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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 changes in commodity prices through derivative financial instruments, and the potential impact of price, and of producers’ access to capital on natural gas drilling, demand for our services, 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 well as our residue gas and NGL infrastructure;

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new, additions to, and changes in, laws and regulations, particularly with regard to taxes, safety, regulatory and protection of the environment, including, but not limited to, climate change legislation, regulation of over-the-counter derivatives market and entities, and hydraulic fracturing regulations, or the increased regulation of our industry, including mandatory setbacks for oil and gas operations and additional local control over such activities, and their impact on producers and customers served by our systems;

•	volatility in the price of our common units;

•	general economic, market and business conditions;

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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 if the 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 or NGLs 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 other permits issued by federal, state and municipal governments, or agencies thereof, the availability of specialized contractors and laborers, and the price of and demand for materials;

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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 indentures governing 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 in competition;

•	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 the operation 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.

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(a)	Represents total NGL capacity or throughput allocated to our proportionate ownership share.

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•	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.

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•	requiring the acquisition of permits or authorizations to conduct regulated activities and imposing obligations in those permits, potentially including 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 threatened and 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 permits issued pursuant to such environmental laws and regulations.

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•	the level of domestic and offshore production;

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•	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.

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•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or 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.

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•	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.

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•	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;

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•	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.

•	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 for acquisitions, 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 and controls;

•	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.

•	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 acquired businesses.

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•	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, sell and 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.

•	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 limited ability to control decisions with respect to the operations of these joint ventures, including decisions with respect to incurrence of expenses and distributions to us;

•	these joint ventures may establish reserves for working capital, capital projects, environmental matters and legal proceedings which would reduce cash available for distribution to us;

•	these joint ventures may incur additional indebtedness, and principal and interest made on such indebtedness may reduce cash otherwise available for distribution to us; and

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•	these joint ventures may require us to make additional capital contributions to fund working capital and capital expenditures, our funding of which could reduce the amount of cash otherwise available for distribution.

•	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 a result 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.

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•	neither our Partnership Agreement nor any other agreement requires DCP Midstream, LLC to pursue a business strategy that favors us. DCP Midstream, 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, including Phillips 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 “DCP Midstream, 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 for resetting the target distribution levels related to its incentive distribution rights without the approval of the special committee of our general partner 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 for actions 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 and reserves, 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 capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can 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 or entering 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 be indemnified 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 common units;

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•	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.

•	the exercise of its right to reset the target distribution levels of its incentive distribution rights at higher levels and receive, in connection with this 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 into common 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.

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

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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the special committee of the board of directors of our general partner and not involving a vote of our unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

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•	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;

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•	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.

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•	a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•	the right of holders of limited partner interests to act with other unitholders to remove or replace the general partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business.

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•	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 Cash for the quarter.

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•	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 year to 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 to holders of record as of the close of business on the first business day of the month in which the distribution will be made.

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(a)	Includes our proportionate share of the earnings of our unconsolidated affiliates. Earnings include the amortization of the net difference between the 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.

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•	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 volume outlooks.

•	We believe we have a solid capital structure and balance sheet.

•	We believe we have access to sufficient capital to fund our growth.

•	Within our Logistics and Marketing Segment, we increased the capacity of the Sand Hills pipeline to 485 MBbls/d during the fourth quarter of 2018.

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•	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. Both expansions 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 at least 600 MMcf/day and is expected to be in service in the fourth quarter of 2019, subject to certain conditions, including required approvals from 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 90 MBls/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/d of natural gas, and is fully subscribed. The natural gas takeaway pipeline is under construction and is anticipated to be in-service in the fourth quarter 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.

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Within our Gathering and Processing Segment, construction of our up to 300 MMcf/d O'Connor 2 facility and associated gathering infrastructure, 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 of bypass. 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 including bypass. The Bighorn facility is expected to be placed into service in phases beginning in the second quarter of 2020.

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(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 difference between 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 operating revenues 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 NGL production.

