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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;

•	volatility in the price of our common units;

•	our ability to hire, train, and retain qualified personnel and key management to execute our business strategy;

•	general economic, market and business conditions;

•	our ability to continue the safe and reliable operation of our assets;

•	our ability to grow through organic growth projects, or acquisitions, and the successful integration and future performance of such assets;

•	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 credit agreement and the indentures governing our notes, as well as our ability to maintain our credit ratings;

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new, additions to, and changes in, laws and regulations, particularly with regard to taxes, safety 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, and their impact on producers and customers served by our systems;

•	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 and changes in competition;

•	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;

•	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 military campaigns, terrorist attacks, and cybersecurity breaches, against, or otherwise impacting, our facilities and systems;

•	our ability to purchase propane from our suppliers and make associated profitable sales transactions for our wholesale propane logistics business;

•	our ability to obtain insurance on commercially reasonable terms, if at all, as well as the adequacy of insurance to cover our losses; and

•	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 and 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.

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•	gathering, compressing, treating, processing natural gas and producing and fractionating NGLs; and

•	logistics and marketing, from which we generate revenues primarily by trading, transporting, storing and marketing natural gas and NGLs, fractionating NGLs, and recovering and selling condensate.

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•	A significant portion of our income is generated from fee-based contracts.

•	We have negotiated terms in our percent-of-proceeds and keep-whole contracts that provide us with downside protection. These terms include volume tiers, pricing floors and provisions that reduce the likelihood that we would be required to operate at an economic loss.

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We have a hedging program where we enter into derivative financial instruments to mitigate a portion of the risk of weakened natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. The commodity derivative instruments used for our hedging program are a combination of direct NGL product, crude oil, and natural gas hedges.

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(a)	Represents total capacity or total volumes allocated to our proportionate ownership share for 2016 divided by 365 days.

(b)	Represents an asset operated by a third party.

(c)	Represents NGL extraction plants and the associated processing capacity.

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(a)	Represents total capacity or throughput allocated to our proportionate ownership share for 2016 divided by 365 days.

(b)	Represents an asset operated by a third party.

(c)	Includes our 100% interest in Seabreeze, Wilbreeze and other NGL pipelines.

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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 to conduct regulated activities and imposing obligations in those permits that reduce or limit impacts to the environment;

•	restricting the way we can handle or dispose of our wastes;

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•	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 permits issued pursuant to such environmental laws and regulations.

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•	the level of domestic and offshore production;

•	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 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

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•	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;

•	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.

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•	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, NGLs and propane;

•	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, and the volume of propane we 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 processing, fractionation or other facilities 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, NGLs and propane;

•	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 otherwise reduce cash available for distribution to us;

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•	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

•	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, propane, NGLs and other hydrocarbons from our pipelines, plants, terminals, or storage facilities, or losses of natural gas, propane 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, in resolving conflicts of interest;

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•	DCP Midstream, LLC and its affiliates, including Phillips 66 and Spectra Energy, 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;

•	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.

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•	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;

•	the amount of cash available for distribution on each unit may decrease;

•	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.

•	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

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•	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;

•	comply with applicable law, any of our debt instruments or other agreements; or

•	provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

•	plus, 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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(a)

Includes the effect of the following acquisitions prospectively from their respective dates of acquisition: (1) the remaining 49.9% interest in East Texas acquired from DCP Midstream, LLC in January 2012; (2) a 10% ownership interest in the Texas Express Pipeline acquired from Enterprise Products Partners, L.P. in April 2012; (3) a 12.5% interest in the Enterprise fractionator and a 20% interest in the Mont Belvieu 1 fractionator, acquired from DCP Midstream, LLC in July 2012; (4) the Crossroads processing plant and 50% interest in CrossPoint Pipeline, LLC, acquired from Penn Virginia Resource Partners, L.P. in July 2012; (5) the O'Connor plant acquired from DCP

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(b)

Includes the effect of the commodity derivative hedge instruments related to the Eagle Ford system, of which 33.33% was acquired from DCP Midstream, LLC in November 2012 and 46.67% was acquired in March 2013; the Goliad plant, of which 33.33% was acquired from DCP Midstream, LLC in December 2012 and 46.67% was acquired in March 2013 and the Southeast Texas storage business acquired from DCP Midstream, LLC in March 2012.

