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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;

•	general economic, market and business conditions;

•	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;

•	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;

•	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 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;

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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;

•	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 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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(a)	Represents total NGL capacity or throughput allocated to our proportionate ownership share for 2017 divided by 365 days.

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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 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 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;

•	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.

•	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;

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•	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;

•	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;

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•	fires and explosions; and

•	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

•	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;

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•	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;

•	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;

•	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, including a relative dilution of any voting rights;

•	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.

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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 7.375% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual 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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(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.

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(b)	Includes net (loss) income attributable to the DCP Midstream Business prior to the date of our acquisition from DCP Midstream, LLC. For additional details, please read Footnote 1 in Item 8. "Financial Statements" in this Annual Report on Form 10-K.

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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.

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•	Within our Gathering and Processing segment, we increased capacity in the DJ Basin by up to 40 MMcf/d starting in June 2017 by placing additional field compression and plant bypass infrastructure in service.

•	We are constructing a 200 MMcf/d natural gas processing plant, the Mewbourn 3 plant, and further expanding our Grand Parkway gathering system, both of which are located in the DJ Basin and expected to be in service in the third quarter of 2018.

•	Our 200 MMcf/d O'Connor 2 plant and associated gathering infrastructure, located in the DJ Basin, is also approved and expected to be in service in 2019. Engineering and permitting are underway, and we have begun purchasing equipment for the construction of the plant.

•	Within our Logistics and Marketing segment, we have completed the expansion of the Sand Hills pipeline to 365 MBbls/d.

•	Further Sand Hills pipeline expansion to 450 MBbls/d is progressing and includes a partial looping of the pipeline and the addition of new pump stations, and is expected to be in service in the second half of 2018.

•	We executed definitive joint venture agreements on our 25% interest in the joint development of the Gulf Coast Express pipeline project, or the "GCX project". The approximately $1.75 billion GCX project is designed to transport up to 1.98 Bcf/d of natural gas. The gas takeaway pipeline is expected to be in service in 2019, pending regulatory approvals.

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We are jointly developing the Cheyenne Connector pipeline (“Cheyenne Connector”) with Tallgrass Energy Partners, LP (operator), and Western Gas Partners, LP and hold an option to invest in this project at a later date. Cheyenne Connector will provide gas takeaway for the DJ Basin, connecting to the Rockies Express Pipeline's Cheyenne Hub where it can then be delivered to numerous demand markets across the country. It will have an initial capacity of at least 600 MMcf/day and is expected to be in service in the second half of 2019, subject to certain conditions, including required approvals from the Federal Energy Regulatory Commission.

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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.

•	$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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$420 million decrease for our Gathering and Processing segment primarily due to lower commodity prices, lower gas and NGL volumes in the South, Midcontinent and Permian regions which impacted both sales and purchases, and unfavorable commodity derivative activity, which was partially offset by higher gas and NGL volumes in our North region and fee based contract realignment efforts; and improved operational efficiencies in the Permian and Midcontinent regions; and

•	$301 million decrease for our Logistics and Marketing segment primarily due to lower commodity prices, lower gas and NGL sales volumes, unfavorable commodity derivative activity and lower wholesale propane fees partially offset by new connections on certain of our NGL pipelines.

•	$184 million decrease in inter-segment eliminations, which related to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to lower commodity prices and lower gas and NGL sales volumes.

•	$434 million decrease for our Gathering and Processing segment for the reasons discussed above; and

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•	$270 million decrease for our Logistics and Marketing segment for the reasons discussed above.

•	$184 million decrease in inter-segment eliminations, which related to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to lower commodity prices and lower gas and NGL sales volumes.

•	$31 million decrease for our Logistics and Marketing segment primarily related to unfavorable commodity derivative activity, the sale of our Northern Louisiana system in July 2016 and lower wholesale propane fees, partially offset by new connections on certain of our NGL pipelines.

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$14 million increase for our Gathering and Processing segment primarily due to the ramp-up of the Lucerne 2 plant in June 2015, completion of the Grand Parkway gathering system in January 2016, higher margins on a specific producer arrangement, higher NGL recoveries in our North region, completion of the Zia II plant in August 2015 in our Permian region, ramp-up of the National Helium plant in September 2015 in our Midcontinent region, fee based contract realignment efforts and improved operational efficiencies in our Permian and Midcontinent regions, partially offset by lower commodity prices, lower volumes across our South, Midcontinent and Permian regions due to reduced drilling activity in prior periods, unfavorable derivative activity and the sale of our Northern Louisiana system.

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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.

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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;

•	$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

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•	$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.

•	$163 million decrease attributable to lower commodity prices, which impacted both sales and purchases, before the impact of derivative activity;

•	$444 million decrease attributable to lower volumes across our South, Midcontinent and Permian regions due to reduced drilling activity in prior periods, partially offset by improved operational efficiencies in the Permian and Midcontinent regions; and

•	$113 million decrease as a result of commodity derivative activity attributable to an increase in unrealized commodity derivative losses of $166 million in 2016 which were partially offset by a $53 million increase in realized cash settlement gains due to movements in forward prices of commodities.

•	$185 million increase attributable to higher gas and NGL sales volumes and the impact of a specific producer arrangement primarily related to our DJ Basin system in our North region;

•	$115 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.