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•	$1,257 million increase for our Logistics and Marketing segment primarily due to higher NGL and crude prices, higher gas and NGL sales volumes which impacts both sales and purchases, partially offset by lower natural gas prices, unfavorable commodity derivative activity and the implementation of ASC 606; and

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$376 million increase for our Gathering and Processing segment due to higher NGL and crude prices, higher gas and NGL sales volumes impacting both sales and purchases due to increased drilling activity in our Eagle Ford system and the impact of Hurricane Harvey in 2017 in the South region, growth projects primarily related to our DJ Basin system in the North region and increased volumes, improved operational performance in our Midcontinent region and favorable commodity derivative activity. These increases were partially offset by lower natural gas prices, the sale of our Douglas gathering system in June 2017 and the implementation of ASC 606;

•	$273 million change in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to higher gas and NGL sales volume, higher commodity prices and the implementation of ASC 606.

•	$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;

•	$273 million change in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to higher gas and NGL sales volumes and higher commodity prices and the implementation of ASC 606;

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$201 million increase for our Gathering and Processing segment primarily related to increased volumes from increased drilling activity in our Eagle Ford system and the impact of Hurricane Harvey in 2017 in the South region, growth projects primarily related to our DJ Basin system in the North region, increased volumes and improved operational performance in the Midcontinent region, favorable commodity derivative activity and 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 commodity spreads primarily associated with Guadalupe and higher NGL marketing margins and transported volumes, partially offset by unfavorable commodity derivative activity, lower margins on wholesale propane and the expiration of a commercial arrangement.

•	$1,571 million increase for our Logistics and Marketing segment primarily due to increased commodity prices and favorable commodity derivative activity, partially offset by lower gas and NGL sales volumes and the sale of our Northern Louisiana System;

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$977 million increase for our Gathering and Processing segment primarily due to higher commodity prices, higher gas and NGL sales volumes primarily related to our North region which impacts both sales and purchases, and higher transportation, processing and other, primarily related to fee based contract realignment efforts. These increases were partially offset by lower gas and NGL sales volumes in the South, Midcontinent and Permian regions, unfavorable commodity derivative activity and the sale of our Northern Louisiana system and Douglas gathering system;

•	$979 million increase in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to higher commodity prices, partially offset by lower gas and NGL sales volumes.

•	$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;

•	$979 million increase in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to higher commodity prices, partially offset by lower gas and NGL sales volumes.

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$150 million increase for our Gathering and Processing segment primarily related to higher commodity prices, increased volume from growth projects, 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 our South, Midcontinent, and Permian regions due to reduced drilling activity in prior periods, the impact of Hurricane Harvey primarily in the South and Permian regions, the sale of our Northern Louisiana system, the sale of our Douglas gathering system and unfavorable commodity derivative activity.

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$5 million decrease for our Logistics and Marketing segment primarily related to lower margins on wholesale propane and the expiration of a contract, the sale of our Northern Louisiana system, lower gas storage margins and lower transportation volumes on certain of our NGL pipelines, partially offset by higher NGL marketing margins, higher gas marketing margins and favorable commodity derivative activity.

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(a)	Earnings from unconsolidated affiliates for Sand Hills, Southern Hills, Front Range, Mont Belvieu 1 and Texas Express include the amortization of the 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.

•	$853 million increase as a result of higher NGL and crude prices, partially offset by lower natural gas prices, which impacted both sales and purchases, 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 to the implementation of ASC 606;

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•	$86 million decrease as a result of commodity derivative activity attributable to an increase in realized cash settlement losses due to movements in 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 wholesale propane business.

•	$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;

•	$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, partially offset by higher throughput volumes.

•	$1,934 million increase as a result of higher commodity prices, which impacted both sales and purchases, before the impact of derivative activity; and

•	$4 million increase as a result of commodity derivative activity attributable to an decrease in unrealized commodity derivative losses of $16 million partially offset by a $12 million decrease in realized cash settlement gains due to movements in forward prices of commodities in 2017;

•	$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 on certain of our NGL pipelines.

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•	$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;

•	$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.

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(a)	Earnings from unconsolidated affiliates includes our 40% ownership of Discovery. Earnings for Discovery include the amortization of the net difference 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.

•	$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 and

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•	$213 million increase attributable to higher NGL and crude prices, partially offset by lower natural gas prices, which impacted both sales and purchases, 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 $136 million, partially offset by a $51 million increase in realized cash settlement losses due to movements in forward prices of commodities in 2018;

•	$158 million decrease in transportation, processing and other primarily related to the implementation of ASC 606.

•	$84 million increase as a result of increased volume from increased drilling activity in our Eagle Ford system and the impact of Hurricane Harvey in 2017 in the South region, growth projects primarily related to our DJ Basin system in the North region and increased volumes and improved operational 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;

•	$16 million decrease primarily as a result of lower volumes due to operational factors, a third-party line strike and weather impacting operations in the Permian region; and

•	$15 million decrease primarily as a result of the sale of our Douglas gathering system in June 2017.