(c)

Prior to the acquisition of the remaining 49.9% limited liability company interest in East Texas in January 2012, we hedged our proportionate ownership of East Texas. Results shown include the unhedged portion of East Texas owned by DCP Midstream, LLC. Our consolidated results depict 66.67% unhedged through March 2012 corresponding with DCP Midstream, LLC’s ownership interest in Southeast Texas. Our consolidated results depict 100% of the Eagle Ford system unhedged through October 2012, and 66.67% from November 2012 through March 2013, and 20% from April 2013 through March 2014 corresponding with DCP Midstream, LLC’s ownership interest in the Eagle Ford system.

(d)	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.

(e)

Our consolidated financial statements include the historical assets, liabilities and results of operations of assets acquired from DCP Midstream, LLC, transactions between entities under common control, representing a change in reporting entity. Earnings for periods prior to these dropdowns are allocated to predecessor operations to derive net income allocable to limited partners. Accordingly, net income attributable to predecessor operations includes the remaining 66.67% interest in Southeast Texas and commodity derivative hedge instruments prior to the date of our acquisition from DCP Midstream, LLC in March 2012; the initial 33.33% interest in the Eagle Ford system prior to the date of our acquisition from DCP Midstream, LLC in November 2012; the additional 46.67% interest in the Eagle Ford system prior to the date of our acquisition from DCP Midstream, LLC in March 2013 and the Lucerne 1 plant prior to the date of our acquisition from DCP Midstream, LLC in March 2014.

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•	Our growing fee-based business represents a significant portion of our estimated margins.

•	We have positive operating cash flow from our well-positioned and diversified assets.

•	We have a well-defined and targeted hedging program.

•	We prudently manage our capital expenditures and focus on fee-based growth projects.

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

•	We believe we have access to sufficient capital.

•	The construction of a 200 MMcf/d cryogenic natural gas processing plant, Mewbourn 3 plant, located in the DJ Basin, which is expected to be in service in late 2018.

•	The Sand Hills pipeline mainline capacity expansion was placed into service during the second quarter of 2016. We are currently expanding the Sand Hills pipeline capacity to its full capacity of 365 MBbls/d, and the expansion is expected to be in service by the end of 2017.

•	On February 1, 2016, we began to participate in earnings for our 15% interest in the Panola intrastate NGL pipeline which completed an expansion in the third quarter of 2016.

•	In the first quarter of 2016, we completed construction on our Grand Parkway gathering system in the DJ Basin. We are currently expanding our Grand Parkway gathering system, and the expansion is expected to be in service by the end of 2018.

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Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced.

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Percent-of-proceeds/liquids arrangements - Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and condensate based on index prices from published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs and condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between the proceeds received and the amount remitted back to the producer. Under percent-of-liquids arrangements, we do not keep any amounts related to residue natural gas proceeds and only keep amounts related to the difference between the proceeds received and the amount remitted back to the producer related to NGLs and condensate. Certain of these arrangements may also result in the producer retaining title to all or a portion of the residue natural gas and/or the NGLs, in lieu of us returning sales proceeds to the producer. Additionally, these arrangements may include fee-based components. Our revenues under percent-of-proceeds arrangements relate directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly to the price of NGLs and condensate.

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(a)	Includes the results of our Lucerne 1 plant, retrospectively adjusted, which we acquired on March 28, 2014.

(b)	Operating revenues include the impact of commodity derivative activity.

(c)	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.

(d)	Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Segment gross margin for each segment consists of total operating revenues for that segment, including commodity derivative activity, less commodity purchases for that segment. Please read “Reconciliation of Non-GAAP Measures”.

(e)	For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the throughput volumes and NGL production.

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$349 million decrease for our Natural Gas Services segment primarily due to decreased commodity prices, lower gas and NGL sales volumes primarily related to our Eagle Ford and East Texas systems which impact both sales and purchases, lower prices and volumes at our natural gas storage and pipeline assets, unfavorable commodity derivative activity and the disposition of our Northern Louisiana system, partially offset by growth in our DJ Basin system; and

•	$54 million decrease for our Wholesale Propane Logistics segment primarily due to lower propane volumes and prices.

•	Purchases of natural gas and NGLs decreased $265 million in 2016 compared to 2015 as a result of decreased commodity prices and lower gas and NGL sales volumes, primarily related to our Eagle Ford and East Texas systems, and decreased volumes at our natural gas storage and pipeline assets, which impact both sales and purchases; and

•	Purchases of propane decreased in 2016 compared to 2015 primarily due to decreased volumes as discussed below under the heading "Propane Sales Volumes" and lower propane prices which impact both sales and purchases.

