DCP Midstream 8K Other Events | DCP-PC 25 May 17

Exhibit 99.3

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our consolidated financial statements and notes included elsewhere in this Form 8-K (and related exhibits).

Overview

We are a Delaware limited partnership formed by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. Concurrent with the completion of the Transaction in the first quarter of 2017 as defined below, management reevaluated our reportable segments and determined that our operations are organized into two reportable segments: (i) Gathering and Processing and (ii) Logistics and Marketing. Segment information for earlier periods has been retrospectively adjusted to reflect these reportable segments. Our Gathering and Processing reportable segment includes operating segments that have been aggregated based on the nature of the products and services provided. Our Gathering and Processing segment consists of gathering, compressing, treating, and processing natural gas, producing and fractionating NGLs, and recovering and selling condensate. Our Logistics and Marketing segment includes transporting, trading, marketing and storing natural gas and NGLs, fractionating NGLs and wholesale propane logistics. The remainder of our business operations is presented as "Other", and consists of unallocated corporate costs.

Our business is impacted by commodity prices and volumes. We mitigate a portion of commodity price risk on an overall partnership basis by growing our fee based assets and by executing on our hedging program, where we hedge commodity prices associated with a portion of our expected natural gas, NGL and condensate equity volumes in our Gathering and Processing segment. Various factors impact both commodity prices and volumes, and as indicated in Item 7A in our 2016 Form 10-K, "Quantitative and Qualitative Disclosures about Market Risk," we have sensitivities to certain cash and non-cash changes in commodity prices. If commodity prices weaken for a sustained period, our volumes may be impacted, particularly as producers are curtailing or redirecting drilling. Drilling activity levels vary by geographic area; we will continue to target our strategy in geographic areas where we expect producer drilling activity.

Our long-term view is that commodity prices will be at levels we believe will support growth in natural gas, condensate and NGL production. We believe future commodity prices will be influenced by the severity of winter and summer weather, the level of North American production and drilling activity by exploration and production companies and the balance of trade between imports and exports of liquid natural gas, NGLs and crude oil.

NGL prices are impacted by the demand from petrochemical and refining industries and export facilities. The petrochemical industry has been making significant investment in building and expanding facilities to convert chemical plants from a heavier oil-based feedstock to lighter NGL-based feedstocks, including ethane. This increased demand expected in the next year should provide support for the increasing supply of ethane. Prior to those facilities commencing operations, ethane prices could remain weak with supply in excess of demand. In addition, export facilities are being expanded and built, which provide support for the increasing supply of NGLs. Although there can be, and has been, volatility in NGL prices, longer term we believe there will be sufficient demand in NGLs to support increasing supply.

Although we have seen a number of bankruptcies by producers in recent years, we believe our contract structure with our producers protects us from a credit perspective since we generally hold the product, sell it and withhold our fees prior to remittance of payments to the producer. Our top 20 producers account for a majority of the total natural gas that we gather and process and of these top 20 producers, twelve are investment grade while the remainder are not investment grade.

In addition to the U.S. financial markets, many businesses and investors continue to monitor global economic conditions. Uncertainty abroad may contribute to volatility in domestic financial and commodity markets.

We believe we are positioned to withstand current and future commodity price volatility as a result of the following:


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

Increased activity levels in producing basins combined with access to capital markets at relatively low costs have historically enabled us to execute our growth strategy. Our targeted strategy may take numerous forms such as organic build opportunities within our footprint, joint venture opportunities, and acquisitions. Growth opportunities will be evaluated in cooperation with producers and customers based on the expected level of drilling activity in these geographic regions and the impacts of higher costs of capital.

Some of our growth projects include the following:


•	Within our Logistics and Marketing segment, the Sand Hills pipeline mainline capacity expansion was placed into service during the second quarter of 2016. We are currently further expanding the Sand Hills pipeline to 365 MBbls/d expected to be in service in the fourth quarter of 2017, and have multiple additional Sand Hills lateral connections in flight throughout 2017.


•	Within our Gathering and Processing segment, the construction of a 200 MMcf/d cryogenic natural gas processing plant, Mewbourn 3 plant, and further expansion of our Grand Parkway gathering system, both of which are located in the DJ Basin and expected to be in service in the fourth quarter of 2018.


•	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 and is included in our Logistics and Marketing segment.


•	In the first quarter of 2016, we completed construction on our Grand Parkway gathering system in the DJ Basin, which is in our Gathering and Processing segment.

As part of our ongoing effort to create efficiencies, reduce costs and transform our business, DCP Midstream, LLC, announced an approximate 10 percent headcount reduction in April 2016, which involved the elimination of certain operational and corporate positions. This has not impacted the operation of our assets.

On April 28, 2016, the unitholders of the Partnership approved the DCP Midstream Partners, LP 2016 Long-Term Incentive Plan (the “2016 LTIP”), which replaced the 2005 long-term incentive plan that expired pursuant to its terms at the end of 2015 (the “2005 LTIP”). Any outstanding awards under the 2005 plan will remain outstanding and settle according to the terms of such grant. The 2016 LTIP authorizes up to 900,000 common units to be available for issuance under awards to employees, officers, and non-employee directors of the General Partner and its affiliates. Awards under the 2016 LTIP may include unit options, phantom units, restricted units, distribution equivalent rights, unit bonuses, common unit awards, and performance awards. The 2016 LTIP will expire on the earlier of the date it is terminated by the board of directors of the General Partner or the date that all common units available under the plan have been paid or issued. We believe the 2016 LTIP is an important tool to attract and retain qualified individuals who are essential to the future success of the Partnership.

Recent Events

On May 17, 2017, we announced the planned divestiture of our Douglas gathering system in Wyoming, which includes approximately 1,500 miles of gathering lines for approximately $128 million, subject to customary closing adjustments. The transaction is expected to close on or before the end of the second quarter. The proceeds from this transaction will be used to fund our strategic organic growth projects around our premier footprint, such as potential expansions of the Sand Hills NGL pipeline in the Permian and additional processing capacity and gathering systems in the DJ Basin.

On April 25, 2017, we announced that the board of directors of the General Partner declared a quarterly distribution of $0.78 per unit. The distribution was paid on May 15, 2017 to unitholders of record on May 9, 2017.

On April 11, 2017, Kinder Morgan Texas Pipeline LLC, a subsidiary of Kinder Morgan, Inc., and DCP Midstream, LP announced they signed a non-binding letter of intent for the Partnership to participate in the development of the proposed Gulf Coast Express Pipeline Project, which will provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. The project is designed to transport up to 1,700,000 dekatherms per day (Dth/d) of natural gas through approximately 430 miles of 42-inch pipeline from the Waha, Texas area to Agua Dulce, Texas. The pipeline is expected to be in service in the second half of 2019, subject to shipper commitments.

