2016 Increase(Decrease) Percent Increase(Decrease) Percent (millions, except operating data)Operating revenues: Sales of natural gas, NGLs and condensate $5,392 $4,943 $3,955 $449 9 % $988 25 %Transportation, processing and other 432 590 580 (158) (27)% 10 2 %Trading and marketing gains (losses), net 19 (66) (45) 85 * (21) (47)%Total operating revenues 5,843 5,467 4,490 376 7 % 977 22 %Purchases and related costs (4,265) (4,090) (3,263) 175 4 % 827 25 %Operating and maintenance expense (692) (602) (611) 90 15 % (9) (1)%Depreciation and amortization expense (346) (343) (344) 3 1 % (1) — %General and administrative expense (19) (19) (14) — — % 5 36 %Asset impairments (145) (48) — 97 * 48 *Other (expense) income, net (6) — 73 (6) * (73) *Gain on sale of assets, net — 34 19 (34) * 15 79 %Earnings from unconsolidated affiliates (a) 8 60 73 (52) (87)% (13) (18)%Segment net income 378 459 423 (81) (18)% 36 9 %Segment net income attributable to noncontrollinginterests (4) (5) (6) (1) (20)% (1) (17)%Segment net income attributable to partners $374 $454 $417 $(80) (18)% $37 9 %Other data: Segment gross margin (b) $1,578 $1,377 $1,227 $201 15 % $150 12 %Non-cash commodity derivative mark-to-market $112 $(24) $(119) $136 * $95 80 %Natural gas wellhead (MMcf/d) (c) 4,769 4,531 5,124 238 5 % (593) (12)%NGL gross production (MBbls/d) (c) 413 375 393 38 10 % (18) (5)%_____________ * Percentage change is not meaningful.(a)Earnings from unconsolidated affiliates includes our 40% ownership of Discovery. Earnings for Discovery include the amortization of the netdifference between the carrying amount of our investment and the underlying equity of the entity.(b)Segment gross margin consists of total operating revenues, less purchases and related costs. Please read “Reconciliation of Non-GAAP Measures”.(c)For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the wellhead volume and NGL production.Year Ended December 31, 2018 vs. Year Ended December 31, 2017Total Operating Revenues — Total operating revenues increased $376 million in 2018 compared to 2017, primarily as a result of the following:•$236 million increase primarily as a result of higher volumes due to increased drilling activity in our Eagle Ford system in the South region,growth projects primarily related to our DJ Basin system in the North region and65increased volumes and improved operational performance in the Midcontinent region, partially offset by the sale of our Douglas gatheringsystem in June 2017 in our North region and $149 million due to the implementation of ASC 606;•$213 million increase attributable to higher NGL and crude prices, partially offset by lower natural gas prices, which impacted both sales andpurchases, before the impact of derivative activity; and•$85 million increase as a result of commodity derivative activity attributable to an increase in unrealized commodity derivative gains of $136million, partially offset by a $51 million increase in realized cash settlement losses due to movements in forward prices of commodities in 2018;These increases were partially offset by:•$158 million decrease in transportation, processing and other primarily related to the implementation of ASC 606.Purchases and Related Costs — Purchases and related costs increased $175 million in 2018 compared to 2017 as a result of increased gas and NGLsales volumes in our South, Midcontinent and North regions and higher NGL and crude prices, partially offset by lower natural gas prices.Operating and Maintenance Expense — Operating and maintenance expense increased in 2018 compared to 2017 primarily as a result of increasedreliability spending, planned maintenance spending associated with anticipated volume growth and costs associated with the ramp-up of our Mewbourn 3plant.Asset Impairments — Asset impairments in 2018 represent the impairment of property, plant and equipment in our Midcontinent and South regions.Asset impairments in 2017 represent the impairment of property, plant and equipment and intangible assets in our South region.Other (Expense) Income — Other expense in 2018 represents the write-off of property, plant and equipment.Gain on Sale of Assets, Net — The gain on sale in 2017 represents the sale of our Douglas gathering system.Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates decreased in 2018 compared to 2017 primarily due to lowerproduction volumes from two offshore wells at Discovery.Segment Gross Margin — Segment gross margin increased $201 million in 2018 compared to 2017, primarily as a result of the following:•$84 million increase as a result of increased volume from increased drilling activity in our Eagle Ford system and the impact of Hurricane Harveyin 2017 in the South region, growth projects primarily related to our DJ Basin system in the North region and increased volumes and improvedoperational performance in the Midcontinent region;•$85 million increase as a result of commodity derivative activity as discussed above; and•$63 million increase as a result of higher commodity prices;These increases were partially offset by:•$16 million decrease primarily as a result of lower volumes due to operational factors, a third-party line strike and weather impacting operationsin the Permian region; and•$15 million decrease primarily as a result of the sale of our Douglas gathering system in June 2017.Total Wellhead — Natural gas wellhead increased in 2018 compared to 2017 reflecting higher volumes primarily from (i) growth projects within theNorth region, (ii) increased drilling activity in our Eagle Ford system and the impact of Hurricane Harvey in 2017 in the South region and (iii) highervolumes in the Midcontinent region due to improved operational performance partially offset by (iv) lower production volumes from two offshore wells atDiscovery in the South region (v) lower volumes in the Permian region due to operational factors and a third-party line strike and (vi) the sale of our Douglasgathering system within our North region.NGL Gross Production — NGL gross production increased in 2018 compared to 2017 primarily as a result of (i) increased drilling activity in the Southregion, (ii) ethane recoveries in the Midcontinent, Permian and North regions (iii) higher volumes in the Midcontinent region due to improved operationalperformance and (iv) growth projects within the North region.66Year Ended December 31, 2017 vs. Year Ended December 31, 2016 Total Operating Revenues — Total operating revenues increased $977 million in 2017 compared to 2016, primarily as a result of the following:•$1,280 million increase attributable to higher commodity prices, which impacted both sales and purchases, before the impact of derivativeactivity;•$100 million increase attributable to higher gas and NGL sales volumes due to the impact of a specific producer arrangement and growth projectsprimarily related to our DJ Basin system in our North region;•$10 million increase in transportation, processing and other primarily related to fee based contract realignment efforts, partially offset by lowervolumes in the South region and the sale of our Northern Louisiana system and Douglas gathering system;These increases were partially offset by:•$392 million decrease primarily as a result of lower volumes across our South, Midcontinent and Permian regions due to reduced drilling activityin prior periods and the impact of Hurricane Harvey primarily related to the South and Permian regions; and•$21 million decrease as a result of commodity derivative activity attributable to a $116 million increase in realized cash settlement losses,partially offset by a decrease in unrealized commodity derivative losses of $95 million due to movements in forward prices of commodities in2017.Purchases and Related Costs — Purchases and related costs increased $827 million in 2017 compared to 2016 as a result of higher commodity pricesand higher gas and NGL sales volumes in our North region, partially offset by decreased volumes in our South, Midcontinent and Permian regions.Operating and Maintenance Expense — Operating and maintenance expense decreased in 2017 compared to 2016 primarily as a result of the sale ofour Northern Louisiana system in July 2016 and Douglas gathering system in June 2017, decreased base operating costs resulting from cost savingsinitiatives, partially offset by increased gathering pipeline remediation spending, planned maintenance spending associated with anticipated volume growthand additional expenses related to Hurricane Harvey.General and Administrative Expense — General and administrative expense increased in 2017 compared to 2016 primarily as a result higher sales taxrefunds in 2016 from cost savings initiatives.Asset Impairments — Asset impairments in 2017 represent the impairment of property, plant and equipment and intangible assets in our South region.Other (Expense) Income — Other income in 2016 represents a producer settlement, net of legal fees partially offset by the write-off of property, plantand equipment.Gain on sale of assets, net - The gain on sale in 2017 represents the sale of our Douglas gathering system. The gain on sale in 2016 represents the saleof our Northern Louisiana system partially offset by a loss on sale of non-core assets.Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates decreased in 2017 compared to 2016 primarily due to lowerproduction volumes from two offshore wells at Discovery.Segment Gross Margin — Segment gross margin increased $150 million in 2017 compared to 2016, primarily as a result of the following:•$231 million increase as a result of higher commodity prices;•$35 million increase as a result of increased volume from growth projects, higher margins associated with a specific producer arrangement, andhigher NGL recoveries primarily related to our DJ Basin system and a producer settlement in our North region;These increases were partially offset by:67•$79 million decrease primarily as a result of lower volumes across our South, Midcontinent and Permian regions due to reduced drilling activityin prior periods and the impact of Hurricane Harvey, partially offset by fee based contract realignment efforts in the Permian and Midcontinentregions and operational efficiencies associated with our investment in digital transformation;•$16 million decrease as a result of the sale of our Northern Louisiana system in our South region and Douglas gathering system in our Northregion; and•$21 million decrease as a result of commodity derivative activity as discussed above.Total Wellhead — Natural gas wellhead decreased in 2017 compared to 2016 reflecting lower volumes primarily from (i) lower volumes associatedwith general declines within the South, Permian and Midcontinent regions (ii) the sale of our Northern Louisiana system within our South region and (iii) thesale of our Douglas gathering system within our North region and (iv) the impact of Hurricane Harvey primarily related to the South and Permian regions,partially offset by (v) general volume increases due to maximizing capacity utilization and growth projects within the North region.NGL Gross Production — NGL production decreased in 2017 compared to 2016 primarily as a result of (i) lower volumes associated with generaldeclines within the South, Permian and Midcontinent regions, (ii) the sale of our Northern Louisiana system within our South region and (iii) the sale of ourDouglas gathering system within our North region and (iv) the impact of Hurricane Harvey primarily related to the South and Permian regions, partially offsetby (v) general volume increases due to maximizing capacity utilization within the North region and (vi) intermittent higher ethane recoveries across allregions.Liquidity and Capital ResourcesWe expect our sources of liquidity to include:•cash generated from operations;•cash distributions from our unconsolidated affiliates;•borrowings under our Credit Agreement;•proceeds from asset rationalization;•debt offerings;•issuances of additional common units, preferred units or other securities;•borrowings under term loans, securitization agreements or other credit facilities; and•letters of credit.We anticipate our more significant uses of resources to include:•quarterly distributions to our common unitholders and General Partner, and distributions to our preferred unitholders;•payments to service our debt;•growth capital expenditures;•contributions to our unconsolidated affiliates to finance our share of their capital expenditures;•business and asset acquisitions; and•collateral with counterparties to our swap contracts to secure potential exposure under these contracts, which may, at times, be significantdepending on commodity price movements.We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditureand acquisition requirements and quarterly cash distributions for the next twelve months.68We routinely evaluate opportunities for strategic investments or acquisitions. Future material investments or acquisitions may require that we obtainadditional capital, assume third party debt or incur other long-term obligations. We have the option to utilize both equity and debt instruments as vehiclesfor the long-term financing of our investment activities and acquisitions.Based on current and anticipated levels of operations, we believe we have adequate committed financial resources to conduct our ongoing business,although deterioration in our operating environment could limit our borrowing capacity, impact our credit ratings, raise our financing costs, as well as impactour compliance with our financial covenant requirements under the Credit Agreement and the indentures governing our notes.Senior Notes — On January 18, 2019, we issued $325 million of additional aggregate principal amount to our existing $500 million 5.375% SeniorNotes due July 2025. The full $825 million 5.375% Senior Notes due July 2025 will be treated as a single series of debt. We received proceeds of $324million, net of underwriters’ fees, related expenses and issuance premiums, which we expect to use for general partnership purposes including the funding ofcapital expenditures and repayment of outstanding indebtedness under the Credit Agreement. Interest on the notes will be paid semi-annually in arrears onthe 15th day of January and July of each year, with the initial interest payment on July 15, 2019.Credit Agreement — As of December 31, 2018, we had unused borrowing capacity of $1,036 million, net of $13 million of letters of credit, and $351million of outstanding borrowings under the Credit Agreement. Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricinggrid. As of February 20, 2019, we had approximately $1,204 million of unused borrowing capacity under the Credit Agreement, net of $13 million of lettersof credit.Issuance of Securities — In November 2017, we filed a shelf registration statement with the SEC that became effective upon filing and allows us toissue an indeterminate amount of common units, preferred units, and debt securities. During the year ended December 31, 2018, we issued $155 million ofour Series B Preferred Units and $106 million of our Series C Preferred Units, net of offering costs. We also issued $825 million in aggregate principal amountof our 5.375% Senior Notes due July 2025 under this shelf registration statement.In August 2017, we filed a shelf registration statement with the SEC which allows us to issue up to $750 million in common units pursuant to our at-the-market program. During the year ended December 31, 2018, we did not issue any common units pursuant to this registration statement, and $750 millionremained available for future sales.Commodity Swaps and Collateral — Changes in natural gas, NGL and condensate prices and the terms of our processing arrangements have a directimpact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. Foradditional information regarding our derivative activities, please read Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" containedherein.When we enter into commodity swap contracts we may be required to provide collateral to the counterparties in the event that our potential paymentexposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract thatgoverns our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to thecollateral thresholds are determined on a counterparty by counterparty basis, and are impacted by the representative forward price curves and notionalquantities under our swap contracts. Due to the interrelation between the representative crude oil and natural gas forward price curves, it is not practical todetermine a pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the samecounterparty. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis.Working Capital — Working capital is the amount by which current assets exceed current liabilities. Current assets are reduced by our quarterlydistributions, which are required under the terms of our Partnership Agreement based on Available Cash, as defined in the Partnership Agreement. In general,our working capital is impacted by changes in the prices of commodities that we buy and sell, inventory levels, and other business factors that affect our netincome and cash flows. Our working capital is also impacted by the timing of operating cash receipts and disbursements, cash collateral we may be requiredto post with counterparties to our commodity derivative instruments, borrowings of and payments on debt and the Securitization Facility, capitalexpenditures, and increases or decreases in other long-term assets. We expect that our future working capital requirements will be impacted by these samerecurring factors.We had working capital deficits of $633 million and $166 million as of December 31, 2018 and 2017, respectively. The change in working capital isprimarily attributable to current maturities of long-term debt. We had a net derivative working capital surplus of $17 million and deficit of $46 million as ofDecember 31, 2018 and 2017, respectively.69As of December 31, 2018, we had $1 million in cash and cash equivalents, of which $1 million was held by consolidated subsidiaries we did not whollyown.Cash Flow — Operating, investing and financing activities were as follows: Year Ended December 31, 2018 2017 2016 (millions)Net cash provided by operating activities$662 $896 $645Net cash used in investing activities$(945) $(391) $(34)Net cash provided by (used in) financing activities$128 $(350) $(613)Year Ended December 31, 2018 vs. Year Ended December 31, 2017Operating Activities - Net cash provided by operating activities decreased $234 million in 2018 compared to the same period in 2017. The changes innet cash provided by operating activities are attributable to our net income adjusted for non-cash charges and changes in working capital as presented in theconsolidated statements of cash flows. In addition, we received $7 million more of cash distributions in excess of earnings from unconsolidated affiliatesduring the year ended December 31, 2018 compared to the same period in 2017. For additional information regarding fluctuations in our earnings anddistributions from unconsolidated affiliates, please read "Results of Operations".Investing Activities - Net cash used in investing activities increased $554 million in 2018 compared to the same period in 2017 primarily as a result ofhigher capital expenditures used for construction of the Mewbourn 3 plant and O'Connor 2 plant, and higher investments in unconsolidated affiliates for thecapacity expansion of the Sand Hills pipeline and investment in Gulf Coast Express, offset by proceeds from the sale of our Douglas gathering system in2017.Financing Activities - Net cash provided by financing activities increased $478 million in 2018 compared to the same period in 2017 primarily as aresult of net proceeds from long-term debt, borrowings under our $200 million Securitization Facility and proceeds from the issuance of Series B and Series CPreferred Units, partially offset by higher distributions paid to limited partners and the general partner due to a higher number of outstanding common unitsand general partner units following our acquisition of the DCP Midstream Business in 2017 and distributions paid to preferred unitholders. We also receivedcash from the acquisition of the DCP Midstream Business in 2017.Year Ended December 31, 2017 vs. Year Ended December 31, 2016Operating Activities - Net cash provided by operating activities increased $251 million in 2017 compared to the same period in 2016. The changes innet cash provided by operating activities are attributable to our net income adjusted for non-cash charges and changes in working capital as presented in theconsolidated statements of cash flows. In addition, we received $10 million less of cash distributions in excess of earnings from unconsolidated affiliatesduring the year ended December 31, 2017. For additional information regarding fluctuations in our earnings from unconsolidated affiliates, please read"Results of Operations".Investing Activities - Net cash used in investing activities increased $357 million in 2017 compared to the same period in 2016 primarily as a result ofhigher capital expenditures used for construction of the Mewbourn 3 plant, Grand Parkway Phase 2 and O'Connor bypass projects and higher investments inunconsolidated affiliates for the capacity expansion of the Sand Hills pipeline. In addition, less proceeds were received in 2017 from the sale of Douglasgathering system compared to proceeds received from the sale of our Northern Louisiana system in 2016.Financing Activities - Net cash used in financing activities decreased $263 million in 2017 compared to the same period in 2016 primarily as a result ofcash received from the issuance of Series A preferred limited partner units and from the Transaction in 2017 partially offset by higher net payments of long-term debt and higher distributions paid to limited partners and the general partner due to a higher number of outstanding common units and general partnerunits following the Transaction.70Capital Requirements — The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existingoperations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of the following:•Maintenance capital expenditures, which are cash expenditures to maintain our cash flows, operating or earnings capacity. These expendituresadd on to or improve capital assets owned, including certain system integrity, compliance and safety improvements. Maintenance capitalexpenditures also include certain well connects, and may include the acquisition or construction of new capital assets; and•Expansion capital expenditures, which are cash expenditures to increase our cash flows, operating or earnings capacity. Expansion capitalexpenditures include acquisitions or capital improvements (where we add on to or improve the capital assets owned, or acquire or construct newgathering lines and well connects, treating facilities, processing plants, fractionation facilities, pipelines, terminals, docks, truck racks, tankageand other storage, distribution or transportation facilities and related or similar midstream assets).We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. Our 2019 plan includes maintenance capital expendituresof between $90 million and $110 million, and expansion capital expenditures of between $600 million and $800 million. Expansion capital expenditures areexpected to include the construction of the O'Connor 2 plant in our DJ Basin as well as the construction of the Gulf Coast Express pipeline, the Front Rangeand Texas Express expansions and the extension of Southern Hills into the DJ Basin via the White Cliffs Pipeline, which are shown as investments inunconsolidated affiliates in our consolidated statements of cash flows.The following table summarizes our maintenance and expansion capital expenditures for our consolidated entities for the years ended December 31,2018 and 2017: Year Ended December 31, 2018 Year Ended December 31, 2017 MaintenanceCapitalExpenditures ExpansionCapitalExpenditures TotalConsolidatedCapitalExpenditures MaintenanceCapitalExpenditures ExpansionCapitalExpenditures TotalConsolidatedCapitalExpenditures (millions)Our portion$99 $502 $601 $90 $279 $369Noncontrolling interest portion andreimbursable projects (a)(2) (4) (6) 2 4 6Total$97 $498 $595 $92 $283 $375 Year Ended December 31, 2016 MaintenanceCapitalExpenditures ExpansionCapitalExpenditures TotalConsolidatedCapitalExpenditures Our portion $86 $57 $143Noncontrolling interest portion and reimbursable projects (a) 3 (2) 1Total $89 $55 $144(a)Represents the noncontrolling interest and reimbursable portion of our capital expenditures. We have entered into agreements with third partieswhereby we will be reimbursed for certain expenditures. Depending on the timing of these payments, we may be reimbursed prior to incurring thecapital expenditure.In addition, we invested cash in unconsolidated affiliates of $354 million and $148 million during the years ended December 31, 2018 and 2017,respectively, to fund our share of capital expansion projects.We intend to make cash distributions to our unitholders and our general partner. Due to our cash distribution policy, we expect that we will distributeto our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, to fund futureacquisitions and capital expenditures.71We expect to fund future capital expenditures with funds generated from our operations, borrowings under our Credit Agreement, and the issuance ofadditional debt and equity securities.Cash Distributions to Unitholders — Our Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all AvailableCash, as defined in the Partnership Agreement. We made cash distributions to our common unitholders and general partner of $658 million and $545 millionduring the years ended December 31, 2018 and 2017, respectively. Distributions paid during the years ended December 31, 2018 reflect the distribution of$40 million of IDR givebacks to the IDR holders, in conjunction with the quarterly distribution, that were previously withheld in 2017 under the PartnershipAgreement. We intend to continue making quarterly distribution payments to our unitholders and general partner to the extent we have sufficient cash fromoperations after the establishment of reserves. In accordance with our Partnership Agreement, distributions declared were $618 million for the year ended December 31, 2018. During the years endedDecember 31, 2018, no IDR giveback was withheld from the distribution declared. On January 23, 2019, we announced that the board of directors of the General Partner declared a quarterly distribution on our common units of $0.78per common unit. The distribution will be paid on February 14, 2019 to unitholders of record on February 4, 2019.On the same date, the board of directors of the General Partner declared a quarterly distribution on our Series B and Series C Preferred Units of $0.4922and $0.4969 per unit, respectively. The Series B distributions will be paid on March 15, 2019 to unitholders of record on March 1, 2019. The Series Cdistribution will be paid on April 15, 2019 to unitholders of record on April 1, 2019.We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders and general partner. See Note 14."Partnership Equity and Distributions" in the Notes to the Consolidated Financial Statements in Item 8. “Financial Statements.”72Total Contractual Cash ObligationsA summary of our total contractual cash obligations as of December 31, 2018, was as follows: Payments Due by Period Total Less than1 year 1-3 years 3-5 years Thereafter (millions)Debt (a)$7,900 $577 $1,548 $1,201 $4,574Operating lease obligations75 22 32 14 7Purchase obligations (b)4,839 1,163 1,210 1,055 1,411Other long-term liabilities (c)154 — 9 20 125Total$12,968 $1,762 $2,799 $2,290 $6,117 (a)Includes interest payments on debt securities that have been issued. These interest payments are $252 million, $448 million, $351 million, and$2,074 million for less than one year, one to three years, three to five years, and thereafter, respectively.(b)Our purchase obligations are contractual obligations and include purchase orders and non-cancelable construction agreements for capitalexpenditures, various non-cancelable commitments to purchase physical quantities of commodities in future periods and other items, including long-term fractionation agreements. For contracts where the price paid is based on an index or other market-based rates, the amount is based on the forwardmarket prices or current market rates as of December 31, 2018. Purchase obligations exclude accounts payable, accrued taxes and other currentliabilities recognized in the consolidated balance sheets. Purchase obligations also exclude current and long-term unrealized losses on derivativeinstruments included in the consolidated balance sheets, which represent the current fair value of various derivative contracts and do not representfuture cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual priceand may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlyingcommodity. In addition, many of our gas purchase contracts include short and long-term commitments to purchase produced gas at market prices.These contracts, which have no minimum quantities, are excluded fromthe table.(c)Other long-term liabilities include asset retirement obligations, long-term environmental remediation liabilities, gas purchase liabilities, and othermiscellaneous liabilities recognized in the December 31, 2018 consolidated balance sheet. The table above excludes non-cash obligations as well as$33 million of Executive Deferred Compensation Plan contributions and $10 million of long-term incentive plans as the amount and timing of anypayments are not subject to reasonable estimation.Off-Balance Sheet ObligationsAs of December 31, 2018, we had no items that were classified as off-balance sheet obligations.73Reconciliation of Non-GAAP MeasuresGross Margin and Segment Gross Margin — In addition to net income, we view our gross margin as an important performance measure of the coreprofitability of our operations. We review our gross margin monthly for consistency and trend analysis.We define gross margin as total operating revenues, less purchases and related costs, and we define segment gross margin for each segment as totaloperating revenues for that segment less commodity purchases for that segment. Our gross margin equals the sum of our segment gross margins. Gross marginand segment gross margin are primary performance measures used by management, as these measures represent the results of product sales and purchases, akey component of our operations. As an indicator of our operating performance, gross margin and segment gross margin should not be considered analternative to, or more meaningful than, operating revenues, net income or loss, net income or loss attributable to partners, operating income, net cashprovided by operating activities or any other measure of financial performance presented in accordance with GAAP.Adjusted EBITDA — We define adjusted EBITDA as net income or loss attributable to partners adjusted for (i) distributions from unconsolidatedaffiliates, net of earnings, (ii) depreciation and amortization expense, (iii) net interest expense, (iv) noncontrolling interest in depreciation and income taxexpense, (v) unrealized gains and losses from commodity derivatives, (vi) income tax expense or benefit, (vii) impairment expense and (viii) certain othernon-cash items. Adjusted EBITDA further excludes items of income or loss that we characterize as unrepresentative of our ongoing operations. Managementbelieves these measures provide investors meaningful insight into results from ongoing operations.Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners,operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with GAAP as measures ofoperating performance, liquidity or ability to service debt obligations.Adjusted EBITDA is used as a supplemental liquidity and performance measure and adjusted segment EBITDA is used as a supplemental performancemeasure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess:•financial performance of our assets without regard to financing methods, capital structure or historical cost basis;•our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard tofinancing methods or capital structure;•viability and performance of acquisitions and capital expenditure projects and the overall rates of return on investment opportunities; and•in the case of Adjusted EBITDA, the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, make cashdistributions to our unitholders and general partner, and finance maintenance capital expenditures.Adjusted Segment EBITDA — We define adjusted segment EBITDA for each segment as segment net income or loss attributable to partners adjustedfor (i) distributions from unconsolidated affiliates, net of earnings, (ii) depreciation and amortization expense, (iii) net interest expense, (iv) noncontrollinginterest in depreciation and income tax expense, (v) unrealized gains and losses from commodity derivatives, (vi) income tax expense or benefit, (vii)impairment expense and (viii) certain other non-cash items. Adjusted segment EBITDA further excludes items of income or loss that we characterize asunrepresentative of our ongoing operations for that segment. Our adjusted segment EBITDA may not be comparable to similarly titled measures of othercompanies because they may not calculate adjusted segment EBITDA in the same manner.Adjusted segment EBITDA should not be considered in isolation or as an alternative to our financial measures presented in accordance with GAAP,including operating revenues, net income or loss attributable to partners, or any other measure of performance presented in accordance with GAAP.Our gross margin, segment gross margin, adjusted EBITDA and adjusted segment EBITDA may not be comparable to a similarly titled measure ofanother company because other entities may not calculate these measures in the same manner. The accompanying schedules provide reconciliations of grossmargin, segment gross margin and adjusted segment EBITDA to their most directly comparable GAAP financial measures.Distributable Cash Flow — We define Distributable Cash Flow as adjusted EBITDA, as defined above, less maintenance capital expenditures, net ofreimbursable projects, less interest expense, less income attributable to preferred units, and certain other items. Maintenance capital expenditures are cashexpenditures made to maintain our cash flows, operating or earnings74capacity. These expenditures add on to or improve capital assets owned, including certain system integrity, compliance and safety improvements.Maintenance capital expenditures also include certain well connects, and may include the acquisition or construction of new capital assets. Incomeattributable to preferred units represent cash distributions earned by the Preferred units. Cash distributions to be paid to the holders of the Preferred Unitsassuming a distribution is declared by our board of directors, are not available to common unit holders. Non-cash mark-to-market of derivative instruments isconsidered to be non-cash for the purpose of computing Distributable Cash Flow because settlement will not occur until future periods, and will be impactedby future changes in commodity prices and interest rates. We compare the Distributable Cash Flow we generate to the cash distributions we expect to pay ourpartners. Using this metric, we compute our distribution coverage ratio. Distributable Cash Flow is used as a supplemental liquidity and performance measureby our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess our abilityto make cash distributions to our unitholders and our general partner.Our Distributable Cash Flow may not be comparable to a similarly titled measure of another company because other entities may not calculateDistributable Cash Flow in the same manner.75The following table sets forth our reconciliation of certain non-GAAP measures: Year Ended December 31, 2018 2017 2016Reconciliation of Non-GAAP Measures(millions) Reconciliation of net income attributable to partners to gross margin: Net income attributable to partners $298 $229 $88Interest expense 269 289 321Income tax expense 3 2 46Operating and maintenance expense 760 661 670Depreciation and amortization expense 388 379 378General and administrative expense 276 290 292Asset impairments 145 48 —Loss from financing activities 19 — —Other expense (income), net 11 11 (65)Restructuring costs — — 13Earnings from unconsolidated affiliates (370) (303) (282)Gain on sale of assets, net — (34) (35)Net income attributable to noncontrolling interests 4 5 6Gross margin $1,803 $1,577 $1,432Non-cash commodity derivative mark-to-market (a) $108 $(28) $(139) Reconciliation of segment net income attributable to partners tosegment gross margin: Logistics and Marketing segment: Segment net income attributable to partners $509 $366 $358Operating and maintenance expense 47 41 43Depreciation and amortization expense 15 14 15General and administrative expense 12 11 9Other expense, net 4 11 5Earnings from unconsolidated affiliates (362) (243) (209)Gain on sale of assets, net — — (16)Segment gross margin $225 $200 $205Non-cash commodity derivative mark-to-market (a) $(4) $(4) $(20) Gathering and Processing segment: Segment net income attributable to partners $374 $454 $417Operating and maintenance expense 692 602 611Depreciation and amortization expense 346 343 344General and administrative expense 19 19 14Asset impairments 145 48 —Other expense (income), net 6 — (73)Earnings from unconsolidated affiliates (8) (60) (73)Gain on sale of assets, net — (34) (19)Net income attributable to noncontrolling interests 4 5 6Segment gross margin $1,578 $1,377 $1,227Non-cash commodity derivative mark-to-market (a) $112 $(24) $(119) 76(a)Non-cash commodity derivative mark-to-market is included in gross margin and segment gross margin, along with cash settlements for ourcommodity derivative contracts. Year Ended December 31, 2018 2017 2016 (millions)Reconciliation of net income attributable to partners to adjusted segment EBITDA: Logistics and Marketing segment: Segment net income attributable to partners (a) $509 $366 $358Non-cash commodity derivative mark-to-market 4 4 20Depreciation and amortization expense, net of noncontrolling interest 15 14 15Distributions from unconsolidated affiliates, net of earnings 49 40 53Gain on sale of assets, net — — (16)Other expense — 9 —Adjusted segment EBITDA $577 $433 $430 Gathering and Processing segment: Segment net income attributable to partners $374 $454 $417Non-cash commodity derivative mark-to-market (112) 24 119Depreciation and amortization expense, net of noncontrolling interest 345 342 343Asset impairments 145 48 —Gain on sale of assets, net — (34) (19)Distributions from unconsolidated affiliates, net of earnings 22 24 21Other expense 7 4 14Adjusted segment EBITDA $781 $862 $895 (a)There were no lower of cost or market adjustments for the year ended December 31, 2018, and lower of cost or market adjustments of $2 million and$3 million for the years ended December 31, 2017 and 2016, respectively. Operating and Maintenance and General and Administrative ExpensePursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into the Services Agreement, which replaced the servicesagreement between the Partnership and DCP Midstream, LLC, dated February 14, 2013, as amended. Under the Services Agreement, we are required toreimburse DCP Midstream, LLC for salaries of personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and otherdirect costs incurred by DCP Midstream, LLC on our behalf. There is no limit on the reimbursements we make to DCP Midstream, LLC under the ServicesAgreement for other expenses and expenditures incurred or payments made on our behalf.Operating and maintenance expenses are costs associated with the operation of a specific asset and are primarily comprised of direct labor, ad valoremtaxes, repairs and maintenance, lease expenses, utilities and contract services. These expenses fluctuate depending on the activities performed during aspecific period. General and administrative expense represents costs incurred to manage the business. This expense includes cost of centralized corporate functionsperformed by DCP Midstream, LLC, including legal, accounting, cash management, insurance administration and claims processing, risk management,health, safety and environmental, information technology, human resources, credit, payroll and engineering and all other expenses necessary or appropriateto the conduct of the business.We also incurred third party general and administrative expenses, which were primarily related to compensation and benefit expenses of the personnel whoprovide direct support to our operations. Also included are expenses associated with annual and77quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, due diligence and acquisition costs, costsassociated with the Sarbanes-Oxley Act of 2002, investor relations activities, registrar and transfer agent fees, incremental director and officer liabilityinsurance costs, and director compensation.78Critical Accounting Policies and EstimatesOur financial statements reflect the selection and application of accounting policies that require management to make estimates and assumptions. Webelieve that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition andresults of operations. These accounting policies are described further in Note 2 of the Notes to Consolidated Financial Statements in Item 8. "FinancialStatements and Supplementary Data."Description Judgments and Uncertainties Effect if Actual Results Differ fromAssumptions Impairment of GoodwillWe evaluate goodwill for impairment annuallyin the third quarter, and whenever events orchanges in circumstances indicate it is morelikely than not that the fair value of areporting unit is less than its carrying amount. We determine fair value using widely acceptedvaluation techniques, namely discounted cashflow and market multiple analyses. Thesetechniques are also used when assigning thepurchase price to acquired assets and liabilities.These types of analyses require us to makeassumptions and estimates regarding industryand economic factors and the profitability offuture business strategies. It is our policy toconduct impairment testing based on our currentbusiness strategy in light of present industry andeconomic conditions, as well as futureexpectations. We primarily use a discounted cash flowanalysis, supplemented by a market approachanalysis, to perform the assessment. Keyassumptions in the analysis include the use ofan appropriate discount rate, terminal yearmultiples, and estimated future cash flowsincluding an estimate of operating and generaland administrative costs. In estimating cashflows, we incorporate current marketinformation (including forecasted commodityprices and volumes), as well as historical andother factors. If our assumptions are notappropriate, or future events indicate that ourgoodwill is impaired, our net income would beimpacted by the amount by which the carryingvalue exceeds the fair value of the reportingunit, to the extent of the balance of goodwill.Two of the three reporting units that containgoodwill are not significantly impacted by theprices of commodities. Rather, they are volumebased businesses that have the potential to beimpacted by commodity prices should suchprices remain depressed for a period of suchduration that NGLs cease to be produced atlevels requiring storage and distribution to endusers. The fair value of goodwill substantiallyexceeded its carrying value in our Northreporting unit, the only reporting unit allocatedgoodwill included within our Gathering andProcessing reportable segment and in ourMarysville reporting unit included within ourLogistics and Marketing reportable segment.For our Wholesale Propane reporting unit,which is included in our Logistics andMarketing reportable segment, the fair valueexceeded the carrying value (includingapproximately $37 million of allocatedgoodwill) by approximately 10%. We did notrecord any goodwill impairment during the yearended December 31, 2018.79Description Judgments and Uncertainties Effect if Actual Results Differ fromAssumptions Impairment of Long-Lived AssetsWe periodically evaluate whether the carryingvalue of long-lived assets has been impairedwhen circumstances indicate the carryingvalue of those assets may not be recoverable.For purposes of this evaluation, long-livedassets with recovery periods in excess of theweighted average remaining useful life of ourfixed assets are further analyzed to determineif a triggering event occurred. If it isdetermined that a triggering event hasoccurred, we prepare a quantitativeevaluation based on undiscounted cash flowprojections expected to be realized over theremaining useful life of the primary asset. Thecarrying amount is not recoverable if itexceeds the sum of undiscounted cash flowsexpected to result from the use and eventualdisposition of the asset. If the carrying value isnot recoverable, the impairment loss ismeasured as the excess of the asset’s carryingvalue over its fair value. Our impairment analyses require management toapply judgment in estimating future cash flowsincluding forecasting useful lives of the assets,future commodity prices, volumes, andoperating costs, assessing the probability ofdifferent outcomes, and with respect to anyrequired fair value estimate, selecting thediscount rate that reflects the risk inherent infuture cash flows. If the carrying value is notrecoverable, we assess the fair value of long-lived assets using commonly acceptedtechniques, and may use more than one method,including, but not limited to, recent third partycomparable sales and discounted cash flowmodels. Using the impairment review methodologydescribed herein, we recorded a $145 millionimpairment charge on long-lived assets duringthe year ended December 31, 2018 when it wasdetermined that the carrying value of certainasset groups or portions of asset groups were notrecoverable. If actual results are not consistentwith our assumptions and estimates or ourassumptions and estimates change due to newinformation, we may be exposed to additionalimpairment charges. If our forecast indicateslower commodity prices in future periods at alevel and duration that results in producerscurtailing or redirecting drilling in areas wherewe operate this may adversely affect ourestimate of future operating results, which couldresult in future impairment due to the potentialimpact on our operations and cash flows. Impairment of Investments in Unconsolidated AffiliatesWe evaluate our investments inunconsolidated affiliates for impairmentwhenever events or changes in circumstancesindicate, in management’s judgment, that thecarrying value of such investment may haveexperienced a decline in value. When evidenceof loss in value has occurred, we compare theestimated fair value of the investment to thecarrying value of the investment to determinewhether an impairment has occurred. Wewould then evaluate if the impairment is otherthan temporary. Our impairment analyses require management toapply judgment in estimating future cash flowsand asset fair values, including forecastinguseful lives of the assets, assessing theprobability of differing estimated outcomes, andselecting the discount rate that reflects the riskinherent in future cash flows. When there isevidence of an other than temporary loss invalue, we assess the fair value of ourunconsolidated affiliates using commonlyaccepted techniques, and may use more thanone method, including, but not limited to,recent third party comparable sales anddiscounted cash flow models. Using the impairment review methodologydescribed herein, we have not recorded anysignificant impairment charges on investmentsin unconsolidated affiliates during the yearended December 31, 2018. If the estimated fairvalue of our unconsolidated affiliates is lessthan the carrying value, we would recognize animpairment loss for the excess of the carryingvalue over the estimated fair value only if theloss is other than temporary. A period of lowercommodity prices may adversely affect ourestimate of future operating results, which couldresult in future impairment due to the potentialimpact on the investee's operations and cashflows. 80Description Judgments and Uncertainties Effect if Actual Results Differ fromAssumptions Accounting for Risk Management Activities and Financial InstrumentsEach derivative not qualifying for the normalpurchases and normal sales exception isrecorded on a gross basis in the consolidatedbalance sheets at its fair value as unrealizedgains or unrealized losses on derivativeinstruments. Derivative assets and liabilitiesremain classified in our consolidated balancesheets as unrealized gains or unrealized losseson derivative instruments at fair value untilthe end of the contractual settlement period.Values are adjusted to reflect the credit riskinherent in the transaction as well as thepotential impact of liquidating open positionsin an orderly manner over a reasonable timeperiod under current conditions. When available, quoted market prices or pricesobtained through external sources are used todetermine a contract’s fair value. For contractswith a delivery location or duration for whichquoted market prices are not available, fairvalue is determined based on pricing modelsdeveloped primarily from historical informationand the expected relationship with quotedmarket prices. If our estimates of fair value are inaccurate, wemay be exposed to losses or gains that could bematerial. A 10% difference in our estimated fairvalue of derivatives at December 31, 2018would have affected net income byapproximately $2 million based on our netderivative position for the year ended December31, 2018. Item 7A. Quantitative and Qualitative Disclosures about Market RiskMarket risk is the risk of loss arising from adverse changes in market prices and rates. We are exposed to market risks, including changes in commodityprices and interest rates. We may use financial instruments such as forward contracts, swaps and futures to mitigate a portion of the effects of identified risks.In general, we attempt to mitigate a portion of the risks related to the variability of future earnings and cash flows resulting from changes in applicablecommodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectivesand similar requirements.Risk Management PolicyWe have established a comprehensive risk management policy, or Risk Management Policy, and a risk management committee, or the RiskManagement Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. Our Risk Management Committeeis composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context ofmarket activities. The Risk Management Committee is responsible for the overall management of commodity price risk and counterparty credit risk,including monitoring exposure limits.See Note 13, Risk Management and Hedging Activities, of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements andSupplementary Data” for further discussion of the accounting for derivative contracts.Commodity Price RiskWe are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales andstorage activities. For gathering services, we receive fees or commodities from producers to bring the natural gas from the wellhead to the processing plant.For processing and storage services, we either receive fees or commodities as payment for these services, depending on the types of contracts. We employestablished policies and procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including forwardcontracts, swaps and futures.Commodity Cash Flow Protection Activities - We closely monitor the risks associated with commodity price changes on our future operations and,where appropriate, use various fixed price swap contracts to mitigate a portion of the effect pricing81fluctuations may have on the value of our assets and operations. Depending on our risk management objectives, we may periodically settle a portion of theseinstruments prior to their maturity.We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with ourgathering, processing and sales activities, thereby stabilizing our cash flows. Our commodity derivative instruments used for our hedging program are acombination of direct NGL product, crude oil, and natural gas hedges.Commodity prices experienced volatility during 2018, as illustrated in Item 1A. Risk Factors - “Our cash flow is affected by natural gas, NGL andcondensate prices.” A decline in commodity prices could result in a decrease in exploration and development activities in certain fields served by our gasgathering and residue gas and NGL pipeline transportation systems, and our natural gas processing and treating plants, which could lead to further reducedutilization of these assets.The derivative financial instruments we have entered into are typically referred to as “swap” contracts. The swap contracts entitle us to receive paymentat settlement from the counterparty to the contract to the extent that the reference price is below the swap price stated in the contract, and we are required tomake payment at settlement to the counterparty to the extent that the reference price is higher than the swap price stated in the contract.We use the mark-to-market method of accounting for all commodity cash flow protection activities, which has significantly increased the volatility ofour results of operations as we recognize, in current earnings, all non-cash gains and losses from the mark-to-market on derivative activity.The following tables set forth additional information about our fixed price swaps used to mitigate a portion of our natural gas and NGL price riskassociated with our percent-of-proceeds arrangements and our condensate price risk associated with our gathering and processing operations. Our positions asof February 20, 2019 were as follows:Commodity SwapsPeriod Commodity NotionalVolume- ShortPositions Reference Price Price RangeJanuary 2019 — March 2019 Natural Gas (66,667) MMBtu/d NYMEX Final Settlement Price (c) $3.01-$4.57/MMBtuApril 2019 — December 2019 Natural Gas (50,000) MMBtu/d NYMEX Final Settlement Price (c) $3.01-$3.28/MMBtuJanuary 2019 — December 2019 NGLs (11,851) Bbls/d (d) Mt.Belvieu (b) $.31-$1.10/GalJanuary 2019 — February 2019 Crude Oil (11,017) Bbls/d (d) NYMEX crude oil futures (a) $51.26-$64.87/BblMarch 2019 — February 2020 Crude Oil (3,781) Bbls/d (d) NYMEX crude oil futures (a) $57.12-$65.32/Bbl (a) Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract (CL).