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•	$84 million decrease for our Natural Gas Services segment primarily related to unfavorable commodity derivative activity, lower commodity prices, and lower gas and NGL volumes on our Eagle Ford and East Texas systems and the disposition of our Northern Louisiana system, partially offset by growth in our DJ Basin system related to Lucerne 2 being placed into service mid-2015; and

•	$22 million decrease for our Wholesale Propane Logistics segment primarily due to lower prices and volumes as discussed below under the heading "Propane Sales Volumes" and a partial recovery of lower of cost or market inventory adjustments during the first quarter of 2015.

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$1,545 million decrease for our Natural Gas Services segment primarily due to decreased commodity prices, lower NGL sales volumes which impact both sales and purchases, lower volumes at our natural gas storage and pipeline assets at the Southeast Texas system, unfavorable commodity derivative activity, a change in the contract structure at our Lucerne 1 plant and a favorable contractual producer settlement in 2014, partially offset by growth in our DJ Basin system; and

•	$206 million decrease for our Wholesale Propane Logistics segment primarily due to lower propane prices and volumes, partially offset by the conversion of one of our assets to a butane export facility.

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$241 million decrease for our Natural Gas Services segment primarily related to lower commodity prices, unfavorable commodity derivative activity, lower volumes on our Eagle Ford system, lower volume and unit margins on our storage assets, a favorable contractual producer settlement in 2014; partially offset by higher valued product and contract mix, growth in our DJ Basin system and a decrease in non-cash lower of cost or market inventory adjustments.

•	$39 million increase for our Wholesale Propane Logistics segment primarily due to a partial recovery of non-cash lower of cost or market inventory adjustments recognized in the fourth quarter of 2014, higher unit margins, the conversion of one of our assets to a butane export facility, partially offset by a decrease in volumes as discussed below under the heading "Propane Sales Volumes".

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(a)	Includes the results of our Lucerne 1 plant, retrospectively adjusted, which we acquired on March 28, 2014.

(b)	For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the earnings of all unconsolidated affiliates which include 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.

(c)	Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas and NGLs. 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 throughput volumes and NGL production.

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•	$171 million decrease attributable to lower gas and NGL sales volumes, primarily related to production declines in our Eagle Ford and East Texas systems, which impacted both sales and purchases;

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$104 million decrease as a result of commodity derivative activity attributable to an $129 million decrease in realized cash settlement gains in 2016, partially offset by a decrease in unrealized commodity derivative losses of $25 million due to movements in forward prices of commodities. Both cash settlements gains and unrealized commodity derivative losses were significantly impacted by the expiration of a substantial portion of our direct commodity hedges at the end of the first quarter of 2016;

•	$59 million decrease attributable to decreased commodity prices, which impacted both sales and purchases, before the impact of commodity derivative activity;

•	$32 million decrease related to the disposition of our Northern Louisiana system;

•	$18 million decrease attributable to decreased prices related to our natural gas storage and pipeline assets at our Southeast Texas system and Northern Louisiana system prior to its disposition on July 1, 2016; and

•	$14 million decrease attributable to decreased volumes related to our natural gas storage and pipeline assets at our Southeast Texas system, partially offset by increased volumes at our Northern Louisiana system prior to the disposition on July 1, 2016, which impacted both purchases and sales.

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$49 million increase in Transportation, processing and other, comprised of a $58 million increase primarily in our DJ Basin system related to Lucerne 2 being placed into service in mid-2015 and Grand Parkway placed into service in January 2016, partially offset by a $9 million decrease primarily related to lower volumes on our East Texas and Eagle Ford systems and the disposal of our Northern Louisiana system.

•	$104 million decrease as a result of commodity derivative activity as discussed above;

•	$25 million decrease as a result of lower gas and NGL volumes primarily related to our Eagle Ford, East Texas and Southeast Texas systems;

•	$14 million decrease as a result of the disposition of our Northern Louisiana system; and

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•	$13 million decrease as a result of lower commodity prices.

•	$58 million increase primarily as a result of higher fee revenue in our DJ Basin system related to Lucerne 2 being placed into service in mid-2015, and Grand Parkway placed into service in January 2016; and

•	$14 million increase primarily related to commercial activities at our Southeast Texas natural gas storage asset.