In February 2017, we further amended our $1.25 billion senior unsecured revolving credit agreement that matures on May 1, 2019, or the Amended and Restated Credit Agreement, to increase the aggregate commitments under the unsecured revolving credit facility to approximately $1.4 billion. The Amended and Restated Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions.

On January 26, 2017, we announced that the board of directors of the General Partner declared a quarterly distribution of $0.78 per unit. The distribution was paid on February 14, 2017 to unitholders of record on February 7, 2017, except that the owners of the Partnership's General Partner received distributions on the units issued on January 1, 2017 beginning with the first quarter 2017 declared distribution.

On December 30, 2016, the Partnership entered into a Contribution Agreement with DCP Midstream, LLC and DCP Midstream Operating, LP (the "Operating Partnership"). On January 1, 2017, DCP Midstream, LLC contributed to us: (i) its ownership interests in all of its subsidiaries owning operating assets, and (ii) $424 million of cash. In consideration of the Partnership’s receipt of the Contributions, (i) the Partnership issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to DCP Midstream GP, LP, the General Partner, in a private placement and (ii) the Operating Partnership assumed $3,150 million of DCP Midstream, LLC’s debt. The transactions and documents contemplated by the Contribution Agreement are collectively referred to as the "Transaction".

General Trends and Outlook

During 2017, our strategic objectives will continue to focus on maintaining stable Distributable Cash Flows from our existing assets and executing on opportunities to sustain our long-term Distributable Cash Flows in light of the significant changes to our business resulting from the Transaction. We believe the key elements to stable Distributable Cash Flows are the diversity of our asset portfolio, our fee-based business which represents a significant portion of our estimated margins, plus our hedged commodity position, the objective of which is to protect against downside risk in our Distributable Cash Flows.

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. Our 2017 plan includes maintenance capital expenditures of between $100 million and $145 million, and expansion capital expenditures between $325 million and $375 million associated with approved projects, for the year ending December 31, 2017. Expansion capital expenditures include the construction of the Mewbourn 3 plant and Grand Parkway Phase 2 in our DJ Basin system, and the capacity expansion of the Sand Hills pipeline, which is shown as an investment in unconsolidated affiliates in our consolidated statements of cash flows.

We anticipate our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Commodity Price Environment - Our business is impacted by commodity prices. If commodity prices weaken for a sustained period, our natural gas throughput and NGL volumes may be impacted, particularly as producers are curtailing or redirecting drilling. Drilling activity levels vary by geographic area; we have observed decreases in drilling activity in certain regions, and increases in drilling activity in others. The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by drilling activity, which may be impacted by prevailing commodity prices. Commodity prices have been lower compared to historical periods and experienced significant volatility during recent years, as illustrated in Item 1A. Risk Factors - “Our cash flow is affected by natural gas, NGL and condensate prices.” Despite recent short-term weakness, our long-term view is that commodity prices will be at levels that we believe will support continued growth in natural gas, condensate and NGL production.

Gathering and Processing Margins - Except for our fee-based contracts, which may be impacted by throughput volumes, our natural gas gathering and processing profitability is dependent upon commodity prices, natural gas supply, and demand for natural gas, NGLs and condensate. Commodity prices, which are impacted by the balance between supply and demand, have historically been volatile. Throughput volumes could further decline should commodity prices and drilling levels continue to experience weakness. Our long-term view is that as industry conditions improve, commodity prices should support continued natural gas production in the United States. During 2016, petrochemical demand remained stable for NGLs as NGLs were a competitive feedstock when compared to crude oil derived feedstocks. We anticipate demand for NGLs by the petrochemical industry will continue in 2017 as chemical plants convert facilities from an oil-based feedstock to a NGL-based feedstock and as export facilities are brought into service. Although there can be, and has been, near-term volatility in NGL prices, longer term we believe there will be sufficient demand in NGLs to balance supply.

Logistics and Marketing - The volumes of NGLs transported on our pipelines, fractionated in our fractionation facilities and stored in our storage facility are dependent on the level of production of NGLs from processing plants connected to our assets. When natural gas prices are high relative to NGL prices, it is less profitable to process natural gas because of the higher value of natural gas compared to the value of NGLs and because of the increased cost of separating the NGLs from the natural gas. As a result, we have experienced periods in the past, in which higher natural gas or lower NGL prices reduce the volume of NGLs extracted at plants connected to our NGL pipelines, fractionation and storage facilities and, in turn, lower the NGL throughput on our assets.

Factors That May Significantly Affect Our Results

Transfers of net assets between entities under common control that represent a change in reporting entity are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method. Accordingly, our consolidated financial statements have been adjusted to include the historical results of The DCP Midstream Business for all periods presented, similar to the pooling method. The financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity.

Gathering and Processing Segment

Our results of operations for our Gathering and Processing segment are impacted by (1) the prices of and relationship between commodities such as NGLs, crude oil and natural gas, (2) increases and decreases in the wellhead volume and quality of natural gas that we gather, (3) the associated Btu content of our system throughput and our related processing volumes, (4) the operating efficiency and reliability of our processing facilities, (5) potential limitations on throughput volumes arising from downstream and infrastructure capacity constraints, and (6) the terms of our processing contract arrangements with producers. This is not a complete list of factors that may impact our results of operations but, rather, are those we believe are most likely to impact those results.

Volume and operating efficiency generally are driven by wellhead production, plant recoveries, operating availability of our facilities, physical integrity and our competitive position on a regional basis, and more broadly by demand for natural gas, NGLs and condensate. Historical and current trends in the price changes of commodities may not be indicative of future trends. Volume and prices are also driven by demand and take-away capacity for residue natural gas and NGLs.

Our processing contract arrangements can have a significant impact on our profitability and cash flow. Our actual contract terms are based upon a variety of factors, including the commodity pricing environment at the time the contract is executed, natural gas quality, geographic location, customer requirements and competition from other midstream service providers. Our gathering and processing contract mix and, accordingly, our exposure to natural gas, NGL and condensate prices, may change as a result of producer preferences, impacting our expansion in regions where certain types of contracts are more common as well as other market factors.

Our Gathering and Processing segment operating results are impacted by market conditions causing variability in natural gas, crude oil and NGL prices. The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by drilling activity, which may be impacted by prevailing commodity prices. The number of active oil and gas drilling rigs in the United States has decreased, from 698 on December 31, 2015 to 563 on December 31, 2016 (Source: IHS). Although the prevailing price of residue natural gas has less short-term significance to our operating results than the price of NGLs, in the long-term, the growth and sustainability of our business depends on commodity prices being at levels sufficient to provide incentives and capital for producers to explore for and produce natural gas.