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•	$1,280 million increase attributable to higher commodity prices, which impacted both sales and purchases, before the impact of derivative activity;

•	$100 million increase attributable to higher gas and NGL sales volumes due to the impact of a specific producer arrangement and growth projects primarily 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 lower volumes in the South region and the sale of our Northern Louisiana system and Douglas gathering system;

•	$392 million decrease primarily as a result of lower volumes across our South, Midcontinent and Permian regions due to reduced drilling activity in 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 in 2017.

•	$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, and higher NGL recoveries primarily related to our DJ Basin system and a producer settlement in our North region;

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•	$79 million decrease primarily as a result of lower volumes across our South, Midcontinent and Permian regions due to reduced drilling activity in prior periods and the impact of Hurricane Harvey, partially offset by fee based contract realignment efforts in the Permian and Midcontinent regions 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 North region; and

•	$21 million decrease as a result of commodity derivative activity as discussed above.

•	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.

•	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 significant depending on commodity price movements.

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•	Maintenance capital expenditures, which are cash expenditures to maintain our cash flows, operating or earnings 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; and

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Expansion capital expenditures, which are cash expenditures to increase our cash flows, operating or earnings capacity. Expansion capital expenditures include acquisitions or capital improvements (where we add on to or improve the capital assets owned, or acquire or construct new gathering lines and well connects, treating facilities, processing plants, fractionation facilities, pipelines, terminals, docks, truck racks, tankage and other storage, distribution or transportation facilities and related or similar midstream assets).

(a)	Represents the noncontrolling interest and reimbursable portion of our capital expenditures. We have entered into agreements with third parties whereby we will be reimbursed for certain expenditures. Depending on the timing of these payments, we may be reimbursed prior to incurring the capital expenditure.

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(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 capital expenditures, 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 forward market prices or current market rates as of December 31, 2018. Purchase obligations exclude accounts payable, accrued taxes and other current

(c)

Other long-term liabilities include asset retirement obligations, long-term environmental remediation liabilities, gas purchase liabilities, and other miscellaneous 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 any payments are not subject to reasonable estimation.

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•	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 to financing 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 cash distributions to our unitholders and general partner, and finance maintenance capital expenditures.

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(a)	Non-cash commodity derivative mark-to-market is included in gross margin and segment gross margin, along with cash settlements for our commodity derivative contracts.

(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.

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(a)	Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements 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 as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations for the effective portion until the service is provided or the associated delivery impacts earnings. For fair value hedges, the change in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations 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 of operations for changes in fair value of a contract until the service is provided or the associated delivery impacts earnings.

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•	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 that demonstrates 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.

•	sales of natural gas, NGLs and condensate;

•	services related to gathering, compressing, treating, and processing natural gas; and

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•	services related to transportation and storage of natural gas and NGLs.

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•

Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with

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•

Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit 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 active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.

•	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.

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(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.

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(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.

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•	If we were to have an effective event of default under our Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right 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 liability position, 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. These provisions apply if we default in making timely payments under other credit arrangements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Credit Agreement. As of December 31, 2018, we were not a party to any agreements that would trigger the cross-default provisions.

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(a)	Relates to Discovery, an unconsolidated affiliate.

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•	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 year to 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 to holders of record as of the close of business on the first business day of the month in which the distribution will be made.

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•	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 Cash for the quarter.

•	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 for that quarter;

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•	second, 13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives 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 unitholder receives 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.

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In March 2018, the New Mexico Environment Department ("NMED") issued two separate Notices of Violation ("NOV") relating to upset and malfunction event emissions at two of our gas processing plants. Following information exchanges and discussions with NMED regarding the events and the propriety of the alleged violations, on February 14, 2019 we entered into preliminary settlement agreements to resolve the alleged violations under each NOV for administrative penalties in the amount of $149,832 and $142,233, respectively. We intend to mitigate a portion of each administrative 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 improperly permitted facility flare and related air emissions from flare operations at one of our gas processing plants that we self-disclosed to CDPHE in December 2017. Following information exchanges and discussions with CDPHE, during the first quarter of 2019, a resolution was proposed pursuant to which the plant's air

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(a)

Gross margin consists of total operating revenues, including commodity derivative activity, less purchases and related costs. Gross margin is viewed as a non-GAAP financial 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 represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful 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 similarly titled 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.