(b) The average monthly OPIS price for Mt. Belvieu TET/Non-TET.(c) NYMEX final settlement price for natural gas futures contracts.(d) Average Bbls/d per time period.Our sensitivities for 2019 as shown in the table below are estimated based on our average estimated commodity price exposure and commodity cashflow protection activities for the calendar year 2019, and exclude the impact of non-cash mark-to-market changes on our commodity derivatives. We utilizedirect product crude oil, natural gas and NGL derivatives to mitigate a portion of our condensate, natural gas and NGL commodity price exposure. Thesesensitivities are associated with our condensate, natural gas and NGL volumes that are currently unhedged.82Commodity Sensitivities Net of Cash Flow Protection Activities Per Unit Decrease Unit ofMeasurement EstimatedDecrease inAnnual NetIncomeAttributable toPartners (millions)NGL prices$0.01 Gallon $3Natural gas prices$0.10 MMBtu $7Crude oil prices$1.00 Barrel $4In addition to the linear relationships in our commodity sensitivities above, additional factors may cause us to be less sensitive to commodity pricedeclines. A portion of our net income is derived from fee-based contracts and a portion from percentage-of-proceeds and percentage-of-liquids processingarrangements that contain minimum fee clauses in which our processing margins convert to fee-based arrangements as commodity prices decline.We estimate the following sensitivities related to the non-cash mark-to-market on our commodity derivatives associated with our open position on ourcommodity cash flow protection activities:Non-Cash Mark-To-Market Commodity Sensitivities Per UnitIncrease Unit ofMeasurement EstimatedMark-to-Market Impact(Decrease inNet IncomeAttributable toPartners) (millions)NGL prices$0.01 Gallon $2Natural gas prices$0.10 MMBtu $2Crude oil prices$1.00 Barrel $1While the above commodity price sensitivities are indicative of the impact that changes in commodity prices may have on our annualized net income,changes during certain periods of extreme price volatility and market conditions or changes in the relationship of the price of NGLs and crude oil may causeour commodity price sensitivities to vary significantly from these estimates.The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price ofNGLs, which in turn has been generally related to the price of crude oil. Although the prevailing price of residue natural gas has less short-term significanceto our operating results than the price of NGLs, in the long-term the growth and sustainability of our business depends on natural gas prices being at levelssufficient to provide incentives and capital for producers to increase natural gas exploration and production. To minimize potential future commodity-basedpricing and cash flow volatility, we have entered into a series of derivative financial instruments.Based on historical trends, we generally expect NGL prices to directionally follow changes in crude oil prices over the long-term. However, the pricingrelationship between NGLs and crude oil may vary, as we believe crude oil prices will in large part be determined by the level of production from major crudeoil exporting countries and the demand generated by growth in the world economy, whereas NGL prices are more correlated to supply and U.S. petrochemicaldemand. Additionally, the level of NGL export demand may also have an impact on prices. We believe that future natural gas prices will be influenced by theseverity of winter and summer weather, the level of North American production and drilling activity of exploration and production companies and thebalance of trade between imports and exports of liquid natural gas and NGLs. Drilling activity can be adversely affected as natural gas prices decrease.Energy market uncertainty could also reduce North American drilling activity. Limited access to capital could also decrease drilling. Lower drilling levelsover a sustained period would reduce natural gas volumes gathered and processed, but could increase commodity prices, if supply were to fall relative todemand levels.83Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certainrisks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodityderivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas andassociated time spreads and basis spreads.A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a differentpoint in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storageassets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transactionallows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps toexecute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the currentperiod consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivativeinstruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our consolidatedstatements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-marketaccounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.The following tables set forth additional information about our derivative instruments, used to mitigate a portion of our natural gas price risk associatedwith our inventory within our natural gas storage operations as of December 31, 2018:Inventory Period ended Commodity Notional Volume - LongPositions Fair Value(millions) WeightedAverage Price December 31, 2018 Natural Gas 9,807,055 MMBtu $34 $3.48/MMBtuCommodity Swaps Period Commodity Notional Volume - (Short)/LongPositions Fair Value(millions) Price Range January 2019-March 2019 Natural Gas (15,512,500) MMBtu $5 $2.99-$4.65/MMBtuJanuary 2019 Natural Gas 4,417,500 MMBtu $— $3.25-$4.13/MMBtuOur wholesale propane logistics business is generally designed to establish stable margins by entering into supply arrangements that specify pricesbased on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plusa margin. Occasionally, we may enter into fixed price sales agreements in the event that a propane distributor desires to purchase propane from us on a fixedprice basis. We manage this risk with both physical and financial transactions, sometimes using non-trading derivative instruments, which generally allow usto swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may on occasion use financialderivatives to manage the value of our propane inventories.We manage our commodity derivative activities in accordance with our Risk Management Policy which limits exposure to market risk and requiresregular reporting to management of potential financial exposure.Valuation - Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practicesare used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair valuesand income recognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. Forcontracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developedprimarily from historical and expected relationships with quoted market prices.Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly mannerover a reasonable time period under current conditions. Changes in market prices and84management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in thenear term.The fair value of our commodity non-trading derivatives is expected to be realized in future periods, as detailed in the following table. The amount ofcash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterpartydefault and other unforeseen events that could impact the amount and/or realization of these values.Fair Value of Contracts as of December 31, 2018Sources of Fair Value Total Maturity in 2019 (millions)Prices supported by quoted market prices and other external sources $3 $4Prices based on models or other valuation techniques 14 13Total $17 $17The “prices supported by quoted market prices and other external sources” category includes our commodity positions in natural gas, NGLs and crudeoil. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from a third party pricing serviceand then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions inNGLs at points for which over-the-counter, or OTC, broker quotes for similar assets or liabilities are available for the full term of the instrument. This categoryalso includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthlyprices as appropriate.The “prices based on models and other valuation techniques” category includes the value of transactions for which inputs to the fair value of theinstrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instrumentsmay be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of themarket point.Credit RiskOur customers include large multi-national petrochemical and refining companies, natural gas marketers, as well as commodity producers. Substantiallyall of our natural gas, propane and NGL sales are made at market-based prices. This concentration of credit risk may affect our overall credit risk, as thesecustomers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’financial condition prior to entering into an agreement, establish credit limits, and monitor the appropriateness of these limits on an ongoing basis. Ourcorporate credit policy, as well as the standard terms and conditions of our agreements, prescribe the use of financial responsibility and reasonable groundsfor adequate assurances. These provisions allow our credit department to request that a counterparty remedy credit limit violations by posting cash or lettersof credit for exposure in excess of an established credit line. The credit line represents an open credit limit, determined in accordance with our credit policy.Our standard agreements also provide that the inability of a counterparty to post collateral is sufficient cause to terminate a contract and liquidate allpositions. The adequate assurance provisions also allow us to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyerprovides security for payment to us in a satisfactory form.Interest Rate RiskInterest rates on Credit Agreement and Securitization Facility borrowings, and future debt offerings could be higher than current levels, causing ourfinancing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive withrespect to acquisitions and capital projects, as our competitors would face similar circumstances. We may mitigate a portion of our future interest rate riskwith interest rate swaps that reduce our exposure to market rate fluctuations by converting variable interest rates on our debt to fixed interest rates andlocking in rates on our anticipated future fixed-rate debt, respectively.At December 31, 2018, the effective weighted-average interest rate on our outstanding debt was 5.20%.85Item 8. Financial StatementsINDEX TO FINANCIAL STATEMENTSDCP MIDSTREAM, LP CONSOLIDATED FINANCIAL STATEMENTS: Report of Independent Registered Public Accounting Firm87Consolidated Balance Sheets as of December 31, 2018 and 201788Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 201689Consolidated Statements of Comprehensive Income for the years ended December 31, 2018, 2017 and 201690Consolidated Statements of Changes in Equity for the years ended December 31, 2018, 2017 and 201691Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 201693Notes to Consolidated Financial Statements9486REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors ofDCP Midstream GP, LLCDenver, ColoradoOpinion on the Financial StatementsWe have audited the accompanying consolidated balance sheets of DCP Midstream, LP and subsidiaries (the "Partnership") as of December 31, 2018 and2017, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in theperiod ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements presentfairly, in all material respects, the financial position of the Partnership as of December 31, 2018 and 2017, and the results of its operations and its cash flowsfor each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States ofAmerica.We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’sinternal control over financial reporting as of December 31, 2018, based on the criteria established in the Internal Control - Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2019, expressed an unqualifiedopinion on the Partnership’s internal control over financial reporting.Change in Accounting PrincipleAs discussed in Note 3 to the financial statements, the Partnership has changed its method of accounting for revenue from contracts with customers in theyear ended December 31, 2018 due to adoption of Accounting Standards Codification Topic 606 - Revenue from Contracts with Customers.Basis for OpinionThese financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financialstatements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to thePartnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and thePCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing proceduresto assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks.Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also includedevaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financialstatements. We believe that our audits provide a reasonable basis for our opinion./s/ Deloitte & Touche LLPDenver, ColoradoFebruary 25, 2019We have served as the Partnership’s auditor since 2004.87DCP MIDSTREAM, LPCONSOLIDATED BALANCE SHEETS December 31, 2018 December 31, 2017ASSETS(millions)Current assets: Cash and cash equivalents$1 $156Accounts receivable: Trade, net of allowance for doubtful accounts of $3 and $8 million, respectively860 773Affiliates166 191Other7 17Inventories79 68Unrealized gains on derivative instruments108 30Collateral cash deposits34 75Other16 12Total current assets1,271 1,322Property, plant and equipment, net9,135 8,983Goodwill231 231Intangible assets, net97 106Investments in unconsolidated affiliates3,340 3,050Unrealized gains on derivative instruments8 3Other long-term assets184 183Total assets$14,266 $13,878LIABILITIES AND EQUITY Current liabilities: Accounts payable: Trade$807 $989Affiliates96 68Other23 19Current debt525 —Unrealized losses on derivative instruments91 76Accrued interest71 71Accrued taxes64 58Accrued wages and benefits64 65Capital spending accrual63 39Other100 103Total current liabilities1,904 1,488Long-term debt4,782 4,707Unrealized losses on derivative instruments8 15Deferred income taxes32 29Other long-term liabilities243 201Total liabilities6,969 6,440Commitments and contingent liabilities (see note 14) Equity: Series A preferred limited partners (500,000 preferred units authorized, issued and outstanding,respectively)489 491Series B preferred limited partners (6,450,000 and zero preferred units authorized, issued and outstanding,respectively)156 —Series C preferred limited partners (4,400,000 and zero preferred units authorized, issued and outstanding,respectively)106 —General partner107 154Limited partners (143,317,328 and 143,309,828 common units authorized, issued and outstanding,respectively)6,418 6,772Accumulated other comprehensive loss(8) (9)Total partners’ equity7,268 7,408Noncontrolling interests29 30Total equity7,297 7,438Total liabilities and equity$14,266 $13,878See accompanying notes to consolidated financial statements.88DCP MIDSTREAM, LPCONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, 2018 2017 2016 (millions, except per unit amounts)Operating revenues: Sales of natural gas, NGLs and condensate $7,764 $6,576 $5,317Sales of natural gas, NGLs and condensate to affiliates 1,610 1,274 952Transportation, processing and other 489 652 647Trading and marketing losses, net (41) (40) (23)Total operating revenues 9,822 8,462 6,893Operating costs and expenses: Purchases and related costs 7,123 6,308 4,978Purchases and related costs from affiliates 896 577 483Operating and maintenance expense 760 661 670Depreciation and amortization expense 388 379 378General and administrative expense 276 290 292Asset impairments 145 48 —Other expense (income), net 11 11 (65)Gain on sale of assets, net — (34) (35)Restructuring costs — — 13Total operating costs and expenses 9,599 8,240 6,714Operating income 223 222 179Loss from financing activities (19) — —Earnings from unconsolidated affiliates 370 303 282Interest expense, net (269) (289) (321)Income before income taxes 305 236 140Income tax expense (3) (2) (46)Net income 302 234 94Net income attributable to noncontrolling interests (4) (5) (6)Net income attributable to partners 298 229 88Net loss attributable to predecessor operations — — 224Series A preferred limited partners' interest in net income (37) (4) —Series B preferred limited partners' interest in net income (8) — —Series C preferred limited partners' interest in net income (2) — —General partner’s interest in net income (164) (164) (124)Net income allocable to limited partners $87 $61 $188Net income per limited partner unit — basic and diluted $0.61 $0.43 $1.64Weighted-average limited partner units outstanding — basic and diluted 143.3 143.3 114.7See accompanying notes to consolidated financial statements.89DCP MIDSTREAM, LPCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Year Ended December 31, 2018 2017 2016 (millions)Net income $302 $234 $94Other comprehensive income: Reclassification of cash flow hedge losses into earnings 1 1 —Total other comprehensive income 1 1 —Total comprehensive income 303 235 94Total comprehensive income attributable to noncontrolling interests (4) (5) (6)Total comprehensive income attributable to partners $299 $230 $88See accompanying notes to consolidated financial statements.90DCP MIDSTREAM, LPCONSOLIDATED STATEMENT OF CHANGES IN EQUITY Partners’ Equity Series APreferredLimitedPartners Series BPreferredLimitedPartners Series CPreferredLimitedPartners Limited Partners General Partner Accumulated OtherComprehensive(Loss) Income NoncontrollingInterests TotalEquity (millions)Balance, January 1,2018 $491 $— $— $6,772 $154 $(9) $30 $7,438Cumulative-effectadjustment(see Note 2) — — — 6 — — — 6Net income 37 8 2 87 164 — 4 302Other comprehensiveincome — — — — — 1 — 1Issuance of 6,450,000Series B Preferred Units — 155 — — — — — 155Issuance of 4,400,000Series C Preferred Units — — 106 — — — — 106Distributions tounitholders (39) (7) (2) (447) (211) — — (706)Distributions tononcontrolling interests — — — — — — (5) (5)Balance, December 31,2018 $489 $156 $106 $6,418 $107 $(8) $29 $7,297See accompanying notes to consolidated financial statements.91DCP MIDSTREAM, LPCONSOLIDATED STATEMENT OF CHANGES IN EQUITY Partners’ Equity PredecessorEquity Series APreferredLimitedPartners Limited Partners General Partner Accumulated OtherComprehensive(Loss) Income NoncontrollingInterests TotalEquity (millions)Balance, January 1, 2017$4,220 $— $2,591 $18 $(8) $32 $6,853Net income— 4 61 164 — 5 234Other comprehensiveincome— — — — 1 — 1Net change in parentadvances— — 418 — — — 418Acquisition of the DCPMidstream Business(4,220) — — — — — (4,220)Issuance of 500,000 SeriesA Preferred Units— 487 — — — — 487Deficit purchase price— — 3,094 — (2) — 3,092Issuance of 28,552,480common units and2,550,644 general partnerunits to DCP Midstream,LLC and affiliate— — 1,033 92 — — 1,125Distributions to limitedpartners and generalpartner— — (425) (120) — — (545)Distributions tononcontrolling interests— — — — — (7) (7)Balance, December 31,2017$— $491 $6,772 $154 $(9) $30 $7,438 Partners’ Equity PredecessorEquity Limited Partners General Partner Accumulated OtherComprehensiveLoss NoncontrollingInterests TotalEquity (millions)Balance, January 1, 2016$4,287 $2,762 $18 $(8) $33 $7,092Net (loss) income(224) 188 124 — 6 94Net change in parent advances157 — — — — 157Distributions to limited partners andgeneral partner— (359) (124) — — (483)Distributions to noncontrollinginterests— — — — (7) (7)Balance, December 31, 2016$4,220 $2,591 $18 $(8) $32 $6,853See accompanying notes to consolidated financial statements.92DCP MIDSTREAM, LPCONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2018 2017 2016 (millions)OPERATING ACTIVITIES: Net income$302 $234 $94Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization expense388 379 378Earnings from unconsolidated affiliates(370) (303) (282)Distributions from unconsolidated affiliates441 367 356Net unrealized (gains) losses on derivative instruments(108) 28 139Gain on sale of assets, net— (34) (35)Asset impairments145 48 —Loss from financing activities19 — —Other, net15 32 68Change in operating assets and liabilities, which (used) provided cash, net of effects ofacquisitions: Accounts receivable(55) (194) (247)Inventories(11) 4 (21)Accounts payable(168) 328 199Other assets and liabilities64 7 (4)Net cash provided by operating activities662 896 645INVESTING ACTIVITIES: Capital expenditures(595) (375) (144)Investments in unconsolidated affiliates(354) (148) (53)Proceeds from sale of assets4 132 163Net cash used in investing activities(945) (391) (34)FINANCING ACTIVITIES: Proceeds from debt5,161 116 3,353Payments of debt(4,560) (811) (3,628)Costs incurred to redeem senior notes(18) — —Proceeds from issuance of preferred limited partner units, net of offering costs261 487 —Distributions to preferred limited partners(46) — —Net change in advances to predecessor from DCP Midstream, LLC— 418 157Distributions to limited partners and general partner(658) (545) (483)Distributions to noncontrolling interests(5) (7) (7)Other(7) (8) (5)Net cash provided by (used in) financing activities128 (350) (613)Net change in cash and cash equivalents(155) 155 (2)Cash and cash equivalents, beginning of period156 1 3Cash and cash equivalents, end of period$1 $156 $1See accompanying notes to consolidated financial statements.93DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 20161. Description of Business and Basis of PresentationDCP Midstream, LP, with its consolidated subsidiaries, or "us", "we", "our" or the "Partnership" is a Delaware limited partnership formed in 2005 by DCPMidstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets.Our Partnership includes our Logistics and Marketing and Gathering and Processing segments. For additional information regarding these segments, seeNote 21 - Business Segments.Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCPMidstream GP, LLC, which we refer to as the General Partner, and which is 100% owned by DCP Midstream, LLC. DCP Midstream, LLC and its subsidiariesand affiliates, collectively referred to as DCP Midstream, LLC, is owned 50% by Phillips 66 and 50% by Enbridge Inc. and its affiliates, or Enbridge. DCPMidstream, LLC directs our business operations through its ownership and control of the General Partner. As of December 31, 2018, DCP Midstream, LLCowned approximately 38.1% of us, including limited partner and general partner interests.The consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where we have the ability to exercisecontrol. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, andinvestments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method.The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America,or GAAP. All intercompany balances and transactions have been eliminated in consolidation.94DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)2. Summary of Significant Accounting PoliciesUse of Estimates - Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidatedfinancial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actualresults could differ from those estimates.Cash and Cash Equivalents - We consider investments in highly liquid financial instruments purchased with an original stated maturity of 90 days orless and temporary investments of cash in short-term money market securities to be cash equivalents.Allowance for Doubtful Accounts - Management estimates the amount of required allowances for the potential non-collectability of accountsreceivable generally based upon the number of days past due, past collection experience and consideration of other relevant factors. However, pastexperience may not be indicative of future collections and therefore additional charges could be incurred in the future to reflect differences betweenestimated and actual collections.Inventories - Inventories, which consist primarily of NGLs and natural gas, are recorded at the lower of weighted-average cost or market value.Transportation costs are included in inventory.Accounting for Risk Management Activities and Financial Instruments - Non-trading energy commodity derivatives are designated as a hedge of aforecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or normalpurchases or normal sales. The remaining non-trading derivatives, which are related to asset-based activities for which the normal purchase or normal saleexception is not elected, are recorded at fair value in the consolidated balance sheets as unrealized gains or unrealized losses in derivative instruments, withchanges in the fair value recognized in the consolidated statements of operations. For each derivative, the accounting method and presentation of gains andlosses or revenue and expense in the consolidated statements of operations are as follows:Classification of ContractAccounting MethodPresentation of Gains & Losses or Revenue & ExpenseTrading DerivativesMark-to-market method (a)Net basis in trading and marketing gains and lossesNon-Trading Derivatives: Cash Flow HedgeHedge method (b)Gross basis in the same consolidated statements of operations categoryas the related hedged item Fair Value HedgeHedge method (b)Gross basis in the same consolidated statements of operations categoryas the related hedged item Normal Purchases or Normal SalesAccrual method (c)Gross basis upon settlement in the corresponding consolidatedstatements of operations category based on purchase or sale Other Non-Trading Derivative ActivityMark-to-market method (a)Net basis in trading and marketing gains and losses, net(a)Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidatedstatements of operations in trading and marketing gains and losses, net during the current period.(b)Hedge method - An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets asunrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the consolidated statements ofoperations for the effective portion until the service is provided or the associated delivery impacts earnings. For fair value hedges, the change in thefair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements ofoperations in the same category as the related hedged item.(c)Accrual method - An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements ofoperations for changes in fair value of a contract until the service is provided or the associated delivery impacts earnings.Cash Flow and Fair Value Hedges - For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of thehedge. In addition, we formally assess both at the inception of the hedging relationship and on an ongoing basis, whether the hedge contract is highlyeffective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment ofhedge effectiveness, unless otherwise noted.95DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses onderivative instruments. The change in fair value of the effective portion of a derivative designated as a cash flow hedge is recorded in partners’ equity inaccumulated other comprehensive income, or AOCI, and the ineffective portion is recorded in the consolidated statements of operations. During the period inwhich the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements ofoperations in the same line item as the item being hedged. Hedge accounting is discontinued prospectively when it is determined that the derivative nolonger qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because thederivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivativecontinues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current periodearnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transactionimpacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCIwill be immediately recognized in current period earnings.The fair value of a derivative designated as a fair value hedge is recorded for balance sheet purposes as unrealized gains or unrealized losses onderivative instruments. We recognize the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings in thecurrent period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the results ofoperations.Valuation - When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contractswith a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarilyfrom historical relationships with quoted market prices and the expected relationship with quoted market prices.Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly mannerover a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of thesecontracts. Accordingly, it is reasonably possible that such estimates may change in the near term.Property, Plant and Equipment - Property, plant and equipment are recorded at historical cost. The cost of maintenance and repairs, which are notsignificant improvements, are expensed when incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.Capitalized Interest - We capitalize interest during construction of major projects. Interest is calculated on the monthly outstanding capital balance andceases in the month that the asset is placed into service. We also capitalize interest on our equity method investments which are devoting substantially allefforts to establishing a new business and have not yet begun planned principal operations. Capitalization ceases when the investee commences plannedprincipal operations. The rates used to calculate capitalized interest are the weighted-average cost of debt, including the impact of interest rate swaps.Asset Retirement Obligations - Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilitiesand obligations related to right-of-way and land easement agreements. We adjust our asset retirement obligation each quarter for any liabilities incurred orsettled during the period, accretion expense and any revisions made to the estimated cash flows.Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonableestimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the lifeof the asset. The liability is determined using a credit-adjusted risk free interest rate, and accretes due to the passage of time based on the time value of moneyuntil the obligation is settled.Goodwill and Intangible Assets - Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We perform anannual impairment test of goodwill at the reporting unit level during the third quarter, and update the test during interim periods when we believe events orchanges in circumstances indicate that we may not be able to recover the carrying value of a reporting unit. We primarily use a discounted cash flow analysis,supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate,terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, weincorporate current market information, as well as historical and other factors, into our forecasted commodity prices. A period of lower commodity prices mayadversely affect our estimate of future operating results, which could result in future goodwill and intangible assets impairment due to the potential impact onour operations and cash flows.96DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts, and related relationships. Theseintangible assets are amortized on a straight-line basis over the period of expected future benefit. Intangible assets are removed from the gross carryingamount and the total of accumulated amortization in the period in which they become fully amortized.Investments in Unconsolidated Affiliates - We use the equity method to account for investments in greater than 20% owned affiliates.We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying valueof such investments may have experienced a decline in value. When there is evidence of loss in value that is other than temporary, we compare the estimatedfair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our investmentsin unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third partycomparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over theestimated fair value is recognized as an impairment loss.Long-Lived Assets - We periodically evaluate whether the carrying value of long-lived assets, including intangible assets, has been impaired whencircumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. Thecarrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:•significant adverse change in legal factors or business climate;•a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast thatdemonstrates continuing losses associated with the use of a long-lived asset;•an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;•significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;•a significant adverse change in the market value of an asset; or•a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. We assess the fairvalue of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third partycomparable sales and discounted cash flow models. Significant changes in market conditions resulting from events such as the condition of an asset or achange in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. A period oflower commodity prices may adversely affect our estimate of future operating results, which could result in future impairment due to the potential impact onour operations and cash flows.Unamortized Debt Discount and Expense - Discounts and expenses incurred with the issuance of long-term debt are amortized over the term of the debtusing the effective interest method. The discounts and unamortized expenses are recorded on the consolidated balance sheets within the carrying amount oflong-term debt.Noncontrolling Interest - Noncontrolling interest represents any third party or affiliate interest in non-wholly owned entities that we consolidate. Forfinancial reporting purposes, the assets and liabilities of these entities are consolidated with those of our own, with any third party or affiliate interest in ourconsolidated balance sheet amounts shown as noncontrolling interest in equity. Distributions to and contributions from noncontrolling interests representcash payments to and cash contributions from, respectively, such third party and affiliate investors.Revenue Recognition - Our operating revenues are primarily derived from the following activities:•sales of natural gas, NGLs and condensate;•services related to gathering, compressing, treating, and processing natural gas; and97DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)•services related to transportation and storage of natural gas and NGLs.Sales of natural gas, NGLs and condensate - We sell our commodities to a variety of customers ranging from large, multi-national petrochemical andrefining companies to regional retail propane distributors. We recognize revenue from commodity sales at the point in time when control is obtained by thecustomer. Generally, the transaction price is determined at the time of each delivery as the variability of commodity pricing is resolved. Customers usuallypay monthly based on the products purchased the previous month.Sales of natural gas, NGLs and condensate include physical sales contracts which qualify as financial derivative instruments, and buy-sell and exchangetransactions which involve purchases and sales of inventory with the same counterparty that are legally contingent or in contemplation of one another as asingle transaction on a combined net basis. Neither of these types of arrangements are contracts with customers within the scope of FASB ASU 2014-09Revenue from Contracts with Customers, or "Topic 606".Gathering, compressing, treating and processing natural gas - For natural gas gathering and processing activities, we receive either fees and/or apercentage of proceeds from commodity sales as payment for these services, depending on the type of contract. For gathering and processing agreementswithin the scope of Topic 606, we recognize the revenue associated with our services when the gas is gathered, treated or processed at our facilities. Underfee-based contracts, we receive a fee for our services based on throughput volumes. Under percent-of-proceeds contracts, we receive either an agreed uponpercentage of the actual proceeds received from our sale of the residue natural gas and NGLs or an agreed upon percentage based on index related prices forthe natural gas and NGLs. Our percent-of-proceeds contracts may also include a fee-based component. Transportation and storage - Revenue from transportation and storage agreements is recognized based on contracted volumes transported and stored inthe period the services are provided.Our service contracts generally have terms that extend beyond one year, and are recognized over time. The performance obligation for most of ourservice contracts encompasses a series of distinct services performed on discrete daily quantities of natural gas or NGLs for purposes of allocating variableconsideration and recognizing revenue while the customer simultaneously receives and consumes the benefits of the services provided. Revenue isrecognized over time consistent with the transfer of goods or services over time to the customer based on daily volumes delivered. Consideration is generallyvariable, and the transaction price cannot be determined at the inception of the contract, because the volume of natural gas or NGLs for which the service isprovided is only specified on a daily or monthly basis. The transaction price is determined at the time the service is provided and the uncertainty is resolved.Customers usually pay monthly based on the services performed the previous month.Purchase arrangements - Under purchase arrangements, we purchase natural gas at either the wellhead or the tailgate of a plant. These purchasearrangements represent an arrangement with a supplier and are recorded in “Purchases and related costs”. Often, we earn fees for services performed prior totaking control of the product in these arrangements and service revenue is recorded for these fees. Revenue generated from the sale of product obtained inthese purchase arrangements are reported as “Sales of natural gas, NGLs and condensate” on the consolidated statements of operations and are recognized ona gross basis as we purchase and take control of the product prior to sale and are the principal in the transaction.Practical expedients - We apply certain practical expedients in Topic 606 and do not disclose information about transaction prices allocated toremaining performance obligations that have original expected durations of one year or less, nor do we disclose information about transaction pricesallocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligationContract liabilities - We have contracts with customers whereby the customer reimburses us for costs to construct certain connections to our operatingassets. These agreements are typically entered into in contemplation with gathering and processing agreements and transportation agreements withcustomers, and are part of the consideration of the contract. We previously accounted for these arrangements as a reduction to the cost basis of our long-livedassets which were amortized as a reduction to depreciation expense over the estimated useful life of the related assets. Under Topic 606, we record thesepayments as deferred revenue which are amortized into revenue over the expected contract term.Purchases and related costs - Purchases and related costs primarily includes (i) the cost of purchased commodities, including NGLs, natural gas andcondensate, and (ii) fees incurred for transportation and fractionation of commodities.98DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)Significant Customers - There were no third party customers that accounted for more than 10% of total operating revenues for the years endedDecember 31, 2018, 2017 and 2016. We had significant transactions with affiliates for the years ended December 31, 2018, 2017 and 2016. See Note 6,Agreements and Transactions with Related Parties and Affiliates.Environmental Expenditures - Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit.Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities forthese expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonablyestimated.Equity-Based Compensation — Liability classified equity-based compensation cost is remeasured at each reporting date at fair value, based on theclosing security price, and is recognized as expense over the requisite service period. Compensation expense for awards with graded vesting provisions isrecognized on a straight-line basis over the requisite service period of each separately vesting portion of the award.Income Taxes - We are structured as a master limited partnership which is a pass-through entity for federal income tax purposes. We owned acorporation that filed its own federal and state corporate income tax returns, which we elected to convert to a limited liability company in 2016. Our incometax expense includes certain jurisdictions, including state, local, franchise and margin taxes of the master limited partnership and subsidiaries. We follow theasset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of temporarydifferences between the financial statement carrying amounts and the tax basis of the assets and liabilities. Our taxable income or loss, which may varysubstantially from the net income or loss reported in the consolidated statements of operations, is proportionately included in the federal income tax returnsof each partner.Net Income or Loss per Limited Partner Unit - Basic and diluted net income or loss per limited partner unit, or LPU, is calculated by dividing netincome or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period using the two-class method. Diluted netincome or loss per limited partner unit is computed based on the weighted average number of limited partner units, plus the effect of dilutive potential unitsoutstanding during the period.3. New Accounting PronouncementsFinancial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-15 “Statement of Cash Flows (Topic 230):Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - In August 2016, the FASB issued ASU 2016-15, which amends certain cashflow statement classification guidance. We adopted the ASU on January 1, 2018 and it has not had any impact on our consolidated cash flows.FASB ASU, 2016-13 "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments" or ASU 2016-13 -In June 2016, the FASB issued ASU 2016-13, which amends current measurement techniques used to estimate credit losses for financial assets. This ASU iseffective for interim and annual reporting periods beginning after December 15, 2019, with the option to early adopt for financial statements that have notbeen issued. We are currently evaluating the potential impact this standard will have on our consolidated financial statements and related disclosures.FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize alease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases. This ASU is effective for interim andannual reporting periods beginning after December 15, 2018, with the option to early adopt for financial statements that have not been issued.We adopted Topic 842 on January 1, 2019 using the modified retrospective approach without application to prior periods. We elected the package ofpractical expedients permitted under the transition guidance within the new standard, and the land easement practical expedient, allowing us to carry forwardour current accounting treatment for land easements on existing agreements. Policy elections made as part of our adoption of Topic 842 include (a) notrecognizing lease assets or liabilities when lease terms are less than twelve months, and (b) for agreements that contain both lease and non-lease components,combining these components together and accounting for them as a single lease. Our leasing activity primarily consists of transportation agreements, officespace, vehicles and equipment. Topic 842 will result in changes to the way we recognize, present and disclose our operating leases in our consolidatedfinancial statements, including the recognition of a lease liability and an offsetting right-of-use asset in our consolidated balance sheets for our operatingleases (with the exception of short-term leases excluded by practical expedient). However, this change will not have any impact on our net income (loss) orcash flows. See Note 19 - Commitments and Contingent Liabilities for a summary of our future minimum rental payments under our various operating leases.99DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)FASB ASU 2014-09 “Revenue from Contracts with Customers" or ASU 2014-09 and related interpretations and amendments - In May 2014, the FASBissued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification Topic 605 “Revenue Recognition.” Weadopted this ASU on January 1, 2018 using the modified retrospective method for contracts that were not completed as of the date of adoption. Under thismethod, the comparative information has not been restated and continues to be reported under the accounting standards in effect for those prior periods.Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration theentity expects to receive in exchange for those goods or services. We recognized the initial cumulative effect of applying this ASU as an adjustment to theopening balance of total partners’ equity. In accordance with the new revenue standard requirements, the impact of adoption on our consolidated statement of operations was as follows: Year Ended December 31, 2018 As Reported Effect ofChange PresentationWithoutAdoption of ASC606 (millions)Statement of Operations Operating revenues Sales of natural gas, NGLs and condensate $7,764 $(148) $7,912Transportation, processing and other $489 $(165) $654 Costs and expenses Purchases and related costs $7,123 $(313) $7,436 Net income $302 $— $302100DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)4. Revenue RecognitionWe disaggregate our revenue from contracts with customers by type of contract for each of our reportable segments, as we believe it best depicts thenature, timing and uncertainty of our revenue and cash flows. The following tables set forth our revenue by those categories: Year Ended December 31, 2018 Gathering andProcessing Logistics andMarketing Eliminations Total (millions)Sales of natural gas $1,955 $2,325 $(1,752) $2,528Sales of NGLs and condensate (a) 3,437 6,692 (3,283) 6,846Transportation, processing and other 432 57 — 489Trading and marketing losses, net (b) 19 (60) — (41) Total operating revenues $5,843$9,014$(5,035)$9,822(a) Includes $4,347 million of revenues from physical sales contracts and buy-sell exchange transactions in our logistics and marketing segment, whichare not within the scope of Topic 606.