The prices of NGLs, crude oil and natural gas can be extremely volatile for periods of time, and may not always have a close relationship. Due to our hedging program, changes in the relationship of the price of NGLs and crude oil may cause our commodity price exposure to vary, which we have attempted to capture in our commodity price sensitivities in Item 7A in our 2016 Form 10-K, “Quantitative and Qualitative Disclosures about Market Risk.” Our results may also be impacted as a result of non-cash lower of cost or market inventory or imbalance adjustments, which occur when the market value of commodities decline below our carrying value.

We face strong competition in acquiring raw natural gas supplies. Our competitors in obtaining additional gas supplies and in gathering and processing raw natural gas includes major integrated oil and gas companies, interstate and intrastate pipelines, and companies that gather, compress, treat, process, transport, store and/or market natural gas. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices for crude oil, natural gas and/or NGLs. Competition is also increased in those geographic areas where our commercial contracts with our customers are shorter term and therefore must be renegotiated on a more frequent basis.

Logistics and Marketing Segment

Our Logistics and Marketing segment operating results are impacted by, among other things, the throughput volumes of the NGLs we transport on our NGL pipelines and the volumes of NGLs we fractionate and store. We transport, fractionate and store NGLs primarily on a fee basis. Throughput may be negatively impacted as a result of our customers operating their processing plants in ethane rejection mode, often as a result of low ethane prices relative to natural gas prices. Factors that impact the supply and demand of NGLs, as described above in our Gathering and Processing segment, may also impact the throughput and volume for our Logistics and Marketing segment.

Our results of operations for our Logistics and Marketing segment are also impacted by increases and decreases in the volume, price and basis differentials of natural gas associated with our natural gas storage and pipeline assets, as well as our underlying derivatives associated with these assets.

Weather

The economic impact of severe weather may negatively affect the nation’s short-term energy supply and demand, and may result in commodity price volatility. Additionally, severe weather may restrict or prevent us from fully utilizing our assets, by damaging our assets, interrupting utilities, and through possible NGL and natural gas curtailments downstream of our facilities, which restricts our production. These impacts may linger past the time of the actual weather event. Although we carry insurance on the vast majority of our assets, insurance may be inadequate to cover our loss in some instances, and in certain circumstances we have been unable to obtain insurance on commercially reasonable terms, if at all.

Capital Markets

Volatility in the capital markets may impact our business in multiple ways, including limiting our producers’ ability to finance their drilling programs and operations and limiting our ability to support or fund our operations and growth. These events may impact our counterparties’ ability to perform under their credit or commercial obligations. Where possible, we have obtained additional collateral agreements, letters of credit from highly rated banks, or have managed credit lines to mitigate a portion of these risks.

Impact of Inflation

Inflation has been relatively low in the United States in recent years. However, the inflation rates impacting our business fluctuate throughout the broad economic and energy business cycles. Consequently, our costs for chemicals, utilities, materials and supplies, labor and major equipment purchases may increase during periods of general business inflation or periods of relatively high energy commodity prices.

Other

The above factors, including sustained deterioration in commodity prices and volumes, other market declines or a decline in our unit price, may negatively impact our results of operations, and may increase the likelihood of a non-cash impairment charge or non-cash lower of cost or market inventory adjustments.

Our Operations

We manage our business and analyze and report our results of operations on a segment basis. Our operations are organized into two reportable segments: (i) Gathering and Processing and (ii) Logistics and Marketing.

Gathering and Processing Segment

Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, transported, stored and sold through our gathering, processing and pipeline systems; the volumes of NGLs and condensate sold; and the level of our realized natural gas, NGL and condensate prices. We generate our revenues and our gross margin for our Gathering and Processing segment principally from contracts that contain a combination of the following arrangements:

•

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.

•

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.

The natural gas supply for our gathering pipelines and processing plants is derived primarily from production areas located in Alabama, Colorado, Kansas, Louisiana, Michigan, New Mexico, Oklahoma, Texas, Wyoming and the Gulf of Mexico. We identify primary suppliers as those individually representing 10% or more of our total natural gas supply. We had no supplier of natural gas representing 10% or more of our total natural gas supply during the year ended December 31, 2016. We actively seek new supplies of natural gas, both to offset natural declines in the production from connected wells and to increase throughput volume. We obtain new natural gas supplies in our operating areas by contracting for production from new wells, connecting new wells drilled on dedicated acreage, or by obtaining natural gas that has been directly received or released from other gathering systems.

We sell natural gas to marketing affiliates of natural gas pipelines, integrated oil companies, national wholesale marketers, industrial end-users and gas-fired power plants. We typically sell natural gas under market index related pricing terms. The NGLs extracted from the natural gas at our processing plants are sold at market index prices to third parties.

We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. As a service to our customers, we may enter into physical fixed price natural gas purchases and sales, utilizing financial derivatives to swap this fixed price risk back to market index.

Logistics and Marketing Segment

We market our NGLs and residue gas and provide logistics and marketing services to third-party NGL producers and sales customers in significant NGL production and market centers in the United States. This includes purchasing NGLs on behalf of third-party NGL producers for shipment on our NGL pipelines and resale in key markets.

Our NGL services include plant tailgate purchases, transportation, fractionation, flexible pricing options, price risk management and product-in-kind agreements. Our primary NGL operations are generally connected to and supplied in part by our Gathering and Processing operations in each of the operating regions.

Our pipelines, fractionation facilities and storage facility provide transportation, fractionation and storage services for customers, primarily on a fee basis. We have entered into contractual arrangements that generally require customers to pay us to transport or store NGLs pursuant to a fee-based rate that is applied to volumes. These contractual arrangements may require our customers to commit a minimum level of volumes to our pipelines and facilities, thereby mitigating our exposure to volume risk. However, the results of operations for this business segment are generally dependent upon the volume of product transported, fractionated or stored and the level of fees charged to customers. We do not take title to the products transported on our NGL pipelines, fractionated in our fractionation facilities or stored in our storage facility; rather, the customer retains title and the associated commodity price risk. The volumes of NGLs transported on our pipelines are dependent on the level of production of NGLs from processing plants connected to our NGL pipelines. When natural gas prices are high relative to NGL prices, it is less profitable to process natural gas because of the higher value of natural gas compared to the value of NGLs and because of the increased cost of separating the NGLs from the natural gas. As a result, we have experienced periods in the past, in which higher natural gas or lower NGL prices reduce the volume of NGLs extracted at plants connected to our NGL pipelines and, in turn, lower the NGL throughput on our assets. Our storage facility in Marysville, Michigan provides storage and related services primarily to regional refining and petrochemical companies and NGL marketers operating in the liquid hydrocarbons industry.