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reviewed and discussed quarterly and annual earnings press releases, quarterly unaudited financial statements, and the annual audited financial statements included in this Annual Report on Form 10-K with management and Deloitte & Touche LLP, our independent auditors, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements;

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reviewed with Deloitte & Touche LLP, who are responsible for expressing an opinion on the conformity of the audited financial statements with generally accepted accounting principles, their judgments as to the quality and acceptability of our accounting principles and such other matters as are required to be discussed with the audit committee under the auditing standards of the Public Company Accounting Oversight Board (PCAOB);

•	received the written disclosures and the letter required by PCAOB Ethics and Independence Rules (independence discussions with audit committees) 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 of nonaudit 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 Auditing Standard No. 16, Communications With Audit Committees, Related Amendments to PCAOB Standards and Transitional Amendments to AU Section 380);

•	discussed with our internal auditors and Deloitte & Touche LLP the overall scope and plans for their respective audits. The audit committee meets 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 the Annual 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 other factors, the following: their historical and recent performance on our audit, the quality and candor of their communications with the audit committee and management, the depth of expertise of their audit team and the value provided by their national office, the appropriateness of their 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 by them and their peer firms.

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•	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 in a 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 the General Partner or its affiliates, or our non-employee directors, and NEOs; and

•	periodically review the compensation of the non-employee directors.

•	attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers in our industry;

•	motivate executive officers and key management employees to achieve strong financial and operational performance;

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•	emphasize performance-based compensation, balancing short-term and long-term results; and

•	reward individual performance.

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1.	Distributable Cash Flow. An objective intended to capture the annual amount of cash that is available for the quarterly distributions to our unitholders. 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 of commodity 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, we established a range of performance from a minimum of $945 million to a maximum of $900 million.

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 Collaboration Center, which utilizes real-time data on our operations, financial systems, and other information to optimize asset performance to achieve higher reliability, margin, and cost savings.

1.	Total Recordable Injury Rate (TRIR). An objective of both employee and contractor incident rates covering the assets of the Partnership. For this objective, 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 this objective, 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 have established certain levels of emissions at such assets.

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1.

We determined that, as of December 31, 2018, our employee population consisted of approximately 2,650 individuals with all of these individuals located in the United States (as reported in Item 1, Business, in this Annual Report on Form 10-K). This population consisted of our full-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 employee population, we compared the 2017 earnings eligible in the short-term incentive plan plus the 2016 actual incentive paid in 2017 of our employees as reflected in our payroll records for 2017. We identified our median employee using this compensation measure, which was consistently applied to all our employees included in the calculation. Since all our employees are located in the United States, as is our CEO, we did 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 such employee’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 Summary Compensation Table above.

(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.

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•	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.

(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 the general partner of DCP Midstream GP, LP, and therefore may be deemed to indirectly beneficially own such securities, but disclaims beneficial ownership 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 address of 100 West Lancaster Avenue, Suite 200, Wayne, Pennsylvania 19087. The Schedule 13G reports that HFA and Mr. Conklin, as the managing partner and 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 1290 Broadway, Suite 1100, Denver, Colorado 80203. The Schedule 13G/A reports that ALPS Advisors, Inc. (“AAI”), an investment adviser registered under the Investment Advisers Act of 1940, as amended, furnishes investment advice to investment companies registered under the Investment Company Act of 1940, as amended (collectively referred to as the “Funds”). In its role as investment advisor, AAI has voting and/or investment power over the registrant's common 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 is an investment company registered under the Investment Company Act of

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(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 our 2016 LTIP, refer to Note 15. "Equity-Based Compensation" in the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

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•	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 its affiliates;

•	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 that may be particularly favorable or advantageous to us.

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(a)

Audit Fees are fees billed by Deloitte for professional services for the audit of our consolidated financial statements included in our annual report on Form 10-K and review of financial statements included in our quarterly reports on Form 10-Q, services that are normally provided by Deloitte in connection with statutory and regulatory filings or engagements or any other service performed by Deloitte to comply with generally accepted auditing standards and include comfort and consent letters in connection with SEC filings and financing transactions.

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•	Asset retirement obligations

•	Depreciable asset lives

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•	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 that demonstrates 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.

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•	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 that demonstrates 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.

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