(b) Not within the scope of Topic 606.The revenue expected to be recognized in the future related to performance obligations that are not satisfied is approximately $219 million as ofDecember 31, 2018. Our remaining performance obligations primarily consist of minimum volume commitment fee arrangements and are expected to berecognized through 2028 with a weighted average remaining life of 5 years as of December 31, 2018. As a practical expedient permitted by ASC 606, thisamount excludes variable consideration as well as remaining performance obligations that have original expected durations of one year or less, as applicable.Our remaining performance obligations also exclude estimates of variable rate escalation clauses in our contracts with customers.5. Contract LiabilitiesOur contract liabilities consist of deferred revenue received from reimbursable projects. The noncurrent portion of deferred revenue is included in otherlong-term liabilities on our consolidated balance sheet.The following table summarizes changes in contract liabilities included in our consolidated balance sheet: December 31, 2018 (millions)Balance, beginning of period $—Cumulative effect of implementation of Topic 606 36Revenue recognized (a) (2)Balance, end of period $34(a) Deferred revenue recognized is included in transportation, processing and other on the consolidated statement of operations.The contract liabilities disclosed in the table above will be recognized as revenue as the obligations are satisfied over the next 35 years as ofDecember 31, 2018.101DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)6. Agreements and Transactions with AffiliatesDCP Midstream, LLCServices Agreement and Other General and Administrative ChargesUnder the Services Agreement, we are required to reimburse DCP Midstream, LLC for costs, expenses, and expenditures incurred or payments made onour behalf for general and administrative functions including, but not limited to, legal, accounting, compliance, treasury, insurance administration and claimsprocessing, risk management, health, safety and environmental, information technology, human resources, benefit plan maintenance and administration,credit, payroll, internal audit, taxes and engineering, as well as salaries and benefits of seconded employees, insurance coverage and claims, capitalexpenditures, maintenance and repair costs and taxes. There is no limit on the reimbursements we make to DCP Midstream, LLC under the ServicesAgreement for costs, expenses and expenditures incurred or payments made on our behalf. The following table summarizes employee related costs that werecharged by DCP Midstream, LLC to the Partnership that are included in the consolidated statements of operations: Year Ended December 31, 2018 2017 2016 (millions)Employee related costs charged by DCP Midstream, LLC Operating and maintenance expense $209 $197 $206General and administrative expense $187 $182 $197Phillips 66 and its AffiliatesWe sell a portion of our residue gas and NGLs to and purchase NGLs from Phillips 66 and its respective affiliates. We anticipate continuing to sellcommodities to and purchase commodities from Phillips 66 and its affiliates in the ordinary course of business.Enbridge and its AffiliatesWe sell NGLs to and purchase NGLs from Enbridge and its affiliates. We anticipate continuing to sell commodities to and purchase commodities fromEnbridge and its affiliates in the ordinary course of business.Unconsolidated AffiliatesWe have entered into 10 to 15-year transportation agreements, with Sand Hills Pipeline, LLC, or Sand Hills, Southern Hills Pipeline, LLC, or SouthernHills, Front Range Pipeline LLC, or Front Range, Texas Express Pipeline LLC, or Texas Express and Gulf Coast Express Pipeline, LLC, or Gulf Coast. Underthe terms of these agreements, which expire between 2028 and 2029, we have committed to transport minimum throughput volumes at rates defined in eachof the pipelines’ respective tariffs.We sell a portion of our residue gas and NGLs to, purchase natural gas and other NGL products from, and provide gathering and transportation services toother unconsolidated affiliates. We anticipate continuing to purchase and sell commodities and provide services to unconsolidated affiliates in the ordinarycourse of business.Under the terms of the Sand Hills LLC Agreement and the Southern Hills LLC Agreement, or the Sand Hills and Southern Hills LLC Agreements, SandHills and Southern Hills are required to reimburse us for any direct costs or expenses (other than general and administration services) which we incur onbehalf of Sand Hills and Southern Hills. Additionally, Sand Hills and Southern Hills each pay us an annual service fee of $5 million, for centralized corporatefunctions provided by us as operator of Sand Hills and Southern Hills, including legal, accounting, cash management, insurance administration and claimsprocessing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. Except withrespect to the annual service fee, there is no limit on the reimbursements Sand Hills and Southern Hills make to us under the Sand Hills and Southern HillsLLC Agreements for other expenses and expenditures which we incur on behalf of Sand Hills or Southern Hills.102DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)Summary of Transactions with AffiliatesThe following table summarizes our transactions with affiliates: Year Ended December 31, 2018 2017 2016 (millions)Phillips 66 (including its affiliates): Sales of natural gas, NGLs and condensate to affiliates $1,534 $1,172 $909Purchases and related costs from affiliates $138 $30 $18Operating and maintenance and general administrative expenses $13 $2 $2Enbridge (including its affiliates): Sales of natural gas, NGLs and condensate to affiliates $11 $48 $—Purchases and related costs from affiliates $35 $43 $33Operating and maintenance and general administrative expenses $— $2 $4Unconsolidated affiliates: Sales of natural gas, NGLs and condensate to affiliates $65 $54 $43Transportation, processing, and other to affiliates $6 $5 $5Purchases and related costs from affiliates $723 $504 $432 We had balances with affiliates as follows: December 31, 2018 December 31, 2017 (millions)Phillips 66 (including its affiliates): Accounts receivable$145 $156Accounts payable$22 $6Other assets$— $—Enbridge (including its affiliates): Accounts receivable$— $11Accounts payable$2 $9Unconsolidated affiliates: Accounts receivable$21 $24Accounts payable$72 $53Other assets$— $47. InventoriesInventories were as follows: December 31, 2018 December 31, 2017 (millions)Natural gas$34 $30NGLs45 38Total inventories$79 $68We recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated market value. These non-cashcharges are a component of purchases and related costs in the consolidated statements of operations. We recognized no lower of cost or net realizable valueadjustments during the year ended December 31, 2018. We103DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)recognized lower of cost or net realizable value adjustments of $2 million and $3 million during the years ended December 31, 2017 and 2016, respectively.8. Property, Plant and EquipmentA summary of property, plant and equipment by classification is as follows: DepreciableLife December 31, 2018 December 31, 2017 (millions)Gathering and transmission systems20 — 50 Years $8,492 $8,473Processing, storage and terminal facilities35 — 60 Years 5,194 5,128Other3 — 30 Years 568 557Construction work in progress 470 374Property, plant and equipment 14,724 14,532Accumulated depreciation (5,589) (5,549)Property, plant and equipment, net $9,135 $8,983Interest capitalized on construction projects was $19 million, $7 million and less than $1 million for the years ended December 31, 2018, 2017 and2016, respectively.Depreciation expense was $378 million, $367 million and $366 million for the years ended December 31, 2018, 2017 and 2016 respectively.Asset Retirement ObligationsWe identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligationsassociated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirementobligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate lifebecause they are owned and will operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plantcontaining asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions thatwould require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot beestimated and no obligation has been recorded.The following table summarizes changes in the asset retirement obligations included in our balance sheets: December 31, 2018 (a) 2017 (a) (millions)Balance, beginning of period$126 $124Accretion expense8 8Change in ARO Estimate6 (6)Balance, end of period$140 $126(a) Asset retirement obligations are included in other long-term liabilities in the consolidated balance sheets. Accretion expense is recorded within operatingand maintenance expense in our consolidated statement of operations. Accretion expense for the year ended December 31, 2016 was $7 million.9. Goodwill and Intangible AssetsWe performed our annual goodwill assessment during the third quarter of 2018 at the reporting unit level, which is conducted by assessing whether (i)the components of our operating segments constitute businesses for which discrete financial information is available, (ii) segment management regularlyreviews the operating results of those components and (iii) whether the economic and regulatory characteristics are similar. As a result of our assessment, weconcluded that the fair value of104goodwill substantially exceeded its carrying value in our North reporting unit, the only reporting unit allocated goodwill included within our Gathering andProcessing reportable segment, and in our Marysville reporting unit included within our Logistics and Marketing reportable segment. For our WholesalePropane reporting unit, which is included in our Logistics and Marketing reportable segment, the fair value exceeded the carrying value (includingapproximately $37 million of allocated goodwill) by approximately 10%. We concluded that the entire amount of goodwill disclosed on the consolidatedbalance sheet is recoverable.We primarily used a discounted cash flow analysis, supplemented by a market approach analysis, to perform our goodwill assessment. Key assumptionsin the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows, including an estimate of operatingand general and administrative costs. In estimating cash flows, we incorporate current market information (including forecasted volumes and commodityprices), as well as historical and other factors. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates changedue to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceedsfair value.We expect that the fair value of our Wholesale Propane reporting unit will continue to exceed its carrying value so long as our estimate of future cashflows and the market valuation remain consistent with current levels. A continued period of volatile propane prices could result in further deterioration ofmarket multiples, comparable sales transactions prices, weighted average costs of capital, and our cash flow estimates. Changes to any one or combination ofthese factors, would result in changes to the reporting unit fair values discussed above which could lead to future impairment charges. Such potentialimpairment could have a material effect on our results of operations.The carrying amount of goodwill in each of our reportable segments was as follows: December 31, 2018 December 31, 2017 (millions) Gathering andProcessing Logistics andMarketing Total Gathering andProcessing Logistics andMarketing TotalBalance, beginning of period$159 $72 $231 $164 $72 $236Dispositions— — — (5) — (5)Balance, end of period$159 $72 $231 $159 $72 $231Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts and related relationships. Thegross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangibleassets, net, and are as follows: December 31, December 31, 2018 2017 (millions)Gross carrying amount$410 $410Accumulated amortization(170) (161)Accumulated impairment(143) (143) Intangible assets, net$97 $106We recorded amortization expense of $9 million, $10 million and $12 million for the years ended December 31, 2018, 2017, and 2016, respectively. Asof December 31, 2018, the remaining amortization periods ranged from approximately 3 years to 17 years, with a weighted-average remaining period ofapproximately 12 years.105Estimated future amortization for these intangible assets is as follows:Estimated Future Amortization(millions)2019 $92020 92021 92022 92023 8Thereafter 53Total $9710. Investments in Unconsolidated AffiliatesThe following table summarizes our investments in unconsolidated affiliates: Carrying Value as of PercentageOwnership December 31, 2018 December 31, 2017 (millions)DCP Sand Hills Pipeline, LLC66.67% $1,791 $1,633DCP Southern Hills Pipeline, LLC66.67% 728 739Discovery Producer Services LLC40.00% 344 362Front Range Pipeline LLC33.33% 175 165Texas Express Pipeline LLC10.00% 95 90Gulf Coast Express Pipeline LLC25.00% 146 —Mont Belvieu Enterprise Fractionator12.50% 24 23Panola Pipeline Company, LLC15.00% 23 24Mont Belvieu 1 Fractionator20.00% 10 10OtherVarious 4 4Total investments in unconsolidated affiliates $3,340 $3,050The following table represents the excess (deficit) of the carrying amount of the investment over (under) the underlying equity of our investments inunconsolidated affiliates as of December 31, 2018 and 2017: Excess (deficit) of Carrying Value over (under)Underlying Equity in Unconsolidated Affiliates December 31, 2018 December 31, 2017 (millions)DCP Sand Hills Pipeline, LLC $634 $648Discovery Producer Services LLC (15) (18)DCP Southern Hills Pipeline, LLC 142 145Front Range Pipeline LLC 4 4Texas Express Pipeline LLC 3 3Mont Belvieu 1 Fractionator — (1)Carrying amounts in excess or deficit of the underlying equity of our unconsolidated affiliates are amortized over the life of the underlying long-livedassets of the affiliate.Earnings from investments in unconsolidated affiliates were as follows:106DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued) Year Ended December 31, 201820172016 (millions)DCP Sand Hills Pipeline, LLC$223$148110DCP Southern Hills Pipeline, LLC684744Discovery Producer Services LLC861 73Front Range Pipeline LLC241719Texas Express Pipeline LLC1999Mont Belvieu Enterprise Fractionator101316Mont Belvieu 1 Fractionator1669Other222Total earnings from unconsolidated affiliates$370$303$282The following tables summarize the combined financial information of our investments in unconsolidated affiliates: Year Ended December 31, 2018 2017 2016 (millions)Statements of operations: Operating revenue$1,560 $1,397 $1,311Operating expenses$613 $647 $539Net income$945 $747 $768 December 31, 2018 December 31, 2017 (millions)Balance sheets: Current assets$411 $244Long-term assets6,359 5,319Current liabilities(424) (196)Long-term liabilities(221) (200)Net assets$6,125 $5,16711. Fair Value MeasurementDetermination of Fair ValueBelow is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair valuesare generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available,we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodityvolatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability underan “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect thecredit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period undercurrent conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, and/or the liquidityof the market.•Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of thecredit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal creditquality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of theinstrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date inaccordance with107DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as anyletters of credit that they have provided.•Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with eachcounterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, aswell as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterpartycredit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.•Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less activemarkets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making anyadditional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark ourpositions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice resultsin the most reliable fair value measurement as viewed by a market participant.We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe thatthe portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within theportfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take aportfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate allvaluation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value,whichever is more applicable. The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values.While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of differentmethodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reportingdate. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policiesaccordingly. See Note 13 - Risk Management and Hedging Activities.Valuation HierarchyOur fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the same level of the fair valuehierarchy as the lowest level input that is significant to the entire measurement. The valuation hierarchy is based upon the transparency of inputs to thevaluation of an asset or liability as of the measurement date. The three levels are defined as follows.•Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.•Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability,either directly or indirectly, for substantially the full term of the financial instrument.•Level 3 — inputs are unobservable and considered significant to the fair value measurement.A financial instrument’s categorization within the hierarchy is based upon the level of judgment involved in the most significant input in thedetermination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of suchinstruments pursuant to the hierarchy.Commodity Derivative Assets and LiabilitiesWe enter into a variety of derivative financial instruments, which may include exchange traded instruments (such as New York Mercantile Exchange, orNYMEX, crude oil or natural gas futures) or over-the-counter, or OTC, instruments (such as natural gas contracts, crude oil or NGL swaps). The exchangetraded instruments are generally executed with a highly rated broker dealer serving as the clearinghouse for individual transactions.108DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)Our activities expose us to varying degrees of commodity price risk. To mitigate a portion of this risk and to manage commodity price risk relatedprimarily to owned natural gas storage and pipeline assets, we engage in natural gas asset based trading and marketing, and we may enter into natural gas andcrude oil derivatives to lock in a specific margin when market conditions are favorable. A portion of this may be accomplished through the use of exchangetraded derivative contracts. Such instruments are generally classified as Level 1 since the value is equal to the quoted market price of the exchange tradedinstrument as of our balance sheet date, and no adjustments are required. Depending upon market conditions and our strategy we may enter into exchangetraded derivative positions with a significant time horizon to maturity. Although such instruments are exchange traded, market prices may only be readilyobservable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information isutilized to the extent it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based uponobservable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as awhole, we would classify the instrument within Level 3.We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We mayenter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-basedinstruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using the OTC derivative instrument markets,which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to sixmonths), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices arereadily observable in the OTC market are generally classified within Level 2. Contracts with a longer time horizon, for which we internally generate a forwardcurve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, butnot limited to, data obtained from third-party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge ofexpected supply sources coming online, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputsare observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturityapproaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing theneed to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon marketconditions and the availability of market observable data.Nonfinancial Assets and LiabilitiesWe utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, equity investments in unconsolidatedaffiliates, and intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date ofacquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classifiedwithin Level 3 in the event that we were required to measure and record such assets at fair value within our consolidated financial statements. Additionally,we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based uponcosts incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property tothe contractually stipulated condition, and would generally be classified within Level 3.During the year ended December 31, 2018, we recognized impairments of property, plant and equipment of $145 million for a portion of a specific assetgroup within the Midcontinent region and a specific asset group in the South region of the Gathering and Processing segment. We considered alternate long-term strategies for the specific portion of the asset group within our Midcontinent region while we projected continuing future losses associated with the useof the asset group within our South region. As it was determined there would be a significant repurposing of the specific portion of the asset group within theMidcontinent region and projected continuing future losses from the asset group within the South region, we determined that a triggering event occurredduring the fourth quarter of 2018 requiring further analysis.The net book value of the assets exceeded the undiscounted cash flows, therefore a fair value calculation was required. Our impairment determinationsinvolved significant assumptions and judgments. We estimated the fair value of future cash flows by forecasting the useful lives of the assets, futurecommodity prices, volumes, operating costs and selecting the discount rate that reflected the risk inherent in future cash flows. Differing assumptionsregarding any of these inputs could have a109DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)significant effect on the various valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3measurements in the fair value hierarchy because they are not observable from objective sources.There were no other impairment indicators which existed in other assets or asset groups requiring additional impairment analyses.During the year ended December 31, 2017, we recognized impairments of property, plant and equipment, intangible assets and investment inunconsolidated affiliates of $48 million in our consolidated statement of operations. The Partnership’s management considered alternate long-term strategiesfor the specific asset group within our South Region. As it was determined there would be a significant repurposing of the asset, management of thePartnership determined that a triggering event occurred during the third quarter 2017, which resulted in the impairment. The following table presents the carrying value of assets measured at fair value on a non-recurring basis, by consolidated balance sheet caption and byvaluation hierarchy, as of and for the years ended December 31, 2018 and 2017. December 31, 2018 December 31, 2017 Net Carrying Value Asset Impairments Net CarryingValue AssetImpairments (millions)Property, plant and equipment$15 $145 $14 $26Intangible assets— — 11 21Investment in unconsolidated affiliates— — 1 1 Total impairments$15 $145 $26 $48The following table presents the financial instruments carried at fair value as of December 31, 2018 and December 31, 2017, by consolidated balancesheet caption and by valuation hierarchy, as described above: December 31, 2018 December 31, 2017 Level 1 Level 2 Level 3 TotalCarryingValue Level 1 Level 2 Level 3 TotalCarryingValue (millions)Current assets: Commodity derivatives (a)$62 $32 $14 $108 $10 $17 $3 $30Short-term investments (b)$— $— $— $— $156 $— $— $156Long-term assets: Commodity derivatives (c)$4 $2 $2 $8 $1 $1 $1 $3Current liabilities: Commodity derivatives (d)$(39) $(52) $— $(91) $(29) $(34) $(13) $(76)Long-term liabilities: Commodity derivatives (e)$(1) $(5) $(2) $(8) $(3) $(11) $(1) $(15)(a)Included in current unrealized gains on derivative instruments in our consolidated balance sheets.(b)Includes short-term money market securities included in cash and cash equivalents in our consolidated balance sheets.(c)Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets.(d)Included in current unrealized losses on derivative instruments in our consolidated balance sheets.(e)Included in long-term unrealized losses on derivative instruments in our consolidated balance sheets.Changes in Levels 1 and 2 Fair Value MeasurementsThe determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted prices for identical or similarassets and liabilities in active markets. Depending upon the information readily observable in the market, and/or the use of identical or similar quoted prices,which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. Toqualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period. In the110DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)event that there is a movement between the classification of an instrument as Level 1 or 2, the transfer would be reflected in a table as “Transfers into or out ofLevel 1 and Level 2”. During the years ended December 31, 2018 and 2017, there were no transfers between Level 1 and Level 2 of the fair value hierarchy.Changes in Level 3 Fair Value MeasurementsThe tables below illustrate a rollforward of the amounts included in our consolidated balance sheets for derivative financial instruments that we haveclassified within Level 3. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, componentsthat are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changesin fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the informationreadily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individualfinancial instrument may differ from one measurement date to the next. The significant unobservable inputs used in determining fair value includeadjustments by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/orcounterparty specific considerations. In the event that there is a movement to/from the classification of an instrument as Level 3, we would reflect such itemsin the table below within the “Transfers into/out of Level 3” captions.We manage our overall risk at the portfolio level and in the execution of our strategy, we may use a combination of financial instruments, which may beclassified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforward below, the gains or losses in the tabledo not reflect the effect of our total risk management activities. Commodity Derivative Instruments CurrentAssets Long-TermAssets CurrentLiabilities Long-TermLiabilities (millions)Year ended December 31, 2018 (a): Beginning balance$3 $1 $(13) $(1)Net unrealized gains (losses) included in earnings (b)14 1 (6) (1)Settlements(3) — 19 —Ending balance$14 $2 $— $(2)Net unrealized gains (losses) on derivatives still held includedin earnings (b)$14 $1 $— $(1)Year ended December 31, 2017 (a): Beginning balance$9 $5 $(23) $—Net unrealized gains (losses) included in earnings (b)14 1 (44) (3)Transfers out of Level 3 (c)— — — 2Settlements(13) — 36 —CME Rule 814 adjustment(7) (5) 18 —Ending balance$3 $1 $(13) $(1)Net unrealized gains (losses) on derivatives still held includedin earnings (b)$3 $(4) $(13) $(1) (a)There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the three and years ended December 31, 2018 and 2017.(b)Represents the amount of unrealized gains or losses for the period, included in trading and marketing gains (losses), net.(c)Amounts transferred out of Level 3 are reflected at fair value at the end of the period.111DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)Quantitative Information and Fair Value Sensitivities Related to Level 3 Unobservable InputsWe utilize the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fairvalue are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any ofthose inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts. December 31, 2018 Product GroupFair Value ForwardCurve Range (millions) Assets NGLs$14 $0.31-$0.96 Per gallonNatural gas$2 $2.01-$2.56 Per MMBtuLiabilities Natural gas$(2) $2.46-$2.88 Per MMBtuEstimated Fair Value of Financial InstrumentsValuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used todevelop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and incomerecognition. When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts witha delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily fromhistorical and expected relationships with quoted market prices.Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderlymanner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value ofthese contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.The fair value of our interest rate swaps, if any, and commodity non-trading derivatives is based on prices supported by quoted market prices and otherexternal sources and prices based on models and other valuation methods. The “prices supported by quoted market prices and other external sources”category includes our interest rate swaps, if any, our NGL and crude oil swaps and our NYMEX positions in natural gas. In addition, this category includesour forward positions in natural gas for which our forward price curves are obtained from a third party pricing service and then validated through an internalprocess which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which OTC brokerquotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs aredirectly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate. The “prices based on models and othervaluation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace andare considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed pricecurve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the specific market point.We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgmentis required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of theamounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect onthe estimated fair value amounts.The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature ofthese instruments or the stated rates approximating market rates. Derivative instruments are carried at fair value.112DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)We determine the fair value of our fixed-rate senior notes and junior subordinated notes based on quotes obtained from bond dealers. The fair value ofborrowings under the Credit Agreement and the Securitization Facility are based on carrying value, which approximates fair value as their interest rates arebased on prevailing market interest rates. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As ofDecember 31, 2018 and December 31, 2017, the carrying value and fair value of our total debt, including current maturities, were as follows: December 31, 2018 December 31, 2017 CarryingValue (a) Fair Value CarryingValue (a) Fair Value (millions) Total debt $5,337 $5,170 $4,736 $4,885(a) Excludes unamortized issuance costs.113DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)12. Debt December 31, 2018 December 31, 2017 (millions)Senior notes: Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a)$— $450Issued March 2014, interest at 2.700% payable semi-annually, due April 2019325 325Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a)600 600Issued September 2011, interest at 4.750% payable semiannually, due September 2021500 500Issued March 2012, interest at 4.950% payable semi-annually, due April 2022350 350Issued March 2013, interest at 3.875% payable semi-annually, due March 2023500 500Issued July 2018, interest at 5.375% payable semi-annually, due July 2025500 —Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 (a)300 300Issued October 2006, interest at 6.450% payable semi-annually, due November 2036300 300Issued September 2007, interest at 6.750% payable semi-annually, due September 2037450 450Issued March 2014, interest at 5.600% payable semi-annually, due April 2044400 400Junior subordinated notes: Issued May 2013, interest at 5.850% payable semi-annually, due May 2043550 550Credit agreement: Revolving credit facility, weighted-average variable interest rate of 3.901%, as of December 31, 2018, due December2022351 —Accounts receivable securitization facility: Accounts receivable securitization facility, weighted-average variable interest rate of 3.303% as of December 31,2018, due August 2019200 —Fair value adjustments related to interest rate swap fair value hedges (a)21 23Unamortized issuance costs(30) (29)Unamortized discount(10) (12)Total debt5,307 4,707Current debt525 —Total long-term debt$4,782 $4,707(a) The swaps associated with this debt were previously terminated. The remaining long-term fair value of approximately$21 million related to the swaps is being amortized as a reduction to interest expense through 2020 and 2030, the original maturity dates of the debt.Accounts Receivable Securitization FacilityIn August 2018, we entered into our Securitization Facility that provides up to $200 million of borrowing capacity through August 2019 at LIBORmarket index rates plus a margin. Under this Securitization Facility, certain of the Partnership’s wholly owned subsidiaries sell or contribute receivables toanother of the Partnership’s consolidated subsidiaries, DCP Receivables LLC (“DCP Receivables”), a bankruptcy-remote special purpose entity created forthe sole purpose of this Securitization Facility. DCP Receivables’ sole activity consists of purchasing receivables from the Partnership’s wholly owned subsidiaries that participate in the SecuritizationFacility and providing these receivables as collateral for DCP Receivables’ borrowings under the Securitization Facility. DCP Receivables is a separate legalentity and the accounts receivable of DCP Receivables, up to the amount of the outstanding debt under the Securitization Facility, are not available to satisfythe claims of creditors of the Partnership, its subsidiaries selling receivables under the Securitization Facility, or their affiliates. Any excess receivables areeligible to satisfy the claims of creditors of the Partnership, its subsidiaries selling receivables under the Securitization Facility, or their affiliates. The amountavailable for borrowing is based on the availability of eligible receivables and other customary factors and conditions. As of December 31, 2018, DCPReceivables had $831 million of our accounts receivable under its114DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)Securitization Facility. Borrowings under the Securitization Facility are included in “Current debt” on the consolidated balance sheet.Senior Notes RedemptionIn August 2018, we redeemed our outstanding $450 million 9.750% Senior Notes due March 2019, totaling $468 million in aggregate principal andmake-whole payments, at a price of 104.008% plus accrued interest through the redemption date. The redemption resulted in a $19 million loss, which isreflected as loss from financing activities on the consolidated statements of operations.Senior Notes IssuanceOn July 17, 2018, we issued $500 million of 5.375% Senior Notes due July 2025, unless redeemed prior to maturity. We received proceeds of $495million, net of underwriters’ fees, related expenses and unamortized discounts which we used to redeem our $450 million 9.750% Senior Notes due March2019. Interest on the notes will be paid semi-annually in arrears on January 15 and July 15 of each year, commencing January 15, 2019.Credit AgreementWe are a party to a $1.4 billion unsecured revolving Credit Agreement (the "Credit Agreement") which matures on December 6, 2022. The CreditAgreement also grants us the option to increase the revolving loan commitment by an aggregate principal amount of up to $500 million, subject to requisitelender approval. The Credit Agreement may be extended for up to two additional one-year periods subject to requisite lender approval. Loans under theCredit Agreement may be used for working capital and other general partnership purposes including acquisitions.The Credit Agreement allows for unrestricted cash and cash equivalents to be netted against consolidated indebtedness for purposes of calculating thePartnership’s Consolidated Leverage Ratio (as defined in the Credit Agreement). Additionally, under the Credit Agreement, the Consolidated Leverage Ratioof the Partnership as of the end of any fiscal quarter shall not exceed 5.00 to 1.0 for each fiscal quarter ending after September 30, 2018; provided that, if thereis a Qualified Acquisition (as defined in the Credit Agreement) during any fiscal quarter ending September 30, 2018 or thereafter, the maximum ConsolidatedLeverage Ratio shall not exceed 5.50 to 1.0 at the end of the three consecutive fiscal quarters, including the fiscal quarter in which the Qualified Acquisitionoccurs.Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the Credit Agreement bears interestat either: (1) LIBOR, plus an applicable margin of 1.45% based on our current credit rating; or (2) (a) the base rate which shall be the higher of the prime rate,the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1%, plus (b) an applicable margin of 0.45% based on our current credit rating. TheCredit Agreement incurs an annual facility fee of 0.30% based on our current credit rating. This fee is paid on drawn and undrawn portions of the $1.4 billionrevolving credit facility.As of December 31, 2018, we had unused borrowing capacity of $1,036 million, net of $13 million of letters of credit, under the Credit Agreement. Ourborrowing capacity may be limited by financial covenants set forth in the Credit Agreement. The financial covenants set forth in the Credit Agreement limitthe Partnership's ability to incur incremental debt by the unused borrowing capacity of $1,036 million as of December 31, 2018. Except in the case of adefault, amounts borrowed under our Credit Agreement will not become due prior to the December 6, 2022 maturity date.Senior Notes and Junior Subordinated NotesOur senior notes and junior subordinated notes, collectively referred to as our debt securities, mature and become payable on their respective due dates,and are not subject to any sinking fund or mandatory redemption provisions. The senior notes are senior unsecured obligations that are guaranteed by thePartnership and rank equally in a right of payment with our other senior unsecured indebtedness, including indebtedness under our Credit Agreement, andthe junior subordinated notes are unsecured and rank subordinate in right of payment to all of our existing and future senior indebtedness. The debt securitiesinclude an optional redemption whereby we may elect to redeem the notes, in whole or in part from time-to-time for a premium. Additionally, we may deferthe payment of all or part of the interest on the junior subordinated notes for one or more periods up115DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)to five consecutive years. The underwriters’ fees and related expenses are recorded in our consolidated balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes.The maturities of our debt as of December 31, 2018 are as follows: DebtMaturities (millions)2019$5252020600202150020227012023500Thereafter2,500Total debt$5,32613. Risk Management and Hedging ActivitiesOur operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interestrates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with either physical or financial transactions. We haveestablished a comprehensive risk management policy and a risk management committee, or the Risk Management Committee, to monitor and manage marketrisks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regularbriefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee isresponsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following describes each of therisks that we manage.Commodity Price RiskOur portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting; however, depending upon ourrisk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. The risks, strategies andinstruments used to mitigate such risks, as well as the method of accounting are discussed and summarized below.Natural Gas Asset Based Trading and MarketingOur natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk relatedto our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage andpipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a differentpoint in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storageassets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transactionallows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps toexecute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the currentperiod consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivativeinstruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our consolidatedstatements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-marketaccounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.116DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)Commodity Cash Flow HedgesIn order for our natural gas storage facility to remain operational, a minimum level of base gas must be maintained in each storage cavern, which iscapitalized on our consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storagecaverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gaswhen we bring the storage caverns into operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid uponsettlement of these hedges economically fixes the cash required to purchase base gas, the deferred losses or gains would remain in accumulated othercomprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flowhedges was in a loss position of $6 million as of December 31, 2018.Commodity Cash Flow Protection ActivitiesWe are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales andstorage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on thecontract type. We may enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate pricesassociated with our gathering, processing and sales activities, thereby stabilizing our cash flows. As of December 31, 2018 our derivative financialinstruments used to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices extend through the first quarter of 2020. Thecommodity derivative instruments used for our hedging programs are a combination of direct NGL product, crude oil and natural gas hedges. Crude oil andNGL transactions are primarily accomplished through the use of forward contracts that effectively exchange floating price risk for a fixed price. The type ofinstrument used to mitigate a portion of the risk may vary depending on our risk management objectives. These transactions are not designated as hedginginstruments for accounting purposes and the change in fair value is reflected in the current period within our consolidated statements of operations as tradingand marketing gains and (losses), net.NGL Proprietary TradingOur NGL proprietary trading activity includes trading energy related products and services. We undertake these activities through the use of fixedforward sales and purchases, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. These energy tradingoperations are exposed to market variables and commodity price risk with respect to these products and services, and these operations may enter into physicalcontracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. Thesephysical and financial instruments are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the currentperiod consolidated statements of operations.We employ established risk limits, policies and procedures to manage risks associated with our natural gas asset based trading and marketing and NGLproprietary trading.Credit RiskOur principal customers range from large, natural gas marketers to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gasand NGL sales are made at market-based prices. This concentration of credit risk may affect our overall credit risk, in that these customers may be similarlyaffected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior toentering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use various masteragreements that include language giving us the right to request collateral to mitigate credit exposure. The collateral language provides for a counterparty topost cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined inaccordance with our credit policy. The collateral language also provides that the inability to post collateral is sufficient cause to terminate a contract andliquidate all positions. In addition, our master agreements and our standard gas and NGL sales contracts contain adequate assurance provisions, which allowus to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides acceptable security for payment.117DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)Contingent Credit FeaturesEach of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contractsmay contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances.We have International Swaps and Derivatives Association, or ISDA, contracts which are standardized master legal arrangements that establish key termsand conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of theprovisions we are subject to are outlined below.•If we were to have an effective event of default under our Credit Agreement that occurs and is continuing, our ISDA counterparties may have theright to request early termination and net settlement of any outstanding derivative liability positions.•Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity contracts in a net liabilityposition, when our credit rating is below investment grade.•Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. Theseprovisions apply if we default in making timely payments under other credit arrangements and the amount of the default is above certain predefinedthresholds, which are significantly high and are generally consistent with the terms of our Credit Agreement. As of December 31, 2018, we were not aparty to any agreements that would trigger the cross-default provisions.Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features. Depending uponthe movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments orinterest rate swap instruments are in either a net asset or net liability position. As of December 31, 2018, we did not have any individual commodityderivative contracts that contain credit-risk related contingent features that were in a net liability position. If we were required to net settle our position withan individual counterparty, due to a credit-risk related event, our ISDA contracts may permit us to net all outstanding contracts with that counterparty,whether in a net asset or net liability position, as well as any cash collateral already posted. As of December 31, 2018, we have not been required to postadditional collateral.CollateralAs of December 31, 2018, we had cash deposits of $34 million, included in collateral cash deposits in our consolidated balance sheets. Additionally, asof December 31, 2018, we held cash of $13 million, included in other current liabilities in our consolidated balance sheet, related to cash postings by thirdparties and letters of credit of $105 million from counterparties to secure their future performance under financial or physical contracts. Collateral amountsheld or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, services, tradingand hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which may impact the amounts of collateralrequirements.Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generallysubject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continuedeliveries to the buyer after the buyer provides security for payment satisfactory to the seller.OffsettingCertain of our derivative instruments are subject to a master netting or similar arrangement, whereby we may elect to settle multiple positions with anindividual counterparty through a single net payment. Each of our individual derivative instruments are presented on a gross basis on the consolidatedbalance sheets, regardless of our ability to net settle our positions. Instruments that are governed by agreements that include net settle provisions allow finalsettlement, when presented with a termination event, of outstanding amounts by extinguishing the mutual debts owed between the parties in exchange for anet amount due. We have trade receivables and payables associated with derivative instruments, subject to master netting or similar agreements, which arenot included in the table below. The following summarizes the gross and net amounts of our derivative instruments: 118DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued) December 31, 2018 December 31, 2017 Gross Amountsof Assets and(Liabilities)Presented in theBalance Sheet Amounts NotOffset in theBalance Sheet -FinancialInstruments NetAmount Gross Amountsof Assets and(Liabilities)Presented in theBalance Sheet Amounts NotOffset in theBalance Sheet -FinancialInstruments NetAmount (millions)Assets: Commodity derivatives$116 $— $116 $33 $— $33Liabilities: Commodity derivatives$(99) $— $(99) $(91) $— $(91) Summarized Derivative InformationThe fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our consolidated balance sheets,by major category, is summarized below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as ofDecember 31, 2018 and December 31, 2017. Balance Sheet Line ItemDecember 31, 2018 December 31, 2017 Balance Sheet Line Item December 31, 2018 December 31, 2017 (millions) (millions)Derivative Assets Not Designated as Hedging Instruments: Derivative Liabilities Not Designated as Hedging Instruments:Commodity derivatives: Commodity derivatives: Unrealized gains on derivativeinstruments — current$108 $30 Unrealized losses on derivativeinstruments — current $(91) $(76)Unrealized gains on derivativeinstruments — long-term8 3 Unrealized losses on derivativeinstruments — long-term (8) (15)Total$116 $33 Total $(99) $(91) The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of andfor the year ended December 31, 2018: InterestRate CashFlowHedges CommodityCash FlowHedges ForeignCurrencyCash FlowHedges (a) Total (millions)Net deferred (losses) gains in AOCI (beginning balance)$(4) $(6) $1 $(9)Losses reclassified from AOCI to earnings — effective portion1 — — 1Net deferred (losses) gains in AOCI (ending balance)$(3) $(6) $1 $(8)Deferred losses in AOCI expected to be reclassified into earnings overthe next 12 months$(1) $— $— $(1)(a)Relates to Discovery Producer Services LLC ("Discovery"), an unconsolidated affiliate. 119DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of andfor the year ended December 31, 2017: InterestRate CashFlowHedges CommodityCash FlowHedges ForeignCurrencyCash FlowHedges (a) Total (millions)Net deferred (losses) gains in AOCI (beginning balance)$(3) $(6) $1 $(8)Losses reclassified from AOCI to earnings — effective portion1 — — 1Deficit purchase price under carrying value(2) — — (2)Net deferred (losses) gains in AOCI (ending balance)$(4) $(6) $1 $(9)(a)Relates to Discovery, an unconsolidated affiliate.For the years ended December 31, 2018 and 2017, no derivative losses attributable to the ineffective portion or to amounts excluded from effectivenesstesting were recognized in trading and marketing gains or losses, net or interest expense in our consolidated statements of operations. For the years endedDecember 31, 2018 and 2017, no derivative losses were reclassified from AOCI to trading and marketing gains or losses, net or interest expense as a result ofthe discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.Changes in the value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recordedin the consolidated statements of operations. The following summarizes these amounts and the location within the consolidated statements of operations thatsuch amounts are reflected:Commodity Derivatives: Statements of Operations Line Item Year Ended December 31, 2018 2017 2016 (millions) Realized (losses) gains $(149) $(12) $116Unrealized gains (losses) 108 (28) (139)Trading and marketing losses, net $(41) $(40) $(23)We do not have any derivative financial instruments that qualify as a hedge of a net investment.The following tables represent, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year.To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the tablesbelow. 120DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued) December 31, 2018 Crude Oil Natural Gas Natural GasLiquids Natural GasBasis SwapsYear of ExpirationNet ShortPosition(Bbls) Net Short Position(MMBtu) Net ShortPosition(Bbls) Net (Short) LongPosition(MMBtu)2019(1,619,000) (40,291,250) (36,312,499) (2,165,000)2020(204,000) — (13,862,378) 3,660,0002021— — (5,755,322) (3,650,000) December 31, 2017 Crude Oil Natural Gas Natural GasLiquids Natural GasBasis SwapsYear of ExpirationNet ShortPosition(Bbls) Net Short Position(MMBtu) Net (Short) LongPosition(Bbls) Net LongPosition(MMBtu)2018(2,701,000) (35,977,400) (19,656,392) 3,202,5002019(631,000) — (2,357,156) 7,177,5002020(50,000) — 238,548 3,660,00014. Partnership Equity and DistributionsPreferred Units — In October 2018 , we issued 4,400,000 of our Series C Preferred Units representing limited partnership interests (including a partialexercise of the underwriters’ option to purchase additional Series C Preferred Units) at a price of $25 per unit. We used the net proceeds of $106 million fromthe issuance of the Series C Preferred Units for general partnership purposes including funding capital expenditures and the repayment of outstandingindebtedness under the Credit Agreement.Distributions of the Series C Preferred Units are payable out of available cash, accrue and are cumulative from the date of original issuance of the SeriesC Preferred Units and are payable quarterly in arrears on January 15th, April 15th, July 15th and October 15th of each year to holders of record as of the closeof business on the first business day of the month in which the distribution will be made. The initial distribution rate will be 7.950% per year of the $25liquidation preference per unit (equal to $1.9875 per unit). On and after October 15, 2023, distributions will accumulate at a percentage of the $25liquidation preference equal to an annual floating rate of the three-month LIBOR plus a spread of 4.882%. The Series C Preferred Units rank senior to ourcommon units with respect to distribution rights and rights upon liquidation.In addition, during the year ended December 31, 2018, we issued 6,450,000 of our Series B Preferred Units for net proceeds of $155 million, net ofoffering costs. During the year ended December 31, 2017, we issued $487 million of our Series A Preferred Units, net of offering costs.Distributions of the Preferred Units are payable out of available cash, accrue and are cumulative from the date of original issuance of the Preferred Units.•Distributions on the Series A Preferred Units are payable semiannually in arrears on June 15th and December 15th of each year.•Distributions on the Series B Preferred Units are payable quarterly in arrears on the 15th day of March, June, September and December of each yearto holders of record as of the close of business on the first business day of the month in which the distribution will be made.