We manage our wholesale propane margins by selling propane to propane distributors under annual sales agreements negotiated each spring which specify floating price terms that provide us a margin in excess of our floating index-based supply costs under our supply purchase arrangements. Our portfolio of multiple supply sources and storage capabilities allows us to actively manage our propane supply purchases and to lower the aggregate cost of supplies. Based on the carrying value of our inventory, timing of inventory transactions and the volatility of the market value of propane, we have historically and may continue to periodically recognize non-cash lower of cost or market inventory adjustments. In addition, we may use financial derivatives to manage the value of our propane inventories.

We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads. A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage.

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (1) volumes; (2) gross margin and segment gross margin; (3) operating and maintenance expense, and general and administrative expense; (4) adjusted EBITDA; (5) adjusted segment EBITDA; and (6) Distributable Cash Flow. Gross margin, segment gross margin, adjusted EBITDA, adjusted segment EBITDA, and Distributable Cash Flow are not measures under accounting principles generally accepted in the United States of America, or GAAP. To the extent permitted, we present certain non-GAAP measures and reconciliations of those measures to their most directly comparable financial measures as calculated and presented in accordance with GAAP. These non-GAAP measures may not be comparable to a similarly titled measure of another company because other entities may not calculate these non-GAAP measures in the same manner.

Volumes - We view wellhead, throughput and storage volumes for our Gathering and Processing segment and our Logistics and Marketing segment as important factors affecting our profitability. We gather and transport some of the natural gas and NGLs under fee-based transportation contracts. Revenue from these contracts is derived by applying the rates stipulated to the volumes transported. Pipeline throughput volumes from existing wells connected to our pipelines will naturally decline over time as wells deplete. Accordingly, to maintain or to increase throughput levels on these pipelines and the utilization rate of our natural gas processing plants, we must continually obtain new supplies of natural gas and NGLs. Our ability to maintain existing supplies of natural gas and NGLs and obtain new supplies are impacted by: (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines; and (2) our ability to compete for volumes from successful new wells in other areas. The throughput volumes of NGLs and gas on our pipelines are substantially dependent upon the quantities of NGLs and gas produced at our processing plants, as well as NGLs and gas produced at other processing plants that have pipeline connections with our NGL and gas pipelines. We regularly monitor producer activity in the areas we serve and in which our pipelines are located, and pursue opportunities to connect new supply to these pipelines. We also monitor our inventory in our NGL and gas storage facilities, as well as overall demand for storage based on seasonal patterns and other market factors such as weather and overall demand.

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the years ended December 31, 2016, 2015 and 2014. The results of operations by segment are discussed in further detail following this consolidated overview discussion.



	Year Ended December 31,									Variance 2016 vs. 2015					Variance 2015 vs. 2014
	2016			2015			2014			Increase (Decrease)			Percent		Increase (Decrease)			Percent
	(Millions, except operating data and percentages)
Operating revenues (a):
Gathering and Processing	$	4,490		$	4,910		$	9,873		$	(420	)	(9	)%	$	(4,963	)	(50	)%
Logistics and Marketing	6,186			6,487			12,649			(301		)	(5	)%	(6,162		)	(49	)%
Intra-segment eliminations	(3,783		)	(3,967		)	(8,497		)	184			5	%	4,530			53	%
Total operating revenues	6,893			7,430			14,025			(537		)	(7	)%	(6,595		)	(47	)%
Purchases:
Gathering and Processing	(3,263		)	(3,697		)	(7,902		)	(434		)	(12	)%	(4,205		)	(53	)%
Logistics and Marketing	(5,981		)	(6,251		)	(12,423		)	(270		)	(4	)%	(6,172		)	(50	)%
Intra-segment eliminations	3,783			3,967			8,497			184			5	%	4,530			53	%
Total purchases	(5,461		)	(5,981		)	(11,828		)	(520		)	(9	)%	(5,847		)	(49	)%
Operating and maintenance expense	(670		)	(732		)	(773		)	(62		)	(8	)%	(41		)	(5	)%
Depreciation and amortization expense	(378		)	(377		)	(348		)	1			—	%	29			8	%
General and administrative expense	(292		)	(281		)	(277		)	11			4	%	4			1	%
Asset impairments	—			(912		)	(18		)	(912		)	(100	)%	894			*
Other income (expense), net	65			(10		)	(7		)	75			*		(3		)	(43	)%
Earnings from unconsolidated affiliates (b)	282			184			82			98			53	%	102			*
Interest expense	(321		)	(320		)	(287		)	1			—	%	33			11	%
Income tax (expense) benefit	(46		)	102			(11		)	(148		)	*		113			*
Gain (loss) on sale of assets, net	35			42			(7		)	(7		)	(17	)%	49			*
Restructuring costs	(13		)	(11		)	—			2			18	%	11			*
Net income attributable to non-controlling interests	(6		)	(5		)	(4		)	1			20	%	1			25	%
Net income (loss) attributable to partners	$	88		$	(871	)	$	547		$	959		*		$	(1,418	)	*
Other data:
Gross margin (c):
Gathering and Processing	$	1,227		$	1,213		$	1,971		$	14		1	%	$	(758	)	(38	)%
Logistics and Marketing	205			236			226			(31		)	(13	)%	10			4	%
Total gross margin	$	1,432		$	1,449		$	2,197		$	(17	)	(1	)%	$	(748	)	(34	)%
Non-cash commodity derivative mark-to-market	$	(139	)	$	46		$	43		$	(185	)	*		$	3		7	%
Natural gas wellhead (MMcf/d) (d)	5,124			5,604			5,896			(480		)	(9	)%	(292		)	(5	)%
NGL gross production (MBbls/d) (d)	393			408			454			(15		)	(4	)%	(46		)	(10	)%
NGL pipelines throughput (MBbls/d) (d)	420			298			224			122			41	%	74			33	%

_________________

* Percentage change is not meaningful.


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


(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, including commodity derivative activity, less purchases of natural gas 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”.


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

Year ended December 31, 2016 vs. Year ended December 31, 2015

Total Operating Revenues — Total operating revenues decreased $537 million in 2016 compared to 2015 primarily as a result of the following:

•

$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.

These decreases were partially offset by:


•	$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.

Total Purchases — Total purchases decreased $520 million in 2016 compared to 2015 primarily as a result of the following:


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


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

These decreases were partially offset by:


•	$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.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2016 compared to 2015 primarily as a result of our headcount reduction in April 2016, plant consolidations and other cost savings initiatives, the disposition of our Northern Louisiana system in July 2016, the sale of certain gas processing plants and gathering systems in the Permian region in 2015, partially offset by the completion of our Lucerne 2 plant in the DJ Basin system in July 2015 and the completion of our Zia II plant in the Southeast New Mexico system in August 2015.