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•	$76 million increase primarily as a result of higher volumes following the ramp-up of the Lucerne 2 plant, completion of the Grand Parkway gathering system in January 2016, higher margins on specific producer arrangements and higher NGL recoveries primarily related to our DJ Basin system in our North region;

•	$77 million increase primarily as a result of the completion of the Zia II plant in the Southeast New Mexico system in our Permian region in August 2015, ramp-up of the National Helium plant in the Liberal system in our Midcontinent region in September 2015 and improved operational efficiencies in the Permian and Midcontinent regions; and

•	$12 million increase primarily as a result of fee based contract realignment efforts in the Permian and Midcontinent regions, partially offset by lower volumes across our South, Midcontinent and Permian regions due to reduced drilling activity in prior periods.

•	$113 million decrease as a result of commodity derivative activity as discussed above;

•	$30 million decrease as a result of lower commodity prices; and

•	$8 million decrease as a result of the sale of our Northern Louisiana system in our South Region.

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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.

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

•	$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.

•	$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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•	$250 million decrease attributable to lower commodity prices, which impacted both sales and purchases, before the impact of derivative activity;

•	$20 million decrease attributable to lower gas and NGL sales volumes, which impacted both sales and purchases

•	$29 million decrease as a result of commodity derivative activity attributable to a $10 million decrease in realized cash settlement gains in 2016 and an increase in unrealized commodity derivative losses of $19 million due to movements in forward prices of commodities; and

•	$2 million decrease primarily due to the sale of our Northern Louisiana system in July 2016 and lower wholesale propane fees partially offset by new connections on certain of our NGL pipelines.

•	$29 million decrease as a result of commodity derivative activity attributable to a $10 million decrease in realized cash settlement gains in 2016 and an increase in unrealized commodity derivative losses of $19 million due to movements in forward prices of commodities;

•	$2 million decrease primarily due to the sale of our Northern Louisiana system in July 2016 and lower wholesale propane fees, partially offset by new connections on certain of our NGL pipeline.

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•	cash generated from operations;

•	cash distributions from our unconsolidated affiliates;

•	borrowings under our Credit Agreement;

•	proceeds from asset rationalization;

•	reduction of incentive distribution right payments during 2018 and 2019;

•	debt offerings;

•	issuances of additional common units, preferred units or other securities;

•	borrowings under term loans; and

•	letters of credit.

•	quarterly distributions to our common unitholders and General Partner, and semi annual 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,

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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 $274 million, $453 million, $346 million, and $2,039 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, 2017. 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, 2017 consolidated balance sheet. The table above excludes non-cash obligations as well as $29 million of Executive Deferred Compensation Plan contributions and $14 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 lower of cost or market adjustments of $2 million, $3 million and $8 million for the years ended December 31, 2017, 2016 and 2015, 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)	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.

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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/index 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, 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/index arrangements relate directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements relate directly with the price of NGLs and condensate.

•

Keep-whole and wellhead purchase arrangements - Under the terms of a keep-whole processing contract, natural gas is gathered from the producer for processing, the NGLs and condensate are sold and the residue natural gas is returned to the producer with a British thermal unit, or Btu, content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under the terms of a wellhead purchase contract, we purchase natural gas from the producer at the wellhead or defined receipt point for processing and then market the resulting NGLs and residue gas at market prices. Under these types of contracts, we are exposed to the difference between the value of the NGLs extracted from processing and the value of the Btu equivalent of residue natural gas, or frac spread. We benefit in periods when NGL prices are higher relative to natural gas prices when that frac spread exceeds our operating costs.

•	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.

•	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

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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.

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•	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 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 years ended December 31, 2017 and 2016.

(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.

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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 Credit Agreement. As of December 31, 2017, 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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•	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 7.375% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual 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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•	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 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 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)	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;

•	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 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;

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•	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, 2017, for filing with the SEC; and

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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.

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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.	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, the level of performance is based on our annual budget.

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 $805 million to a maximum of $875 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 $940 million to a maximum of $890 million.

1.	Capacity Utilization. An objective intended to drive asset efficiency by measuring gas volume per compressor.

2.	Customer Gas Curtailed. An objective to measure the impact of reliability on customer volume with the intent to maximize our customers’ productivity.

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3.	DCP 2.0 EBITDA Contribution. An objective intended to capture the additional EBITDA from the DCP 2.0 innovation strategies.

1.	Total Recordable Injury Rate (TRIR). An objective of both employee and contractor injury rates covering the assets of the Partnership. For this objective, the maximum level of performance is a TRIR of 0.35 and the minimum level of performance is a TRIR of 0.75.

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 3.0 and a minimum level of performance is a PSE Ratio of 5.64.

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, 2017, 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.

2.	To identify the “median employee” 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.

3.	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.”

4.	Once we identified our median employee, we combined all of the elements of such employee’s total compensation for 2017.

5.	With respect to the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2017 Summary Compensation Table above.

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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 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 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 February 6, 2018 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 Advisors Act of 1940, furnishes investment advice to investment companies registered under the Investment Company Act of 1940 (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. The Funds have the right to receive or the power to direct the receipt of dividends from, or the proceeds from the sale of the common units held in their respective accounts. Alerian MLP ETF is an investment company registered under the Investment Company Act of 1940 and is one of the Funds to which AAI provides investment advice. The common units reported herein are owned by the Funds and AAI disclaims beneficial ownership of such common units.

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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.”

(2)	This information 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 thereunder. 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.

(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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•	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.

•	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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