•Distributions on the Series C Preferred Units are payable quarterly in arrears on the 15th day of January, April, July and October of each year toholders of record as of the close of business on the first business day of the month in which the distribution will be made.121DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)The Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. Holders of the Preferred Units haveno voting rights except for certain limited protective voting rights set forth in our Partnership Agreement.Common Units — During the years ended December 31, 2018 and 2017, we issued no common units pursuant to our at-the-market program. As ofDecember 31, 2018, $750 million of common units remained available for sale pursuant to our at-the-market program.Definition of Available Cash — Our Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all of our AvailableCash, as defined in the Partnership Agreement, to unitholders of record on the applicable record date, as determined by our general partner. Available Cash,for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:•less the amount of cash reserves established by our general partner to:•provide for the proper conduct of our business, including reserves for future capital expenditures and anticipated credit needs;•comply with applicable law or any debt instrument or other agreement or obligation;•provide funds to make payments on the Preferred Units; or•provide funds for distributions to our common unitholders and to our general partner for any one or more of the next four quarters.•plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cashfor the quarter.General Partner Interest and Incentive Distribution Rights - The general partner is entitled to a percentage of all quarterly distributions equal to itsgeneral partner interest of approximately 2% and limited partner interest of approximately 36% as of December 31, 2018. The general partner has the right,but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner or limited partner interest.The incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash when pre-defined distributiontargets are achieved. Currently, our distribution to our general partner related to its incentive distribution rights is at the highest level. The general partner’sincentive distribution rights were not reduced as a result of our common unit and preferred unit issuances, and will not be reduced if we issue additional unitsin the future and the general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest. Please read theDistributions of Available Cash sections below for more details about the distribution targets and their impact on the general partner’s incentive distributionrights.As part of the Transaction, Phillips 66 and Enbridge agreed, if required, to provide a reduction to incentive distributions payable to our General Partnerunder our Partnership Agreement of up to $100 million annually through 2019 to target an approximate 1.0 times distribution coverage ratio. Under theterms of our amended Partnership Agreement, the amount of incentive distributions paid to our General Partner will be evaluated by our General Partner onboth a quarterly and annual basis and may be reduced each quarter by an amount determined by our General Partner (the “IDR giveback”). If nodetermination is made by our General Partner, the quarterly IDR giveback will be $20 million. The IDR giveback, of up to $100 million annually, will besubject to a true-up at the end of the year by taking our total distributable cash flow (as adjusted under our amended Partnership Agreement) less the totalannual distribution payable to our unitholders, adjusted to target an approximate 1.0 times coverage ratio. During the year ended December 31, 2018 and inconjunction with the quarterly distribution, the Partnership distributed $40 million of incentive distribution rights ("IDR") givebacks to the IDR holders thatwere previously withheld under the amended Partnership Agreement during the year ended December 31, 2017, in accordance with the Third Amendment tothe Partnership Agreement.Distributions of Available Cash - Our Partnership Agreement, after adjustment for the general partner’s relative ownership level, requires that we makedistributions of Available Cash from operating surplus for any quarter in the following manner:•first, to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives a total of $0.4025 per unit forthat quarter;122DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)•second, 13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholderreceives a total of $0.4375 per unit for that quarter;•third, 23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholderreceives a total of $0.525 per unit for that quarter; and•thereafter, 48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders.Distributions — The following table presents our cash distributions paid in 2018, 2017 and 2016:Payment DatePer UnitDistribution Total CashDistribution (millions)Distributions to common unitholders November 14, 2018$0.7800 $155August 14, 2018$0.7800 $154May 15, 2018$0.7800 $155February 14, 2018$0.7800 $194November 14, 2017$0.7800 $155August 14, 2017$0.7800 $134May 15, 2017$0.7800 $135February 14, 2017$0.7800 $121November 14, 2016$0.7800 $120August 12, 2016$0.7800 $121May 13, 2016$0.7800 $121February 12, 2016$0.7800 $121 Distributions to Series A Preferred unitholders December 17, 2018$36.8750 $18June 15, 2018$41.9965 $21 Distributions to Series B Preferred unitholders December 17, 2018$0.4922 $3September 17, 2018$0.6781 $415. Equity-Based CompensationOn April 28, 2016, the unitholders of the Partnership approved the 2016 Long-Term Incentive Plan (the “2016 LTIP” and, together with the 2012 LTIP,the “LTIP”). The 2016 plan authorizes up to 900,000 common units to be available for issuance under awards to employees, officers, and non-employeedirectors of the General Partner and its affiliates. Awards under the 2016 LTIP may include unit options, phantom units, restricted units, distributionequivalent rights, unit bonuses, common unit awards, and performance awards. The 2016 LTIP will expire on the earlier of the date it is terminated by theboard of directors of the General Partner or the date that all common units available under the plan have been paid or issued.On February 15, 2012, the board of directors of our General Partner adopted the 2012 LTIP (the "2012 LTIP") for employees, consultants and directorsof our General Partner and its affiliates who perform services for us. The 2012 LTIP provided for the grant of phantom units and DERs. The 2012 LTIPphantom units consist of a notional unit based on the value of common units or shares of Phillips 66 and Enbridge. The LTIPs are administered by theGeneral Partner’s board of directors. All awards under the LTIPs are subject to cliff vesting.123DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)Since we have the intent and ability to settle certain awards within our control in units, we classify them as equity awards based on their fair value. Thefair value of our equity awards is determined based on the closing price of our common units on the grant date. Compensation expense on equity awards isrecognized ratably over each vesting period. We account for other awards which are subject to settlement in cash, including DERs, as liability awards.Compensation expense on these awards is recognized ratably over each vesting period, and will be re-measured each reporting period for all awardsoutstanding until the units are vested. The fair value of all liability awards is determined based on the closing price of our common units at each measurementdate.Under DCP Midstream, LLC's Long-Term Incentive Plan ("DCP Midstream LTIP"), awards may be granted to key employees. The DCP Midstream LTIPprovides for the grant of Strategic Performance Units ("SPUs") and Phantom Units. The SPUs and Phantom Units consist of a notional unit based on the fairmarket value of a common unit of the Partnership. Prior to 2018, the SPUs and Phantom Units consisted of a notional unit based on the weighted averagevalue of common shares of Phillips 66 and Enbridge as of the grant date.Liability classified equity-based compensation expense was $11 million, $23 million and $18 million for the years ended December 31, 2018, 2017and 2016, respectively.The following table presents the fair value of unvested unit-based awards related to the strategic performance units and phantom units: VestingPeriod(years) UnrecognizedCompensationExpense atDecember 31, 2018(millions) EstimatedForfeitureRate Weighted-AverageRemainingVesting(years)DCP Midstream LTIP: SPUs3 $4 0%-11% 2Phantom Units1-3 $4 0%-11% 2124DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)Strategic Performance Units - The number of SPUs that will ultimately vest range in value of up to 200% of the outstanding SPUs, depending on theachievement of specified performance targets over a three year period. The final performance payout is determined by the compensation committee of ourGeneral Partner. The DERs are paid in cash at the end of the performance period. The following table presents information related to SPUs: Units Grant Date Weighted-Average Price Per Unit Measurement DateWeighted-Average PricePer UnitOutstanding at January 1, 2016208,459 $48.46 Granted131,610 $45.31 Forfeited(8,463) $46.27 Vested (a)(98,295) $54.05 Outstanding at December 31, 2016233,311 $44.41 Granted98,628 $76.38 Forfeited(18,577) $50.31 Vested (b)(98,627) $58.80 Outstanding at December 31, 2017214,735 $51.98 Granted168,160 $36.23 Forfeited(10,933) $47.79 Vested (c)(120,643) $48.41 Outstanding at December 31, 2018251,319 $43.33 $34.30Expected to vest231,936 $43.54 $34.53(a) The 2014 grants vested at 130%.(b) The 2015 grants vested at 180%.(c) The 2016 grants vested at 165%.The estimate of SPUs that are expected to vest is based on highly subjective assumptions that could change over time, including the expected forfeiturerate and achievement of performance targets.The following table presents the fair value of units vested and the unit-based liabilities paid for unit-based awards related to the strategic performanceunits: Units Fair Value of UnitsVested Unit-Based LiabilitiesPaid (millions)Vested or paid in cash in 201698,295 $7 $4Vested or paid in cash in 201798,627 $11 $7Vested or paid in cash in 2018120,643 $9 $11125DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)Phantom Units - The DERs are paid quarterly in arrears. The following table presents information related to Phantom Units: Units Grant Date Weighted-Average Price Per Unit Measurement DateWeighted-Average PricePer UnitOutstanding at January 1, 2016204,368 $49.85 Granted132,870 $45.33 Forfeited(3,240) $48.62 Vested(126,681) $50.13 Outstanding at December 31, 2016207,317 $46.80 Granted180,337 $59.43 Forfeited(16,677) $51.73 Vested(169,896) $53.35 Outstanding at December 31, 2017201,081 $52.18 Granted242,780 $36.87 Forfeited(17,696) $45.35 Vested(194,459) $45.16 Outstanding at December 31, 2018231,706 $42.55 $33.08Expected to vest215,482 $42.52 $33.06The following table presents the fair value of units vested and the unit-based liabilities paid for unit based awards related to the phantom units: Units Fair Value of UnitsVested Unit-Based Liabilities Paid (millions)Vested or paid in cash in 2016126,681 $4 $5Vested or paid in cash in 2017169,896 $7 $4Vested or paid in cash in 2018194,459 $5 $716. BenefitsWe do not have our own employees. The employees supporting our operations are employees of DCP Services, LLC, for which we incur charges underthe Services Agreement. All DCP Services, LLC employees who have reached the age of 18 and work at least 20 hours per week are eligible for participationin the 401(k) and retirement plan, to which a range of 4% to 7% of each eligible employee’s qualified earnings is contributed to the retirement plan, based onyears of service. All new employees are automatically enrolled in the 401(k) plan at a 6% contribution level. Employees can opt out of these contributionlevel or change it at any time. Additionally, DCP Services, LLC matches employees’ contributions in the 401(k) plan up to 6% of qualified earnings. Duringthe years ended December 31, 2018, 2017 and 2016, we expensed plan contributions of $30 million, $29 million and $29 million, respectively.DCP Services, LLC offers certain eligible executives the opportunity to participate in the EDC Plan. The EDC Plan allows participants to defer currentcompensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The EDC Plan also has make-whole provisions for planparticipants who may otherwise be limited in the amount that we can contribute to the 401(k) plan on the participant’s behalf.126DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)17. Net Income or Loss per Limited Partner UnitOur net income or loss is allocated to the general partner and the limited partners in accordance with their respective ownership percentages, afterallocating Available Cash generated during the period in accordance with our Partnership Agreement.Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unitusing the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the termsof the Partnership Agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period,whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner hasother legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.These required disclosures do not impact our overall net income or loss or other financial results; however, in periods in which aggregate net incomeexceeds our Available Cash it will have the impact of reducing net income per LPU.Basic and diluted net income or loss per LPU is calculated by dividing net income or loss allocable to limited partners, by the weighted-averagenumber of LPUs outstanding during the period. Diluted net income or loss per LPU is computed based on the weighted average number of units plus theeffect of potential dilutive units outstanding during the period using the two-class method.18. Income TaxesWe are structured as a master limited partnership with sufficient qualifying income, which is a pass-through entity for federal income tax purposes. Weowned a corporation that filed its own federal, foreign and state corporate income tax returns. During the year ended December 31, 2016, we elected toconvert the corporation to a limited liability company for federal income tax purposes. The income tax expense related to this corporation is included in ourincome tax expense, along with state and local taxes of the limited liability entities.Income tax expense consists of the following: Year Ended December 31, 2018 2017 2016 (millions)Current: Federal income tax expense$— $— $(19) State income tax expense— (1) (2)Deferred: Federal income tax expense— — (22)State income tax expense(3) (1) (3)Total income tax expense$(3) $(2) $(46) As of December 31, 2018 and 2017, we had state deferred tax liabilities of $32 million and $29 million, respectively. The state deferred tax liabilitiesare primarily associated with Texas franchise taxes. During the year ended December 31, 2016, we recorded a reduction to our net federal deferred tax asset of$58 million resulting from the conversion of our corporation to a limited liability company.Our effective tax rate differs from statutory rates, primarily due to being structured as a master limited partnership, which is a pass-through entity forfederal income tax purposes, while being treated as a taxable entity in certain states, primarily Texas. The State of Texas imposes a margin tax that is assessedat 0.75%, of taxable margin apportioned to Texas for each year ended December 31, 2018, 2017 and 2016.127DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)19. Commitments and Contingent LiabilitiesLitigation — We are not a party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings andcommercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of the foregoingmatters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a materialadverse effect on our results of operations, financial position, or cash flow.Insurance — Our insurance coverage is carried with third-party insurers and with an affiliate of Phillips 66. Our insurance coverage includes: (i) generalliability insurance covering third-party exposures; (ii) statutory workers’ compensation insurance; (iii) automobile liability insurance for all owned, non-owned and hired vehicles; (iv) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (v)property insurance, which covers the replacement value of real and personal property and includes business interruption; and (vi) insurance covering ourdirectors and officers for acts related to our business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which arecommon for companies with similar types of operations.Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, fractionating, or storingnatural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owneror operator of these facilities, we must comply with laws and regulations at the federal, state and, in some cases, local levels that relate to worker safety,pipeline safety, air and water quality, solid and hazardous waste management and disposal, and other environmental matters. The cost of planning, designing,constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and regulations, worker safety standards,and safety standards applicable to our various facilities. In addition, there is increasing focus from (i) regulatory bodies and communities, and throughlitigation, on hydraulic fracturing and the real or perceived environmental or public health impacts of this technique, which indirectly presents some risk toour available supply of natural gas and the resulting supply of NGLs, (ii) regulatory bodies regarding pipeline system safety which could impose additionalregulatory burdens and increase the cost of our operations, (iii) state and federal regulatory officials regarding the emission of greenhouse gases, which couldimpose regulatory burdens and increase the cost of our operations, and (iv) regulatory bodies and communities that could prevent or delay the developmentof fossil fuel energy infrastructure such as pipelines, plants, and other facilities used in our business. Failure to comply with these various health, safety andenvironmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits,which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation.Management believes that, based on currently known information, compliance with these existing laws and regulations will not have a material adverseeffect on our results of operations, financial position or cash flows.We make expenditures in connection with environmental matters as part of our normal operations. As of December 31, 2018 and 2017, environmentalliabilities included in our consolidated balance sheets as other current liabilities were $3 million and $4 million, respectively. As of December 31, 2018 and2017, environmental liabilities included in our consolidated balance sheets as other long-term liabilities were $8 million and $8 million, respectively.The following pending proceedings involve governmental authorities under federal, state, and local laws regulating the discharge of materials into theenvironment. It is not possible for us to predict the final outcome of these pending proceedings; however, we do not expect the outcome of one or more ofthese proceedings to have a material adverse effect to our results of operations, financial position, or cash flows:•In March 2018, the New Mexico Environment Department ("NMED") issued two separate Notices of Violation ("NOV") relating to upset andmalfunction event emissions at two of our gas processing plants. Following information exchanges and discussions with NMED regarding the eventsand the propriety of the alleged violations, on February 14, 2019 we entered into preliminary settlement agreements to resolve the alleged violationsunder each NOV for administrative penalties in the amount of $149,832 and $142,233, respectively. We intend to mitigate a portion of eachadministrative penalty through the implementation of environmentally beneficial projects.•In April 2018, the Colorado Department of Public Health and Environment ("CDPHE") issued a Compliance Advisory in relation to an improperlypermitted facility flare and related air emissions from flare operations at one of our gas processing plants that we self-disclosed to CDPHE inDecember 2017. Following information exchanges and discussions with CDPHE, during the first quarter of 2019, a resolution was proposed pursuantto which the plant's air128DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)permit would be revised to include the flare and emissions limits for such flare in addition to us paying an administrative penalty as well as aneconomic benefit payment generally covering the period when the flare was required to be included in the facility air permit, in a combined amountexpected to be between approximately $195,000 and $240,000. We are still evaluating and holding discussions with CDPHE as to the foregoingamounts and proposed settlement terms.Other Commitments and Contingencies — We utilize assets under operating leases in several areas of operation. Consolidated rental expense,including leases with no continuing commitment, totaled $30 million, $33 million and $37 million for the years ended December 31, 2018, 2017, and 2016,respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2018: Future Minimum RentalPayments as of December 31,2018 (millions) 2019$22 202018 202114 20229 20235 Thereafter7 Total minimum rental payments$7520. Restructuring CostsIn April 2016, we announced an approximate 10 percent headcount reduction, which involved the elimination of certain operational and corporatepositions, as part of ongoing effort to create efficiencies, reduce costs and transform our business. As a result of this headcount reduction, we recorded one-time employee termination costs of approximately $13 million, which are included in restructuring costs in our consolidated statements of operations for theyear ended December 31, 2016.21. Business SegmentsOur operations are organized into two reportable segments: (i) Logistics and Marketing and (ii) Gathering and Processing. These segments are monitoredseparately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have beenidentified based on the differing products and services, regulatory environment and the expertise required for these operations. Our Gathering and Processingreportable segment includes operating segments that have been aggregated based on the nature of the products and services provided. Gross margin is aperformance measure utilized by management to monitor the operations of each segment. The accounting policies of the reportable segments are the same asthose described in the summary of significant accounting policies included in Note 2 - Summary of Significant Accounting Policies.Our Logistics and Marketing segment includes transporting, trading, marketing, and storing natural gas and NGLs, fractionating NGLs, and wholesalepropane logistics. Our Gathering and Processing segment consists of gathering, compressing, treating, processing natural gas, producing and fractionatingNGLs, and recovering condensate. The remainder of our business operations is presented as “Other,” and consists of unallocated corporate costs. Eliminationof inter-segment transactions are reflected in the eliminations column.129DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)The following tables set forth our segment information: Year Ended December 31, 2018: Logistics andMarketing Gathering andProcessing Other Eliminations Total (millions)Total operating revenue$9,014 $5,843 $— $(5,035) $9,822Gross margin (a)$225 $1,578 $— $— $1,803Operating and maintenance expense(47) (692) (21) — (760)Depreciation and amortization expense(15) (346) (27) — (388)General and administrative expense(12) (19) (245) — (276)Asset impairments— (145) — — (145)Other expense, net(4) (6) (1) — (11)Loss from financing activities— — (19) — (19)Earnings from unconsolidated affiliates362 8 — — 370Interest expense— — (269) — (269)Income tax expense— — (3) — (3)Net income (loss)$509 $378 $(585) $— $302Net income attributable to noncontrolling interests— (4) — — (4)Net income (loss) attributable to partners$509 $374 $(585) $— $298Non-cash derivative mark-to-market (b)$(4) $112 $— $— $108Capital expenditures$8 $570 $17 $— $595Investments in unconsolidated affiliates, net$350 $4 $— $— $354Year Ended December 31, 2017: Logistics andMarketing Gathering andProcessing Other Eliminations Total (millions)Total operating revenue$7,757 $5,467 $— $(4,762) $8,462Gross margin (a)$200 $1,377 $— $— $1,577Operating and maintenance expense(41) (602) (18) — (661)Depreciation and amortization expense(14) (343) (22) — (379)General and administrative expense(11) (19) (260) — (290)Asset impairments— (48) — — (48)Other expense(11) — — — (11)Gain on sale of assets, net— 34 — — 34Earnings from unconsolidated affiliates243 60 — — 303Interest expense— — (289) — (289)Income tax expense— — (2) — (2)Net income (loss)$366 $459 $(591) $— $234Net income attributable to noncontrolling interests— (5) — — (5)Net income (loss) attributable to partners$366 $454 $(591) $— $229Non-cash derivative mark-to-market (b)$(4) $(24) $— $— $(28)Non-cash lower of cost or market adjustments$2 $— $— $— $2Capital expenditures$3 $350 $22 $— $375Investments in unconsolidated affiliates, net$147 $1 $— $— $148130DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)Year Ended December 31, 2016: Logistics andMarketing Gathering andProcessing Other Eliminations Total (millions)Total operating revenue$6,186 $4,490 $— $(3,783) $6,893Gross margin (a)$205 $1,227 $— $— $1,432Operating and maintenance expense(43) (611) (16) — (670)Depreciation and amortization expense(15) (344) (19) — (378)General and administrative expense(9) (14) (269) — (292)Other (expense) income(5) 73 (3) — 65Gain on sale of assets, net16 19 — — 35Restructuring costs— — (13) — (13)Earnings from unconsolidated affiliates209 73 — — 282Interest expense— — (321) — (321)Income tax expense— — (46) — (46)Net income (loss)$358 $423 $(687) $— $94Net income attributable to noncontrolling interests— (6) — — (6)Net income (loss) attributable to partners$358 $417 $(687) $— $88Non-cash derivative mark-to-market (b)$(20) $(119) $— $— $(139)Non-cash lower of cost or market adjustments$3 $— $— $— $3Capital expenditures$10 $107 $27 $— $144Investments in unconsolidated affiliates, net$52 $1 $— $— $53 December 31, December 31, 2018 2017 (millions)Segment long-term assets: Gathering and Processing$9,058 $8,943Logistics and Marketing3,661 3,348Other (c)276 265Total long-term assets12,995 12,556Current assets1,271 1,322Total assets$14,266 $13,878(a)Gross margin consists of total operating revenues, including commodity derivative activity, less purchases and related costs. Gross margin is viewed as a non-GAAPfinancial measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it representsthe results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or moremeaningful than, net income or net cash provided by operating activities as determined in accordance with GAAP. Our gross margin may not be comparable to a similarlytitled measure of another company because other entities may not calculate gross margin in the same manner.(b)Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts.(c)Other long-term assets not allocable to segments consist of corporate leasehold improvements and other long-term assets.131DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)22. Supplemental Cash Flow Information Year Ended December 31, 2018 2017 2016 (millions)Cash paid for interest: Cash paid for interest, net of amounts capitalized$259 $290 $306Cash paid for income taxes, net of income tax refunds$3 $2 $2Non-cash investing and financing activities: Property, plant and equipment acquired with accounts payable and accrued liabilities$99 $58 $27Other non-cash changes in property, plant and equipment$5 $5 $(3)23. Quarterly Financial Data (Unaudited) Our consolidated results of operations by quarter for the years ended December 31, 2018 and 2017 were as follows:2018 First Second Third Fourth Year endedDecember 31,2018 (millions, except per unit amounts)Total operating revenues $2,139 $2,317 $2,759 $2,607 $9,822Operating income $53 $34 $66 $70 $223Net income $63 $62 $82 $95 $302Net income attributable to noncontrolling interests $(1) $(1) $(1) $(1) $(4)Net income attributable to partners $62 $61 $81 $94 $298Net income allocable to limited partners $12 $10 $26 $39 $87Basic and diluted net income per limited partner unit $0.08 $0.07 $0.18 $0.28 $0.612017 First Second Third Fourth Year EndedDecember 31,2017 (millions, except per unit amounts)Total operating revenues $2,121 $1,949 $2,055 $2,337 $8,462Operating income (loss) $101 $78 $(19) $62 $222Net income (loss) $101 $89 $(20) $64 $234Net income attributable to noncontrolling interests $— $(1) $— $(4) $(5)Net income (loss) attributable to partners $101 $88 $(20) $60 $229Net income allocable to limited partners $59 $47 $(59) $14 $61Basic and diluted net income per limited partner unit $0.41 $0.33 $(0.41) $0.10 $0.43 24. Supplementary Information - Condensed Consolidating Financial InformationThe following condensed consolidating financial information presents the results of operations, financial position and cash flows of DCP Midstream,LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a 100% owned subsidiary, and non-guarantor subsidiaries, as well as theconsolidating adjustments necessary to present DCP Midstream, LP’s results on a consolidated basis. The parent guarantor has agreed to fully andunconditionally guarantee debt securities of the subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries arereflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cashflows, or financial position had the subsidiaries operated as independent entities.132DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued) Condensed Consolidating Balance Sheets December 31, 2018 ParentGuarantor SubsidiaryIssuer Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated (millions)ASSETS Current assets: Cash and cash equivalents$— $— $1 $— $1Accounts receivable, net— — 1,033 — 1,033Inventories— — 79 — 79Other— — 158 — 158Total current assets— — 1,271 — 1,271Property, plant and equipment, net— — 9,135 — 9,135Goodwill and intangible assets, net— — 328 — 328Advances receivable — consolidated subsidiaries2,452 1,883 — (4,335) —Investments in consolidated subsidiaries4,818 8,113 — (12,931) —Investments in unconsolidated affiliates— — 3,340 — 3,340Other long-term assets— — 192 — 192Total assets$7,270 $9,996 $14,266 $(17,266) $14,266LIABILITIES AND EQUITY Accounts payable and other current liabilities$2 $71 $1,306 $— $1,379Current maturities of long-term debt— 325 200 — 525Advances payable — consolidated subsidiaries— — 4,335 (4,335) —Long-term debt— 4,782 — — 4,782Other long-term liabilities— — 283 — 283Total liabilities2 5,178 6,124 (4,335) 6,969Commitments and contingent liabilities Equity: Partners’ equity: Net equity7,268 4,821 8,118 (12,931) 7,276Accumulated other comprehensive loss— (3) (5) — (8)Total partners’ equity7,268 4,818 8,113 (12,931) 7,268Noncontrolling interests— — 29 — 29Total equity7,268 4,818 8,142 (12,931) 7,297Total liabilities and equity$7,270 $9,996 $14,266 $(17,266) $14,266 133DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued) Condensed Consolidating Balance Sheets December 31, 2017 ParentGuarantor SubsidiaryIssuer Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated (millions)ASSETS Current assets: Cash and cash equivalents$— $155 $1 $— $156Accounts receivable, net— — 981 — 981Inventories— — 68 — 68Other— — 117 — 117Total current assets— 155 1,167 — 1,322Property, plant and equipment, net— — 8,983 — 8,983Goodwill and intangible assets, net— — 337 — 337Advances receivable — consolidated subsidiaries2,895 1,614 — (4,509) —Investments in consolidated subsidiaries4,513 7,522 — (12,035) —Investments in unconsolidated affiliates— — 3,050 — 3,050Other long-term assets— — 186 — 186Total assets$7,408 $9,291 $13,723 $(16,544) $13,878LIABILITIES AND EQUITY Accounts payable and other current liabilities$— $71 $1,417 $— $1,488Advances payable — consolidated subsidiaries— — 4,509 (4,509) —Long-term debt— 4,707 — — 4,707Other long-term liabilities— — 245 — 245Total liabilities— 4,778 6,171 (4,509) 6,440Commitments and contingent liabilities Equity: Partners’ equity: Net equity7,408 4,517 7,527 (12,035) 7,417Accumulated other comprehensive loss— (4) (5) — (9)Total partners’ equity7,408 4,513 7,522 (12,035) 7,408Noncontrolling interests— — 30 — 30Total equity7,408 4,513 7,552 (12,035) 7,438Total liabilities and equity$7,408 $9,291 $13,723 $(16,544) $13,878 134DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued) Condensed Consolidating Statement of Operations Year Ended December 31, 2018 ParentGuarantor SubsidiaryIssuer Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated (millions)Operating revenues: Sales of natural gas, NGLs and condensate$— $— $9,374 $— $9,374Transportation, processing and other— — 489 — 489Trading and marketing losses, net— — (41) — (41)Total operating revenues— — 9,822 — 9,822Operating costs and expenses: Purchases and related costs— — 8,019 — 8,019Operating and maintenance expense— — 760 — 760Depreciation and amortization expense— — 388 — 388General and administrative expense— — 276 — 276Asset impairments— — 145 — 145Other expense, net— — 11 — 11Total operating costs and expenses— — 9,599 — 9,599Operating income— — 223 — 223Loss from financing activities— (19) — — (19)Interest expense, net— (268) (1) — (269)Income from consolidated subsidiaries298 585 — (883) —Earnings from unconsolidated affiliates— — 370 — 370Income before income taxes298 298 592 (883) 305Income tax expense— — (3) — (3)Net income298 298 589 (883) 302Net income attributable to noncontrolling interests— — (4) — (4)Net income attributable to partners$298 $298 $585 $(883) $298 Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2018 ParentGuarantor SubsidiaryIssuer Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated (millions)Net income$298 $298 $589 $(883) $302Other comprehensive income: Reclassification of cash flow hedge losses intoearnings— 1 — — 1Other comprehensive income fromconsolidated subsidiaries1 — — (1) —Total other comprehensive income1 1 — (1) 1Total comprehensive income299 299 589 (884) 303Total comprehensive income attributable tononcontrolling interests— — (4) — (4)Total comprehensive income attributable to partners$299 $299 $585 $(884) $299135DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued) Condensed Consolidating Statement of Operations Year Ended December 31, 2017 ParentGuarantor SubsidiaryIssuer Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated (millions)Operating revenues: Sales of natural gas, NGLs and condensate$— $— $7,850 $— $7,850Transportation, processing and other— — 652 — 652Trading and marketing losses, net— — (40) — (40)Total operating revenues— — 8,462 — 8,462Operating costs and expenses: Purchases and related costs— — 6,885 — 6,885Operating and maintenance expense— — 661 — 661Depreciation and amortization expense— — 379 — 379General and administrative expense— — 290 — 290Asset impairments— — 48 — 48Gain on sale of assets, net— — (34) — (34)Other expense, net— — 11 — 11Total operating costs and expenses— — 8,240 — 8,240Operating income— — 222 — 222Interest expense, net— (289) — — (289)Income from consolidated subsidiaries229 518 — (747) —Earnings from unconsolidated affiliates— — 303 — 303Income before income taxes229 229 525 (747) 236Income tax expense— — (2) — (2)Net income229 229 523 (747) 234Net income attributable to noncontrolling interests— — (5) — (5)Net income attributable to partners$229 $229 $518 $(747) $229 Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2017 ParentGuarantor SubsidiaryIssuer Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated (millions)Net income$229 $229 $523 $(747) $234Other comprehensive income: Reclassification of cash flow hedge losses intoearnings— 1 — — 1Other comprehensive income fromconsolidated subsidiaries1 — — (1) —Total other comprehensive income1 1 — (1) 1Total comprehensive income230 230 523 (748) 235Total comprehensive income attributable tononcontrolling interests— — (5) — (5)Total comprehensive income attributable to partners$230 $230 $518 $(748) $230136DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued) Condensed Consolidating Statement of Operations Year Ended December 31, 2016 ParentGuarantor SubsidiaryIssuer Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated (millions)Operating revenues: Sales of natural gas, NGLs and condensate$— $— $6,269 $— $6,269Transportation, processing and other— — 647 — 647Trading and marketing losses, net— — (23) — (23)Total operating revenues— — 6,893 — 6,893Operating costs and expenses: Purchases and related costs— — 5,461 — 5,461Operating and maintenance expense— — 670 — 670Depreciation and amortization expense— — 378 — 378General and administrative expense— — 292 — 292Gain on sale of assets, net— — (35) — (35)Restructuring costs— — 13 — 13Other income, net— — (65) — (65)Total operating costs and expenses— — 6,714 — 6,714Operating income— — 179 — 179Interest expense, net— (321) — — (321)Income from consolidated subsidiaries88 409 — (497) —Earnings from unconsolidated affiliates— — 282 — 282Income before income taxes88 88 461 (497) 140Income tax expense— — (46) — (46)Net income88 88 415 (497) 94Net income attributable to noncontrolling interests— — (6) — (6)Net income attributable to partners$88 $88 $409 $(497) $88 Condensed Consolidating Statement of Comprehensive Income Year Ended December 31, 2016 ParentGuarantor SubsidiaryIssuer Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated (millions)Net income$88 $88 $415 $(497) $94Other comprehensive income: Total other comprehensive income— — — — —Total comprehensive income88 88 415 (497) 94Total comprehensive income attributable tononcontrolling interests— — (6) — (6)Total comprehensive income attributable topartners$88 $88 $409 $(497) $88137DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued) Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2018 ParentGuarantor SubsidiaryIssuer Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated (millions)OPERATING ACTIVITIES Net cash (used in) provided by operatingactivities$— $(263) $925 $— $662INVESTING ACTIVITIES: Intercompany transfers443 (269) — (174) —Capital expenditures— — (595) — (595)Investments in unconsolidated affiliates, net— — (354) — (354)Proceeds from sale of assets— — 4 — 4Net cash provided by (used in) investingactivities443 (269) (945) (174) (945)FINANCING ACTIVITIES: Intercompany transfers— — (174) 174 —Proceeds from debt— 4,961 200 — 5,161Payments of debt— (4,560) — — (4,560)Costs incurred to redeem senior notes— (18) — — (18)Proceeds from issuance of preferred limited partnerunits, net of offering costs261 — — — 261Distributions to preferred limited partners(46) — — — (46)Distributions to limited partners and generalpartner(658) — — — (658)Distributions to noncontrolling interests— — (5) — (5)Other— (6) (1) — (7)Net cash (used in) provided by financingactivities(443) 377 20 174 128Net change in cash and cash equivalents— (155) — — (155)Cash and cash equivalents, beginning of period— 155 1 — 156Cash and cash equivalents, end of period$— $— $1 $— $1138DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued) Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2017 ParentGuarantor SubsidiaryIssuer Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated (millions)OPERATING ACTIVITIES Net cash (used in) provided by operatingactivities$— $(283) $1,179 $— $896INVESTING ACTIVITIES: Intercompany transfers58 1,141 — (1,199) —Capital expenditures— — (375) — (375)Investments in unconsolidated affiliates, net— — (148) — (148)Proceeds from sale of assets— — 132 — 132Net cash provided by (used in) investingactivities58 1,141 (391) (1,199) (391)FINANCING ACTIVITIES: Intercompany transfers— — (1,199) 1,199 —Proceeds from long-term debt— 116 — — 116Payments of debt— (811) — — (811)Proceeds from issuance of preferred limited partnerunits, net of offering costs487 — — — 487Net change in advances to predecessor from DCPMidstream, LLC— — 418 — 418Distributions to limited partners and generalpartner(545) — — — (545)Distributions to noncontrolling interests— — (7) — (7)Other— (8) — — (8)Net cash used in financing activities(58) (703) (788) 1,199 (350)Net change in cash and cash equivalents— 155 — — 155Cash and cash equivalents, beginning of period— — 1 — 1Cash and cash equivalents, end of period$— $155 $1 $— $156139DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued) Condensed Consolidating Statements of Cash Flows Year Ended December 31, 2016 ParentGuarantor SubsidiaryIssuer Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated (millions)OPERATING ACTIVITIES Net cash (used in) provided by operatingactivities$— $(305) $950 $— $645INVESTING ACTIVITIES: Intercompany transfers483 585 — (1,068) —Capital expenditures— — (144) — (144)Investments in unconsolidated affiliates, net— — (53) — (53)Proceeds from sale of assets— — 163 — 163Net cash (used in) provided by investingactivities483 585 (34) (1,068) (34)FINANCING ACTIVITIES: Intercompany transfers— — (1,068) 1,068 —Proceeds from long-term debt— 3,353 — — 3,353Payments of long-term debt— (3,628) — — (3,628)Net change in advances to predecessor from DCPMidstream, LLC— — 157 — 157Distributions to limited partners and generalpartner(483) — — — (483)Distributions to noncontrolling interests— — (7) — (7)Other— (5) — — (5)Net cash provided by (used in) financingactivities(483) (280) (918) 1,068 (613)Net change in cash and cash equivalents— — (2) — (2)Cash and cash equivalents, beginning of year— — 3 — 3Cash and cash equivalents, end of year$— $— $1 $— $125. Subsequent EventsOn January 23, 2019, we announced that the board of directors of the General Partner declared a quarterly distribution on our common units of $0.78per common unit. The distribution will be paid on February 14, 2019 to unitholders of record on February 4, 2019.On the same date, the board of directors of the General Partner declared a quarterly distribution on our Series B and Series C Preferred Units of $0.4922and $0.4969 per unit, respectively. The Series B distributions will be paid on March 15, 2019 to unitholders of record on March 1, 2019. The Series Cdistribution will be paid on April 15, 2019 to unitholders of record on April 1, 2019.On January 18, 2019, we issued $325 million of additional aggregate principal amount to our existing $500 million 5.375% Senior Notes due July2025. The full $825 million 5.375% Senior Notes due July 2025 will be treated as a single series of debt. We received proceeds of $324 million, net ofunderwriters’ fees, related expenses and issuance premiums, which we expect to use for general partnership purposes including the funding of capitalexpenditures and repayment of outstanding indebtedness under the Credit Agreement. Interest on the notes will be paid semi-annually in arrears on the 15thday of January and July of each year, with the initial interest payment on July 15, 2019.140DCP MIDSTREAM, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 2016 - (Continued)On January 30, 2019, we entered into a purchase and sale agreement with NGL Energy Partners LP to sell Gas Supply Resources, our wholesale propanebusiness primarily consisting of seven natural gas liquids terminals in the Eastern United States within our Logistics and Marketing segment forapproximately $90 million, subject to customary purchase price adjustments. The transaction is expected to close effective March 1, 2019. We expect torecognize a loss on sale of approximately $8 million, net of goodwill, in the first quarter of 2019.141Item 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureThere were no changes in or disagreements with accountants on accounting and financial disclosures during the year ended December 31, 2018.Item 9A. Controls and ProceduresEvaluation of Disclosure Controls and ProceduresWe maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file orsubmit to the SEC under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), is recorded, processed, summarized and reported within thetime periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to the management of our general partner,including our general partner’s principal executive and principal financial officers (whom we refer to as the "Certifying Officers"), as appropriate to allowtimely decisions regarding required disclosure. The management of our general partner evaluated, with the participation of the Certifying Officers, theeffectiveness of our disclosure controls and procedures as of December 31, 2018, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon thatevaluation, the Certifying Officers concluded that, as of December 31, 2018, our disclosure controls and procedures were effective at a reasonable assurancelevel.Changes in Internal Control Over Financial ReportingThere were no changes in internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during thequarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.Management’s Annual Report On Internal Control Over Financial ReportingOur general partner is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term isdefined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance to our management andboard of directors of our general partner regarding the preparation and fair presentation of published financial statements.All internal control systems, no matter how well designed, have inherent limitations. Therefore, internal control over financial reporting may notprevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequatebecause of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.Our management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internalcontrol over financial reporting as of December 31, 2018 based on the "Internal Control-Integrated Framework (2013)" issued by the Committee ofSponsoring Organizations of the Treadway Commission. Based on that evaluation, management concluded that our internal control over financial reportingwas effective at the reasonable assurance level as of December 31, 2018.Deloitte & Touche LLP, an independent registered public accounting firm, has issued their report, included immediately following, regarding ourinternal control over financial reporting.142REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors ofDCP Midstream GP, LLCDenver, ColoradoOpinion on Internal Control over Financial ReportingWe have audited the internal control over financial reporting of DCP Midstream, LP and subsidiaries (the "Partnership") as of December 31, 2018, based oncriteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission(COSO). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, basedon criteria established in Internal Control - Integrated Framework (2013) issued by COSO.We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidatedfinancial statements as of and for the year ended December 31, 2018, of the Company and our report dated February 25, 2019, expressed an unqualifiedopinion on those consolidated financial statements.Basis for OpinionThe Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness ofinternal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Ourresponsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit. We are a public accounting firmregistered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and theapplicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining anunderstanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operatingeffectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. Webelieve that our audit provides a reasonable basis for our opinion.Definition and Limitations of Internal Control over Financial ReportingA company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal controlover financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary topermit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the companyare being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financialstatements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate./s/ Deloitte & Touche LLPDenver, ColoradoFebruary 25, 2019143Item 9B. Other Information2019 Compensatory ArrangementsOn February 22, 2019, the Compensation Committee (the “Compensation Committee”) of the Board of Directors of DCP Midstream, LLC, the owner ofthe general partner (the “General Partner”) of the general partner of DCP Midstream, LP (the “Partnership”), established compensation levels for namedexecutive officers of the General Partner (the “NEOs”) for the 2019 fiscal year, to be effective as of March 25, 2019, as shown below:Name Base Salary Short-TermIncentive Target Long-Term IncentiveTarget TotalWouter T. van Kempen $695,000 100% 355% $3,857,250Sean P. O'Brien $459,740 75% 225% $1,838,960Brent L. Backes $436,560 65% 140% $1,331,508Don A. Baldridge $403,650 75% 175% $1,412,775Brian S. Frederick $402,220 75% 175% $1,407,770The Compensation Committee also established the performance criteria for certain compensation arrangements for the NEOs for the 2019 fiscal year. Theperformance criteria relate to grants to the NEOs under the DCP Services, LLC 2008 Long-Term Incentive Plan (the “LTI Plan”) and awards to the NEOsunder the short term cash incentive program (“STI”).The LTI Plan provides for the grant of cash-settled phantom units and cash-settled dividend equivalent rights. The phantom units consist of a notionalunit based on the fair market value of a common unit of the Partnership. The phantom units will be granted half in restricted phantom units (“RPUs”) and halfin strategic performance units (“SPUs”). RPUs will vest at the end of a three-year vesting period. SPUs will vest at a range of 0% to 200% depending on thelevel of achievement, as determined by the Compensation Committee, during a three-year performance period measured equally by (i) distributable cash flowper common unit of the Partnership and (ii) relative total shareholder return of the Partnership as compared to the following peer group:Andeavor Logistics LPEquitrans Midstream CorporationPhillips 66 Partners LPAntero Midstream GP LPGenesis Energy, L.P.SemGroup CorporationBuckeye Partners, L.P.Holly Energy Partners, L.P.Shell Midstream Partners, L.P.Cheniere Energy, Inc.Magellan Midstream Partners, L.P.Summit Midstream Partners, LPCrestwood Equity Partners LPMPLX LPTallgrass Energy, LPEnable Midstream Partners, LPNGL Energy Partners LPTarga Resources Corp.EnLink Midstream, LLCNuStar Energy L.P.TC PipeLines, LPEQM Midstream Partners, LPONEOK, Inc.Western Gas Equity Partners, LPAdditionally, on February 22, 2019, the Compensation Committee approved modifying the SPU grants awarded in 2018 in order to replace the peer grouptherein with the same peer group above that applies to the 2019 SPU grants. As a result of a number of consolidations and eliminations of constituentcompanies in the original 2018 SPU peer group, the Compensation Committee determined that it was appropriate to modify the peer group for the 2018 SPUgrants in order to establish a peer group that it believes is representative of the companies that investors use to assess our relative performance.The foregoing description of the SPU and RPU grants is qualified in its entirety by reference to the terms of the grant agreements, the forms of which arefiled herewith as Exhibits 10.12 and 10.13, respectively.The 2019 payout opportunity for STI awards will be based on the level of performance achieved by the Partnership on annual strategic priorities andgoals, including financial metrics of distributable cash flow, constant price cash generation, and cost; operational objectives involving varioustransformational efforts; and safety and environmental criteria such as recordable injury rate, process safety events, and emissions. 