General and Administrative Expense — General and administrative expense increased in 2016, compared to 2015, primarily due to nonrecurring costs driven by the closing of the Transaction as described in the recent events section, partially offset by our headcount reduction in April 2016 and other cost savings initiatives.

Asset Impairments - Asset impairments in 2015 represented impairments of goodwill, property, plant and equipment and intangible assets.

Other Income (Expense), net — Other income, net in 2016 represented a producer settlement net of legal fees, partially offset by charges for discontinued construction projects. Other expense, net in 2015 primarily represented charges for discontinued construction projects.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2016 compared to 2015, primarily as a result of Enbridge’s contribution of its interests in Sand Hills and Southern Hills in November 2015, higher pipeline throughput volumes on Southern Hills, Sand Hills and Front Range due to growth in NGL production from new plants placed into service in 2015 and as a result of the ramp-up of the Keathley Canyon volumes at Discovery.

Income Tax (Expense) Benefit — Income tax benefit decreased in 2016 compared to 2015 primarily due to impairments of property, plant and equipment and intangible assets recorded in the fourth quarter of 2015.

Gain (loss) on Sale of Assets, Net — Gain on sale of assets during 2016 primarily related to the sale of our Northern Louisiana system. During 2015, we recognized gains related to the sale of certain gas processing plants and gathering systems.

Net Income Attributable to Partners — Net income attributable to partners increased in 2016 compared to 2015 for the reasons discussed above.

Gross Margin — Gross margin decreased $17 million in 2016 compared to 2015 primarily as a result of the following:


•	$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.

These decreases were partially offset by:

•

$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.

Year Ended December 31, 2015 vs. Year Ended December 31, 2014

Total Operating Revenues — Total operating revenues decreased $6,595 million in 2015 compared to 2014 primarily as a result of the following:

•

$4,963 million decrease for our Gathering and Processing segment primarily due to lower commodity prices and lower gas and NGL volumes in the South, Midcontinent and Permian regions which impacted both sales and purchases, partially offset by higher gas and NGL volumes in our North region, favorable commodity derivative activity and fee based contract realignment efforts and the sale of certain gas processing plants and gathering systems in our Midcontinent and Permian regions, partially offset by the completion and ramp-up of the Lucerne 2 plant in June 2015, completion and ramp-up of the Zia II plant in August 2015 and ramp-up of the National Helium plant in September 2015; and


•	$6,162 million decrease for our Logistics and Marketing segment primarily due to lower commodity prices, lower gas and NGL sales volumes and unfavorable commodity derivative activity, partially offset by the conversion of one of our assets to a butane export facility and higher NGL storage margins.

These decreases were partially offset by:


•	$4,530 million increase in inter-segment eliminations, which relate to sales of 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.

Total Purchases — Total purchases decreased $5,847 million in 2015 compared to 2014 primarily as a result of the following:


•	$4,205 million decrease for our Gathering and Processing segment for the reasons discussed above; and


•	$6,172 million decrease for our Logistics and Marketing segment for the reasons discussed above.

These decreases were partially offset by:


•	$4,530 million decrease in inter-segment eliminations, which relate to sales of 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.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2015 compared 2014 primarily as a result of the sale of certain gas processing plants and gathering systems in the Permian region in 2015 and other cost savings initiatives. In addition, 2014 results included higher spending on reliability programs.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2015 compared to 2014 primarily as a result the completion of expansion projects including the Lucerne 2 plant in our DJ Basin system in our North Region and the completion of the Zia II plant in our Southeast New Mexico system in our Permian region, partially offset by the sale of certain gas processing plants and gathering systems in our Permian region.

Asset Impairments — Asset impairments in 2015 represented impairments of goodwill, property, plant and equipment and intangible assets. During the same period in 2014, asset impairments represented the impairment of goodwill.

Other Income (Expense), net — Other expense, net in 2015 and 2014 primarily represented discontinued construction projects.

Gain (loss) on Sale of Assets, net — Gain on sale of assets for the year ended December 31, 2015 primarily related to the sale of certain gas processing plants and gathering systems in our Midcontinent and Permian regions. During the same period in 2014, we recognized a loss related to the sale of an investment in an unconsolidated affiliate.

Earnings from Unconsolidated Affiliates — Equity in earnings of unconsolidated affiliates increased in 2015 compared to 2014, primarily attributable to the ramp-up of Sand Hills and Front Range, the completion of the Keathley Canyon project at Discovery in February 2015 and Enbridge's contribution of its interests in Sand Hills and Southern Hills in the fourth quarter of 2015.

Interest Expense, net — Interest expense increased in 2015 compared to 2014 as a result of higher average outstanding debt balances associated with the growth of our operations and lower capitalized interest.

Income Tax (Expense) Benefit — Income tax benefit (expense) increased in 2015 compared to 2014 primarily attributable to impairments of property, plant and equipment and intangible assets recorded in the fourth quarter of 2015.

Restructuring Costs — As part of our initial phase in our restructuring plan to reduce general and administrative and non-core operational costs, we recorded approximately $11 million in employee termination costs during 2015.

Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:

Earnings from investments in unconsolidated affiliates were as follows:



	Year Ended December 31,
	2016		2015		2014
	(Millions)
DCP Sand Hills Pipeline, LLC	$	110	$	63	$	26
Discovery Producer Services LLC	73		54		7
DCP Southern Hills Pipeline, LLC	44		18		15
Front Range Pipeline LLC	19		17		2
Mont Belvieu Enterprise Fractionator	16		15		17
Mont Belvieu 1 Fractionator	9		9		12
Texas Express Pipeline LLC	9		8		3
Other	2		—		—
Total earnings from unconsolidated affiliates	$	282	$	184	$	82

Distributions received from investments in unconsolidated affiliates were as follows:



	Year Ended December 31,
	2016		2015		2014
	(Millions)
DCP Sand Hills Pipeline, LLC	$	139	$	71	$	43
Discovery Producer Services LLC	94		69		15
DCP Southern Hills Pipeline, LLC	56		24		23
Front Range Pipeline LLC	24		17		15
Mont Belvieu Enterprise Fractionator	18		13		19
Mont Belvieu 1 Fractionator	11		12		14
Texas Express Pipeline LLC	11		11		8
Other	3		—		4
Total distributions from unconsolidated affiliates	$	356	$	217	$	141

Results of Operations — Gathering and Processing Segment

The results of operations for our Gathering and Processing segment are as follows:



		Year Ended December 31,									Variance 2016 vs. 2015					Variance 2015 vs. 2014
		2016			2015			2014			Increase (Decrease)			Percent		Increase (Decrease)			Percent
	(Millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	3,955		$	4,377		$	9,375		$	(422	)	(10	)%	$	(4,998	)	(53	)%
Transportation, processing and other		580			465			463			115			25	%	2			—	%
Trading and marketing (losses) gains, net		(45		)	68			35			(113		)	*		33			94	%
Total operating revenues		4,490			4,910			9,873			(420		)	(9	)%	(4,963		)	(50	)%
Purchases of natural gas and NGLs		(3,263		)	(3,697		)	(7,902		)	(434		)	(12	)%	(4,205		)	(53	)%
Operating and maintenance expense		(611		)	(668		)	(725		)	(57		)	(9	)%	(57		)	(8	)%
Depreciation and amortization expense		(344		)	(343		)	(315		)	1			—	%	28			9	%
General and administrative expense		(14		)	(22		)	(27		)	(8		)	(36	)%	(5		)	(19	)%
Asset impairments		—			(876		)	(18		)	(876		)	(100	)%	858			*
Other income (expense), net		73			(1		)	(5		)	74			*		4			*
Earnings from unconsolidated affiliates (a)		73			54			5			19			35	%	49			*
Gain (loss) on sale of assets, net		19			42			(7		)	(23		)	(55	)%	49			*
Segment net income (loss)		423			(601		)	879			1,024			*		(1,480		)	*
Segment net income attributable to non-controlling interests		(6		)	(5		)	(4		)	1			20	%	1			25	%
Segment net income (loss) attributable to partners		$	417		$	(606	)	$	875		$	1,023		*		$	(1,481	)	*
Other data:
Segment gross margin (b)		$	1,227		$	1,213		$	1,971		$	14		1	%	$	(758	)	(38	)%
Non-cash commodity derivative mark-to-market		$	(119	)	$	47		$	39		$	(166	)	*		$	8		21	%
Natural gas throughput wellhead (MMcf/d) (c)		5,124			5,604			5,896			(480		)	(9	)%	(292		)	(5	)%
NGL gross production (MBbls/d) (c)		393			408			454			(15		)	(4	)%	(46		)	(10	)%

_________________

* Percentage change is not meaningful.


(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 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, including commodity derivative activity, less purchases of natural gas and NGLs. 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 volumes and NGL production.

Year Ended December 31, 2016 vs. Year Ended December 31, 2015

Total Operating Revenues — Total operating revenues decreased $420 million in 2016 compared to 2015, primarily as a result of the following:


•	$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.

These decreases were partially offset by:


•	$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.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs decreased $434 million in 2016 compared to 2015 as a result of decreased commodity prices and lower gas and NGL sales volumes in our South, Midcontinent and Permian regions, partially offset by increased volumes in our North region.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2016 compared to 2015 primarily as a result of our headcount reduction in April 2016, plant consolidations and other cost savings initiatives, the disposition of our Northern Louisiana system in July 2016 and the sale of certain gas processing plants and gathering systems in the Permian region in 2015, partially offset by the completion of our Lucerne 2 plant in the DJ Basin system in July 2015 and the completion of our Zia II plant in the Southeast New Mexico system in August 2015.

General and Administrative Expense — General and administrative expense decreased in 2016 compared to 2015 primarily as a result of our headcount reduction in April 2016 and other cost savings initiatives.

Asset Impairments — Asset impairments in 2015 represented impairments of goodwill, property, plant and equipment and intangible assets.

Other Income (Expense), net — Other income, net in 2016 represented a producer settlement net of legal fees, partially offset by charges from discontinued construction projects.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2016 compared to 2015 primarily as a result of the ramp-up of the Keathley Canyon volumes at Discovery.

Gain on Sale of Assets, net — Gain on sale of assets during 2016 primarily related to the sale of our Northern Louisiana system in our South region. During 2015, we recognized gains related to the sale of certain gas processing plants and gathering systems in our Midcontinent and Permian regions.

Segment Gross Margin — Segment gross margin increased $14 million in 2016 compared to 2015, primarily as a result of the following:


•	$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.

These increases were partially offset by:


•	$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.

Total Wellhead Volumes - Natural gas wellhead throughput decreased in 2016 compared to 2015 reflecting lower volumes primarily from (i) our Eagle Ford and East Texas systems within our South region (ii) lower volumes associated with the general declines within the Permian and Midcontinent regions (iii) the disposition of our Northern Louisiana system within our South region and (iv) disposition of certain gas processing plants and gathering systems in the Midcontinent and Permian regions, which were partially offset by (i) the ramp-up of the Lucerne 2 plant in our North region which commenced operations in June 2015 (ii) completion of the Zia II plant in August 2015 and (iii) ramp-up of the National Helium plant in September 2015.

NGL Gross Production - NGL production decreased in 2016 compared to 2015 reflecting lower volumes primarily from (i) our Eagle Ford and East Texas systems within our South region (ii) lower volumes associated with the general declines within the Permian and Midcontinent regions (iii) the disposition of our Northern Louisiana system within our South region (iv) disposition of certain gas processing plants in the Midcontinent and Permian regions and (v) higher ethane rejection, which were partially offset by (i) the ramp-up of the Lucerne 2 plant in our North region which commenced operations in June 2015 (ii) completion of the Zia II plant in August 2015 and (iii) ramp-up of the National Helium plant in September 2015.

Year Ended December 31, 2015 vs. Year Ended December 31, 2014

Total Operating Revenues — Total operating revenues decreased $4,963 million in 2015 compared to 2014, primarily as a result of the following:


•	$4,284 million decrease attributable to lower commodity prices, which impacted both sales and purchases, before the impact of derivative activity; and

•

$915 million decrease attributable to lower volumes across our South, Midcontinent and Permian regions due to reduced drilling activity in the current period and the sale of certain gas processing plants and gathering systems in our Midcontinent and Permian regions, partially offset by the completion and ramp-up of the Lucerne 2 plant in June 2015, completion and ramp-up of the Zia II plant in August 2015 and ramp-up of the National Helium plant in September 2015.