•	$822 million decrease attributable to decreased commodity prices, which impact both sales and purchases, before the impact of commodity derivative activity;

•	$481 million decrease primarily attributable to lower NGL sales volumes, which impact both sales and purchases, including the effects of contractual changes, higher ethane rejection and a third party outage;

•	$110 million decrease attributable to decreased prices related to our natural gas storage and pipeline assets at our Southeast Texas and Northern Louisiana systems;

•	$72 million decrease attributable to decreased volumes related to our natural gas storage and pipeline assets at our Southeast Texas system which impacts both purchases and sales;

•	$72 million decrease as a result of commodity derivative activity attributable to a $150 million increase in realized cash settlement gains in 2015, partially offset by an increase in unrealized commodity derivative losses of $222 million due to movements in forward prices of commodities;

•	$21 million decrease attributable to a change in the contract structure at our Lucerne 1 plant whereby revenues changed from a gross presentation to a net fee presentation; and

•	$14 million decrease due to a favorable contractual producer settlement in 2014.

•	$24 million increase attributable to growth in our DJ Basin system; and

•	$23 million attributable to increased volumes at our natural gas storage and pipeline assets related to our Northern Louisiana system, which impacts both purchases and sales.

•	$147 million decrease as a result of lower commodity prices;

•	$72 million decrease as a result of commodity derivative activity as discussed above;

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•	$30 million decrease attributable to lower volumes on our Eagle Ford system;

•	$21 million decrease attributable to lower volume and unit margins on our natural gas storage assets; and

•	$14 million decrease as a result of a favorable contractual producer settlement in 2014;

•	$21 million increase as a result of higher valued product and contract mix;

•	$17 million increase as a result of growth in our DJ Basin system which includes the ramp-up of our Lucerne 2 plant which commenced operations in June 2015; and

•	$5 million increase related to a decrease in non-cash lower of cost or market inventory adjustments.

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(a)

For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the earnings of all unconsolidated affiliates which include our 33.33% ownership in each of the Sand Hills and Southern Hills pipelines, 33.33% ownership of the Front Range pipeline, 20% ownership of the Mont Belvieu 1 fractionator, 15% interest in the Panola intrastate pipeline, 12.5% ownership of the Mont Belvieu Enterprise fractionator and 10% ownership of the Texas Express pipeline. Earnings 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)	For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the throughput volumes of unconsolidated affiliates.

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(a)	Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of propane. Please read “Reconciliation of Non-GAAP Measures”.

•	$32 million decrease attributable to decreased volumes as discussed below under the heading "Propane Sales Volumes";

•	$21 million decrease attributable to lower propane prices which impacted both sales and purchases; and

•	$1 million decrease as a result of commodity derivative activity attributable to a decrease in unrealized commodity derivative gains of $3 million due to movements in forward prices of commodities, partially offset by a $2 million decrease in realized cash settlement losses in 2016.

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•	$164 million decrease attributable to lower propane prices which impact both sales and purchases; and

•	$54 million decrease attributable to decreased volumes as discussed below under the heading "Propane Sales Volumes".

•	$9 million increase attributable to the conversion of one of our assets to a butane export facility;

•	$3 million increase as a result of commodity derivative activity attributable to a $6 million increase in unrealized commodity derivative gains due to movements in forward prices of commodities, partially offset by an increase in cash settlement losses of $3 million.

•	cash generated from operations;

•	cash distributions from our unconsolidated affiliates;

•	borrowings under our Amended and Restated Credit Agreement;

•	debt offerings;

•	issuances of additional common units, including issuances we may make to DCP Midstream, LLC;

•	borrowings under term loans; and

•	letters of credit.

•	quarterly distributions to our unitholders and general partner;

•	payments to service our debt;

•	growth capital expenditures;

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•	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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•	$6 million increase in cash attributable to higher net income in 2014, after adjusting our net income for non-cash items.

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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 $80 million, $131 million, $118 million, and $543 million for less than one year, one to three years, three to five years, and thereafter, respectively.

(b)	Our operating lease obligations are contractual obligations and include railcar leases, which provide supply and storage infrastructure for our Wholesale Propane Logistics business and a firm transportation commitment within our Natural Gas Services business.

(c)

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 propane supply for our Wholesale Propane Logistics business and other items. 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, 2016. Purchase obligations exclude accounts payable, accrued interest payable and other current liabilities recognized in the consolidated balance sheets. Purchase obligations also exclude current and long-term unrealized losses on derivative instruments included in the consolidated balance sheet, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity. 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 from the table.