144PART IIIItem 10. Directors, Executive Officers and Corporate GovernanceManagement of DCP Midstream, LPWe do not have directors or officers, which is commonly the case with publicly traded partnerships. Our operations and activities are managed by ourgeneral partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as our General Partner.Our General Partner is 100% owned by DCP Midstream, LLC. The officers and directors of our General Partner are responsible for managing us. All of thedirectors of our General Partner are appointed annually by DCP Midstream, LLC and all of the officers of our General Partner serve at the discretion of thedirectors. Unitholders are not entitled to elect the directors of our General Partner or participate, directly or indirectly, in our management or operations.Board of Directors and Executive Officers of DCP Midstream GP, LLCThe board of directors of our General Partner currently has eight members, three of whom are independent as defined under the independence standardsestablished by the NYSE. Because we are a listed limited partnership and a controlled company, we are not required by the NYSE rules to have a majority ofindependent directors on the board of directors of our General Partner or to establish a compensation committee or a nominating/corporate governancecommittee. However, the board of directors of our General Partner has established an audit committee consisting of three independent members of the boardand a special committee to address conflict situations.Our General Partner’s board of directors annually reviews the independence of directors and affirmatively makes a determination that each directorexpected to be independent has no material relationship with our General Partner, either directly or indirectly as a partner, unitholder or officer of anorganization that has a relationship with our General Partner. Our General Partner’s board of directors has affirmatively determined that Messrs. Fowler,Kimble, and Waycaster satisfy the SEC and NYSE independence standards.The executive officers of our General Partner are responsible for establishing and executing strategic business and operation plans and managing theday-to-day affairs of our business. All of our executive officers are also executive officers of DCP Midstream, LLC. We utilize employees of DCP Midstream,LLC, including the executive officers, to operate our business and provide us with general and administrative services that are reimbursed to DCP Midstream,LLC pursuant to the terms of the Services Agreement.The following table shows information regarding the current directors and executive officers of our General Partner, DCP Midstream GP, LLC. Directorsare appointed annually by DCP Midstream, LLC and hold office for one year or until their successors have been elected and qualified or until the earlier oftheir death, resignation, removal or disqualification. Officers serve at the discretion of the board of directors of our general partner. There are no familyrelationships among any of the directors or executive officers.Name Age Position with DCP Midstream GP, LLC Wouter T. van Kempen 49 Chairman of the Board, President, Chief Executive Officer, and DirectorSean P. O'Brien 49 Group Vice President and Chief Financial OfficerBrent L. Backes 59 Group Vice President and General CounselDon Baldridge 49 President, CommercialBrian S. Frederick 53 President, Asset OperationsAllen C. Capps 48 DirectorFred J. Fowler 72 DirectorWilliam F. Kimble 59 DirectorMark Maki 54 DirectorBrian Mandell 55 DirectorBill W. Waycaster 80 DirectorJohn Zuklic 51 Director145Wouter T. van Kempen was appointed as DCP Midstream GP, LLC’s Chief Executive Officer ("CEO") in January 2013, Chairman of the Board inJanuary 2014, and President in February 2016. Mr. van Kempen is also the Chairman of the Board, President and Chief Executive Officer for DCP Midstream,LLC, which is the owner of DCP Midstream GP, LLC, since January 2013. Mr. van Kempen was previously DCP Midstream, LLC’s President and ChiefOperating Officer from September 2012 until January 2013, where he led the gathering and processing and the marketing and logistics business units andoversaw all corporate functions of the organization; President, Gathering and Processing, from January 2012 to August 2012; President, MidcontinentBusiness Unit, and Chief Development Officer, from August 2010 to December 2011. Prior to joining DCP Midstream, LLC in August 2010, Mr. van Kempenwas President of Duke Energy Generation Services from September 2006 to July 2010 and Vice President of Mergers and Acquisitions from December 2005to September 2006. Mr. van Kempen joined Duke Energy in 2003 and served in a number of management positions. Prior to Duke Energy, Mr. van Kempenwas employed by General Electric, where he served in increasing roles of responsibility becoming the staff executive for corporate mergers and acquisitionsin 1999.Sean P. O'Brien was appointed Group Vice President and Chief Financial Officer of DCP Midstream GP, LLC in January 2014. Mr. O'Brien is also theGroup Vice President and Chief Financial Officer for DCP Midstream, LLC and has served in that position since May 2012. Prior to that time, Mr. O’Brienwas Senior Vice President and Treasurer of DCP Midstream, LLC from May 2011 and prior to that, he served as Vice President, Financial Planning andAnalysis from September 2009. Prior to joining DCP Midstream, LLC in September 2009, Mr. O’Brien was with Duke Energy Corporation where he served asGeneral Manager of Financial Planning and Forecasting for Duke Energy’s Commercial Business Unit from May 2006, and prior to that, he was VicePresident and Controller of Duke Energy Generation Services from May 2005. Mr. O’Brien joined Duke Energy in 1997. Mr. O’Brien is a certified publicaccountant with over 25 years of experience in the finance area and over 20 years of experience in the energy industry.Brent L. Backes was appointed Group Vice President and General Counsel of DCP Midstream GP, LLC in February 2017. Mr. Backes has also served asthe Group Vice President and General Counsel of DCP Midstream, LLC since February 2002. Prior to joining DCP Midstream, LLC in 1998, Mr. Backes wasan attorney in private practice focusing on mergers and acquisitions and regulatory matters in the energy industry since 1987.Don Baldridge was appointed President, Commercial of DCP Midstream GP, LLC in February 2017. Mr. Baldridge has also been a President of DCPMidstream, LLC overseeing the commercial, marketing, and logistics businesses since March 2013 and before that was Vice President, Natural Gas and NGLMarketing since February 2011. Mr. Baldridge previously served as our Vice President, Business Development from January 2009 until February 2011. Mr.Baldridge joined DCP Midstream, LLC in March 2005. Mr. Baldridge brings more than 25 years of experience in the energy industry, including commercial,trading and business development activities.Brian S. Frederick was appointed President, Asset Operations of DCP Midstream GP, LLC in February 2017. Mr. Frederick has also been President,Asset Operations of DCP Midstream, LLC since February 2014 and prior to that was President of the Southern and Midcontinent business units of DCPMidstream, LLC since March 2013. Mr. Frederick joined DCP Midstream, LLC in 1999 and previously served as Vice President of Corporate Developmentand Vice President of Gas Marketing. Mr. Frederick has more than 25 years of experience in the energy industry leading operations, commercial, trading andbusiness development teams.Allen C. Capps was appointed a director of DCP Midstream GP, LLC in August 2016. Mr. Capps is currently the senior vice president and chiefaccounting officer of Enbridge. Prior to assuming his current role in February 2017, Mr. Capps served in a similar capacity as vice president and controller ofSpectra Energy since January 2012. From April 2010 until January 2012, Mr. Capps served as Vice President, Business Development, Storage andTransmission, for Union Gas Limited, Spectra Energy’s Canadian natural gas utility, and as Vice President and Treasurer of Spectra Energy from December2007 to April 2010. Mr. Capps has broad experience in the energy industry having served in various senior level finance and accounting roles since 2003.Fred J. Fowler was appointed a director of DCP Midstream GP, LLC in March 2015. Mr. Fowler is the former president and chief executive officer ofSpectra Energy, retiring from that position in December 2008. Prior to Spectra Energy’s separation from Duke Energy Corporation in December 2006, Mr.Fowler served as group president for Duke Energy’s gas transmission business since April 2006. Prior to that, Mr. Fowler served as president and chiefoperating officer of Duke Energy Corporation since November 2002. Mr. Fowler began his career in the energy industry in 1968. Mr. Fowler served as vicechairman of the board of directors of TEPPCO Partners, L.P. from March 1998 to February 2003 and as chairman of the board of directors of our GeneralPartner from April 2007 to January 2009. Mr. Fowler currently serves on the boards of directors of Encana Corp. and PG&E Corporation.146William F. Kimble was appointed a director of DCP Midstream GP, LLC in June 2015. Mr. Kimble retired in February 2015 from KPMG LLP (“KPMG”),one of the largest audit, tax and advisory services firms in the world. Mr. Kimble served as KPMG’s Office Managing Partner for the Atlanta office andManaging Partner - Southeastern United States, where he was responsible for the firm’s audit, advisory and tax operations from 2009 until his retirement. Mr.Kimble was also responsible for moderating KPMG’s Audit Committee Institute and Audit Committee Chair Sessions. Until his retirement, Mr. Kimble hadbeen with KPMG or its predecessor firm since 1986. During his tenure with KPMG, Mr. Kimble held numerous senior leadership positions, including GlobalChairman of Industrial Markets. Mr. Kimble also served as KPMG’s Energy Sector Leader for approximately 10 years and was the executive director ofKPMG’s Global Energy Institute. Mr. Kimble currently serves on the board of directors of PRGX Global, Inc. and its audit committee and Liberty OilfieldServices Inc. and its audit committee.Mark Maki was appointed a director of DCP Midstream GP, LLC in July 2018. Mr. Maki serves as senior vice president, corporate planning andsponsored vehicles of Enbridge, having assumed this role in May 2018 after serving as Senior Vice President - Finance Business Partners since October 2016.Mr. Maki also served as a director of the general partner of Enbridge Energy Partners, L.P. (“EEP”) and Enbridge Energy Management, L.L.C. (“EEQ”) fromOctober 2010 to December 2018 and as President of both companies from January 2014 to December 2018. Previously, Mr. Maki served as President of EEPand Senior Vice President of EEQ from October 2010 to January 2014 and he served Enbridge as Acting President, Gas Pipelines during 2013. Mr. Maki alsopreviously served as Vice President - Finance of EEP and EEQ from July 2002. Prior to that time, Mr. Maki served as Controller of EEP and EEQ from June2001, and prior to that, as Controller of Enbridge Pipelines from September 1999. Mr. Maki began his career with Enbridge in 1986.Brian Mandell was appointed a director of DCP Midstream GP, LLC in May 2015. Mr. Mandell has nearly 30 years of oil and gas industry experienceserving in various marketing, commercial, and midstream roles. He is currently Senior Vice President, Marketing and Commercial, for Phillips 66. Hepreviously served as Senior Vice President, Commercial, for Phillips 66. Prior to that, he served as Phillips 66's President, Global Marketing, and prior to that,Global Trading Lead, Clean Products, Commercial. Prior to joining Phillips 66 in May 2012, he worked for ConocoPhillips as Manager, U.S. GasolineTrading since 2011. Previously, Mr. Mandell served in the Commercial NGL group and was named Manager of NGL Trading after working as Manager ofProcessing Assets and Business Development in 2006. Mr. Mandell began his career with Conoco in 1991 working in various marketing roles.Bill W. Waycaster was appointed a director of DCP Midstream GP, LLC in June 2015. Mr. Waycaster retired in April 2003 from Texas PetrochemicalsLLC (“Texas Petrochemicals”) after working in the hydrocarbon process industries for over 45 years. Mr. Waycaster was President and Chief ExecutiveOfficer of Texas Petrochemicals from April 1992 until his retirement. Prior to that, Mr. Waycaster spent 27 years at The Dow Chemical Company (“Dow”)serving as Vice President and General Manager of Hydrocarbons and Energy Resources when he left to join Texas Petrochemicals. Mr. Waycaster heldpositions at Dow ranging from Project Engineer to Vice President of Business and Asset Management. Mr. Waycaster previously served on the board ofdirectors of the National Petrochemical and Refiners Association, where he served as Chairman of the Petrochemicals Committee and Executive Committee,and also served on the board of directors of the American Chemistry Council. Mr. Waycaster has previously served on the board of directors of each of DestecEnergy, Inc. and Enterprise Products GP, LLC.John Zuklic was appointed a director of DCP Midstream GP, LLC in May 2015. Mr. Zuklic has more than 20 years of oil and gas industry experienceserving in various finance and commercial roles. He is currently Vice President and Treasurer of Phillips 66 and prior to assuming that role in May 2015 wasGeneral Manager, Global Commercial Risk and Compliance. Before joining Phillips 66 and assuming the role of Assistant Treasurer in May 2012, Mr. Zuklicworked for ConocoPhillips as Manager, Treasury Services, since 2008. In 2004, he was named Principal Consultant, Treasury, and prior to that he wasDirector, Midstream Finance, from 2000 to 2004. Prior to joining ConocoPhillips in 2000, Mr. Zuklic worked at BP p.l.c. for five years in various treasury,finance, and commercial positions.Director Experience and QualificationsDCP Midstream, LLC evaluates and recommends candidates for membership on the board of directors of our General Partner based on establishedcriteria. When evaluating director candidates, nominees and incumbent directors, DCP Midstream, LLC has informed us that it considers, among other things,educational background, knowledge of our business and industry, professional reputation, independence, and ability to represent the best interests of ourunitholders. DCP Midstream, LLC and the board of directors of our General Partner believe that the above-mentioned attributes, along with the leadershipskills and experience in the midstream natural gas industry, provide the Partnership with a capable and knowledgeable board of directors.147Wouter T. van Kempen - Mr. van Kempen was appointed a director because of his extensive knowledge of and experience with our assets as Chairman,President, and Chief Executive Officer of DCP Midstream GP, LLC and as Chairman, President and Chief Executive Officer of DCP Midstream, LLC. Mr. vanKempen brings strong management experience having served in positions of increasing responsibility at Duke Energy and General Electric.Allen C. Capps - Mr. Capps was appointed a director because of his strong background in the energy industry including his leadership roles inaccounting, finance, and business development with Enbridge and Spectra Energy.Fred J. Fowler - Mr. Fowler was appointed a director because of his extensive knowledge and experience of the energy industry, including a strongunderstanding of our assets, customers, regulatory environment, and competitive landscape. Mr. Fowler brings leadership, management, and business skillsdeveloped as an executive and a director at public and privately held companies.William F. Kimble - Mr. Kimble was appointed a director because of his extensive accounting background and experience as a director of other publiccompanies. Mr. Kimble brings significant knowledge of the most current and pressing audit and financial compliance matters and reporting obligations facedby public companies.Mark Maki - Mr. Maki was appointed a director because of his broad range of experience in the pipeline industry having progressed through a series ofaccounting, regulatory, financial, and executive roles of increasing responsibility during his tenure with Enbridge in the United States and Canada. Mr. Makibrings financial expertise, leadership skills, knowledge of our business environment, and knowledge of master limited partnerships developed over 30 plusyears in the industry.Brian Mandell - Mr. Mandell was appointed a director because of his strong background and knowledge with over two decades of senior leadershipexperience in a variety of roles including commercial and marketing within the industry.Bill W. Waycaster - Mr. Waycaster was appointed a director because of his lengthy tenure in the energy industry and executive management experience,spanning a period of over 50 years. Mr. Waycaster contributes valuable insight into strategic, corporate governance, and compliance matters with his priorpublic company leadership and board experience.John Zuklic - Mr. Zuklic was appointed a director because of his strong knowledge and extensive experience in the energy industry gained through hiscurrent and past roles in treasury, finance, commercial, and risk management.Section 16(a) Beneficial Ownership Reporting ComplianceSection 16(a) of the Exchange Act requires DCP Midstream GP, LLC’s directors and executive officers, and persons who own more than 10% of aregistered class of our equity securities to file with the SEC and the NYSE initial reports of ownership and reports of changes in ownership of our commonunits and our other equity securities and to furnish us with copies of such reports. To our knowledge, based solely on a review of the copies of reports andamendments thereto furnished to us and written representations that no other reports were required, all Section 16(a) filing requirements applicable to suchreporting persons were complied with on a timely basis during the fiscal year ended December 31, 2018.Audit CommitteeThe board of directors of our General Partner has a standing audit committee. The audit committee is composed of three independent directors, WilliamF. Kimble (chairman), Fred J. Fowler, and Bill W. Waycaster, each of whom is able to understand fundamental financial statements and at least one of whomhas past experience in accounting or related financial management experience. Mr. Kimble has been designated by the board as the audit committee’sfinancial expert meeting the requirements promulgated by the SEC as set forth in Item 407(d) of Regulation S-K of the Exchange Act based upon hiseducation and employment experience as more fully detailed in Mr. Kimble’s biography set forth above.The board has determined that each member of the audit committee is independent under Section 303A.02 of the NYSE listing standards and Section10A(m)(3) of the Exchange Act. In making the independence determination, the board considered the requirements of the NYSE and our CorporateGovernance Guidelines. Among other factors, the board considered current or previous employment with us, our auditors or their affiliates by the director orhis immediate family members, ownership of our voting securities, and other material relationships with us.The audit committee has adopted a charter, which has been ratified and approved by the board of directors. The primary purpose of the audit committeeis to assist the board of directors in its oversight of (1) the integrity of the financial statements of the Partnership, (2) the compliance by the General Partnerand the Partnership with legal and regulatory requirements, and the148General Partner’s and the Partnership’s Code of Business Ethics, (3) the independent auditor’s qualifications and independence and (4) the performance of thePartnership’s internal audit function and independent auditors.Special CommitteeThe board of directors of our General Partner has a special committee. The special committee, comprised of two or more of our independent directors, isconvened on an ad hoc basis and will review specific matters that the board believes may involve conflicts of interest, including transactions between us andDCP Midstream, LLC or its affiliates. The special committee will determine if the resolution of the conflict of interest is fair and reasonable to us, or ongrounds no less favorable to us than generally available from unrelated third parties. The special committee meets as requested by the board of directors. Themembers of the special committee may not be officers or employees of our General Partner or directors, officers or employees of its affiliates. Each of themembers of the special committee meet the independence and experience standards established by the NYSE and the Exchange Act. Any matters approvedby the special committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our General Partnerof any duties it may owe us or our unitholders.Corporate Governance Guidelines, Code of Business Ethics, and Audit Committee CharterThe board of directors of our general partner adopted Corporate Governance Guidelines that outline the important policies and practices regarding ourgovernance.We have adopted a Code of Business Ethics applicable to all persons serving as our directors, officers (including without limitation, our principalexecutive officer, principal financial officer and principal accounting officer) and employees. We intend to disclose any amendment to or waiver of our Codeof Business Ethics that applies to our executive officers or directors on our website at www.dcpmidstream.com in order to satisfy disclosure requirementsunder SEC and NYSE rules relating to such information.Copies of our Corporate Governance Guidelines, Code of Business Ethics and Audit Committee Charter are available on our website atwww.dcpmidstream.com. Copies of these items are also available free of charge in print to any person who sends a request to the office of the CorporateSecretary of DCP Midstream at 370 17th Street, Suite 2500, Denver, Colorado 80202. The information contained on, or connected to, our website is notincorporated 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 or furnish to theSEC.Meeting of Non-Management Directors and Communications with DirectorsAt each quarterly meeting of the board of directors of our general partner, the independent directors meet in an executive session, which executivesessions are presided over by William F. Kimble. In addition, at each quarterly meeting of the board of directors, the non-management members of the boardmeet in executive session, which executive sessions are presided over by Fred J. Fowler.Unitholders or interested parties may communicate with any and all members of our board, including our non-management directors, or any committeeof our board, by transmitting correspondence by mail or facsimile addressed to one or more directors by name or to the chairman of the board or anycommittee of the board at the following address and fax number: Name of the Director(s), c/o Corporate Secretary, DCP Midstream, 370 17th Street, Suite2500, Denver, Colorado 80202, fax number 720-944-0124.Report of the Audit CommitteeThe audit committee oversees our financial reporting process on behalf of the board of directors. Management has the primary responsibility for thefinancial statements and the reporting process including the systems of internal controls over financial reporting. The audit committee operates under awritten charter approved by the board of directors. The charter, among other things, provides that the audit committee is responsible for the appointment,compensation, oversight, retention, and termination of the independent auditor. In this context, the audit committee:•reviewed and discussed quarterly and annual earnings press releases, quarterly unaudited financial statements, and the annual audited financialstatements included in this Annual Report on Form 10-K with management and Deloitte & Touche LLP, our independent auditors, including adiscussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity ofdisclosures in the financial statements;149•reviewed with Deloitte & Touche LLP, who are responsible for expressing an opinion on the conformity of the audited financial statements withgenerally accepted accounting principles, their judgments as to the quality and acceptability of our accounting principles and such othermatters as are required to be discussed with the audit committee under the auditing standards of the Public Company Accounting OversightBoard (PCAOB);•received the written disclosures and the letter required by PCAOB Ethics and Independence Rules (independence discussions with auditcommittees) provided to the audit committee by Deloitte & Touche LLP;•discussed with Deloitte & Touche LLP its independence from management and us and considered the compatibility of the provision ofnonaudit service by the independent auditors with the auditors’ independence;•discussed with Deloitte & Touche LLP the matters required to be discussed by statement on auditing standards No. 16 (PCAOB AuditingStandard No. 16, Communications With Audit Committees, Related Amendments to PCAOB Standards and Transitional Amendments to AUSection 380);•discussed with our internal auditors and Deloitte & Touche LLP the overall scope and plans for their respective audits. The audit committeemeets with the internal auditors and Deloitte & Touche LLP, with and without management present, to discuss the results of their examinations,their evaluations of our internal controls and the overall quality of our financial reporting;•based on the foregoing reviews and discussions, recommended to the board of directors that the audited financial statements be included in theAnnual Report on Form 10-K for the year ended December 31, 2018, for filing with the SEC; and•approved the reappointment of Deloitte & Touche LLP to serve as our independent auditors based on an annual consideration of, among otherfactors, the following: their historical and recent performance on our audit, the quality and candor of their communications with the auditcommittee and management, the depth of expertise of their audit team and the value provided by their national office, the appropriateness oftheir fees, how effectively they maintained their independence, their tenure as our independent auditors, their knowledge of our operations,accounting policies and practices, and internal control over financial reporting, and external data relating to audit quality and performance bythem and their peer firms.This report has been furnished by the members of the audit committee of the board of directors:Audit Committee William F. Kimble (Chairman)Fred J. FowlerBill W. WaycasterThe report of the audit committee in this report shall not be deemed incorporated by reference into any other filing by DCP Midstream, LP under theSecurities Act of 1933, as amended, or the Exchange Act, except to the extent that we specifically incorporate this information by reference, and shall nototherwise be deemed filed under such laws.150Item 11. Executive CompensationCompensation Discussion and AnalysisGeneralWe were formed in 2005. Similar to other publicly traded partnerships, our operations are managed by our general partner, DCP Midstream GP, LP,which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as our General Partner. Our General Partner is 100% owned byDCP Midstream, LLC. When we refer herein to the board of directors, we are referring to the board of directors of our General Partner. Additionally, when werefer herein to the compensation committee, we are referring to the compensation committee of the board of directors of DCP Midstream, LLC, comprised ofChairman Greg C. Garland, Chairman and CEO of Phillips 66 and Al Monaco, President and CEO of Enbridge Inc.We have entered into the Services Agreement with DCP Midstream, LLC pursuant to which, among other matters, DCP Services, LLC makes availableits employees who manage and operate our assets and serve as the executive officers, including the named executive officers, or NEOs, of our General Partner.For the year ended December 31, 2018, the NEOs of our General Partner were Wouter T. van Kempen, Chairman of the Board, President, and Chief ExecutiveOfficer (Principal Executive Officer); Sean P. O’Brien, Group Vice President and Chief Financial Officer (Principal Financial Officer); Brent L. Backes, GroupVice President and General Counsel, Don A. Baldridge, President, Commercial and Brian S. Frederick, President, Asset Operations.The NEOs prior to the Transaction allocated their time between managing our business and the business of DCP Midstream, LLC. Following the closingof the Transaction, each of the current NEOs devotes all of their time to our business.The General Partner has not entered into employment agreements with any of the NEOs. The NEOs do not receive any separate compensation from us fortheir services to our business or as executive officers of our General Partner. We pay DCP Midstream, LLC the full cost for the compensation of our NEOs. Thecompensation committee has the ultimate decision-making authority with respect to the total compensation that DCP Midstream, LLC pays to the NEOs.Compensation DecisionsAll compensation decisions concerning the officers and employees dedicated to our operations and management are made by the compensationcommittee. The compensation committee’s responsibilities on compensation matters include the following:•annually review the Partnership’s goals and objectives relevant to compensation of the NEOs;•annually evaluate the NEO’s performance in light of the Partnership’s goals and objectives, and approve the compensation levels for the NEOs;•periodically evaluate the terms and administration of short-term and long-term incentive plans to assure that they are structured and administered ina manner consistent with the Partnership’s goals and objectives;•periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;•retain and terminate any compensation consultant to assist in the evaluation of compensation for directors who are not officers or employees of theGeneral Partner or its affiliates, or our non-employee directors, and NEOs; and•periodically review the compensation of the non-employee directors.Compensation PhilosophyThe Partnership’s compensation program is structured to provide the following benefits:•attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that ofother executive officers in our industry;•motivate executive officers and key management employees to achieve strong financial and operational performance;151•emphasize performance-based compensation, balancing short-term and long-term results; and•reward individual performance.Methodology - Advisors and Peer CompaniesThe compensation committee reviews data from market surveys provided by independent consultants to assess our competitive position with respect tobase salary, annual short-term incentives and long-term incentive compensation for our NEOs as well as the compensation package for our non-employeedirectors. With respect to NEO compensation, the compensation committee also considers individual performance, levels of responsibility, skills andexperience. In 2017, management, on behalf of the compensation committee, engaged the services of Mercer, a compensation consultant, to conduct a studyto assist us in establishing overall compensation packages for the NEOs for 2018. We consider Mercer to be independent of the Partnership and therefore, thework performed by Mercer does not create a conflict of interest. The Mercer study was based on compensation for a group of peer companies with similaroperations obtained from public documents as well as multiple survey sources, including the 2017 Mercer Benchmark Database and the 2017 Mercer TotalCompensation Survey for the Energy Sector.The Mercer study was comprised of the following peer companies:Boardwalk Pipeline Partners, LPMagellan Midstream Partners, L.P.Buckeye Partners, L.P.MPLX LPCrestwood Equity Partners LPNuStar Energy L.P.Enable Midstream Partners, LPONEOK, Inc.EnLink Midstream Partners, LPTarga Resources Corp.Genesis Energy, L.P.Western Gas Partners, LPStudies such as this generally include only the most highly compensated officers of each company, which correlates with most of the NEOs. The resultsof this study as well as other factors such as targeted performance objectives served as a benchmark for establishing total annual direct compensationpackages for the NEOs. Peer data from the Mercer study and the data point that represents the 50th percentile of the market in the surveys were used to assessthe competitiveness of the total annual direct compensation packages for the NEOs.Components of CompensationThe total annual direct compensation program for the NEOs consists of three components: (1) base salary; (2) a short-term cash incentive, or STI, whichis based on a percentage of annual base salary; and (3) the present value of a grant of phantom units payable in cash upon vesting under the DCP Services,LLC 2008 Long-Term Incentive Plan, or LTIP, which is based on a percentage of annual base salary. Effective March 26, 2018, the base salary, short-termincentive targets, and long-term incentive targets for our NEOs were as follows:Name and Principal Position Base Salary Short-TermIncentiveTarget Long-TermIncentiveTarget TotalWouter T. van Kempen, Chairman, President & CEO $682,900 100% 275% $3,243,775Sean P. O'Brien, Group Vice President & Chief Financial Officer $437,850 75% 200% $1,641,938Brent L. Backes, Group Vice President & General Counsel $423,840 65% 140% $1,292,712Don A. Baldridge, President, Commercial $390,000 75% 175% $1,365,000Brian S. Frederick, President, Asset Operations $402,220 75% 175% $1,407,770In allocating compensation among these components, we believe a significant portion of the compensation of the NEOs should be performance-basedsince these individuals have a greater opportunity to influence our performance. In making this allocation, we have relied in part on the Mercer study andconsidered each component of compensation as described below.Base Salary - Base salaries for NEOs are determined based upon job responsibilities, level of experience, individual performance, and comparisons tothe salaries of individuals in similar positions obtained from the Mercer study. The goal of the152base salary component is to compensate NEOs at a level that approximates the median salaries of individuals in comparable positions at comparably sizedcompanies in our industry.The base salaries for NEOs are generally reevaluated annually as part of our performance review process, or when there is a change in the level of jobresponsibility. The compensation committee annually considers and approves a merit increase in base salary based upon the results of this performancereview process. Merit increases are based on industry trends and a review of individual performance in certain categories, such as business values,environmental, health & safety performance, leadership, financial results, project results, attitude, ability and knowledge.Annual Short-Term Cash Incentive - Under the STI plan, annual cash incentives are provided to executives to promote the achievement of ourperformance objectives. Target incentive opportunities for executives under the STI are established as a percentage of base salary. Incentive amounts areintended to provide total cash compensation at the market median for executive officers in comparable positions when target performance is achieved, belowthe market median when performance is less than target and above the market median when performance exceeds target. The Mercer study was used todetermine the competitiveness of the incentive opportunity for comparable positions. STI payments are generally paid in cash in March of each year for theprior fiscal year’s performance.The 2018 STI objectives were initially designed and proposed by our Chairman of the Board, President, and CEO and subsequently approved by thecompensation committee. All STI objectives are tied to the performance of the Partnership and are subject to change each year based on annual strategicpriorities and goals. The 2018 objectives comprising the total STI opportunity for the NEOs are described below.Financial objectives (65% of total STI):1.Distributable Cash Flow. An objective intended to capture the annual amount of cash that is available for the quarterly distributions to ourunitholders. For this objective, we established a range of performance from a minimum of $600 million to a maximum of $670 million.2.Constant Price Cash Generation. An objective intended to capture the cash generated from operations for the Partnership excluding the effect ofcommodity prices. For this objective, we established a range of performance from a minimum of $930 million to a maximum of $1,020 million.3.Cost. An objective intended to capture the ongoing operating and general and administrative costs of the Partnership. For this objective, weestablished a range of performance from a minimum of $945 million to a maximum of $900 million.Operational objectives (20% of total STI):1.Plant Downtime. An objective to measure operating reliability improvement with the intent to maximize our customers’ productivity.2.Operational EBITDA Improvement. An objective intended to capture the additional EBITDA generated through DCP's Integrated CollaborationCenter, which utilizes real-time data on our operations, financial systems, and other information to optimize asset performance to achieve higherreliability, margin, and cost savings.Safety & Environmental Objectives (15% of total STI):1.Total Recordable Injury Rate (TRIR). An objective of both employee and contractor incident rates covering the assets of the Partnership. For thisobjective, the maximum level of performance is a TRIR of 0.32 and the minimum level of performance is a TRIR of 0.67.2.Process Safety Event Ratio (PSE Ratio). An objective using a broad definition of process safety events covering the assets of the Partnership. For thisobjective, the maximum level of performance is a PSE Ratio of 2.37 and a minimum level of performance is a PSE Ratio of 4.39.3.Total Emissions. An objective of air emissions, natural gas vented or flared, covering the assets of the Partnership. For this objective, we haveestablished certain levels of emissions at such assets.153The payout on the Partnership objectives range from 0% if the minimum level of performance is not achieved, 50% if the minimum level of performanceis achieved, 100% if the target level of performance is achieved and 200% if the maximum level of performance is achieved. When the performance level fallsbetween these percentages, payout will be evaluated using straight-line interpolation with the final percentages determined by the compensation committee.Early in 2019, management prepared a report on the achievement of the Partnership objectives during 2018. These results were then reviewed andapproved by the compensation committee. The level of performance achieved in 2018 for each of the STI objectives was as follows:STI Objectives Level of Performance AchievedDistributable Cash Flow At MaximumConstant Price Cash Generation At MaximumCost Below MinimumPlant Downtime Below MinimumOperational EBITDA Improvement At MaximumTotal Recordable Injury Rate (TRIR) At MaximumProcess Safety Event Ratio (PSE Ratio) Between Target & MaximumTotal Emissions Between Minimum & TargetLong-Term Incentive Plan - The LTIP has the objective of providing a focus on long-term value creation and enhancing executive retention. Under theLTIP, phantom units are issued where half of such phantom units are strategic performance units, or SPUs, and half are restricted phantom units, or RPUs. TheSPUs will vest based upon the level of achievement of certain performance objectives over a three-year performance period, or the Performance Period. TheRPUs will vest if the executive officer remains employed at the end of a three-year vesting period, or the Vesting Period. We believe this program promotesretention of the executive officers, and focuses the executive officers on the goal of long-term value creation.For 2018, the SPUs had the following two performance measures: (1) distributable cash flow, or DCF, as defined in Item 7. “Management’s Discussionand Analysis of Financial Condition and Results of Operations,” per common unit of the Partnership over the Performance Period; and (2) relative totalshareholder return, or RTSR, defined as total shareholder return of the Partnership over the Performance Period relative to the below peer group. Half of theSPUs will be measured against the DCF performance measure and the other half will be measured against the RTSR performance measure. The compensationcommittee believes in utilizing DCF of the Partnership, which is a liquidity and performance measure that reflects our ability to make cash distributions toour unitholders and our general partner, and RTSR, which reflects our performance as compared to a group of representative companies that investors use toassess our relative performance, because they measure management’s effectiveness and directly align the performance of the NEOs with the success of thePartnership. We believe these performance measures provide management with appropriate incentives for our disciplined and steady growth.For the DCF performance measure, DCF for the Partnership will be measured against the final DCF per common unit for the fiscal year 2020 ascalculated from its 2020 financial statements.As discussed in Item 9B. “Other Information,” the peer group applicable to the 2018 SPU grants under the LTIP was modified such that the peer groupfor the RTSR performance measure for the 3-year performance period that started in 2018 is as follows:Andeavor Logistics LPEquitrans Midstream CorporationPhillips 66 Partners LPAntero Midstream GP LPGenesis Energy, L.P.SemGroup CorporationBuckeye Partners, L.P.Holly Energy Partners, L.P.Shell Midstream Partners, L.P.Cheniere Energy, Inc.Magellan Midstream Partners, L.P.Summit Midstream Partners, LPCrestwood Equity Partners LPMPLX LPTallgrass Energy, LPEnable Midstream Partners, LPNGL Energy Partners LPTarga Resources Corp.EnLink Midstream, LLCNuStar Energy L.P.TC PipeLines, LPEQM Midstream Partners, LPONEOK, Inc.Western Gas Equity Partners, LPThese SPU and RPU awards are granted as of January 1st each year. Award recipients also receive the right to receive dividend equivalent rights, orDERs, on the number of common units earned during the Vesting Period. The DERs on the SPUs are paid in cash at the end of the Performance Period and theDERs on the RPUs are paid quarterly in cash during the Vesting154Period. The amount paid on the DERs is equal to the quarterly distributions actually paid on the underlying securities during the Performance Period and theVesting Period on the number of SPUs earned or RPUs granted, respectively.Our practice is to determine the dollar amount of long-term incentive compensation that we want to provide, and to then grant a number of SPUs andRPUs that have a fair market value equal to that amount on the date of grant, which is based on the average closing price of our common units on the NYSEfor the 20 trading days prior to the date of grant under the LTIP. Target long-term incentive opportunities for executives under the plan are established as apercentage of base salary, using the Mercer study data for individuals in comparable positions.In the event an award recipient’s employment is terminated after the first anniversary of the grant date for reasons of death, disability, retirement, orlayoff, the recipient’s: (i) SPUs will contingently vest on a pro rata basis for time worked over the Performance Period and final performance, measured at theend of the Performance Period, will determine the payout and (ii) RPUs will become fully vested and payable. Termination of employment for any otherreason will result in the forfeiture of any unvested units and unpaid DERs.Other Compensation - In addition, executives are eligible to participate in other compensation programs, which include but are not limited to:Company Matching and Retirement Contributions to Defined Contribution Plans - Executives may elect to participate in a 401(k) and retirement plan.Under the plan, executives may elect to defer up to 75% of their eligible compensation, or up to the limits specified by the Internal Revenue Service. Wematch the first 6% of eligible compensation contributed by the executive to the plan. In addition, we make retirement contributions ranging from 4% to 7%of the eligible compensation of qualifying participants to the plan, based on years of service, up to the limits specified by the Internal Revenue Service. Wehave no defined benefit plans.Miscellaneous Compensation - Executive officers are eligible to participate in a non-qualified deferred compensation program. Executive officers areallowed to defer up to 75% of their base salary, up to 90% of their STI and up to 100% of their LTIP or other compensation. Executive officers elect either toreceive amounts contributed during specific plan years as a lump sum at a specific date, subject to Internal Revenue Service rules, as an annuity (up to fiveyears) at a specific date, subject to Internal Revenue Service rules, or in a lump sum or annual annuity (over three to ten years) at termination.Within the non-qualified deferred compensation program is a non-qualified, defined contribution retirement plan in which benefits earned under theplan are attributable to compensation in excess of the annual compensation limits under Section 401(k) of the Code. Under this part of the plan, we make acontribution of up to 13% of compensation, as defined by the plan, to the non-qualified deferred compensation program.Benefit Programs - We provide employees, including the executive officers, with a variety of health and welfare benefit programs. The health andwelfare programs are intended to protect employees against catastrophic loss and promote well-being. These programs include medical, dental, life insurance,accidental death and disability, and long-term disability. We also provide employees with a monthly parking pass or a pass to be used on publictransportation systems.We do not provide any material perquisites or any other personal benefits to our executives.We are a partnership and not a corporation for U.S. federal income tax purposes, and therefore, are not subject to the executive compensation taxdeductible limitations of Section 162(m) of the Code. Accordingly, none of the compensation paid to NEOs is subject to the limitation.155Board of Directors Report on CompensationOur General Partner’s board of directors does not have a compensation committee. The board of directors of the General Partner has reviewed anddiscussed with management the “Compensation Discussion and Analysis” presented above. Members of management with whom the board of directors haddiscussions are the Chairman of the Board, President, and Chief Executive Officer of the General Partner and the Group Vice President and Chief HumanResources Officer of DCP Midstream, LLC. In addition, we engaged the services of Mercer, a compensation consultant, to conduct a study to assist us inestablishing overall compensation packages for the executives. Based on this review and discussion, the board of directors of the General Partnerrecommended that the “Compensation Discussion and Analysis” referred to above be included in this Annual Report on Form 10-K for the year endedDecember 31, 2018.The information contained in this Board of Directors Report on Compensation shall not be deemed to be “soliciting material” or to be “filed” with theSEC, nor shall such information be incorporated by reference into any filing with the SEC, or subject to the liabilities of Section 18 of the Exchange Act,except to the extent that we specifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended (the "Securities Act"),or the Exchange Act.Board of DirectorsWouter T. van Kempen (Chairman)Allen C. CappsFred J. FowlerWilliam F. KimbleMark MakiBrian MandellBill W. WaycasterJohn Zuklic156Executive Compensation TablesThe following tables and accompanying narrative disclosures provide information regarding compensation of our named executive officers, or NEOs, asof December 31, 2018.Summary Compensation TableThe following table summarizes the compensation awarded to, earned by or paid to the named executive officers of our General Partner for the servicesthey provided to our business:Name and Principal Position Year Salary LTIAwards(c) Non-EquityIncentive PlanCompensation (d) All OtherCompensation(e) Total Wouter T. van Kempen, Chairman of the Board, President and Chief Executive Officer 2018 $679,292 $1,877,950 $1,039,657 $650,366 $4,247,265 2017 $664,250 $1,506,735 $1,074,511 $442,250 $3,687,746 2016 $— $— $— $— $1,303,012 (a) Sean P. O’Brien, Group Vice President and Chief Financial Officer 2018 $428,117 $875,653 $540,568 $306,141 $2,150,479 2017 $398,550 $662,999 $451,295 $204,895 $1,717,739 2016 $— $— $— $— $545,503 (a) Brent L. Backes, Group Vice President and General Counsel (b) 2018 $420,518 $593,418 $418,341 $296,270 $1,728,547 2017 $408,538 $576,480 $429,562 $215,903 $1,630,483 Don A. Baldridge, President, Commercial (b) 2018 $386,338 $682,430 $487,815 $245,738 $1,802,321 2017 $373,438 $469,399 $392,655 $175,427 $1,410,919 Brian S. Frederick, President, Operations (b) 2018 $399,065 $704,141 $366,461 $251,846 $1,721,513 2017 $387,673 $489,116 $407,623 $172,112 $1,456,524 (a) Prior to the Transaction, this NEO allocated 40% of his time between managing our business and the business of DCP Midstream, LLC where the time devoted to ourbusiness was driven by the needs and demands of our ongoing business and business development efforts. This amount represents the portion of the fixed general andadministrative fee we paid to DCP Midstream, LLC under the Services Agreement as reimbursement for the time this NEO allocated to our business.(b) This individual was first appointed an executive officer of our General Partner on February 9, 2017 and therefore was not an NEO in 2016.(c) The amounts in this column reflect the grant date fair value of strategic performance units, or SPUs, and restricted phantom units, or RPUs granted under the LTIP, and arecomputed in accordance with the provisions of the FASB Accounting Standards Codification, or ASC, 718 “Compensation-Stock Compensation”, or ASC 718. SPU awards aresubject to performance conditions and the amounts shown are for target performance because target is the probable outcome. For SPUs granted in 2018, the performanceconditions are between 0% if the minimum level of performance is not achieved to 200% if the maximum level of performance is achieved. The maximum value payable on theSPUs based on the 2018 grant date fair value, assuming the SPUs vested at the highest level of performance conditions, would be $1,877,950 for Wouter T. van Kempen,$875,653 for Sean P. O’Brien, $593,418 for Brent L. Backes, $682,430 for Don A. Baldridge, and $704,141 for Brian S. Frederick.(d) Includes amounts payable under the STI Plan, including any amounts voluntarily deferred. These amounts are expected to be paid in March 2019.(e) Includes DERs, Partnership contributions to the defined contribution plan and Partnership contributions to the nonqualified deferred compensation plan, as described in moredetail below.157All Other Compensation“All Other Compensation” in the summary compensation table includes the following for 2018:NameCompany retirementcontributions todefined contributionplans Nonqualified deferredcompensation programcontributions DERs TotalWouter T. van Kempen$27,500 $280,884 $341,982 $650,366Sean P. O’Brien$30,250 $111,503 $164,388 $306,141Brent L. Backes$33,000 $146,469 $116,801 $296,270Don A. Baldridge$30,250 $89,254 $126,234 $245,738Brian S. Frederick$35,750 $103,891 $112,205 $251,846Grants of Plan-Based AwardsFollowing are the grants of plan-based awards to the NEOs during the year ended December 31, 2018: Estimated Future Payouts underNon-Equity Incentive Plan Awards (a) Estimated Future Payouts underEquity Incentive Plan Awards Name GrantDate (b) Minimum($) Target($) Maximum($) Minimum(#) Target(#) Maximum(#) Grant DateFair Valueof LTIPAwards ($)Wouter T. vanKempen N/A $— $679,292 $1,358,584 — — — $—SPUs $— $— $— — 25,950 51,900 $938,975RPUs $— $— $— 25,950 25,950 25,950 $938,975Sean P. O’Brien N/A $— $321,088 $642,176 — — — $—SPUs $— $— $— — 12,100 24,200 $437,826RPUs $— $— $— 12,100 12,100 12,100 $437,826Brent L. Backes N/A $— $273,336 $546,673 — — — $—SPUs $— $— $— — 8,200 16,400 $296,709RPUs $— $— $— 8,200 8,200 8,200 $296,709Don A. Baldridge N/A $— $289,754 $579,508 — — — $—SPUs $— $— $— — 9,430 18,860 $341,215RPUs $— $— $— 9,430 9,430 9,430 $341,215Brian S. Frederick N/A $— $299,298 $598,597 — — — $—SPUs $— $— $— — 9,730 19,460 $352,070RPUs $— $— $— 9,730 9,730 9,730 $352,070(a) Amounts shown represent amounts under the STI. If minimum levels of performance are not met, then the payout for one or more of the components of the STI may bezero.