These decreases were partially offset by:


•	$201 million increase attributable to higher gas and NGL sales volumes primarily related to our DJ Basin system in our North region;


•	$2 million increase in transportation, processing and other primarily related to fee based contract realignment efforts; and


•	$33 million increase as a result of commodity derivative activity attributable to an increase in unrealized commodity derivative gains of $8 million in 2015 and $25 million increase in realized cash settlement gains due to movements in forward prices of commodities.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs decreased $4,205 million in 2015 compared to 2014 primarily as a result of decreased commodity prices and lower gas and NGL sales volumes in our South, Midcontinent and Permian regions and the sale of certain gas processing plants in our Midcontinent and Permian regions, partially offset by the completion and ramp-up of the Lucerne 2 plant in June 2015, completion and ramp-up of the Zia II plant in August 2015 and ramp-up of the National Helium plant in September 2015.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2015 compared to 2014 primarily as a result of the sales of certain gas processing plants and gathering systems in the Permian region in 2015 and other cost savings initiatives. In addition, 2014 results included higher spending on reliability programs.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2015 compared to 2014 primarily as a result of the completion of expansion projects including the Lucerne 2 plant in our DJ Basin system in our North Region and the Zia II plant in our Southeast New Mexico system in our Permian region, partially offset by the sale of certain gas processing plants and gathering systems in our Permian region.

General and Administrative Expense — General and administrative expense decreased in 2015 compared to 2014 primarily as a result of our headcount reduction in January 2015.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2015 compared to 2014 primarily as a result of the completion and ramp-up of the Keathley Canyon project at Discovery in February 2015.

Other (Income) Expense, net — Other expense, net in 2015 and 2014 primarily represented charges for discontinued construction projects.

Gain on Sale of Assets, net — Gain on sale of assets for the year ended December 31, 2015 primarily related to the sale of certain gas processing plants and gathering systems in our Midcontinent and Permian regions. During the same period in 2014, we recognized a loss related to the sale of an investment in an unconsolidated affiliate.

Segment Gross Margin — Segment gross margin decreased $758 million in 2015 compared to 2014, primarily as a result of the following:


•	$897 million decrease as a result of lower commodity prices; and


•	$44 million decrease primarily as a result of lower volumes across our Midcontinent, South and Permian regions due to reduced drilling activity in 2015 and the sale of certain gas processing plants in our Midcontinent and Permian regions, partially offset by fee based contract realignment efforts across our Midcontinent, South and Permian regions.

These decreases were partially offset by:


•	$83 million increase primarily as a result of higher volumes following the completion and ramp-up of the Lucerne 2 plant in June 2015, higher NGL recoveries primarily related to our DJ Basin system in our North region and higher margins on a specific producer arrangement;


•	$67 million increase primarily as a result of the completion and ramp-up 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 plant operational efficiencies in the Permian and Midcontinent regions; and


•	$33 million increase as a result of commodity derivative activity as discussed above.

Total Wellhead Volumes — Natural gas wellhead throughput decreased in 2015 compared to 2014 reflecting lower volumes primarily from (i) our Eagle Ford and East Texas systems within our South region (ii) lower volumes associated with the general declines within the Permian and Midcontinent regions and (iii) the sale of certain gas processing plants and gathering systems in our Midcontinent and Permian regions, which were partially offset by (i) the completion and ramp-up of the Keathley Canyon project at Discovery which commenced operations in February 2015 (ii) Lucerne 2 plant in our DJ Basin system in our North region which commenced operations in June 2015 (iii) completion of our Zia II plant in our Southeast New Mexico system in our Permian region in August 2015 and (iv) ramp-up of our National Helium plant in our Liberal system in our Midcontinent region in September 2015.

NGL Gross Production — NGL gross production decreased in 2015 compared to 2014 reflecting lower volumes primarily from (i) our Eagle Ford and East Texas systems within our South region (ii) lower volumes associated with the general declines within the Permian and Midcontinent regions and (iii) the sale of certain gas processing plants and gathering systems in our Midcontinent and Permian regions, which were partially offset by (i) the completion and ramp-up of the Keathley Canyon project at Discovery which commenced operations in February 2015 (ii) Lucerne 2 plant in our DJ Basin system in our North region which commenced operations in June 2015 (iii) completion of our Zia II plant in our Southeast New Mexico system in our Permian region in August 2015 and (iv) ramp-up of our National Helium plant in our Liberal system in our Midcontinent region in September 2015.

Results of Operations — Logistics and Marketing Segment

The results of operations for our Logistics and Marketing segment are as follows:



		Year Ended December 31,									Variance 2016 vs. 2015					Variance 2015 vs. 2014
		2016			2015			2014			Increase (Decrease)			Percent		Increase (Decrease)			Percent
	(Millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate		$	6,094		$	6,364		$	12,540		$	(270	)	(4	)%	$	(6,176	)	(49	)%
Transportation, processing and other		70			72			56			(2		)	(3	)%	16			29	%
Trading and marketing gains, net		22			51			53			(29		)	(57	)%	(2		)	(4	)%
Total operating revenues		6,186			6,487			12,649			(301		)	(5	)%	(6,162		)	(49	)%
Purchases of natural gas and NGLs		(5,981		)	(6,251		)	(12,423		)	(270		)	(4	)%	(6,172		)	(50	)%
Operating and maintenance expense		(43		)	(49		)	(44		)	(6		)	(12	)%	5			11	%
Depreciation and amortization expense		(15		)	(16		)	(17		)	(1		)	(6	)%	(1		)	(6	)%
General and administrative expense		(9		)	(11		)	(14		)	(2		)	(18	)%	(3		)	(21	)%
Asset impairments		—			(9		)	—			(9		)	(100	)%	9			*
Other expense, net		(5		)	(8		)	—			(3		)	(38	)%	8			*
Gain on sale of assets, net		16			—			—			16			*		—			*
Earnings from unconsolidated affiliates (a)		209			130			77			79			61	%	53			69	%
Segment net income		358			273			228			85			31	%	45			20	%
Segment net income attributable to non-controlling interests		—			—			—			—			*		—			*
Segment net income attributable to partners		$	358		$	273		$	228		$	85		31	%	$	45		20	%
Other data:
Segment gross margin (b)		$	205		$	236		$	226		$	(31	)	(13	)%	$	10		4	%
Non-cash commodity derivative mark-to-market		$	(20	)	$	(1	)	$	4		$	(19	)	*		$	(5	)	*
NGL pipelines throughput (MBbls/d)		420			298			224			122			41	%	74			33	%


(a)	For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the throughput volumes of unconsolidated affiliates. 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)	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”.

Year Ended December 31, 2016 vs. Year Ended December 31, 2015

Total Operating Revenues — Total operating revenues decreased $301 million in 2016 compared to 2015, primarily as a result of the following:


•	$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.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs decreased $270 million in 2016 compared to 2015 as a result of lower commodity prices and lower gas and NGL sales volumes.

Operating and Maintenance Expense — Operating and maintenance expense decreased in 2016 compared to 2015 primarily as a result of our headcount reduction in April 2016, other cost savings initiatives and the sale of our Northern Louisiana system in July 2016.