(d)

Other long-term liabilities include $28 million of asset retirement obligations of which an insignificant amount may be settled within the next five years, $5 million of gas purchase liability, $3 million of right of way liability and $1 million of environmental reserves recognized in the December 31, 2016 consolidated balance sheet. In addition, $6 million of deferred state income taxes were excluded from the table above 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)	Includes $3 million, $6 million and $11 million in the lower of cost or market adjustments for the years ended December 31, 2016, 2015 and 2014, respectively.

(b)	There were no lower of cost or market adjustments for the year ended December 31, 2016. Includes $2 million and $13 million in the lower of cost or market adjustments for the years ended December 31, 2015 and 2014, respectively.

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(a)	Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract.

(b)	NYMEX final settlement price for natural gas futures contracts.

(c)	The average monthly OPIS price for Mt. Belvieu TET/Non-TET.

(d)	Average Bbls/d per time period.

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(a)

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.

(b)	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.

(c)	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 gains and losses from commodity derivative activity during the current period.

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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.

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Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas; and fractionating, storing and transporting NGLs. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced.

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Percent-of-proceeds/liquids arrangements - Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and condensate based on published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and condensate, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs and condensate,

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•	Propane sales arrangements - Under propane sales arrangements, we generally purchase propane from natural gas processing plants and fractionation facilities, and crude oil refineries. We sell propane on a wholesale basis to propane distributors, who in turn resell to their customers. Our sales of propane are not contingent upon the resale of propane by propane distributors to their customers.

•	Persuasive evidence of an arrangement exists - Our customary practice is to enter into a written contract.

•	Delivery - Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.

•	The fee is fixed or determinable - We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.

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Collectability is reasonably assured - Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected.

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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 our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided.

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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.

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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/out of Level 3 for the years ended December 31, 2016 and 2015.

(b)	Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net.

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•	If we were to have an effective event of default under our Amended and Restated 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.

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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 Amended and Restated Credit Agreement. As of December 31, 2016, we were not a party to any agreements that would trigger the cross-default provisions.

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(a)	There is no cash collateral pledged or received against these positions.

(a)	Relates to Discovery, an unconsolidated affiliate.

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(a)	Relates to Discovery, an unconsolidated affiliate.

(b)	Included in interest expense in our consolidated statements of operations.

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•	less the amount of cash reserves established by the general partner to:

•	provide funds for distributions to the 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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•	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;

•	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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(a)

Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. 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 cash flow 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)	The segment information for the year ended December 31, 2014 includes the results of our Lucerne 1 plant. This transfer of net assets between entities under common control was accounted for as if the transfer occurred at the beginning of the period to furnish comparative information, similar to the pooling method.

(d)	Other long-term assets not allocable to segments consist of unrealized gains on derivative instruments, corporate leasehold improvements and other long-term assets.

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(e)	Represents intersegment revenues consisting of sales of NGLs in our NGL Logistics segment to our Wholesale Propane segment.

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•	reviewed and discussed the audited financial statements in this Annual Report on Form 10-K with management, 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, our independent auditors, who are responsible for expressing an opinion on the conformity of those 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 generally accepted auditing standards;

•	received the written disclosures and the letter required by standard No. 1 of the independence standards board (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, 2016, for filing with the SEC; and

•	approved the selection and appointment of Deloitte & Touche LLP to serve as our independent auditors.

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•	annually review the Partnership’s and DCP Midstream, LLC’s (hereinafter, the “DCP Enterprise”) goals and objectives relevant to compensation of the NEOs;

•	annually evaluate the NEO’s performance in light of the DCP Enterprise’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 DCP Enterprise’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 non-employee director and NEO compensation; and

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

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•	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;

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

•	reward individual performance.

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1.

Cash Generation. An objective intended to capture the cash generated from operations for DCP Midstream, LLC, the owner of our General Partner and, prior to the Transaction, the operator of our assets, which consolidates the cash generated by the assets of the Partnership. For this objective, the target level of performance is cash generated of $605 million, the maximum level of performance is $775 million and the minimum level of performance is $450 million.

2.	EBIT ROCE. An objective intended to capture the constant price EBIT (earnings before interest and taxes) ROCE (return on capital employed) of DCP Midstream, LLC. For this objective, the target level of performance is EBIT ROCE of 2.8%, the maximum level of performance is 4.0% and the minimum level of performance is 1.1%.

3.	Cost. An objective intended to capture the operating and general and administrative costs of DCP Midstream, LLC. For this objective, the target level of performance is cost of $990 million, the maximum level of performance is cost of $960 million and the minimum level of performance is $1,045 million.