(b) Grant Date is not applicable with respect to Non-Equity Incentive Plan Awards. The SPUs awarded on January 1, 2018 under the LTIP will vest in their entirety onDecember 31, 2020 if the specified performance conditions are satisfied or, if minimum levels of performance are not met, then the payout may be zero. The RPUsawarded on January 1, 2018 under the LTIP will vest in their entirety on December 31, 2020 if the NEO is still employed by DCP Services, or earlier in the case ofdeath, disability, retirement or layoff.158Outstanding Equity Awards at Fiscal Year-EndFollowing are the outstanding equity awards for the NEOs as of December 31, 2018: Outstanding LTIP AwardsName Equity IncentivePlan Awards:Unearned UnitsThat Have NotVested(a) Equity IncentivePlan Awards:Market Value ofUnearned UnitsThat Have NotVested(b)Wouter T. van Kempen 117,600 $4,297,099Sean P. O’Brien 53,790 $1,949,245Brent L. Backes 26,540 $1,029,687Don A. Baldridge 40,680 $1,453,904Brian S. Frederick 42,090 $1,506,943(a) SPUs awarded in 2017 and 2018 vest in their entirety over a range of 0% to 200% on December 31, 2019 and 2020, respectively, if the specified performanceconditions are satisfied. RPUs awarded in 2017 and 2018 vest in their entirety on December 31, 2019 and 2020, respectively. To determine the outstanding awards, thecalculation of the number of SPUs that are expected to vest is based on assumed performance of 200% as the previous fiscal year performance has exceeded targetperformance.(b) Value calculated based on the closing price on the NYSE on December 31, 2018 of our common units of $26.49, Enbridge’s common stock of $31.08, and Phillips66’s common stock of $86.15. The disclosed value includes distribution equivalents earned but not vested as of December 31, 2018 with respect to SPUs awarded in2017 and 2018. Distribution equivalents accrued in 2018 on outstanding SPUs are also reported within “All Other Compensation” in the Summary CompensationTable.Stock Awards VestedFollowing are the stock awards vested for the NEOs for the year ended December 31, 2018: Stock Awards Name Number of UnitsAcquired on Vesting Value Realized onVesting(a) Wouter T. van Kempen 53,279(c)$2,772,649(c)Sean P. O’Brien 29,184(c)$1,548,918(c)Brent L. Backes 18,526(b)$787,381(b)Don A. Baldridge 23,404(c)$1,257,517(c)Brian S. Frederick 13,376 $686,271 (a) Value calculated based on the average closing prices on the NYSE for the last 20 trading days in 2018 of our common units of $30.62, Enbridge’s common stock of$31.45, and Phillips 66’s common stock of $87.13. The disclosed value includes distribution equivalents accrued as of December 31, 2018 with respect to SPUsawarded in 2016 and distribution equivalents paid in 2018 on RPUs awarded in 2016, 2017, and 2018. The distribution equivalents attributable to 2018 for such SPUs,and the distribution equivalents attributable to all of such RPUs, are also reported within “All Other Compensation” in the Summary Compensation Table.(b) Includes 8,200 units that vested on December 31, 2018 due to his retirement eligibility, the value of which is based on the closing price on the NYSE on December 31,2018 of our common units of $26.49.(c) Includes 11,729 units for the applicable NEOs that vested on October 21, 2018, the value of which is based on the average closing prices on the NYSE for the last 20trading days prior to the vesting date of Enbridge’s common stock of $32.95 and Phillips 66’s common stock of $112.85.159Nonqualified Deferred CompensationFollowing is the nonqualified deferred compensation for the NEOs for the year ended December 31, 2018:Name ExecutiveContributionsin Last FiscalYear(a) RegistrantContributionsin Last FiscalYear(b) AggregateEarnings inLast FiscalYear(c) AggregateWithdrawal/Distributions AggregateBalance atDecember 31,2018(d)Wouter T. van Kempen $269,226 $280,884 $138,366 $— $2,604,253Sean P. O’Brien $257,519 $111,503 $31,700 $(128,520) $707,824Brent L. Backes $71,488 $146,469 $151,878 $— $3,088,345Don A. Baldridge $367,985 $89,254 $48,152 $(23,863) $1,166,857Brian S. Frederick $47,888 $103,891 $(41,071) $— $2,323,436(a) These amounts are included in the Summary Compensation Table for the year 2018 as follows: $71,488 for Mr. Backes; $289,754 for Mr. Baldridge; and $47,888 forMr. Frederick.(b) These amounts are included in the Summary Compensation Table for the year 2018.(c) At the election of each executive officer, the performance of non-qualified deferred compensation is linked to certain mutual funds or to the US High Yield BB ratedBond Index specific to the Energy sector.(d) Includes amounts previously reported in the Summary Compensation Table for prior years.Potential Payments upon Termination or Change in ControlThe General Partner has not entered into any employment agreements with any of our executive officers. The NEOs participate in executive severancearrangements maintained by DCP Services, LLC in the event of termination of employment that is involuntary or not for cause. Mr. Backes is retirementeligible and any voluntary termination would be treated as a retirement.As noted above, the SPUs, RPUs and the related dividend equivalent rights, or DERs, will become payable to executive officers under certain circumstancerelated to termination. When an employee terminates employment with the Partnership, they are entitled to a cash payment for the amount of unused vacationhours at the date of their termination.In the event of a change in control, the disposition of SPUs, RPUs and the related DERs will be determined by the board of directors of DCP Midstream, LLC.There are no formal plans for severance in the event of a change in control.The following table presents payments in the event of termination for reasons of death, disability, or if the recipient is terminated by the General Partner forreasons other than cause as of the last business day of 2018: 2018 STI Severance 2016 LTI Accelerated LTIP TotalWouter T. van Kempen$1,039,657 $1,024,350 $1,964,413 $2,223,581 $6,252,001Sean P. O’Brien$540,568 $437,850 $825,253 $1,006,943 $2,810,614Brent L. Backes (a)$418,341 $423,840 $846,717 $778,423 $2,467,321Don A. Baldridge$487,815 $390,000 $551,916 $748,953 $2,178,684Brian S. Frederick$366,461 $402,220 $632,514 $776,535 $2,177,730(a) Also applicable for retirementCEO Pay RatioWe are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation ofWouter T. van Kempen, the Chairman of the Board, President, and CEO of our General Partner:For 2018, our last completed fiscal year, the median of the annual total compensation of all employees of our company (other than our CEO) was $102,450,and the annual total compensation of our CEO, as reported in the Summary Compensation Table160above, was $4,247,265. Based on this information, for 2018, Mr. van Kempen’s total annual compensation was 41 times that of the median of the annual totalcompensation of all employees.As permitted by the SEC rules, the median employee utilized for this pay ratio disclosure for the fiscal year ended 2018 is the same employee identified forour prior pay ratio disclosure for the fiscal year ended 2017 because there were no changes during our fiscal year ended 2018 with respect to our employeepopulation, employee compensation arrangements, or to the same median employee’s circumstances that we reasonably believe would result in a significantchange to this pay ratio disclosure. In preparing this pay ratio disclosure, we took the following steps:1.We determined that, as of December 31, 2018, our employee population consisted of approximately 2,650 individuals with all of theseindividuals located in the United States (as reported in Item 1, Business, in this Annual Report on Form 10-K). This population consisted of ourfull-time, part-time, and temporary employees, and was substantially the same as our employee population for the prior fiscal year.2.In originally identifying the "median employee" for purposes of our prior pay ratio disclosure for the fiscal year ended 2017, from our employeepopulation, we compared the 2017 earnings eligible in the short-term incentive plan plus the 2016 actual incentive paid in 2017 of ouremployees as reflected in our payroll records for 2017. We identified our median employee using this compensation measure, which wasconsistently applied to all our employees included in the calculation. Since all our employees are located in the United States, as is our CEO, wedid not make any cost-of-living adjustments in identifying the "median employee."3.With respect to calculating the total annual compensation disclosed above for the median employee, we combined all of the elements of suchemployee’s total compensation for 2018.4.With respect to the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2018 SummaryCompensation Table above.The pay ratio disclosed above is a reasonable estimate calculated in accordance with SEC rules, based on our records and the methodologies described above.The SEC rules for identifying the median compensated employee and calculating the pay ratio allow companies to use a variety of methodologies and applyvarious assumptions. The application of various methodologies may result in significant differences in the results reported by other SEC reportingcompanies. As a result the pay ratio reported by other SEC reporting companies may differ substantially from, and may not be comparable to, the pay ratio wedisclose above.Director CompensationGeneral - Members of the board of directors who are officers or employees of the General Partner or its affiliates do not receive compensation for servingas directors.For 2018, the board approved an annual compensation package for non-employee directors, consisting of an annual $90,000 cash retainer and an annualgrant of common units that approximate $100,000 of value on the date of grant. Chairpersons of committees of the board received an additional annual cashretainer of $20,000. All cash retainers were paid on a quarterly basis in arrears. Directors did not receive additional fees for attending meetings of the board orits committees. The directors were reimbursed for out-of-pocket expenses associated with their membership on the board of directors.Following is the compensation earned by the General Partner’s non-employee directors for the year ended December 31, 2018:Name Fees Earned or Paidin Cash UnitAwards (a) TotalFred J. Fowler $90,000 $100,475 $190,475William F. Kimble (b) $110,000 $100,475 $210,475Bill W. Waycaster (c) $110,000 $100,475 $210,475(a)The amounts in this column reflect the grant date fair value of common unit awards computed in accordance with ASC 718.(b)Mr. Kimble received an additional $20,000 annually as the audit committee chair.(c)Mr. Waycaster received an additional $20,000 annually as the special committee chair.Each director is entitled to be fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.161Compensation Committee Interlocks and Insider ParticipationAs discussed above, our General Partner’s board of directors does not maintain a compensation committee. In 2018, the compensation committee of theboard of directors of DCP Midstream, LLC, the owner of our General Partner, determined all elements of compensation for our NEOs. Only Mr. van Kempenwas a director and a NEO of our General Partner. Further Mr. van Kempen is a non-voting member of the board of directors of DCP Midstream, LLC; however,he is not a member of the compensation committee thereof, nor did he participate in deliberations of such board with regard to his own compensation. During2018, none of our NEOs served as a director or member of a compensation committee of another entity that has or has had an executive officer who served asa member of our board of directors, the board of directors of DCP Midstream, LLC, or the compensation committee of the board of directors of DCPMidstream, LLC.162Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder MattersThe following table sets forth the beneficial ownership of our common units and Preferred Units for:•each person known by us to be the beneficial owner of more than 5% of our common units;•each director of DCP Midstream GP, LLC;•each NEO of DCP Midstream GP, LLC; and•all directors and executive officers of DCP Midstream GP, LLC as a group.The percentage of total common units beneficially owned is based on 143,317,328 outstanding common units and the percentage of Series A PreferredUnits beneficially owned is based on 500,000 outstanding Series A Preferred Units as of February 20, 2019. None of the named beneficial owners set forth inthe table below owns any of the 6,450,000 outstanding Series B Preferred Units or any of the 4,400,000 outstanding Series C Preferred Units as ofFebruary 20, 2019.Name of Beneficial Owner (a) Common UnitsBeneficially Owned Percentage ofCommon UnitsBeneficially Owned Series A PreferredUnits BeneficiallyOwned Percentage of SeriesA Preferred UnitsBeneficially OwnedDCP Midstream, LLC (b) 52,762,526 36.8% — —Harvest Fund Advisors LLC (c) 11,848,552 8.3% — —ALPS Advisors, Inc. (d) 8,973,905 6.3% — —Wouter T. van Kempen 2,540 * 750 *Sean P. O'Brien — — — —Brent L. Backes 10,406 * 150 *Don Baldridge 10,689 * 50 *Brian Frederick 5,500 * — —Allen C. Capps — — — —Fred J. Fowler 26,800 * — —William F. Kimble 8,700 * — —Mark Maki — — — —Brian Mandell — — — —Bill W. Waycaster 8,700 * — —John Zuklic — — — —All directors and executive officers as a group (12persons) 73,335 * 950 *_____________* Less than 1%.(a)Unless otherwise indicated, the address for all beneficial owners in this table is 370 17th Street, Suite 2500, Denver, Colorado 80202.(b)Includes 1,887,618 common units held by DCP Midstream GP, LP. DCP Midstream, LLC is the sole member of DCP Midstream GP, LLC, which is thegeneral partner of DCP Midstream GP, LP, and therefore may be deemed to indirectly beneficially own such securities, but disclaims beneficialownership except to the extent of its pecuniary interest therein.(c)As reported on Schedule 13G filed with the SEC on February 14, 2019 by Harvest Fund Advisors LLC ("HFA") and Eric M. Conklin each with an addressof 100 West Lancaster Avenue, Suite 200, Wayne, Pennsylvania 19087. The Schedule 13G reports that HFA and Mr. Conklin, as the managing partnerand chair of the investment committee of HFA, have sole voting and dispositive power over 11,848,552 of the reported units.(d)As reported on Schedule 13G/A filed with the SEC on February 4, 2019 by ALPS Advisors, Inc. and Alerian MLP ETF each with an address of 1290Broadway, Suite 1100, Denver, Colorado 80203. The Schedule 13G/A reports that ALPS Advisors, Inc. (“AAI”), an investment adviser registered underthe Investment Advisers Act of 1940, as amended, furnishes investment advice to investment companies registered under the Investment Company Act of1940, as amended (collectively referred to as the “Funds”). In its role as investment advisor, AAI has voting and/or investment power over the registrant'scommon units that are owned by the Funds, and may be deemed to be the beneficial owner of such common units held by the Funds. Alerian MLP ETF isan investment company registered under the Investment Company Act of1631940 and is one of the Funds to which AAI provides investment advice. Alerian MLP ETF has shared voting and investment power over 8,973,905common units. The common units reported herein are owned by the Funds and AAI disclaims beneficial ownership of such common units.Equity Compensation Plan InformationThe following table sets forth information about our equity compensation plans as of December 31, 2018.Plan CategoryNumber of securities tobe issued upon exerciseof outstanding options,warrants and rightsWeighted-averageexercise price ofoutstanding options,warrants and rightsNumber of securitiesremaining available for futureissuance under equitycompensation plans (excludingsecurities reflected in column(a)) (a)(b)(c)Equity compensation plans approved by unitholders (1)—$—878,100Equity compensation plans not approved by unitholders———Total—$—878,100(1)This information relates to our 2016 LTIP, which was approved by unitholders at a special meeting on April 28, 2016. For more information on our2016 LTIP, refer to Note 15. "Equity-Based Compensation" in the Notes to Consolidated Financial Statements in Item 8. “Financial Statements andSupplementary Data.”Item 13. Certain Relationships and Related Transactions, and Director IndependenceDistributions and Payments to our General Partner and its AffiliatesThe following table summarizes the distributions and payments to be made by us to our General Partner and its affiliates in connection with ourformation, ongoing operation, and liquidation. These distributions and payments are determined by and among affiliated entities and, consequently, are notthe result of arm’s-length negotiations.Operational Stage:Distributions of Available Cash to our General Partner andits affiliatesWe will generally make cash distributions to the unitholders and to our General Partner, inaccordance with their pro rata interest. In addition, if distributions exceed the minimumquarterly distribution and other higher target levels, our General Partner will be entitled toincreasing percentages of the distributions, up to 48% of the distributions above the highesttarget level. Currently, our distribution to our general partner related to its incentive distributionrights is at the highest level.Payments to our General Partner andits affiliatesFor further information regarding payments to our General Partner, please see the “ServicesAgreement” section below.Withdrawal or removal of our General PartnerIf our General Partner withdraws or is removed, its general partner interest and its incentivedistribution rights will either be sold to the new general partner for cash or converted intocommon units, in each case for an amount equal to the fair market value of those interests.Liquidation Stage:LiquidationUpon our liquidation, the partners, including our General Partner, will be entitled to receiveliquidating distributions according to their respective capital account balances.Services AgreementUnder the Service Agreement, we are required to reimburse DCP Midstream, LLC for costs, expenses, and expenditures incurred or payments made onour behalf for general and administrative functions including, but not limited to, legal, accounting, compliance, treasury, insurance administration and claimsprocessing, risk management, health, safety and environmental, information technology, human resources, benefit plan maintenance and administration,credit, payroll, internal audit, taxes and engineering, as well as salaries and benefits of seconded employees, insurance coverage and claims, capitalexpenditures, maintenance and repair costs and taxes. There is no limit on the reimbursements we make to DCP Midstream, LLC under the ServicesAgreement for costs, expenses and expenditures incurred or payments made on our behalf.164Our General Partner and its affiliates will also receive payments from us pursuant to the contractual arrangements described below under the caption“Contracts with Affiliates.”The Services Agreement, other than the indemnification provisions, will be terminable by DCP Midstream, LLC at its option if our general partner isremoved without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The Services Agreement will alsoterminate in the event of a change of control of us, our General Partner or DCP Midstream, LLC.CompetitionNone of DCP Midstream, LLC, or any of its affiliates, including Phillips 66 and Enbridge, is restricted, under either the Partnership Agreement or theServices Agreement, from competing with us. DCP Midstream, LLC and any of its affiliates, including Phillips 66 and Enbridge, may acquire, construct ordispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.Contracts with AffiliatesWe sell a portion of our residue gas and NGLs to and purchase NGLs from Phillips 66 and its respective affiliates. We anticipate continuing to purchaseand sell these commodities to Phillips 66 and its respective affiliates in the ordinary course of business.We sell NGLs to and purchase NGLs from Enbridge and its affiliates. We anticipate continuing to sell commodities to and purchase commodities fromEnbridge and its affiliates in the ordinary course of business.Unconsolidated AffiliatesUnder the terms of their respective operating agreements, Sand Hills and Southern Hills are required to reimburse us for any direct costs or expenses(other than general and administration services) which we incur on behalf of Sand Hills and Southern Hills. Additionally, Sand Hills and Southern Hills eachpay us an annual service fee of $5 million, for centralized corporate functions provided by us as operator of Sand Hills and Southern Hills, including legal,accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology,human resources, credit, payroll, taxes and engineering. Except with respect to the annual service fee, there is no limit on the reimbursements Sand Hills andSouthern Hills make to us under the respective operating agreements for other expenses and expenditures which we incur on behalf of Sand Hills or SouthernHills.Transportation ArrangementsThe Texas Express, Front Range, Sand Hills, Southern Hills and Gulf Coast Express pipelines have in place 10 to 15-year transportation agreementswith us pursuant to which we have committed to transport minimum throughput volumes at rates defined in each respective pipeline’s tariffs.Review, Approval or Ratification of Transactions with Related PersonsOur Partnership Agreement contains specific provisions that address potential conflicts of interest between the owner of our general partner and itsaffiliates, including DCP Midstream, LLC on one hand, and us and our subsidiaries, on the other hand. Whenever such a conflict of interest arises, our generalpartner will resolve the conflict. Our general partner may, but is not required to, seek the approval of such resolution from the special committee of the boardof directors of our general partner, which committee is comprised of independent directors and acts as our conflicts committee. The Partnership Agreementprovides that our general partner will not be in breach of its obligations under the Partnership Agreement or its duties to us or to our unitholders if theresolution of the conflict is:•approved by the conflicts committee;•approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of itsaffiliates;•on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or•fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions thatmay be particularly favorable or advantageous to us.If our general partner does not seek approval from the special committee and the board of directors of our general partner determines that the resolutionor course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it willbe presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner orthe Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflictis165specifically provided for in our Partnership Agreement, our general partner or the conflicts committee may consider any factors it determines in good faith toconsider when resolving a conflict. When our Partnership Agreement requires someone to act in good faith, it requires that person to reasonably believe thathe is acting in the best interests of the Partnership, unless the context otherwise requires.In addition, our code of business ethics requires that all employees, including employees of affiliates of DCP Midstream, LLC who perform services forus and our general partner, avoid or disclose any activity that may interfere, or have the appearance of interfering, with their responsibilities to us.Director IndependencePlease see Item 10. “Directors, Executive Officers and Corporate Governance” in this Annual Report on Form 10-K for information about theindependence of our general partner’s board of directors and its committees.Item 14. Principal Accountant Fees and ServicesThe following table presents fees for professional services rendered by Deloitte & Touche LLP, or Deloitte, our principal accountant, for the audit of ourfinancial statements, and the fees billed for other services rendered by Deloitte: Year Ended December 31,Type of Fees 2018 2017 (millions)Audit Fees (a) $3 $4(a)Audit Fees are fees billed by Deloitte for professional services for the audit of our consolidated financial statements included in our annual reporton Form 10-K and review of financial statements included in our quarterly reports on Form 10-Q, services that are normally provided by Deloitte inconnection with statutory and regulatory filings or engagements or any other service performed by Deloitte to comply with generally acceptedauditing standards and include comfort and consent letters in connection with SEC filings and financing transactions.For the last two fiscal years, Deloitte has not billed us for assurance and related services, unless such services were reasonably related to the performanceof the audit or review of our financial statements, which are included in the table above. Deloitte Tax has been engaged to review the Federal tax return of thePartnership and prepare and process the K-1 schedules for unitholders for a total fixed fee of $275,000. Prior to this engagement Deloitte had not providedany services to us over the last two fiscal years related to tax compliance, tax services and tax planning.Audit Committee Pre-Approval PolicyThe audit committee pre-approves all audit and permissible non-audit services provided by the independent auditors on a case-by-case basis. Theseservices may include audit services, audit-related services, tax services and other services. The audit committee has pre-approved audit related services thatdo not impair the independence of the independent auditors for up to $50,000 per engagement, and up to an aggregate of $100,000 annually, provided theaudit committee is notified of such audit-related services in a timely manner. The audit committee may, however, from time to time delegate its authority toany audit committee member, who will report on the independent auditor services that were approved at the next audit committee meeting.PART IV166Item 15. Exhibits, Financial Statement Schedules(a) Financial Statement SchedulesConsolidated Financial Statements and Financial Statement Schedules included in this Item 15:Consolidated Financial Statements of Discovery Producer Services LLCConsolidated Financial Statements of DCP Sand Hills Pipeline, LLCConsolidated Financial Statements of DCP Southern Hills Pipeline, LLC167 FINANCIAL STATEMENTSDiscovery Producer Services LLCYears Ended December 31, 2018, 2017 and 2016168REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Members and Management Committee ofDiscovery Producer Services LLCOpinion on the Financial StatementsWe have audited the accompanying consolidated balance sheets of Discovery Producer Services LLC (the “Company”) as of December31, 2018 and 2017, the related consolidated statements of operations and comprehensive income, members’ capital and cash flows foreach of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidatedfinancial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial positionof the Company at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in theperiod ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.Adoption of New Accounting StandardAs discussed in Notes 2 and 3 to the consolidated financial statements, the Company changed its method for accounting for revenueeffective January 1, 2018. Our opinion is not modified with respect to this matter.Basis for OpinionThese financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on theCompany’s financial statements based on our audits. We are a public accounting firm registered with the Public Company AccountingOversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S.federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally acceptedin the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance aboutwhether the financial statements are free of material misstatement, whether due to error or fraud.Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to erroror fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidenceregarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles usedand significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believethat our audits provide a reasonable basis for our opinion./s/ Ernst & Young LLPWe have served as the Company’s auditor since 2002Tulsa, OklahomaFebruary 21, 2019169DISCOVERY PRODUCER SERVICES LLCCONSOLIDATED BALANCE SHEETS December 31, 2018 2017ASSETS(In thousands)Current assets: Cash and cash equivalents$18,187 $22,827 Trade accounts receivable: Affiliate11,142 13,339 Other6,674 3,911 Prepaid insurance2,607 2,886Inventory3,509 2,923Total current assets42,119 45,886Property, plant and equipment, net1,079,375 1,124,864Intangible assets, net13,564 13,084 Total assets$1,135,058 $1,183,834 LIABILITIES AND MEMBERS’ CAPITAL Current liabilities: Accounts payable: Affiliate$344 $1,110 Other17,595 16,602 Asset retirement obligations505 24,184 Deferred revenue17,968 19,784 Other current liabilities224 209Total current liabilities36,636 61,889Non Current liabilities Asset retirement obligations136,684 97,896Deferred revenue61,559 71,135Customer deposits2,795 3,491Commitments and contingent liabilities (Note 6) Members' capital Members' capital accounts896,055 948,030 Other comprehensive income1,329 1,393 Total members’ capital897,384 949,423 Total liabilities and members’ capital$1,135,058 $1,183,834See accompanying notes to the financial statements.170DISCOVERY PRODUCER SERVICES LLCCONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME Year Ended December 31, 2018 2017 2016 (In thousands) Revenues: Product sales: Affiliate$46,699 $165,525 $129,609 Third-party3,871 93 120 Transportation services22,675 46,395 60,112 Gathering and processing services: Affiliate1,005 687 330 Third-party69,504 191,351 200,723Commodity consideration44,497 ——— Other revenues9,606 8,793 9,012Total revenues197,857 412,844 399,906Costs and expenses: Product cost Affiliate— 8,750 6,168 Third-party47,819 126,610 95,364Proceesing commodity expense: Affiliate9,151 — — Third-party6,894 — — Operating and maintenance expenses: Affiliate9,610 9,510 8,679 Third-party28,692 28,719 23,479 Depreciation, amortization and accretion71,080 93,110 76,110 Taxes other than income2,932 2,913 2,702 General and administrative expenses- affiliate7,639 7,454 7,219 Other (income) expense, net(24) (6,553) 129Total costs and expenses183,793 270,513 219,850Operating income14,064 142,331 180,056Interest income (expense)(638) 177 (46)Net income13,426 142,508 180,010 Net loss from derivative instruments, including amounts reclassified into earnings(64) (63) (63)Comprehensive income$13,362 $142,445 $179,947See accompanying notes to the financial statements.171DISCOVERY PRODUCER SERVICES LLCCONSOLIDATED STATEMENT OF MEMBERS' CAPITAL Williams FieldServices Group,LLC DCP AssetsHolding, LP Accumulated OtherComprehensiveIncome Total (In thousands)Balance December 31, 2015$642,896 $427,570 $1,519 $1,071,985Distributions(140,540) (93,694) — (234,234)Net income108,006 72,004 — 180,010Other comprehensive loss— — (63) (63)Balance December 31, 2016$610,362 $405,880 $1,456 $1,017,698Contributions834 556 — 1,390Distributions(127,266) (84,844) — (212,110)Net income85,504 57,004 — 142,508Other comprehensive loss— — (63) (63)Balance December 31, 2017$569,434 $378,596 $1,393 $949,423Contributions5,454 3,636 — 9,090Distributions(45,420) (30,280) — (75,700)Net income8,056 5,370 — 13,426Cumulative effect adjustments - Adoption of ASU 606(Note 3)725 484 — 1,209Other comprehensive loss— — (64) (64)Balance December 31, 2018538,249 357,806 1,329 897,384See accompanying notes to financial statements.172DISCOVERY PRODUCER SERVICES LLCCONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2018 2017 2016 (In thousands)OPERATING ACTIVITIES: Net income$13,426 $142,508 $180,010Adjustments to reconcile cash provided by operations: Depreciation, amortization, and accretion71,080 93,110 76,110 Net loss on retirement of equipment— — 140 Other non-cash item800 (6,556) — Cash provided (used) by changes in assets and liabilities: Trade accounts receivable(567) 25,726 (1,136) Prepaid insurance280 37 440 Inventory(126) (199) (10) Accounts payable1,504 6,221 2,368 Asset retirement obligation(4,724) (679) — Customer deposits(696) 147 2,683 Other current liabilities14 (50) (94) Deferred revenue(11,443) (30,452) (15,908)Net cash provided by operating activities69,548 229,813 244,603INVESTING ACTIVITIES: Property, plant and equipment - capital expenditures *7,578 (7,390) (8,594)Net cash used by investing activities7,578 (7,390) (8,594)FINANCING ACTIVITIES: Distributions to members(75,700) (212,110) (234,234) Capital contributions9,090 1,390 —Net cash used by financing activities(66,610) (210,720) (234,234)Increase (decrease) in cash and cash equivalents(4,640) 11,703 1,775Cash and cash equivalents beginning of period22,827 11,124 9,349Cash and cash equivalents end of period$18,187 $22,827 $11,124 Supplemental Disclosures Non cash additions to PP&E$— $5,300 $— * Increase to property, plant and equipment$(6,302) $(8,300) $(8,756)Changes in related accounts payable - affiliate, accounts payable, and construction retainage payable(1,276) 910 162 Capital expenditures$(7,578) $(7,390) $(8,594)See accompanying notes to financial statements.173DISCOVERY PRODUCER SERVICES LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNote 1. Organization and Description of BusinessUnless the context clearly indicates otherwise, references in this report to “we”, “our”, “us” or similar language refers to Discovery Producer Services LLCand its wholly-owned subsidiary, Discovery Gas Transmission LLC (DGT). We are a Delaware limited liability company formed on June 24, 1996 for thepurpose of constructing and operating a cryogenic natural gas processing plant near Larose, Louisiana and a natural gas liquids fractionator near Paradis,Louisiana. DGT is a Delaware Limited Liability Company formed on June 24, 1996 for the purpose of constructing and operating an offshore natural gasdeep water pipeline in the Gulf of Mexico which connects to our gas processing plant in Larose, Louisiana. We have since connected several laterals to theDGT pipeline to expand our presence in the Gulf of Mexico.We are owned 60% by Williams Field Services Group, LLC (WFS) (a wholly-owned subsidiary of The Williams Companies, Inc. (WMB)) and 40% by DCPAssets Holding, LP (a wholly-owned subsidiary of DCP Midstream Partners, LP (DCP)). WFS is our operator. Herein, The Williams Companies, Inc., and WFSare collectively referred to as “Williams.”We evaluated our disclosure of subsequent events through February 21, 2019, the date our financial statements were issued.Note 2. Summary of Significant Accounting PoliciesBasis of Presentation. The consolidated financial statements have been prepared based upon accounting principles generally accepted in the UnitedStates and include the accounts of the parent and our wholly-owned subsidiary, DGT. Intercompany accounts and transactions have been eliminated.Accounting standards issued and adoptedIn May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 “Revenue from Contracts with Customers (Topic 606)” (ASC 606).ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount thatreflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenuedisclosures.We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition method for all contracts with customers,which included applying the provisions of ASC 606 beginning January 1, 2018, to all contracts not completed as of that date with the cumulative effect ofapplying the standard for periods prior to January 1, 2018, as an adjustment to Members’ capital, upon adoption. As a result of our adoption, the cumulativeimpact to our Total members’ capital, at January 1, 2018, was an increase of $1.0 million in the Consolidated Balance Sheet.For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606. The adjustment to Total members’capital upon adoption of ASC 606 is primarily comprised of the impact to the timing of recognition of a contract with changes in the stated fixed capacitycharge over time and the associated change in the time period over which the deferred revenue is recognized under ASC 606. Under ASC 606, our revenueswill increase in situations where we receive noncash consideration, which exists primarily in certain of our gas processing contracts where we receivecommodities as full or partial consideration for services provided. In addition, we will present the cost of natural gas associated with such noncashconsideration as processing commodity expense on the Consolidated Statements of Operations and Comprehensive Income. The increase in revenues fornoncash consideration will be offset by a similar increase in product cost when the commodities received are subsequently sold. Additionally, under ASC606, our presentation of product sales and purchases will be recorded net on the Consolidated Statements of Operations and Comprehensive Income forcertain arrangements wherein Discovery is considered to be an agent in its commodity purchase and sale agreements. Financial systems and internal controlsnecessary for adoption were implemented effective January 1, 2018. (See Note 3 - Revenue Recognition.)New accounting standards issued not yet adoptedIn February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new leaseaccounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, andcauses lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with acorresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding theamount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land174Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessedunder ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient tonot apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under theprevious lease guidance in ASC Topic 840 “Leases.”In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior to ASU 2018-11, a modifiedretrospective transition was required for financing or operating leases existing at or entered into after the beginning of the earliest comparative periodpresented in the financial statements. ASU 2018-11 allows entities an additional transition method to the existing requirements whereby an entity couldadopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoptionwithout adjustment to the financial statements for periods prior to adoption. ASU 2018-11 also allows a practical expedient that permits lessors to notseparate non-lease components from the associated lease component if certain conditions are present. ASU 2016-02 is effective for interim and annual periodsbeginning after December 15, 2018. Early adoption is permitted. We adopted ASU 2016-02 effective January 1, 2019.We are substantially complete with our review of contracts to identify leases based on the modified definition of a lease and implementing changesto our internal controls to support management in the accounting for and disclosure of leasing activities upon adoption of ASU 2016-02. We implemented afinancial lease accounting system to assist management in the accounting for leases upon adoption. The most significant expected changes to our financialstatements relate to the recognition of a lease liability and offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases, which weestimate to be less than 1% of total assets. We have also evaluated ASU 2016-02’s available practical expedients on adoption. Of these practical expedients,we are electing to adopt the practical expedients, which include the practical expedient to not separate lease and non-lease components by both lessees andlessors by class of underlying assets and the land easements practical expedient.In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on FinancialInstruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and otherreceivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model thatgenerally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interimand annual periods beginning after December 15, 2019. Early adoption is permitted. ASU 2016-13 requires varying transition methods for the differentcategories of amendments. We are evaluating the impact of ASU 2016-13 on our consolidated financial statements. Although we do not expect ASU 2016-13to have a significant impact, it will impact our trade receivables as the related allowance for credit losses will be recognized earlier under the expected lossmodel than under our current policy.Use of Estimates. The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United Statesrequires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes.Actual results could differ from those estimates.Significant estimates and assumptions include:•Asset retirement obligations•Depreciable asset livesCash and Cash Equivalents. The cash and cash equivalents balance includes cash equivalents which are invested in funds with high-quality, short-termsecurities and instruments that are issued or guaranteed by the U.S. government. These securities have maturities of three months or less when acquired.Trade Accounts Receivable. Trade accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We donot recognize an allowance for doubtful accounts at the time the revenue that generates the accounts receivable is recognized. We estimate the allowance fordoubtful accounts based on existing economic conditions, the financial condition of the customers and the amount and age of past due accounts.Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against theallowance for doubtful accounts only after all collection attempts have been exhausted. There is no allowance for doubtful accounts as of December 31, 2018and 2017.Prepaid Insurance. Prepaid insurance represents the unamortized balance of insurance premiums. These payments are amortized on a straight-line basisover the policy term.175Gas Imbalances. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than thequantities delivered on behalf of those shippers. This results in gas transportation imbalance receivables and payables. The imbalance is recovered or repaidin cash, based on market-based prices, or through the receipt or delivery of gas in the future. Imbalance receivables are valued based on the lower of thecurrent market prices; or the weighted average cost of natural gas in the system. Imbalance payables are valued at current market prices. Settlement ofimbalances requires an agreement between the pipelines and shippers as to the allocations of volumes to specific transportation contracts, and the timing ofdelivery of gas based on operational conditions. Pursuant to a settlement with our shippers issued by the Federal Energy Regulatory Commission (FERC) onFebruary 5, 2008, if a cash-out refund is due and payable to a shipper during any year pursuant to our FERC Gas Tariff, the shipper will be deemed to haveimmediately assigned its right to the refund amount to us.Inventory. Inventories primarily consist of materials and supplies, with a minor amount related to natural gas liquids.Property, Plant and Equipment. Property, plant and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptionsand judgments relative to capitalized costs, useful lives and salvage values. The natural gas and natural gas liquids maintained in the pipeline facilitiesnecessary for their operation (line fill) are included in property, plant and equipment. Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated useful lives of 25 to 35 years. Expenditures for maintenance and repairs are expensed as incurred. Expenditures that extend theuseful lives of the assets or increase their functionality are capitalized. The cost of property, plant and equipment sold or retired and the related accumulateddepreciation is removed from the accounts in the period of sale or disposition. Gains and losses on the disposal of property, plant and equipment are recordedin operating income.We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset increases thecarrying value of the underlying physical asset and is depreciated with the underlying physical asset. We measure changes in the liability due to passage oftime by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as correspondingaccretion expense included in operating income.Intangible Assets. Our intangible assets are primarily related to amounts we paid to another party to allow us to access and serve product being shipped ontheir pipeline. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate theseassets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining usefullife.Impairment of Long-Lived Assets. We evaluate long-lived assets for impairment when events or changes in circumstances indicate that, in ourmanagement’s judgment, the carrying value of such assets may not be recoverable. When such a determination has been made, we compare our estimate ofundiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether the carrying value is recoverable. If thecarrying value is not recoverable, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assetsand recording a loss for the amount by which the carrying value exceeds the estimated fair value. There were no impairments recorded during 2018, 2017 and2016.Customer Deposits. We extend credit to customers in the normal course of business and perform ongoing credit evaluations of our customers. We mayrequire cash deposit from our customers based on their overall creditworthiness. The dollars are recorded as a non -current liability on the consolidatedbalance sheet. Income Taxes. For federal tax purposes, we have elected to be treated as a partnership with each member being separately taxed on its ratable share of ourtaxable income. This election, to be treated as a pass-through entity, also applies to our wholly-owned subsidiary, DGT. Therefore, no income taxes ordeferred income taxes are reflected in the consolidated financial statements.Other Comprehensive loss. Amounts recorded in other comprehensive loss relate to cash flow hedges we entered into to hedge forecasted foreign currency-denominated payments for pipeline construction. We recorded the effective portion of changes in the fair value of those hedges in other comprehensive loss,and reclassify such amounts into income on a straight-line basis over the period that we are depreciating the assets to which the hedges related.Revenue Recognition. Revenue for sales of products is recognized in the period of delivery, and revenues from the gathering, transportation, and processingof gas are recognized in the period the service is provided based on contractual terms and the176related natural gas and liquid volumes. DGT is subject to FERC regulations, and accordingly, certain revenues collected may be subject to possible refundsupon final orders in pending cases. DGT records rate refund liabilities considering its and other third parties’ regulatory proceedings, advice of counsel,estimated total exposure as discounted and risk weighted, and collection and other risks. There was no rate refund liability accrued at December 31, 2018 or2017.Customers for our service revenues are comprised of oil and natural gas producers. Williams is the primary customer for our sales of natural gas liquids.A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. Acontract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation issatisfied. A performance obligation is distinct if the service is separately identifiable from other items in the integrated package of services and if a customercan benefit from it on its own or with other resources that are readily available to the customer. An integrated package of services typically represents a singleperformance obligation if the services are contained within the same contract or within multiple contracts entered into in contemplation with one another thatare highly interdependent or highly interrelated, meaning each of the services is significantly affected by one or more of the other services in the contract.Our service revenue contracts contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfiedover time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a singleperformance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.For our businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial objective, as we have theability to negotiate the mix of consideration between reimbursements and amounts billed over time. Accordingly, we generally recognize reimbursements ofconstruction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment.The contract liability is recognized into service revenues as the underlying performance obligations are satisfied.Gathering, Processing, and Transportation ServicesRevenues from our businesses include contracts for natural gas gathering, processing, treating, compression, transportation, and other related serviceswith contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. As such, revenue is recognizedat the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certaincontracts in our businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or suchcapacity has been made available.We generally earn a contractually stated fee per unit for the volume of product transported, gathered, or processed. The rate is generally fixed; however,certain contracts contain variable rates that are subject to change based on levels of throughput. For all of our contracts, we allocate the transaction price toeach performance obligation based on the relative standalone selling price. The excess of consideration received over revenue recognized results in thedeferral of those amounts until future periods based on a units of production or straight-line methodology.Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of natural gas liquids (NGLs) and taketitle to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retainedat the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combinationof factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and isnot specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third partybased on the sales price at the time of sale. As a result, revenue is recognized both at the time the processing service is provided in product sales and at thetime the NGLs retained as part of the processing service are sold in gathering and processing commodity consideration third party. The recognition ofrevenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher product cost at the time ofsale. Given that most inventory is sold in the same period that it is generated, the impact of these transactions is expected to have little impact to operatingincome.177Product SalesIn the course of providing gathering and processing services to customers of our businesses, we may receive different quantities of natural gas fromcustomers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of naturalgas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements. Revenue is recognized from the sale of naturalgas upon settlement of imbalances.In certain instances, we purchase NGLs, and natural gas from our oil and natural gas producer customers. In addition, we retain NGLs as consideration incertain processing arrangements, as discussed above in the Service Revenues section. We recognize revenue from the sale of these commodities when theproducts have been sold and delivered, except in certain instances where we have concluded that we are an agent in the arrangement, in which case we recordsuch sales on a net basis. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction.Note 3. Revenue RecognitionContract AssetsThe following table presents a reconciliation of our contract assets: Year-to-Date December 31. 2018 (Thousands)Balance at beginning of period (January 1, 2018) $800Payments received and deferred (435)Impairment of contract asset (365)Balance at end of period (December 31, 2018) $—Contract LiabilitiesOur contract liabilities consist of advance payments primarily from construction reimbursements, prepayments, and other billings for which futureservices are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has beensatisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current ornoncurrent according to when such amounts are expected to be recognized.Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide uswith a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer thepromised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed ourcontracts for significant financing components and determined that one contract contains a significant financing component. As a result, we recognizenoncash interest expense based on the effective interest method and revenue (noncash) is recognized utilizing units of production over the life of thecorresponding customer contract.The following table presents a reconciliation of our contract liabilities: Year-to-Date December 31. 