4.	Reliability. Operating objectives of reliable operation of mechanical and system processes, equipment analysis and preventive maintenance schedules for engines, compressors and turbines covering the assets of the DCP Enterprise. For these objectives, we have established the minimum, target and maximum levels of performance.

5.	Capacity Utilization. An operating objective of volume per compressor for the assets of the DCP Enterprise. For this objective, we have established the minimum, target and maximum level of performance.

6.	Contract Realignment. A commercial objective intended to capture the additional margin from contracting activities for the DCP Enterprise. For this objective we have established the minimum, target and maximum levels of performance.

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7.	Total Recordable Injury Rate (TRIR). A safety objective of both employee and contractor injury rates covering the assets of the DCP Enterprise. For this objective, the target level of performance during the year is a TRIR of 0.51, the maximum level of performance is a TRIR of 0.35 and a minimum level of performance is a TRIR of 0.90.

8.	Process Safety Event Rate (PSE Rate). A safety objective using a broad definition of process safety events covering the assets of the DCP Enterprise. For this objective, the target level of performance during the year is a PSE Rate of 4.32, the maximum level of performance is a PSE Rate of 3.2 and a minimum level of performance is a PSE Rate of 7.

9.	Emissions. An environmental objective of non-routine air emissions, natural gas vented or flared, covering the assets of the DCP Enterprise. For this objective, we have established certain levels of emissions at such assets that comprise the minimum, target and maximum level of performance for this objective.

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(a)	Includes all awards that vested during the year, regardless of whether the awards will be settled in our common units, Phillips 66 common stock, Spectra Energy common stock or cash.

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(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 is the audit committee chair.

(c)	Mr. Waycaster is the special committee chair.

•	each person known by us to be the beneficial owner of more than 5% of our 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.

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(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 the general partner of DCP Midstream GP, LP and 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/A filed with the SEC on February 13, 2017 by Advisory Research, Inc. with an address of 180 North Stetson Avenue, Suite 5500, Chicago, Illinois 60601 and Piper Jaffray Companies with an address of 800 Nicollet Mall, Suite 800, Minneapolis, Minnesota 55402. The Schedule 13G/A reports that Advisory Research, Inc. has sole voting power over 8,922,931 of the reported units and sole dispositive power over all of the reported units and Piper Jaffray Companies has shared voting power over 8,922,931 of the reported units and shared dispositive power over all of the reported units.

(d)

As reported on Schedule 13G/A filed with the SEC on January 25, 2017 by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne each having an address of 1800 Avenue of the Stars, Third Floor, Los Angeles, California 90067. The Schedule 13G/A reports that Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne each have shared voting power and shared dispositive power over all of the reported units.

(e)	As reported on Schedule 13G filed with the SEC on February 9, 2017 by OppenheimerFunds, Inc. having an address of 225 Liberty Street, New York, New York 10281. The Schedule 13G reports that OppenheimerFunds, Inc. has shared voting and dispositive power over all of the reported units.

(1)

The information disclosed in this row relates to our 2016 LTIP, which was approved by unitholders at a special meeting on April 28, 2016. The 2016 LTIP makes 900,000 common units available for issuance with respect to awards under the 2016 Plan. 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.”

(2)

The information disclosed in this row relates to our 2005 LTIP, which expired pursuant to its terms at the end of 2015, and therefore no equity securities remain available for issuance other than 940 phantom units that were granted in 2014 and vested on December 31, 2016. No value is shown in column (b) because the phantom units do not have an exercise price and represent the right to receive either cash or common units upon settlement at the discretion of the Board. For more information on our 2005 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 Securities and Exchange Commission filings and financing transactions.

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•	Asset retirement obligations

•	Depreciable asset lives

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•	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); and

•	Storage expense under a 20-year agreement to store parts, tools and equipment in a warehouse owned by Williams PERK, LLC (an affiliate of WFS) through 2033.

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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.

•	Persuasive evidence of an arrangement exists - Our customary practice is to enter into a written contract.

•	Delivery - Delivery is deemed to have occurred when the services are rendered.

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•	The fee is fixed or determinable - We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable.

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Collectability is reasonably assured - Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected.

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#	Pursuant to Item 601(b)(2) of Regulation S-K, the Partnership agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.

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#	Pursuant to Item 601(b)(2) of Regulation S-K, the Partnership agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.