2018 (Thousands)Balance at beginning of period (January 1, 2018) $90,918Payments received and deferred 9,422Recognized in revenue (20,813)Balance at end of period (December 31, 2018) $79,527178The following table presents the amount of the contract liabilities balance as of December 31, 2018, expected to be recognized as revenue in each of thenext five years as performance obligations are expected to be satisfied: (Thousands)2019 $18,2672020 12,9172021 9,5292022 6,9842023 6,276Thereafter 25,554Total $79,527Remaining Performance ObligationsThe following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2018.These primarily include long-term contracts containing fixed payments associated with gathering services and offshore production handling. As a practicalexpedient permitted by ASC 606, this table excludes variable consideration as well as consideration in contracts that is recognized in revenue as billed. Italso excludes consideration received prior to December 31, 2018, that will be recognized in future periods (see above for Contract Liabilities and theexpected recognition of those amounts within revenue). As noted above, certain of our contracts contain evergreen and other renewal provisions for periodsbeyond the initial term of the contract. The remaining performance obligation amounts as of December 31, 2018, do not consider potential futureperformance obligations for which the renewal has not been exercised. (Thousands)2019 $24,2222020 19,9812021 16,0322022 12,2172023 10,736Thereafter 18,349Total $101,537179Impact of Adoption of ASC 606The following table depicts the impact of the adoption of ASC 606 on our 2018 financial statements. The adoption of ASC 606 did not result inadjustments to total operating, investing, or financing cash flows.DISCOVERY PRODUCER SERVICES LLCCONSOLIDATED BALANCE SHEETS As reported Adjustments resultingfrom ASC 606 Balance withoutadoption of ASC 606 ASSETS(In thousands)Current assets: Cash and cash equivalents$18,187 $— $18,187 Trade accounts receivable: Affiliate11,142 — 11,142 Other6,674 — 6,674 Prepaid insurance2,607 — 2,607Inventory3,509 (186) 3,323Total current assets42,119 (186) 41,933Property, plant and equipment, net1,079,375 — 1,079,375Intangible assets, net13,564 — 13,564 Total assets$1,135,058 $(186) $1,134,872 LIABILITIES AND MEMBERS’ CAPITAL Current liabilities: Accounts payable: Affiliate$344 $— $344 Other17,595 — 17,595 Asset retirement obligations505 — 505 Deferred revenue17,968 — 17,968 Other current liabilities224 — 224Total current liabilities36,636 — 36,636Non Current liabilities Asset retirement obligations136,684 — 136,684Deferred revenue61,559 (575) 60,984Customer deposits2,795 — 2,795Commitments and contingent liabilities (Note 6) Members' capital Members' capital accounts896,055 389 896,444 Other comprehensive income1,329 — 1,329 Total members’ capital897,384 389 897,773 Total liabilities and members’ capital$1,135,058 $(186) $1,134,872180DISCOVERY PRODUCER SERVICES LLCCONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME As reported Adjustments resultingfrom ASC 606 Balance withoutadoption of ASC 606 (In thousands) Revenues: Product sales: Affiliate$46,699 $123,116 $169,815 Third-party3,871 5,199 9,070 Transportation services22,675 — 22,675 Gathering and processing services: Affiliate1,005 (508) 497 Third-party69,504 — 69,504Commodity consideration44,497 (44,497) — Other revenues9,606 800 10,406Total revenues197,857 84,110 281,967Costs and expenses: Product cost Affiliate— 9,151 9,151 Third-party47,819 90,586 138,405Proceesing commodity expense: Affiliate9,151 (9,151) — Third-party6,894 (6,894) — Operating and maintenance expenses: Affiliate9,610 — 9,610 Third-party28,692 (147) 28,545 Depreciation, amortization and accretion71,080 — 71,080 Taxes other than income2,932 — 2,932 General and administrative expenses- affiliate7,639 — 7,639 Other (income) expense, net(24) — (24)Total costs and expenses183,793 83,545 267,338Operating income14,064 565 14,629Interest income (expense)(638) 1,033 395Net income13,426 1,598 15,024 Net loss from derivative instruments, including amounts reclassified intoearnings(64) — (64)Comprehensive income$13,362 $1,598 $14,960181DISCOVERY PRODUCER SERVICES LLCCONSOLIDATED STATEMENT OF MEMBERS' CAPITAL As reported Adjustments resultingfrom ASC 606 Balance withoutadoption of ASC606 (Thousands)Balance December 31, 2017$949,423 $— $949,423Contributions9,090 — 9,090Distributions(75,700) — (75,700)Net income13,426 1,598 15,024Cumulative effect adjustments - Adoption of ASU606 (Note 3)1,209 (1,209) —Other comprehensive loss(64) — (64)Balance December 31, 2018897,384 389 897,773Note 4. Related Party TransactionsWe have various business transactions with our members and subsidiaries and affiliates of our members. Revenues include sales to Williams of NGLs towhich we take title and excess natural gas. The related-party revenues associated with Williams in 2018, 2017, and 2016 were $48.1 million, $166.1 million,and $129.9 million, respectively. During 2018, Phillips 66 (an affiliate of DCP) paid us an exchange fee of $.4 million. The amount is netted in product sales.Also in 2018, we paid Phillips 66 $2 million for connection to their River Parish NGL system. We recorded the payment as an intangible asset. There were notransactions with Phillip 66 in 2017 or 2016.Processing commodity expense- affiliate includes natural gas purchases from Williams for fuel and shrink requirements.We have no employees. Pipeline and plant operations are performed under operation and maintenance agreements with Williams. Most costs for materials,services and other charges are third-party charges and are invoiced directly to us. Operating and maintenance expenses- affiliate includes the following:Direct payroll and employee benefit costs incurred on our behalf by Williams;Transportation expense under a 10-year transportation agreement for pipeline capacity through 2020 from Texas Eastern Transmission, LP(an affiliate of DCP) for $1.1 million in each of 2018, 2017 and 2016; andStorage expense under a 20-year agreement to store parts, tools and equipment in a warehouse owned by Williams PERK, LLC (an affiliate ofWFS) through 2033 for $0.3 million in each of 2018, 2017 and 2016.General and administrative expenses - affiliate includes a monthly operation and management fee paid to Williams to cover the cost of accountingservices, computer systems and management services provided to us.We also pay Williams a project management fee to cover the cost of managing capital projects. This fee is determined on a project by project basis and iscapitalized as part of the construction costs. A summary of the payroll costs and project fees charged to us by Williams and capitalized are as follows: Years Ended December 31, 2018 2017 2016 (In thousands)Capitalized labor$321 $464 $754Capitalized project fee203 179 249Total$524 $643 $1,003182Note 5. Property, Plant, and EquipmentProperty, plant, and equipment consisted of the following at December 31, 2018 and 2017: Estimated Years Ended December 31, Depreciable 2018 2017 Lives (In thousands) Property, plant, and equipment: Pipelines$1,110,217 $1,108,031 25 - 35 years Plant and other equipment547,654 532,502 25 - 35 years Buildings31,521 31,521 25 - 35 years Land and land rights8,673 8,544 0 - 35 years Construction work in progress1,565 4,012 Total property, plant, and equipment1,699,630 1,684,610 Less accumulated depreciation620,255 559,746 Net property, plant, and equipment$1,079,375 $1,124,864 Depreciation expense in 2018, 2017 and 2016 was $61.7 million, $83.5 million and $66.8 million, respectively.Commitments for construction and acquisition of property, plant and equipment totaled $0.9 million at December 31, 2018.Our asset retirement obligations relate primarily to our offshore platforms and pipelines and our onshore processing and fractionation facilities. At the endof the useful life of each respective asset, we are legally or contractually obligated to dismantle the offshore platforms, properly abandon the offshorepipelines, remove the onshore facilities and related surface equipment and restore the surface of the property.A rollforward of our asset retirement obligation for 2018 and 2017 is presented below: Years Ended December 31, 2017 2016 (In thousands)Balance at January 1$122,080 $123,440Accretion expense7,231 7,553Estimate revisions*12,602 (10,909)New obligation incurred— 2,675Settlements(4,724) (679)Balance at December 31$137,189 $122,080*2018 includes an increase of $31.5 million primarily associated with an increase in the estimated retirement cost for our Paradis and Larose plants, partiallyoffset by an $18.9 million reduction due to the final spending for a retirement being less than the liability recorded. 2017 includes a $12.3 million reductionrelated to assets determined not to have a retirement obligation.Note 6. Intangible AssetsGross intangible assets at December 31, 2018 and 2017 were $23.3 million and $20.7 million, respectively. Accumulated amortization at December 31,2018 and 2017 was $9.8 million and $7.6 million, respectively. The amortization expense was $2.1 million for 2018, $2.0 million for 2017, and $2.0 millionand 2016. The intangible assets are being amortized on a straight-line basis with lives between 10 and 20 years. Amortization expense is expected to be $2.3million annually for the next five years.183Note 7. Commitments and Contingent LiabilitiesWe lease the land on which the Paradis fractionator and the Larose processing plant are located. The term for the leases were renewed for an additional10 years beginning in 2017. The future minimum annual rentals under this non-cancelable lease as of December 31, 2018 are payable as follows: (In thousands)2019$1152020115202111520221152023120Thereafter478Total$1,058Total rent and lease expense for 2018, 2017, and 2016, including a cancelable platform space lease and miscellaneous month-to-month leases, was $0.9million, $1.4 million, and $1.1 million, respectively. These amounts exclude the Texas Eastern and PERK transactions which are disclosed in Note 4.Environmental Matters. We are subject to extensive federal, state, and local environmental laws and regulations which affect our operations related to theconstruction and operation of our facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminalenforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. We have not beennotified and are not currently aware of any material noncompliance under the various environmental laws and regulations.Other. We are party to various other claims, legal actions and complaints arising in the ordinary course of business. We estimate that, for all matters forwhich we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilitiesare immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made withoutconsideration of any potential recovery from third parties. There are no significant matters for which we are unable to reasonably estimate a range of possibleloss.17Note 8. Financial Instruments, Concentrations of Credit Risk and Major CustomersFair Value of Financial InstrumentsFair value is defined as the price which would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants atthe measurement date. Assets and liabilities recorded or disclosed at fair value are categorized based upon the level of judgment associated with the inputsused to measure their fair values. These categories include (in descending order of priority): Level 1, defined as observable inputs such as quoted prices inactive markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined asunobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.The carrying value of cash and cash equivalents, accounts receivable, accounts payable, customer deposits, other current assets and other current liabilitiesapproximate their fair value because of their short-term nature, and each represents a Level 1 estimate. Concentrations of Credit RiskOur cash equivalents balance is primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by theU.S. government.At December 31, 2018, substantially all of customer accounts receivable result from product sales and gathering from our largest customers. Thisconcentration may impact our overall credit risk either positively or negatively, in that the entity may be similarly affected by industry-wide changes ineconomic or other conditions. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness areevaluated regularly. Our credit policy and the184relatively short duration of receivables mitigate the risk of uncollected receivables. We incurred no gain/loss on receivables in 2018, 2017 or 2016.Major CustomersWilliams accounted for $48.1 million (24.3%), $166.1 million (40%), and $129.9 million (32%) respectively, of our total revenues in 2018, 2017, and2016. These revenues were for the sale of NGLs purchased from or received as compensation under processing contracts with third-party producers.During 2018, Anadarko accounted for $40.9 million (20.6%) of our total revenues. These revenues were for gathering, processing, transportation,commodity consideration and other services.During 2017, ExxonMobil Corporation accounted for $68.6 million (16.6%), and Anadarko accounted for $53.7 million (13.0%), of our total revenues.These revenues were for gathering, processing, transportation and other services.During 2016, ExxonMobil Corporation accounted for $81.9 million (20.5%), and ENI Petroleum accounted for $50.5 million (12.6%), of our totalrevenues. These revenues were for gathering, processing, transportation and other services.Note 9. Rate and Regulatory MattersRate and Regulatory Matters. Pursuant to the terms of its FERC Gas Tariff, DGT has the right to file, on an annual basis, a request with the FERC for a fuellost-and-unaccounted-for gas (FL&U) percentage (“the retention rate”) to be assessed shippers for the upcoming fiscal year beginning July 1. On May 31,2017, DGT filed a report with the FERC stating that it was not revising its currently effective FL&U retention rate of 0.0 percent at this time based upon theactual fuel use, system loss and gas retained experienced in 2016. On December 21, 2017, the FERC issued a letter order accepting the May 31, 2017 report.The actual system loss for 2017 was $2.3 million. On May 31, 2018, DGT filed to increase the FL&U retention rate from 0.0% (zero percent) to 0.13%(thirteen one-hundredths of one percent) per dekatherm (Dt) to be assessed on gas received into DGT’s system commencing July 1, 2018. The revisedretention rate was based upon the actual fuel use, system loss and gas retained in 2017. On June 22, 2018, the FERC issued a letter order approving therequested retention rate revision. The actual system loss for 2018 was $1.5 million with FL&U recovered of $0.3 million. The above amounts were recognizedin each year’s respective operating income.On November 15, 2017, DGT filed its annual HMRE surcharge adjustment to maintain the $0.0500 per Dt surcharge effective January 1, 2018. The filingreflected an additional $0.1 million of qualifying HMRE costs to be recovered by the surcharge. As reflected in the application, the total HMRE amount to berecovered over future periods was $14.5 million as of September 30, 2017. The Commission approved the requested surcharge by letter order dated December22, 2017.On November 15, 2018, DGT filed its annual HMRE surcharge adjustment to maintain the currently effective $0.0500 per Dt surcharge for 2019. The filingreflected an additional $0.13 million of qualifying HMRE costs to be recovered by the surcharge. As reflected in the application, the total HMRE amount tobe recovered over future periods was $9.4 million as of September 30, 2018. The Commission approved the requested surcharge by letter order datedDecember 11, 2018.Note 10. Subsequent EventsDuring January 2019, we made distributions to our partners totaling $3.4 million.185DCP SAND HILLS PIPELINE, LLCConsolidated Financial Statements for theYears Ended December 31, 2018, 2017 and 2016186INDEPENDENT AUDITORS’ REPORTTo the Members ofDCP Sand Hills Pipeline, LLCDenver, ColoradoWe have audited the accompanying consolidated financial statements of DCP Sand Hills Pipeline, LLC and subsidiary (the "Company"), whichcomprise the consolidated balance sheets as of December 31, 2018 and 2017, and the related consolidated statements of operations, changes inmembers’ equity, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes to the consolidatedfinancial statements.Management's Responsibility for the Consolidated Financial StatementsManagement is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accountingprinciples generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal controlrelevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraudor error.Auditors' ResponsibilityOur responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordancewith auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtainreasonable assurance about whether the consolidated financial statements are free from material misstatement.An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. Theprocedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidatedfinancial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to theCompany's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in thecircumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we expressno such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significantaccounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.OpinionIn our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of DCP SandHills Pipeline, LLC and its subsidiary as of December 31, 2018 and 2017, and the results of their operations and their cash flows for each of thethree years in the period ended December 31, 2018 in accordance with accounting principles generally accepted in the United States of America.Emphasis of MatterAs discussed in discussed in Note 3 to the consolidated financial statements, in 2018, the Company adopted new accounting guidance related torecognition of revenue from contracts with customers. Our opinion is not modified with respect to this matter./s/ Deloitte & Touche LLPDenver, ColoradoFebruary 8, 2019187DCP SAND HILLS PIPELINE, LLCCONSOLIDATED BALANCE SHEETS December 31,December 31, 20182017 (millions)ASSETS Current assets: Cash and cash equivalents$16.6$17.5Accounts receivable: Affiliates40.025.0Trade and other15.19.2Other current assets0.10.2Total current assets71.851.9Property, plant and equipment, net1,815.61,547.0Other long-term assets6.53.5Total assets$1,893.9$1,602.4 LIABILITIES AND MEMBERS’ EQUITY Current liabilities: Accounts payable: Trade and other$12.7$14.4Affiliates6.24.5Deferred revenue - affiliates—3.5Accrued taxes14.88.4Accrued capital expenditures9.712.9Accrued liabilities and other6.08.6Total current liabilities49.452.3Contract liabilities - affiliates34.0—Other long-term liabilities5.34.5Total liabilities88.756.8Commitments and contingent liabilities Total members’ equity1,805.21,545.6Total liabilities and members’ equity$1,893.9$1,602.4See Notes to Consolidated Financial Statements.188DCP SAND HILLS PIPELINE, LLCCONSOLIDATED STATEMENTS OF OPERATIONS Year EndedDecember 31, 2018 Year EndedDecember 31, 2017 Year EndedDecember 31, 2016 (millions)Operating revenues: Transportation - affiliates$389.0 $246.4 $182.5Transportation91.4 85.6 86.3Other revenue - affiliates— — 0.2Total operating revenues480.4 332.0 269.0Operating costs and expenses: Cost of transportation - affiliates6.0 3.6 6.8Cost of transportation3.0 3.0 3.8Operating and maintenance expense68.8 42.9 35.9Depreciation expense36.4 30.1 28.9General and administrative expense - affiliates5.2 5.2 5.2General and administrative expense2.6 2.5 2.5Total operating costs and expenses122.0 87.3 83.1Operating income358.4 244.7 185.9Interest income1.0 0.4 0.1Income tax expense(2.7) (1.7) (1.6)Net income$356.7 $243.4 $184.4See Notes to Consolidated Financial Statements.189DCP SAND HILLS PIPELINE, LLCCONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’ EQUITY DCP SandHolding, LLC DCP PipelineHolding LLC Phillips 66 SandHills LLC TotalMembers’Equity (millions)Balance, January 1, 2016 $431.3 $431.4 $431.4 $1,294.1Contributions from members 22.0 21.8 21.9 65.7Distributions to members (69.6) (69.6) (69.6) (208.8)Net income 61.5 61.4 61.5 184.4Balance, December 31, 2016 445.2 445.0 445.2 1,335.4Contributions from members 73.3 73.2 73.3 219.8Distributions to members (84.3) (84.4) (84.3) (253.0)Net income 81.1 81.2 81.1 243.4Balance, December 31, 2017 515.3 515.0 515.3 1,545.6Contributions from members 27.1 155.6 91.4 274.1Distributions to members (24.4) (227.7) (126.1) (378.2)Cumulative effect adjustment (see Note 2) 2.3 2.4 2.3 7.0Transfer of interest in DCP Sand Hills Pipeline, LLC (see Note 1) (555.7) 555.7 — —Net income 35.4 202.5 118.8 356.7Balance, December 31, 2018 $— $1,203.5 $601.7 $1,805.2See Notes to Consolidated Financial Statements.190DCP SAND HILLS PIPELINE, LLCCONSOLIDATED STATEMENTS OF CASH FLOWS Year EndedDecember 31, 2018Year EndedDecember 31, 2017Year EndedDecember 31, 2016 (millions)OPERATING ACTIVITIES: Net income$356.7$243.4$184.4Adjustments to reconcile net income to net cash provided by operating activities: Depreciation expense36.430.128.9Other(1.9)0.71.0Change in operating assets and liabilities: Accounts receivable(21.2)(13.3)(0.9)Accounts payable(0.6)2.9(1.7)Deferred revenues(3.5)(11.2)(19.0)Other current assets——0.1Other current liabilities9.01.05.9Other long-term assets(2.9)0.4(2.7)Other long-term liabilities2.0(0.1)(0.6)Net cash provided by operating activities374.0253.9195.4INVESTING ACTIVITIES: Capital expenditures(270.8)(211.2)(57.3)Proceeds from sale of assets——0.1Net cash used in investing activities(270.8)(211.2)(57.2)FINANCING ACTIVITIES: Contributions from members274.1219.865.7Distributions to members(378.2)(253.0)(208.8)Net cash used in financing activities(104.1)(33.2)(143.1)Net change in cash and cash equivalents(0.9)9.5(4.9)Cash and cash equivalents, beginning of period17.58.012.9Cash and cash equivalents, end of period$16.6$17.5$8.0See Notes to Consolidated Financial Statements.191DCP SAND HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 20161. Description of Business and Basis of PresentationDCP Sand Hills Pipeline, LLC, with its consolidated subsidiary, or Sand Hills, "we", "our", the "Company", or "us", is engaged in the business oftransporting natural gas liquids, or NGLs. The Sand Hills pipeline is a common carrier pipeline which provides takeaway service from plants in the Permianand the Eagle Ford basins to fractionation facilities along the Texas Gulf Coast and the Mont Belvieu, Texas market hub. The Sand Hills pipeline was placedinto service in June 2013. We are a limited liability company owned 66.665% by DCP Pipeline Holding LLC, a 100% owned subsidiary of DCP Midstream, LP, or DCP Midstream,and 33.335% by Phillips 66 Sand Hills LLC, a 100% owned subsidiary of Phillips 66 Partners LP, or Phillips 66 Partners. On May 1, 2018, DCP SandHolding, LLC, a 100% owned subsidiary of DCP Midstream, contributed its 33.335% ownership interest in the Company to DCP Pipeline Holding LLC.Previously, we were owned 33.330% by DCP Pipeline Holding LLC, 33.335% by DCP Sand Holding, LLC, and 33.335% by Phillips 66 Sand Hills LLC.Throughout these consolidated financial statements, DCP Midstream and Phillips 66 Partners will together be referenced as the members. DCP Midstream isthe operator of the Sand Hills pipeline.The Company allocates revenues, costs, and expenses in accordance with the terms of the Second Amended and Restated LLC Agreement, which becameeffective on September 3, 2013, or the LLC Agreement, to each of the members based on each member’s ownership interest. Under terms of the LLCAgreement, the members are required to fund capital calls necessary to fund the capital requirements of the Company, including capital expansion andworking capital requirements. Under the terms of the LLC Agreement, cash calls and cash distributions from operations are allocated to the members basedupon each member’s respective ownership interest.The consolidated financial statements include the accounts of Sand Hills and its 100% owned subsidiary and have been prepared in accordance withaccounting principles generally accepted in the United States of America, or GAAP. Intercompany balances and transactions have been eliminated.Transactions between us and the members have been identified in the consolidated financial statements as transactions between affiliates.2. Summary of Significant Accounting PoliciesUse of Estimates - Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidatedfinancial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actualresults could differ from those estimates.Cash and Cash Equivalents - Cash and cash equivalents include all cash balances and investments in highly liquid financial instruments purchased withan original stated maturity of 90 days or less and temporary investments of cash in short-term money market securities.Distributions - Under the terms of the LLC Agreement, we are required to make quarterly distributions to the members based on Available Cash, as theterm is defined in the LLC Agreement. Available Cash distributions are paid pursuant to the members’ respective ownership percentages at the date thedistributions are due.Estimated Fair Value of Financial Instruments - The fair value of cash and cash equivalents, accounts receivable and accounts payable included in theconsolidated balance sheets are not materially different from their carrying amounts because of the short-term nature of these instruments. We may investavailable cash balances in short-term money market securities. As of December 31, 2018 and 2017, we invested $16.6 million and $17.5 million,respectively, in short-term money market securitieswhich are included in cash and cash equivalents in our consolidated balance sheets. Given that short-term money market securities are publicly traded andmarket prices are readily available, these investments are considered Level 1 fair value measurements.Concentration of Credit Risk - Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and accountsreceivable. We extend credit to customers and other parties in the normal course of business and have established various procedures to manage our creditexposure, including initial credit approvals, credit limits and rights of offset.192DCP SAND HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016Property, Plant and Equipment - Property, plant and equipment are recorded at historical cost. The cost of maintenance and repairs, which are notsignificant improvements, are expensed when incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.Asset Retirement Obligations - Our asset retirement obligations, or AROs, relate primarily to the contractual obligations relating to the retirement orabandonment of our transportation pipelines, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust ourAROs each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. Assetretirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate offair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of theasset. The liability is determined using a credit-adjusted risk-free interest rate and accretes due to the passage of time based on the time value of money untilthe obligation is settled. None of our assets are legally restricted for purposes of settling AROs.Long-Lived Assets - We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate thecarrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is notrecoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. We consider variousfactors when determining if these assets should be evaluated for impairment, including but not limited to:•a significant adverse change in legal factors or business climate;•a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast thatdemonstrates continuing losses associated with the use of a long-lived asset;•an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;•significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;•a significant adverse change in the market value of an asset; or•a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. We assess the fairvalue of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third partycomparable sales and discounted cash flow models. Significant changes in market conditions resulting from events such as the condition of an asset or achange in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.Revenue Recognition - Our operating revenues are primarily derived from services related to transportation of NGLs. Revenues from transportationagreements are recognized based on contracted volumes transported in the period the services are provided. Our contracts generally have terms that extendbeyond one year, and related revenues are recognized over time. The performance obligation for most of our contracts encompasses a series of distinctservices performed on discrete daily quantities of NGLs for purposes of allocating variable consideration and recognizing revenue while the customersimultaneously receives and consumes the benefits of the transportation services provided. Revenue is recognized over time consistent with the transfer ofservices over time to the customer based on daily volumes delivered. Consideration is generally variable, and the transaction price cannot be determined atthe inception of the contract, because the volume of NGLs for which the service is provided is only specified on a daily or monthly basis. The transactionprice is determined at the time the service is provided as the uncertainty is resolved.Contract liabilities - We have contracts with customers whereby the customer reimburses us for costs we incur to construct certain connections to ouroperating assets. These agreements are typically entered into in conjunction with transportation agreements with customers. We previously accounted forthese arrangements as a reduction to the cost basis of our long-lived193DCP SAND HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016assets which were amortized as a reduction to depreciation expense over the estimated useful life of the related assets. Under Topic 606 we record thesepayments as contract liabilities which will be amortized into revenue over the expected contract term.Significant Customers - There was no third party customer that accounted for more than 10% of total operating revenue for the year ended December 31,2018 and one third party customer that accounted for more than 10% of total operating revenue for the year ended December 31, 2017 and 2016. There weresignificant transactions with affiliates for each of the years ended December 31, 2018, 2017 and 2016. See Note 6, Agreements and Transactions withAffiliates.Environmental Expenditures - Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit.Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities forthese expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonablyestimated.Income Taxes - We are structured as a limited liability company, which is a pass-through entity for federal income tax purposes. As a limited liabilitycompany, we do not pay federal income taxes. Instead, our income or loss for tax purposes is allocated to each of the members for inclusion in their respectivetax returns. Consequently, no provision for federal income taxes has been reflected in these consolidated financial statements. We are subject to the Texasmargin tax, which is treated as a state income tax. We follow the asset and liability method of accounting for state income taxes. Under this method, deferredincome taxes are recognized for the tax consequences of temporary differences between the consolidated financial statement carrying amounts and the taxbasis of the assets and liabilities. For the years ended December 31, 2018, 2017 and 2016, deferred state income tax expense totaled $0.5 million, $0.5million and $0.7 million, respectively. For the years ended December 31, 2018, 2017 and 2016, current state income tax expense totaled $2.2 million, $1.2million and $0.9 million, respectively.3. Recent Accounting PronouncementsFASB ASU, 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - InAugust 2016, the FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. We adopted this ASU on January 1, 2018and it has not had any impact on our consolidated cash flows.FASB ASU, 2016-13 “Financial Instruments-Credit Losses (Topic 326),” or ASU 2016-13 - In June 2016, the FASB issued ASU 2016-13, whichrequires measuring all expected credit losses for financial instruments held at the reporting date based on historical experience and immediate recognition ofmanagement’s estimates of current expected credit losses. We intend to adopt this ASU when it is effective for public entities, which is for annual reportingperiods beginning after December 15, 2019, and we are currently assessing the impact of adoption on our consolidated results of operations, cash flows andfinancial position.FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize alease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases.We adopted Topic 842 on January 1, 2019 using the modified retrospective method. We elected the package of practical expedients permitted under thetransition guidance within the new standard, and the land easement practical expedient, allowing us to carry forward our current accounting treatment forland easements on existing agreements. Policy elections made as part of our adoption of Topic 842 include (a) not recognizing lease assets or liabilities whenlease terms are less than twelve months, and (b) for agreements that contain both lease and non-lease components, combining these components together andaccounting for them as a single lease. Topic 842 will result in changes to the way we recognize, present and disclose our operating leases in our consolidatedfinancial statements, including the recognition of a lease liability and an offsetting right-of-use asset in our consolidated balance sheets for our operatingleases (with the exception of short-term leases excluded by practical expedient). However, this change will not have any impact on our net income or cashflows. We are not a lessor under any agreements. See our future minimum lease payments under our operating leases in Note 8.FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations and amendments - In May2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification Topic 605 “RevenueRecognition.” We adopted this ASU on January 1, 2018 using the194DCP SAND HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016modified retrospective method. Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amountthat reflects the consideration the entity expects to receive in exchange for those goods or services. We recognized the initial cumulative effect of applyingthis ASU as an adjustment to the 2018 opening balance of members’ equity.The adjustment to members' equity represents the difference between amortizing deferred customer balances over the fixed asset useful life versus theestimated contract term. The cumulative effect of the changes made to our consolidated January 1, 2018 balance sheet for the adoption of Topic 606 was asfollows: Balance atDecember 31,2017 Adjustments due toASU 2014-09 Balance atJanuary 1, 2018 (millions)Balance sheet Assets Property, plant and equipment, net $1,547.0 $43.7 $1,590.7 Liabilities and members’ equity Liabilities Contract liabilities $— $36.7 $36.7 Members’ equity $1,545.6 $7.0 $1,552.6In accordance with the new revenue standard requirements, the impact of adoption on our consolidated statement of operations and balance sheet was asfollows: Year Ended December 31, 2018 As Reported Balances WithoutAdoption of ASC606 Effect of Change (millions)Statement of operations Operating revenues Transportation $480.4 $477.5 $2.9 Operating costs and expenses Depreciation expense $36.4 $35.3 $1.1195DCP SAND HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016 December 31, 2018 As Reported BalancesWithoutAdoption of ASC606 Effect of Change (millions)Balance sheet Assets Property, plant and equipment, net $1,815.6 $1,771.0 $44.6 Liabilities and members’ equity Liabilities Contract liabilities $34.0 $— $34.0 Members’ equity $1,805.2 $1,810.4 $(5.2)Aside from the adjustments to the opening consolidated balance sheet noted above, the impact of adoption on our consolidated total operating,financing or investing activities of our consolidated statement of cash flows for the period ended December 31, 2018 was immaterial.4. Remaining Performance ObligationOur remaining performance obligations consist primarily of minimum volume commitment fee arrangements. Upon completion of the performanceobligations associated with these arrangements, customers are invoiced and revenue is recognized as transportation revenue in the consolidated statements ofoperations. The total amount of remaining performance obligations is estimated at approximately $488.6 million as of December 31, 2018. Our remainingperformance obligations are expected to be recognized through 2024 with a weighted average remaining life of 3 years as at December 31, 2018. As apractical expedient permitted by ASC 606, this amount excludes variable consideration as well as remaining performance obligations that have originalexpected durations of one year or less, as applicable. Our remaining performance obligations also exclude estimates of variable rate escalation clauses in ourcontracts with customers.5. Contract Assets and LiabilitiesDuring 2018, we have entered into agreements with customers that provide for minimum volume commitments. Under these agreements, our customersagree to ship a minimum volume of product on our pipeline over an agreed time period. If a customer fails to meet its minimum volume commitment for aspecified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between the actual product volumes and theminimum volume commitment for that period. We record revenue under minimum volume contracts during periods of shortfall when it is known that thecustomer cannot, or will not, make up some or all of the deficiency in subsequent periods. For the year ended December 31, 2018, we recognized $1.9 millionof deficiency fees, which is reflected in transportation revenue. Our contract liabilities primarily consist of deferred revenue received from reimbursable projects. The following table summarizes changes in contractliabilities included in our balance sheets:196DCP SAND HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016 December 31,2018 (millions) Balance, beginning of period $36.7Additions 2.0Revenue recognized (a) (2.9)Other (b) (1.8)Balance, end of period $34.0(a) Deferred revenue recognized is included in affiliate transportation revenues on the consolidated statement of operations.(b) Amended reimbursable projects6. Summary of Transactions with AffiliatesDCP MidstreamUnder the LLC Agreement, we are required to reimburse DCP Midstream for any direct costs or expenses (other than general and administration services)incurred by DCP Midstream on our behalf. Additionally, we pay DCP Midstream an annual service fee of $5.0 million, for centralized corporate functionsprovided by DCP Midstream on our behalf, including legal, accounting, cash management, insurance administration and claims processing, riskmanagement, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. These expenses are includedin general and administrative expense - affiliates in the consolidated statements of operations. Except with respect to the annual service fee, there is no limiton the reimbursements we make to DCP Midstream under the LLC Agreement for other expenses and expenditures incurred or payments made on our behalf.We have entered into transportation agreements with DCP Midstream, which include a commitment to transport volumes at rates defined in our tariffs.These 15-year transportation agreements became effective in June 2013. We currently, and anticipate to continue to, transact with DCP Midstream in theordinary course of business. DCP Midstream was a significant customer during the years ended December 31, 2018, 2017 and 2016.DCP Southern Hills Pipeline, LLCWe have a long-term capacity arrangement with DCP Southern Hills Pipeline, LLC, or Southern Hills, which expires in March 2023. Under the terms ofthis agreement, Southern Hills has the right to transport minimum throughput volumes on the Sand Hills pipeline at rates defined in the transportationagreement.Summary of Transactions with Affiliates197DCP SAND HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016The following table summarizes our transactions with affiliates: Year EndedDecember 31,2018 Year EndedDecember 31,2017Year EndedDecember 31,2016 (millions)DCP Midstream and its affiliates: Transportation - affiliates $384.1 $236.7$169.8Cost of transportation - affiliates $6.0 $3.6$6.8General and administrative expense - affiliates $5.0 $5.0$5.0Southern Hills: Transportation - affiliates $3.3 $3.2$3.2Phillips 66: Transportation - affiliates $1.5 $6.5$9.5General and administrative expense - affiliates $0.2 $0.2$0.2Enbridge: Transportation - affiliates $0.1 $—$—We had balances with affiliates as follows: December 31,December 31, 20182017 (millions)DCP Midstream and its affiliates: Accounts receivable $39.7$23.8Accounts payable $6.2$4.5Deferred revenue $—$3.5Contract liabilities $34.0$—Southern Hills: Accounts receivable $0.3$0.3Phillips 66: Accounts receivable $—$0.9Other current assets $0.1$—7. Property, Plant and EquipmentProperty, plant and equipment by classification is as follows:198DCP SAND HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016 Depreciable December 31,December 31, Life 20182017 (millions) Transmission systems20-50 Years $1,957.9$1,530.3Processing facilities35-60 Years 0.30.3Other3-30 Years 3.43.2Land 0.40.2Construction work in progress 20.8140.9Property, plant and equipment 1,982.81,674.9Accumulated depreciation (167.2)(127.9)Property, plant and equipment, net $1,815.6$1,547.0Asset Retirement Obligations - As of December 31, 2018 and 2017, we had AROs of $1.9 million and $1.7 million, respectively, included in other long-term liabilities in our consolidated balance sheets. For each of the years ended December 31, 2018, 2017 and 2016, accretion expense was less than $0.1million. Accretion expense is recorded within operating and maintenance expense in our consolidated statements of operations.8. Commitments and Contingent LiabilitiesRegulatory Compliance - In the ordinary course of business, we are subject to various laws and regulations. In the opinion of our management,compliance with existing laws and regulations will not materially affect our consolidated results of operations, financial position, or cash flows.Litigation - We are not party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings and variouscommercial disputes that arose during the development of the Sand Hills pipeline and in the ordinary course of our business. Management currently believesthat the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage and otherindemnification arrangements, will not have a material adverse effect on our consolidated results of operations, financial position, or cash flows.General Insurance - Insurance for Sand Hills is written in the commercial markets and through affiliate companies, which management believes isconsistent with companies engaged in similar commercial operations with similar assets. Our insurance coverage includes general liability and excessliability insurance above the established primary limits for general liability. All coverage is subject to certain limits and deductibles, the terms andconditions of which are common for companies with similar types of operations.Environmental - The operation of pipelines for transporting NGLs is subject to stringent and complex laws and regulations pertaining to health, safety,and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state, and, in somecases, local levels that relate to worker safety, pipeline safety, air and water quality, solid and hazardous waste storage, management, transportation anddisposal, and other environmental matters. The cost of planning, designing, constructing, and operating pipelines incorporates compliance withenvironmental laws and regulations, worker safety standards, and safety standards applicable to our various facilities. In addition, there is increasing focusfrom (i) regulatory bodies and communities, and through litigation, on hydraulic fracturing and the real or perceived environmental or public health impactsof this technique, which indirectly presents some risk to the available supply of natural gas and the resulting supply of NGLs, (ii) regulatory bodies regardingpipeline system safety which could impose additional regulatory burdens and increase the cost of our operations, and (iii) regulatory bodies and communitiesthat could prevent or delay the development of fossil fuel energy infrastructure such as pipeline and associated facilities used in our business. Failure tocomply with various health, safety and environmental laws and regulations may trigger a variety of administrative, civil, and potentially criminalenforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and theissuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these existing lawsand regulations will not have a material adverse effect on our consolidated results of operations, financial position, or cash flows.199DCP SAND HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016Operating Leases - Consolidated rental expense, including leases with no continuing commitment, was $4.7 million, $3.9 million and $3.5 million,respectively, for the years ended December 31, 2018, 2017 and 2016. Rental expense for leases with escalation clauses is recognized on a straight line basisover the initial lease term. Minimum lease payments under our operating leases is $1.8 million for year ended December 31, 2019.9. Supplemental Cash Flow Information Year EndedDecember 31,2018Year EndedDecember 31,2017Year EndedDecember 31,2016 (millions)Non-cash investing and financing activities: Property, plant and equipment acquired with accrued liabilitiesand accounts payable$18.2$20.6$15.1Cumulative effect of applying ASU 2014-09 on property, plantand equipment$43.7$—$—Cumulative effect of applying ASU 2014-09 on contractliabilities$(36.7)$—$—Cumulative effect of applying ASU 2014-09 on members’ equity$(7.0)$—$—Other non-cash changes in property, plant and equipment, net$0.4$0.1$(0.3)10. Subsequent EventsWe have evaluated subsequent events occurring through February 8, 2019, the date the consolidated financial statements were available to be issued andhave identified no events that require adjustments to or disclosure in these consolidated financial statements.200DCP SOUTHERN HILLS PIPELINE, LLCConsolidated Financial Statements for theYears Ended December 31, 2018, 2017 and 2016201INDEPENDENT AUDITORS’ REPORTTo the Members ofDCP Southern Hills Pipeline, LLCDenver, ColoradoWe have audited the accompanying consolidated financial statements of DCP Southern Hills Pipeline, LLC and subsidiary (the "Company"), which comprisethe consolidated balance sheets as of December 31, 2018 and 2017, and the related consolidated statements of operations, changes in members’ equity,and cash flows for each of the three years in the period ended December 31, 2018, and the related notes to the consolidated financial statements.Management's Responsibility for the Consolidated Financial StatementsManagement is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principlesgenerally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparationand fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.Auditors' ResponsibilityOur responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance withauditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the consolidated financial statements are free from material misstatement.An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. Theprocedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financialstatements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company's preparation andfair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purposeof expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluatingthe appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating theoverall presentation of the consolidated financial statements.We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.OpinionIn our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of DCP Southern HillsPipeline, LLC and its subsidiary as of December 31, 2018 and 2017, and the results of their operations and their cash flows for each of the three years in theperiod ended December 31, 2018 in accordance with accounting principles generally accepted in the United States of America.Emphasis of MatterAs discussed in discussed in Note 3 to the consolidated financial statements, in 2018, the Company adopted new accounting guidance related to recognitionof revenue from contracts with customers. Our opinion is not modified with respect to this matter./s/ Deloitte & Touche LLPDenver, ColoradoFebruary 8, 2019202DCP SOUTHERN HILLS PIPELINE, LLCCONSOLIDATED BALANCE SHEETS December 31,December 31, 20182017 (millions)ASSETS Current assets: Cash and cash equivalents$5.7$5.7Accounts receivable: Affiliates14.012.4Trade and other1.10.4Other current assets0.10.2Total current assets20.918.7Property, plant and equipment, net908.3902.1Total assets$929.2$920.8 LIABILITIES AND MEMBERS’ EQUITY Current liabilities: Accounts payable: Trade and other$7.3$5.9Affiliates1.81.4Accrued taxes1.81.3Accrued capital expenditures4.50.1Accrued liabilities and other3.04.1Total current liabilities18.412.8Contract liabilities - affiliates14.5—Other long-term liabilities1.91.7Total liabilities34.814.5Commitments and contingent liabilities Total members’ equity894.4906.3Total liabilities and members’ equity$929.2$920.8See Notes to Consolidated Financial Statements.203DCP SOUTHERN HILLS PIPELINE, LLCCONSOLIDATED STATEMENTS OF OPERATIONS Year EndedDecember 31,2018 Year EndedDecember 31,2017 Year EndedDecember 31,2016 (millions)Operating revenues: Transportation - affiliates$157.6 $127.7 $125.7Transportation8.8 5.2 4.9Other revenue - affiliates0.8 — —Total operating revenues167.2 132.9 130.6Operating costs and expenses: Cost of transportation - affiliates3.3 3.3 3.5Operating and maintenance expense29.3 27.0 26.7Depreciation expense21.2 20.9 20.7General and administrative expense - affiliates5.2 5.2 5.2General and administrative expense2.1 1.8 1.6Total operating costs and expenses61.1 58.2 57.7Operating income106.1 74.7 72.9Interest income0.3 0.1 —Income tax expense(0.3) (0.3) (0.2)Net income$106.1 $74.5 $72.7See Notes to Consolidated Financial Statements.204DCP SOUTHERN HILLS PIPELINE, LLCCONSOLIDATED STATEMENT OF CHANGES IN MEMBERS’ EQUITY DCP SouthernHolding, LLC DCP PipelineHolding LLC Phillips 66Southern HillsLLC TotalMembers’Equity (millions)Balance, January 1, 2016 $311.0 $310.0 $311.0 $932.0Contributions from members 1.5 1.6 1.5 4.6Distributions to members (28.1) (28.0) (28.1) (84.2)Net income 24.2 24.3 24.2 72.7Balance, December 31, 2016 308.6 307.9 308.6 925.1Distributions to members (31.1) (31.1) (31.1) (93.3)Net income 24.8 24.9 24.8 74.5Balance, December 31, 2017 302.3 301.7 302.3 906.3Contributions from members — 2.0 1.0 3.0Distributions to members (7.8) (75.2) (41.5) (124.5)Cumulative effect adjustment (see Note 2) 1.2 1.1 1.2 3.5Transfer of interest in DCP Southern Hills Pipeline,LLC (see Note 1) (305.7) 305.7 — —Net income 10.0 60.6 35.5 106.1Balance, December 31, 2018 $— $595.9 $298.5 $894.4See Notes to Consolidated Financial Statements.205DCP SOUTHERN HILLS PIPELINE, LLCCONSOLIDATED STATEMENTS OF CASH FLOWS Year EndedDecember 31,2018Year EndedDecember 31,2017Year EndedDecember 31,2016 (millions)OPERATING ACTIVITIES: Net income$106.1$74.5$72.7Adjustments to reconcile net income to net cash provided byoperating activities: Depreciation expense21.220.920.7Other(1.1)0.10.3Change in operating assets and liabilities: Accounts receivable(2.2)(1.5)(1.5)Accounts payable1.60.9(0.7)Deferred revenues - affiliates——(13.3)Other current liabilities1.40.51.0Other long-term liabilities1.6——Net cash provided by operating activities128.695.479.2INVESTING ACTIVITIES: Capital expenditures(7.1)(0.4)(0.5)Proceeds from sale of assets—0.20.1Net cash used in investing activities(7.1)(0.2)(0.4)FINANCING ACTIVITIES: Distributions to members(124.5)(93.3)(84.2)Contributions from members3.0—4.6Net cash used in financing activities(121.5)(93.3)(79.6)Net change in cash and cash equivalents—1.9(0.8)Cash and cash equivalents, beginning of period5.73.84.6Cash and cash equivalents, end of period$5.7$5.7$3.8See Notes to Consolidated Financial Statements.206DCP SOUTHERN HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears Ended December 31, 2018, 2017 and 20161. Description of Business and Basis of PresentationDCP Southern Hills Pipeline, LLC, with its consolidated subsidiary, or Southern Hills, "we", "our", the "Company", or "us", is engaged in the business oftransporting natural gas liquids, or NGLs. The Southern Hills pipeline is a common carrier pipeline which provides takeaway service from plants in thePermian and the Eagle Ford basins to fractionation facilities along the Texas Gulf Coast and the Mont Belvieu, Texas market hub. The Southern Hillspipeline was placed into service in June 2013. We are a limited liability company owned 66.665% by DCP Pipeline Holding LLC, a 100% owned subsidiary of DCP Midstream, LP, or DCP Midstream,and 33.335% by Phillips 66 Southern Hills LLC, a 100% owned subsidiary of Phillips 66 Partners LP, or Phillips 66 Partners. On May 1, 2018, DCP SouthernHolding, LLC, a 100% owned subsidiary of DCP Midstream, contributed its 33.335% ownership interest in the Company to DCP Pipeline Holding LLC.Previously, we were owned 33.330% by DCP Pipeline Holding LLC, 33.335% by DCP Southern Holding, and 33.335% by Phillips 66 Southern Hills LLC.Throughout these consolidated financial statements, DCP Midstream and Phillips 66 Partners will together be referenced as the members. DCP Midstream isthe operator of the Southern Hills pipeline.The Company allocates revenues, costs, and expenses in accordance with the terms of the Second Amended and Restated LLC Agreement, which becameeffective on September 3, 2013, or the LLC Agreement, to each of the members based on each member’s ownership interest. Under terms of the LLCAgreement, the members are required to fund capital calls necessary to fund the capital requirements of the Company, including capital expansion andworking capital requirements. Under the terms of the LLC Agreement, cash calls and cash distributions from operations are allocated to the members basedupon each member’s respective ownership interest.The consolidated financial statements include the accounts of Southern Hills and its 100% owned subsidiary and have been prepared in accordance withaccounting principles generally accepted in the United States of America, or GAAP. Intercompany balances and transactions have been eliminated.Transactions between us and the members have been identified in the consolidated financial statements as transactions between affiliates.2. Summary of Significant Accounting PoliciesUse of Estimates - Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidatedfinancial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actualresults could differ from those estimates.Cash and Cash Equivalents - Cash and cash equivalents include all cash balances and investments in highly liquid financial instruments purchased withan original stated maturity of 90 days or less and temporary investments of cash in short-term money market securities.Distributions - Under the terms of the LLC Agreement, we are required to make quarterly distributions to the members based on Available Cash, as theterm is defined in the LLC Agreement. Available Cash distributions are paid pursuant to the members’ respective ownership percentages at the date thedistributions are due.Estimated Fair Value of Financial Instruments - The fair value of cash and cash equivalents, accounts receivable and accounts payable included in theconsolidated balance sheets are not materially different from their carrying amounts because of the short-term nature of these instruments. We may investavailable cash balances in short-term money market securities. As of December 31, 2018 and 2017, we invested $5.6 million and $5.7 million, respectively,in short-term money market securitieswhich are included in cash and cash equivalents in our consolidated balance sheets. Given that the short-term money market securities are publicly tradedand market prices are readily available, these investments are considered Level 1 fair value measurements.Concentration of Credit Risk - Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and accountsreceivable. We extend credit to customers and other parties in the normal course of business207DCP SOUTHERN HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016and have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and rights of offset.Property, Plant and Equipment - Property, plant and equipment are recorded at historical cost. The cost of maintenance and repairs, which are notsignificant improvements, are expensed when incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.Asset Retirement Obligations - Our asset retirement obligations, or AROs, relate primarily to the contractual obligations relating to the retirement orabandonment of our transportation pipelines, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust ourAROs each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. Assetretirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate offair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of theasset. The liability is determined using a credit-adjusted risk-free interest rate and accretes due to the passage of time based on the time value of money untilthe obligation is settled. None of our assets are legally restricted for purposes of settling AROs.Long-Lived Assets - We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate thecarrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is notrecoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. We consider variousfactors when determining if these assets should be evaluated for impairment, including but not limited to:•a significant adverse change in legal factors or business climate;•a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast thatdemonstrates continuing losses associated with the use of a long-lived asset;•an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;•significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;•a significant adverse change in the market value of an asset; or•a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. We assess the fairvalue of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third partycomparable sales and discounted cash flow models. Significant changes in market conditions resulting from events such as the condition of an asset or achange in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.Revenue Recognition - Our operating revenues are primarily derived from services related to transportation of NGLs. Revenues from transportationagreements are recognized based on contracted volumes transported in the period the services are provided. Our contracts generally have terms that extendbeyond one year, and related revenues are recognized over time. The performance obligation for most of our contracts encompasses a series of distinctservices performed on discrete daily quantities of NGLs for purposes of allocating variable consideration and recognizing revenue while the customersimultaneously receives and consumes the benefits of the transportation services provided. Revenue is recognized over time consistent with the transfer ofservices over time to the customer based on daily volumes delivered. Consideration is generally variable, and the transaction price cannot be determined atthe inception of the contract, because the volume of NGLs for which the service is provided is only specified on a daily or monthly basis. The transactionprice is determined at the time the service is provided as the uncertainty is resolved.208DCP SOUTHERN HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016Contract liabilities - We have contracts with customers whereby the customer reimburses us for costs we incur to construct certain connections to ouroperating assets. These agreements are typically entered into in conjunction with transportation agreements with customers. We previously accounted forthese arrangements as a reduction to the cost basis of our long-lived assets which were amortized as a reduction to depreciation expense over the estimateduseful life of the related assets. Under Topic 606 we record these payments as contract liabilities which will be amortized into revenue over the expectedcontract term.Significant Customers - There was no third party customer that accounted for more than 10% of total operating revenue for the years ended December 31,2018, 2017 and 2016. There were significant transactions with affiliates for each of the years ended December 31, 2018, 2017 and 2016. See Note 6,Agreements and Transactions with Affiliates.Environmental Expenditures - Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit.Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities forthese expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonablyestimated.Income Taxes - We are structured as a limited liability company, which is a pass-through entity for federal income tax purposes. As a limited liabilitycompany, we do not pay federal income taxes. Instead, our income or loss for tax purposes is allocated to each of the members for inclusion in their respectivetax returns. Consequently, no provision for federal income taxes has been reflected in these consolidated financial statements. We are subject to the Texasmargin tax, which is treated as a state income tax. We follow the asset and liability method of accounting for state income taxes. Under this method, deferredincome taxes are recognized for the tax consequences of temporary differences between the consolidated financial statement carrying amounts and the taxbasis of the assets and liabilities. For the years ended December 31, 2018, 2017 and 2016, deferred state income tax expense totaled $0.1 million, $0.2million and $0.2 million, respectively . For the years ended December 31, 2018, 2017 and 2016, current state income tax expense totaled $0.2 million, $0.1million and $0.1 million, respectively.3. Recent Accounting PronouncementsFASB ASU, 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - InAugust 2016, the FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. We adopted this ASU on January 1, 2018and it has not had any impact on our consolidated cash flows.FASB ASU, 2016-13 “Financial Instruments-Credit Losses (Topic 326),” or ASU 2016-13 - In June 2016, the FASB issued ASU 2016-13, whichrequires measuring all expected credit losses for financial instruments held at the reporting date based on historical experience and immediate recognition ofmanagement’s estimates of current expected credit losses. We intend to adopt this ASU when it is effective for public entities, which is for annual reportingperiods beginning after December 15, 2019, and we are currently assessing the impact of adoption on our consolidated results of operations, cash flows andfinancial position.FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which requires lessees to recognize alease liability on a discounted basis and the right of use of a specified asset at the commencement date for all leases.We adopted Topic 842 on January 1, 2019 using the modified retrospective method. We elected the package of practical expedients permitted under thetransition guidance within the new standard, and the land easement practical expedient, allowing us to carry forward our current accounting treatment forland easements on existing agreements. Policy elections made as part of our adoption of Topic 842 include (a) not recognizing lease assets or liabilities whenlease terms are less than twelve months, and (b) for agreements that contain both lease and non-lease components, combining these components together andaccounting for them as a single lease. Topic 842 will result in changes to the way we recognize, present and disclose our operating leases in our consolidatedfinancial statements, including the recognition of a lease liability and an offsetting right-of-use asset in our consolidated balance sheets for our operatingleases (with the exception of short-term leases excluded by practical expedient). However, this change will not have any impact on our net income or cashflows. We are not a lessor under any agreements. See our future minimum lease payments under our operating leases in Note 8.209DCP SOUTHERN HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations and amendments - In May2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of Accounting Standards Codification Topic 605 “RevenueRecognition.” We adopted this ASU on January 1, 2018 using the modified retrospective method. Under the new standard, revenue is recognized when acustomer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goodsor services. We recognized the initial cumulative effect of applying this ASU as an adjustment to the 2018 opening balance of members’ equity.The adjustment to members' equity represents the difference between amortizing deferred customer balances over the fixed asset useful life versus theestimated contract term. The cumulative effect of the changes made to our consolidated January 1, 2018 balance sheet for the adoption of Topic 606 was asfollows: Balance atDecember 31,2017 Adjustmentsdue to ASU2014-09 Balance atJanuary 1,2018 (millions)Balance sheet Assets Property, plant and equipment, net $902.1 $17.9 $920.0 Liabilities and members’ equity Liabilities Contract liabilities $— $14.4 $14.4 Members’ equity $906.3 $3.5 $909.8In accordance with the new revenue standard requirements, the impact of adoption on our consolidated statement of operations and balance sheet was asfollows: Year Ended December 31, 2018 As Reported BalancesWithoutAdoption ofASC 606 Effect ofChange (millions)Statement of operations Operating revenues Transportation $166.4 $164.6 $1.8 Operating costs and expenses Depreciation expense $21.2 $20.8 $0.4210DCP SOUTHERN HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016 December 31, 2018 As Reported BalancesWithoutAdoption ofASC 606 Effect ofChange (millions)Balance sheet Assets Property, plant and equipment, net $908.3 $889.4 $18.9 Liabilities and members’ equity Liabilities Contract liabilities $15.5 $— $15.5 Members’ equity $894.4 $896.5 $(2.1)Aside from the adjustments to the opening consolidated balance sheet noted above, the impact of adoption on our consolidated total operating,financing or investing activities of our consolidated statement of cash flows for the period ended December 31, 2018 was immaterial.4. Remaining Performance ObligationOur remaining performance obligations consist primarily of minimum volume commitment fee arrangements. Upon completion of the performanceobligations associated with these arrangements, customers are invoiced and revenue is recognized as transportation revenue in the consolidated statements ofoperations. The total amount of remaining performance obligations is estimated at approximately $294.1 million as of December 31, 2018. Our remainingperformance obligations are expected to be recognized through 2024 with a weighted average remaining life of 3 years as of December 31, 2018. As apractical expedient permitted by ASC 606, this amount excludes variable consideration as well as remaining performance obligations that have originalexpected durations of one year or less, as applicable. Our remaining performance obligations also exclude estimates of variable rate escalation clauses in ourcontracts with customers.5. Contract LiabilitiesOur contract liabilities primarily consist of deferred revenue received from reimbursable projects. The following table summarizes changes in contractliabilities included in our balance sheets: December 31,2018 (millions) Balance, beginning of period $14.4Additions 2.9Revenue recognized (a) (1.8)Balance, end of period 15.5Current contract liabilities (1.0)Long-term contract liabilities $14.5(a) Deferred revenue recognized is in transportation revenues on the consolidated statement of operations.211DCP SOUTHERN HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 20166. Summary of Transactions with AffiliatesDCP MidstreamUnder the LLC Agreement, we are required to reimburse DCP Midstream for any direct costs or expenses (other than general and administration services)incurred by DCP Midstream on our behalf. Additionally, we pay DCP Midstream an annual service fee of $5.0 million, for centralized corporate functionsprovided by DCP Midstream on our behalf, including legal, accounting, cash management, insurance administration and claims processing, riskmanagement, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. These expenses are includedin general and administrative expense - affiliates in the consolidated statements of operations. Except with respect to the annual service fee, there is no limiton the reimbursements we make to DCP Midstream under the LLC Agreement for other expenses and expenditures incurred or payments made on our behalf.We have entered into transportation agreements with DCP Midstream, which include a commitment to transport volumes at rates defined in our tariffs.These 15-year transportation agreements became effective in June 2013. We currently, and anticipate to continue to, transact with DCP Midstream in theordinary course of business. DCP Midstream was a significant customer during the years ended December 31, 2018, 2017 and 2016.DCP Sand Hills Pipeline, LLCWe have a long-term capacity arrangement with DCP Sand Hills Pipeline, LLC, or Sand Hills, which expires in March 2023. Under the terms of thisagreement, Southern Hills has the right to transport minimum throughput volumes on the Sand Hills pipeline at rates defined in the transportation agreement.Summary of Transactions with AffiliatesThe following table summarizes our transactions with affiliates: Year EndedDecember 31,2018 Year EndedDecember 31,2017Year EndedDecember 31,2016 (millions)DCP Midstream and its affiliates: Transportation - affiliates $157.6 $127.7$125.7Other revenue - affiliates $0.8 $—$—General and administrative expense - affiliates $5.0 $5.0$5.0Cost of transportation - affiliates $— $0.1$0.3Sand Hills: Cost of transportation - affiliates $3.3 $3.2$3.2Phillips 66: General and administrative expense - affiliates $0.2 $0.2$0.2We had balances with affiliates as follows:212DCP SOUTHERN HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016 December 31,December 31, 20182017 (millions)DCP Midstream and its affiliates: Accounts receivable $14.0$12.4Accounts payable $1.5$1.1Contract liabilities $14.5$—Sand Hills: Accounts payable $0.3$0.3Phillips 66: Other current assets $0.1$—7. Property, Plant and EquipmentProperty, plant and equipment by classification is as follows: Depreciable December 31,December 31, Life 20182017 (millions) Transmission systems20-50 Years $1,010.6$988.8Other3-30 Years 3.93.3Land 2.02.0Construction work in progress 6.70.2Property, plant and equipment 1,023.2994.3Accumulated depreciation (114.9)(92.2)Property, plant and equipment, net $908.3$902.1Asset Retirement Obligations - As of December 31, 2018 and 2017, we had AROs of $0.9 million and $0.8 million, respectively, included in other long-term liabilities in our consolidated balance sheets. For each of the years ended December 31, 2018, 2017 and 2016, accretion expense was less than $0.1million. Accretion expense is recorded within operating and maintenance expense in our consolidated statements of operations.8. Commitments and Contingent LiabilitiesRegulatory Compliance - In the ordinary course of business, we are subject to various laws and regulations. In the opinion of our management,compliance with existing laws and regulations will not materially affect our consolidated results of operations, financial position, or cash flows.Litigation - We are not party to any significant legal proceedings, but are a party to various administrative and regulatory proceedings and variouscommercial disputes that arose during the development of the Southern Hills pipeline and in the ordinary course of our business. Management currentlybelieves that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage and otherindemnification arrangements, will not have a material adverse effect on our consolidated results of operations, financial position, or cash flows.General Insurance - Insurance for Southern Hills is written in the commercial markets and through affiliate companies, which management believes isconsistent with companies engaged in similar commercial operations with similar assets. Our insurance coverage includes general liability and excessliability insurance above the established primary limits for general liability. All coverage is subject to certain limits and deductibles, the terms andconditions of which are common for companies with similar types of operations.213DCP SOUTHERN HILLS PIPELINE, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ContinuedYears Ended December 31, 2018, 2017 and 2016Environmental - The operation of pipelines for transporting NGLs is subject to stringent and complex laws and regulations pertaining to health, safety,and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state, and, in somecases, local levels that relate to worker safety, pipeline safety, air and water quality, solid and hazardous waste storage, management, transportation anddisposal, and other environmental matters. The cost of planning, designing, constructing, and operating pipelines incorporates compliance withenvironmental laws and regulations, worker safety standards, and safety standards applicable to our various facilities. In addition, there is increasing focusfrom (i) regulatory bodies and communities, and through litigation, on hydraulic fracturing and the real or perceived environmental or public health impactsof this technique, which indirectly presents some risk to the available supply of natural gas and the resulting supply of NGLs, (ii) regulatory bodies regardingpipeline system safety which could impose additional regulatory burdens and increase the cost of our operations, and (iii) regulatory bodies and communitiesthat could prevent or delay the development of fossil fuel energy infrastructure such as pipeline and associated facilities used in our business. Failure tocomply with various health, safety and environmental laws and regulations may trigger a variety of administrative, civil, and potentially criminalenforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and theissuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these existing lawsand regulations will not have a material adverse effect on our consolidated results of operations, financial position, or cash flows.Operating Leases - Consolidated rental expense, including leases with no continuing commitment, was $0.4 million, $0.2 million and $0.2 million,respectively, for the years ended December 31, 2018, 2017 and 2016. Rental expense for leases with escalation clauses is recognized on a straight line basisover the initial lease term.9. Supplemental Cash Flow Information Year EndedDecember 31,2018Year EndedDecember 31,2017Year EndedDecember 31,2016 (millions)Non-cash investing and financing activities: Property, plant and equipment acquired with accrued liabilitiesand accounts payable$4.6$0.1$—Cumulative effect of applying ASU 2014-09 on property, plantand equipment$17.9$—$—Cumulative effect of applying ASU 2014-09 on contractliabilities$(14.4)$—$—Cumulative effect of applying ASU 2014-09 on members’ equity$(3.5)$—$—Other non-cash changes in property, plant and equipment, net$—$—$(0.3)10. Subsequent EventsWe have evaluated subsequent events occurring through February 8, 2019, the date the consolidated financial statements were available to be issued andhave identified no events that require adjustments to or disclosure in these condensed consolidated financial statements.214(b) ExhibitsExhibitNumber Description2.1 *# Contribution, Conveyance and Assumption Agreement, dated December 7, 2005, among DCP Midstream Partners, LP, DCP MidstreamOperating LP, DCP Midstream GP, LLC, DCP Midstream GP, LP, Duke Energy Field Services, LLC, DEFS Holding 1, LLC, DEFSHolding, LLC, DCP Assets Holdings, LP, DCP Assets Holdings, GP, LLC, Duke Energy Guadalupe Pipeline Holdings, Inc., DukeEnergy NGL Services, LP, DCP LP Holdings, LP and DCP Black Lake Holdings, LLC (attached as Exhibit 10.3 to DCP MidstreamPartners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on December 12, 2005).2.2 *# Contribution Agreement, dated October 9, 2006, between DCP LP Holdings, LP and DCP Midstream Partners, LP (attached as Exhibit10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on October 13, 2006).2.3 *# Purchase and Sale Agreement, dated March 7, 2007, between Anadarko Gathering Company, Anadarko Energy Services Company andDCP Midstream Partners, LP (attached as Exhibit 99.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on May 14, 2007).2.4 *# Contribution and Sale Agreement, dated May 21, 2007, between Gas Supply Resources Holdings, Inc., DCP Midstream, LLC and DCPMidstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s Current Report on Form 8-K (File No. 001-32678)filed with the SEC on May 25, 2007).2.5 *# Contribution Agreement, dated May 23, 2007, among DCP LP Holdings, LP, DCP Midstream, LLC, DCP Midstream GP, LP and DCPMidstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s Current Report on Form 8-K (File No. 001-32678)filed with the SEC on May 25, 2007).2.6 *# Contribution Agreement dated February 24, 2009, among DCP LP Holdings, LLC, DCP Midstream GP, LP DCP Midstream, LLC, andDCP Midstream Partners, LP (attached as Exhibit 10.16 to DCP Midstream Partners, LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on March 5, 2009).2.7 *# Purchase and Sale Agreement by and Among DCP Midstream, LLC and DCP Midstream Partners, LP dated as of November 4, 2010(attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC onNovember 8, 2010).2.8 *# Contribution Agreement between DCP Southeast Texas, LLC and DCP Partners SE Texas LLC dated as of November 4, 2010 (attachedas Exhibit 2.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on November 8,2010).2.9 *# Contribution Agreement, dated November 4, 2011, among DCP LP Holdings, LLC, DCP Midstream GP, LP, DCP Midstream, LLC andDCP Midstream Partners, LP (attached as Exhibit 10.7 to DCP Midstream, LLC’s Schedule 13D (File No. 005-81287) dated as ofJanuary 13, 2012).2.10 *# Contribution Agreement, dated February 27, 2012, among DCP LP Holdings, LLC, DCP Midstream, LLC and DCP Midstream Partners,LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC onMarch 1, 2012).2.11 * First Amendment to Contribution Agreement, dated March 30, 2012, among DCP LP Holdings, LLC, DCP Midstream, LLC and DCPMidstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678)filed with the SEC on April 5, 2012).2.12 *# Contribution Agreement among DCP LP Holdings, LLC, DCP Midstream, LLC and DCP Midstream Partners, LP dated June 25, 2012(attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on June29, 2012).2.13 *# Contribution Agreement, dated November 2, 2012, among DCP LP Holdings, LLC, DCP Midstream GP, LP, DCP Midstream, LLC, andDCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners LP’s Current Report on Form 8-K (File No. 001-32678)filed with the SEC on November 7, 2012).2.14 *# Contribution Agreement dated February 27, 2013 among DCP LP Holdings, LLC, DCP Midstream, LLC and DCP Midstream Partners,LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC onFebruary 27, 2013).2.15 * First Amendment to Contribution Agreement, dated March 28, 2013, among DCP LP Holdings, LLC, DCP Midstream, LLC, and DCPMidstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678)filed with the SEC on April 3, 2013).2.16 *# Purchase and Sale Agreement (O'Connor Plant) by and between DCP Midstream Partners, LP and DCP Midstream, LP dated August 5,2013 (attached as Exhibit 2.1 to DCP Midstream Partners, LP's Current Report on Form 8-K (File No. 001-32678) filed with the SEC onAugust 6, 2013).215ExhibitNumber Description2.17 *# Purchase and Sale Agreement (Front Range Pipeline) by and among DCP Midstream Partners, LP and DCP Midstream, LP dated August5, 2013 (attached as Exhibit 2.2 to DCP Midstream Partners, LP's Current Report on Form 8-K (File No. 001-32678) filed with the SECon August 6, 2013).2.18 *# Purchase and Sale Agreement, dated February 25, 2014, by and between DCP Midstream, LP, as seller, and DCP Midstream Partners, LP,as buyer (attached as Exhibit 2.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SECon February 26, 2014).2.19 *# Contribution Agreement, dated February 25, 2014, among DCP LP Holdings, LLC, DCP Midstream GP, LP, DCP Midstream, LLC, andDCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on February 26, 2014).2.20 * First Amendment to Contribution Agreement, dated February 27, 2014, among DCP LP Holdings, LLC, DCP Midstream GP, LP, DCPMidstream, LLC, and DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on February 28, 2014).2.21 * Second Amendment to Contribution Agreement, dated March 28, 2014, among DCP LP Holdings, LLC, DCP Midstream GP, LP, DCPMidstream, LLC, and DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on April 2, 2014).2.22 *# Contribution Agreement, dated December 30, 2016, by and among DCP Midstream, LLC, DCP Midstream Partners, LP and DCPMidstream Operating, LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678)filed with the SEC on January 6, 2017).3.1 * Certificate of Limited Partnership of DCP Midstream Partners, LP dated August 5, 2005 (attached as Exhibit 3.1 to DCP MidstreamPartners, LP's Registration Statement on Form S-1 (File No. 333-128378) filed with the SEC on September 16, 2005).3.2 * Certificate of Amendment to Certificate of Limited Partnership of DCP Midstream Partners, LP dated January 11, 2017 (attached asExhibit 3.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on January 17, 2017).3.3 * Fourth Amended and Restated Agreement of Limited Partnership of DCP Midstream, LP dated October 4, 2018 (attached as Exhibit 3.1to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on October 4, 2018).4.1 * Indenture dated as of September 30, 2010 for the issuance of debt securities between DCP Midstream Operating, LP, as issuer, anyGuarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee (attached as Exhibit 4.1 to DCP MidstreamPartners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on September 30, 2010).4.2 * Second Supplemental Indenture dated as of March 13, 2012 to Indenture dated as of September 30, 2010 between DCP MidstreamOperating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee(attached as Exhibit 4.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC onMarch 13, 2012).4.3 * Third Supplemental Indenture dated as of June 14, 2012 to Indenture dated as of September 30, 2010 between DCP MidstreamOperating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee(attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on June14, 2012).4.4 * Fifth Supplemental Indenture dated as of March 14, 2013 to Indenture dated as of September 30, 2010 between DCP MidstreamOperating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee(attached as Exhibit 4.3 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC onMarch 14, 2013).4.5 * Sixth Supplemental Indenture dated as of March 13, 2014 to Indenture dated as of September 30, 2010 between DCP MidstreamOperating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee(attached as Exhibit 4.3 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC onMarch 13, 2014).4.6 * Seventh Supplemental Indenture dated as of July 17, 2018 to Indenture dated as of September 30, 2010 between DCP MidstreamOperating, LP, as issuer, DCP Midstream, LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee (attachedas Exhibit 4.3 to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on July 17, 2018).4.7 * Indenture, dated as of August 16, 2000, by and between Duke Energy Field Services, LLC and The Chase Manhattan Bank (attached asExhibit 4.1 to DCP Midstream Partners, LP's Current Report on Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2017).216ExhibitNumber Description4.8 * First Supplemental Indenture, dated August 16, 2000, by and between Duke Energy Field Services, LLC and The Chase ManhattanBank (attached as Exhibit 4.1 to DCP Midstream, LLC’s Current Report on Form 8-K (File No. 000-31095) filed with the SEC onAugust 16, 2000).4.9 * Fifth Supplemental Indenture, dated as of October 27, 2006, by and between Duke Energy Field Services, LLC and The Bank of NewYork (as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank) (attached as Exhibit 4.3 to DCPMidstream Partners, LP's Current Report on Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2017).4.10 * Sixth Supplemental Indenture, dated September 17, 2007, by and between DCP Midstream, LLC (formerly known as Duke Energy FieldServices, LLC) and The Bank of New York (as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase ManhattanBank) (attached as Exhibit 4.4 to DCP Midstream Partners, LP's Current Report on Form 8-K (File No. 001-32678) filed with the SEC onJanuary 6, 2017).4.11 * Ninth Supplemental Indenture, dated March 11, 2010, by and between DCP Midstream, LLC (formerly known as Duke Energy FieldServices, LLC) and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor toJPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank) (attached as Exhibit 4.6 to DCP Midstream Partners, LP'sCurrent Report on Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2017).4.12 * Tenth Supplemental Indenture, dated September 19, 2011, by and between DCP Midstream, LLC (formerly known as Duke EnergyField Services, LLC) and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, assuccessor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank) (attached as Exhibit 4.7 to DCP MidstreamPartners, LP's Current Report on Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2017).4.13 * Eleventh Supplemental Indenture, dated January 1, 2017, by and between DCP Midstream Operating, LP, DCP Midstream, LLC andThe Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan ChaseBank, N.A., formerly known as The Chase Manhattan Bank) (attached as Exhibit 4.8 to DCP Midstream Partners, LP's Current Report onForm 8-K (File No. 001-32678) filed with the SEC on January 6, 2017).4.14 * Twelfth Supplemental Indenture, dated January 1, 2017, by and among DCP Midstream Operating, LP (as successor to DCP Midstream,LLC (formerly known as Duke Energy Field Services, LLC)), DCP Midstream Partners, LP and The Bank of New York Mellon TrustCompany, N.A. (as successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as TheChase Manhattan Bank) (attached as Exhibit 4.9 to DCP Midstream Partners, LP's Current Report on Form 8-K (File No. 001-32678)filed with the SEC on January 6, 2017).4.15 * Indenture, dated as of May 21, 2013, by and between DCP Midstream Operating, LP (as issuer and successor to DCP Midstream, LLC)and the Bank of New York Mellon Trust Company, N.A (attached as Exhibit 4.10 to DCP Midstream Partners, LP's Current Report onForm 8-K (File No. 001-32678) filed with the SEC on January 6, 2017).4.16 * First Supplemental Indenture, dated May 21, 2013, by and between DCP Midstream, LLC and the Bank of New York Mellon TrustCompany, N.A (attached as Exhibit 4.11 to DCP Midstream Partners, LP's Current Report on Form 8-K (File No. 001-32678) filed withthe SEC on January 6, 2017).4.17 * Second Supplemental Indenture, dated January 1, 2017, by and between DCP Midstream Operating, LP, DCP Midstream, LLC and TheBank of New York Mellon Trust Company, N.A (attached as Exhibit 4.12 to DCP Midstream Partners, LP's Current Report on Form 8-K(File No. 001-32678) filed with the SEC on January 6, 2017).4.18 * Form of Unit Certificate for 7.375% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (attached asExhibit 4.1 to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on November 20, 2017).4.19 Form of Unit Certificate for 7.875% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (attached asExhibit 4.1 to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on May 11, 2018).4.20 Form of Unit Certificate for 7.95% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (attached asExhibit 4.1 to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on October 4, 2018).10.1 * Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated December 7, 2005, as amended byAmendment No. 1 dated January 20, 2009 (attached as Exhibit 3.1 to DCP Midstream Partners, LP's Annual Report on Form 10-K (FileNo. 001-32678) filed with the SEC on March 5, 2009).217ExhibitNumber Description10.2 * Amendment No. 2 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated February 14,2013 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC onFebruary 21, 2013).10.3 * Amendment No. 3 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated November 6,2013 (attached as Exhibit 3.3 to DCP Midstream Partners, LP’s Quarterly Report on Form 10-Q (File No. 001-32678) filed with the SECon November 6, 2013).10.4 * Amendment No. 4 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP,LLC dated December 30,2016 (attached as Exhibit 10.4 to DCP Midstream, LP’s Annual Report onForm 10-K (File No. 001-32678) filed with the SEC onFebruary 15, 2017).10.5 * First Amended and Restated Agreement of Limited Partnership of DCP Midstream GP, LP dated December 7, 2005 (attached as Exhibit3.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on December 12, 2005).10.6 *+ DCP Midstream Partners, LP 2012 Long-Term Incentive Plan (attached as Exhibit 10.26 to DCP Midstream Partners, LP’s AnnualReport on Form 10-K (File No. 001-32678) filed with the SEC on February 29, 2012).10.7 *+ Form of Phantom Unit and DERs Grant for Directors under the DCP Midstream Partners, LP 2012 Long-Term Incentive Plan (attached asExhibit 10.27 to DCP Midstream Partners, LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on February 29,2012).10.8 *+ Form of Performance Phantom Unit Grant Agreement and DERs Grant for Officers/Employees under the DCP Midstream Partners, LP2012 Long-Term Incentive Plan (attached as Exhibit 10.28 to DCP Midstream Partners, LP’s Annual Report on Form 10-K (File No.001-32678) filed with the SEC on February 29, 2012).10.9 *+ Form of Restricted Phantom Unit Grant Agreement and DERs Grant under the DCP Midstream Partners, LP 2012 Long-Term IncentivePlan (attached as Exhibit 10.29 to DCP Midstream Partners, LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SECon February 29, 2012).10.10 *+ DCP Midstream Partners, LP 2016 Long-Term Incentive Plan (attached as Exhibit A to DCP Midstream Partners, LP's Definitive ProxyStatement on Schedule 14A (File No. 001-32678) filed with the SEC on March 15, 2016).10.11 *+ DCP Services, LLC 2008 Long-Term Incentive Plan, as amended and restated effective March 1, 2017 (attached as Exhibit 10.3 to DCPMidstream, LP’s Quarterly Report on Form 10-Q (File No. 001-32678) filed with the SEC on May 10, 2017).10.12 *+ Form of Strategic Performance Unit Grant Agreement under the DCP Services, LLC 2008 Long-Term Incentive Plan.10.13 *+ Form of Restricted Phantom Unit Grant Agreement under the DCP Services, LLC 2008 Long-Term Incentive Plan.10.14 *+ DCP Midstream, LP Executive Deferred Compensation Plan (attached as Exhibit 10.18 to DCP Midstream, LP’s Annual Report on Form10-K (File No. 001-32678) filed with the SEC on February 15, 2017).10.15 *+ DCP Midstream, LP Executive Deferred Compensation Plan Adoption Agreement (attached as Exhibit 10.19 to DCP Midstream, LP’sAnnual Report on Form 10-K (File No. 001-32678) filed with the SEC on February 15, 2017).10.16 *+ DCP Services, LLC Executive Severance Plan.10.17 *+ Amendment to the DCP Services, LLC Executive Severance Plan.10.18 * Services and Employee Secondment Agreement, dated January 1, 2017, by and between DCP Services, LLC and DCP MidstreamPartners, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LP's Current Report on Form 8-K (File No. 001-32678) filed with theSEC on January 6, 2017).10.19 * Second Amended and Restated Credit Agreement, dated as of December 6, 2017, by and among DCP Midstream Operating, LP, DCPMidstream, LP, Mizuho Bank, Ltd., as administrative agent, and the lenders party thereto (attached as Exhibit 10.1 to DCP Midstream,LP's Current Report on Form 8-K (File No. 001-32678) filed with the SEC on December 8, 2017).10.20 * Receivables Financing Agreement, dated August 13, 2018, among DCP Receivables LLC, as borrower, the Partnership, as initialservicer, the lenders, LC participants and group agents that are parties thereto from time to time, PNC Bank National Association, asAdministrative Agent and LC Bank and PNC Capital Markets LLC, as Structuring Agent (attached as Exhibit 10.1 to DCP Midstream,LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on August 14, 2018).10.21 * Receivables Sale and Contribution Agreement, dated August 13, 2018, between the originators from time to time party thereto and DCPReceivables LLC (attached as Exhibit 10.2 to DCP Midstream, LP’s Current Report on Form 8-K (File No. 001-32678) filed with theSEC on August 14, 2018).218ExhibitNumber Description21.1 List of Subsidiaries of DCP Midstream, LP.23.1 Consent of Deloitte & Touche LLP on Consolidated Financial Statements of DCP Midstream, LP and the effectiveness of DCPMidstream, LP's internal control over financial reporting.23.2 Consent of Deloitte & Touche LLP on Consolidated Financial Statements of DCP Sand Hills Pipeline, LLC and DCP Southern HillsPipeline, LLC23.3 Consent of Ernst & Young LLP on Consolidated Financial Statements of Discovery Producer Services LLC.24.1 Power of Attorney (incorporated by reference to the signature page of this Annual Report on Form 10-K).31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-OxleyAct of 2002.32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-OxleyAct of 2002.101 Financial statements from the Annual Report on Form 10-K of DCP Midstream, LP for the year ended December 31, 2018, formatted inXBRL: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements ofComprehensive Income, (iv) the Consolidated Statements of Cash Flows, (v) the Consolidated Statements of Changes in Equity, and(vi) the Notes to the Consolidated Financial Statements.* Such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.+ Denotes management contract or compensatory plan or arrangement.# Pursuant to Item 601(b)(2) of Regulation S-K, the Partnership agrees to furnish supplementally a copy of any omittedschedule to the Securities and Exchange Commission upon request.219Item 16. Form 10-K SummaryNone.220SIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized. DCP Midstream, LP By:DCP Midstream GP, LPits General Partner By:DCP Midstream GP, LLCits General Partner February 25, 2019By:/s/ Wouter T. van Kempen Name:Wouter T. van Kempen Title:President and Chief Executive Officer (Principal Executive Officer)221POWER OF ATTORNEYKNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints each of Wouter T. van Kempenand Sean P. O'Brien as his true and lawful attorney-in-fact and agent with full power of substitution and resubstitution, for him and in his name, place, andstead, in any and all capacities, to sign any and all amendments to this annual report, and to file the same, with all exhibits thereto and other documents inconnection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power andauthority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as hemight or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, and each of them, or their or his substitute orsubstitutes, may lawfully do or cause to be done by virtue hereof.Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of theregistrant and in the capacities and on the dates indicated.SignatureTitle (Position with DCP Midstream GP, LLC)Date /s/ Wouter T. van KempenChief Executive Officer, President,Chairman of the Board and DirectorFebruary 25, 2019Wouter T. van Kempen(Principal Executive Officer) /s/ Sean P. O'BrienGroup Vice President and Chief Financial OfficerFebruary 25, 2019Sean P. O'Brien(Principal Financial Officer) /s/ Richard A. LovingChief Accounting OfficerFebruary 25, 2019Richard A. Loving(Principal Accounting Officer) /s/ Allen C. CappsDirectorFebruary 25, 2019Allen C. Capps /s/ Fred J. FowlerDirectorFebruary 25, 2019Fred J. Fowler /s/ William F. KimbleDirectorFebruary 25, 2019William F. Kimble /s/ Mark MakiDirectorFebruary 25, 2019Mark Maki /s/ Brian MandellDirectorFebruary 25, 2019Brian Mandell /s/ Bill WaycasterDirectorFebruary 25, 2019Bill Waycaster /s/ John ZuklicDirectorFebruary 25, 2019John Zuklic 222Exhibit 21.1SUBSIDIARIES OF DCP MIDSTREAM, LPEntityJurisdiction of OrganizationCentana Intrastate Pipeline, LLCDelawareCimarron River Pipeline, LLCDelawareCollbran Valley Gas Gathering, LLC (75%)ColoradoDauphin Island Gathering PartnersTexasDCP Assets Holding GP, LLCDelawareDCP Assets Holding, LPDelawareDCP Black Lake Holdings, LPDelawareDCP Cheyenne Connector, LLCDelawareDCP Dauphin Island, LLCDelawareDCP East Texas Gathering, LLCDelawareDCP GCX Pipeline LLCDelawareDCP Grands Lacs LLCMichiganDCP Guadalupe Pipeline, LLCDelawareDCP Hinshaw Pipeline, LLCDelawareDCP Intrastate Network, LLCDelawareDCP Litchfield LLCMichiganDCP LP Holdings, LLCDelawareDCP Lucerne 2 Plant LLCDelawareDCP Michigan Holdings LLCDelawareDCP Michigan Pipeline & Processing LLCMichiganDCP Midstream Holding, LLCDelawareDCP Midstream Marketing, LLCDelawareDCP Midstream Operating, LLCDelawareDCP Midstream Operating, LPDelawareDCP Mobile Bay Processing, LLCDelawareDCP New Mexico Development, LLCDelawareDCP NGL Operating, LLCDelawareDCP NGL Services, LLCDelawareDCP Operating Company, LPDelawareDCP Partners Colorado LLCDelawareDCP Partners Logistics, LLCDelawareDCP Partners MB I LLCDelawareDCP Partners MB II LLCDelawareDCP Pipeline Holding LLCDelawareDCP Raptor Pipeline, LLCDelawareDCP Receivables LLCDelawareDCP Saginaw Bay Lateral LLCDelawareDCP South Central Texas LLCDelawareDCP Sweeny LLCDelawareDCP Tolar Gas Service, LLCDelawareDCP Tolar Pipeline, LLCDelawareDCP Wattenberg Pipeline LLCDelawareDCP Wyoming Assets LLCDelawareDCP Zia Plant LLCDelawareEasTrans, LLCDelawareFuels Cotton Valley Gathering, LLCDelawareExhibit 21.1Gas Supply Resources Holdings, LLCDelawareGas Supply Resources LLCTexasGSR Northeast Terminals LLCDelawareJackson Pipeline Company (75%)MichiganMarysville Hydrocarbons Holdings, LLCDelawareMarysville Hydrocarbons LLCDelawareNational Helium, LLCDelawareRock Creek Midstream LLCDelawareSaginaw Bay Lateral Michigan Limited Partnership (46%)MichiganWilbreeze Pipeline, LLCDelawareExhibit 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe consent to the incorporation by reference in Registration Statement Nos. 333-142271 and 333‑211905 on Form S-8 and Registration Statement Nos.333-221419, 333-219927, and 333‑182642 on Form S-3 of our reports dated February 25, 2019, relating to (1) the consolidated financial statements of DCPMidstream, LP and subsidiaries (the “Partnership”) (which report expresses an unqualified opinion and includes an explanatory paragraph regarding thePartnership’s change in method of accounting for revenue from contracts with customers in 2018, due to the adoption of Accounting Standards CodificationTopic 606 - Revenue from Contracts with Customers) and (2) the effectiveness of the Partnership’s internal control over financial reporting, appearing in thisAnnual Report on Form 10-K of DCP Midstream, LP for the year ended December 31, 2018./s/ Deloitte & Touche LLPDenver, ColoradoFebruary 25, 2019Exhibit 23.2CONSENT OF INDEPENDENT AUDITORSWe consent to the incorporation by reference in the following Registration Statements of our reports dated February 8, 2019, relating to the consolidatedfinancial statements of DCP Sand Hills Pipeline, LLC and subsidiary as of December 31, 2018 and 2017, and for each of the three years in the period endedDecember 31, 2018, and the consolidated financial statements of DCP Southern Hills Pipeline, LLC and subsidiary as of December 31, 2018 and 2017, andfor each of the three years in the period ended December 31, 2018 (collectively, “the Companies”) (which reports each express an unqualified opinion andinclude an explanatory paragraph regarding the Companies’ change in method of accounting for revenue from contracts with customers in 2018, due to theadoption of Accounting Standards Codification Topic 606 - Revenue from Contracts with Customers), appearing in this Annual Report on Form 10-K of DCPMidstream, LP for the year ended December 31, 2018:•Registration Statement Nos. 333-142271 and 333-211905 on Form S-8 of DCP Midstream, LP, and•Registration Statement Nos. 333-221419, 333-219927, and 333-182642 on Form S-3 of DCP Midstream, LP./s/ Deloitte & Touche LLPDenver, ColoradoFebruary 25, 2019 Exhibit 23.3CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe consent to the incorporation by reference in the following Registration Statements:1.Registration Statement (Form S-3 No. 333-182642) of DCP Midstream, LP (the “Partnership”),2.Registration Statement (Form S-3 No. 333-219927) of the Partnership,3.Registration Statement (Form S-3 No. 333-221419) of the Partnership,4.Registration Statement (Form S-8 No. 333-142271) pertaining to the Partnership’s Long-Term Incentive Plan, and5.Registration Statement (Form S-8 No. 333-211905) pertaining to the Partnership’s Long-Term Incentive Plan;of our report dated February 21, 2019, with respect to the consolidated financial statements of Discovery Producer Services LLC,included in this Annual Report (Form 10-K) of the Partnership for the year ended December 31, 2018./s/ Ernst & Young LLPTulsa, OklahomaFebruary 21, 2019Exhibit 31.1Certification Pursuant toSection 302 of the Sarbanes-Oxley Act of 2002I, Wouter T. van Kempen, certify that:1.I have reviewed this annual report on Form 10-K of DCP Midstream, LP for the year ended December 31, 2018;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in ExchangeAct Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for theregistrant and have:(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared;(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles;(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting.Date: February 25, 2019 /s/ Wouter T. van KempenWouter T. van KempenPresident and Chief Executive Officer(Principal Executive Officer)DCP Midstream GP, LLC, general partner ofDCP Midstream GP, LP, general partner ofDCP Midstream, LPExhibit 31.2Certification Pursuant toSection 302 of the Sarbanes-Oxley Act of 2002I, Sean P. O'Brien, certify that:1.I have reviewed this annual report on Form 10-K of DCP Midstream, LP for the year ended December 31, 2018;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in ExchangeAct Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for theregistrant and have:(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared;(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles;(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting.Date: February 25, 2019 /s/ Sean P. O'BrienSean P. O'BrienGroup Vice President and Chief Financial Officer(Principal Financial Officer)DCP Midstream GP, LLC, general partner ofDCP Midstream GP, LP, general partner ofDCP Midstream, LPExhibit 32.1Certification of President and Chief Executive OfficerPursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)The undersigned, the President and Chief Executive Officer of DCP Midstream GP, LLC, general partner of DCP Midstream GP, LP, general partner of DCPMidstream, LP (the “Partnership”), hereby certifies that, to his knowledge on the date hereof:(a)the annual report on Form 10-K of the Partnership for the year ended December 31, 2018, filed on the date hereof with the Securities and ExchangeCommission (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and(b)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. /s/ Wouter T. van KempenWouter T. van KempenPresident and Chief Executive Officer(Principal Executive Officer)February 25, 2019A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership andfurnished to the Securities and Exchange Commission or its staff upon request.Exhibit 32.2Certification of Group Vice President and Chief Financial OfficerPursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)The undersigned, the Group Vice President and Chief Financial Officer of DCP Midstream GP, LLC, general partner of DCP Midstream GP, LP, generalpartner of DCP Midstream, LP (the “Partnership”), hereby certifies that, to his knowledge on the date hereof:(a)the annual report on Form 10-K of the Partnership for the year ended December 31, 2018, filed on the date hereof with the Securities and ExchangeCommission (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and(b)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. /s/ Sean P. O'BrienSean P. O'BrienGroup Vice President and Chief Financial Officer(Principal Financial Officer)February 25, 2019A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership andfurnished to the Securities and Exchange Commission or its staff upon request.

Continue reading text version or see original annual report in PDF format above