Asset Impairments — Asset impairments for the year ended December 31, 2015 primarily related to impairments of property, plant and equipment and intangible assets.

Other Expense, net — Other expense, net in 2016 and 2015 primarily represents charges for discontinued construction projects.

Gain on Sale of Assets, net — Gain on sale of assets for the year ended December 31, 2016 primarily related to the sale of our Northern Louisiana system.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2016 compared to 2015 primarily as a result of Enbridge’s contribution of its interests in Sand Hills and Southern Hills in November 2015, higher pipeline throughput volumes on Southern Hills, Sand Hills and Front Range due to growth in NGL production from new plants placed into service in 2015 and earnings on the Panola pipeline beginning in February 2016.

Segment Gross Margin — Segment gross margin decreased $31 million in 2016 compared to 2015, primarily as a result of the following:


•	$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.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2016 compared to 2015 primarily as a result of Enbridge’s contribution of its interests in Sand Hills and Southern Hills in November 2015, higher throughput volumes on Sand Hills, Southern Hills and Front Range due to growth in NGL production from new plants placed into service in 2015 and the throughput volumes on Panola commencing February 2016.

Year Ended December 31, 2015 vs. Year Ended December 31, 2014

Total Operating Revenues — Total operating revenues decreased $6,162 million in 2015 compared to 2014, primarily as a result of the following:


•	$5,682 million decrease attributable to lower commodity prices, which impacted both sales and purchases, before the impact of derivative activity;


•	$494 million decrease attributable to lower gas and NGL sales volumes, which impacted both sales and purchases; and


•	$2 million decrease as a result of commodity derivative activity attributable to an increase in unrealized commodity derivative losses of $5 million in 2015 partially offset by a $3 million increase in realized cash settlement gains due to movements in forward prices of commodities.

These decreases were partially offset by:


•	$16 million increase primarily attributable to the conversion of one of our assets to a butane export facility and higher NGL storage margins.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs decreased $6,172 million in 2015 compared to 2014 as a result of decreased commodity prices and lower gas and NGL sales volumes.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2015 compared to 2014 primarily as a result of increased asset reliability spending, partially offset by our headcount reduction in January 2015 and other cost savings initiatives.

Asset Impairments — Asset impairments for the year ended December 31, 2015 primarily related to impairments of property, plant and equipment and intangible assets.

Other Expense — Other expense, net in 2015 primarily represents charges for discontinued construction projects.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2015 compared to 2014 primarily as a result of the Enbridge’s contribution of its interests in Sand Hills and Southern Hills in November 2015 and the ramp-up of Sand Hills and Texas Express and Front Range which commenced operations in February 2014, partially offset by reduced fractionated volumes at both of our Mont Belvieu fractionators and unfavorable location pricing at one of our Mont Belvieu fractionators.

Segment Gross Margin — Segment gross margin increased $10 million in 2015 compared to 2014, primarily as a result of the following:


•	$16 million increase primarily attributable to the conversion of one of our assets to a butane export facility and higher NGL storage margins; and


•	$27 million increase from wholesale propane primarily due to a partial recovery of lower of cost or market inventory adjustments recognized in the fourth quarter of 2014 and higher unit margins, partially offset by a decrease in volumes.

These increases were partially offset by:


•	$31 million decrease primarily attributable lower volumes and unit margins on our natural gas storage assets and decreased gains from NGL marketing; and


•	$2 million decrease as a result of commodity derivative activity attributable to a an increase in unrealized commodity derivative losses of $5 million in 2015 partially offset by a $3 million increase in realized cash settlement gains due to movements in forward prices of commodities.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2015 compared to 2014 as a result of Enbridge’s contribution of its interests in Sand Hills and Southern Hills in November 2015, volume growth on certain of our pipelines including Sand Hills and Southern Hills, Front Range which commenced operations in February 2014 and the ramp-up of Texas Express.

Liquidity and Capital Resources

We expect our sources of liquidity to include:


•	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;


•	borrowings under term loans; and


•	letters of credit.

We anticipate our more significant uses of resources to include:


•	quarterly distributions to our unitholders and general partner;


•	payments to service our debt;


•	growth and maintenance 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.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure, debt service obligations, and acquisition requirements, and quarterly cash distributions for the next twelve months.

We routinely evaluate opportunities for strategic investments or acquisitions. Future material investments or acquisitions may require that we obtain additional capital, assume third party debt or incur other long-term obligations. We have the option to utilize both equity and debt instruments as vehicles for the long-term financing of our investment activities and acquisitions.

Based on current and anticipated levels of operations, we believe we have adequate committed financial resources to conduct our ongoing business, although deterioration in our operating environment could limit our borrowing capacity, further impact our credit ratings, raise our financing costs, as well as impact our compliance with our financial covenant requirements under the Amended and Restated Credit Agreement and the indentures governing our notes.

In February 2017, we further amended our $1.25 billion senior unsecured revolving credit agreement that matures on May 1, 2019, to increase the aggregate commitments under the unsecured revolving credit facility to approximately $1.4 billion. The Amended and Restated Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions.

As of December 31, 2016, there was $195 million of outstanding borrowings on the revolving credit facility under the Amended and Restated Credit Agreement. We had unused borrowing capacity of $1,031 million, net of $24 million of letters of credit, under the Amended and Restated Credit Agreement. The financial covenants set forth in the Amended and Restated Credit Agreement limit the Partnership's ability to incur incremental debt by $970 million as of December 31, 2016. We used a portion of the cash received from the Transaction to repay outstanding debt on our revolving credit facility. Our cost of borrowing under the Amended and Restated Credit Agreement is determined by a ratings-based pricing grid. In the first quarter of 2017, our credit rating was lowered. As a result of this action, interest rates on outstanding borrowings under the Amended and Restated Credit Agreement increased. As of May 19, 2017, we had no outstanding borrowings on the revolving credit facility and had approximately $1,374 million, net of $24 million of letters of credit, of unused borrowing capacity under the Amended and Restated Credit Agreement.

On January 1, 2017, DCP Midstream, LLC contributed to us: (i) its ownership interests in all of its subsidiaries owning operating assets, and (ii) $424 million of cash. In consideration of the Partnership’s receipt of the Contributions, (i) the Partnership issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to DCP Midstream GP, LP, the General Partner, in a private placement, and (ii) the Operating Partnership assumed $3,150 million of DCP Midstream, LLC’s debt. The incentive distributions payable to the holders of the Partnership’s incentive distribution rights with respect to the fiscal years 2017, 2018 and 2019, in certain circumstances, may be reduced in an amount up to $100 million per fiscal year as necessary to provide that the Distributable Cash Flow of the Partnership (as adjusted) during such year meets or exceeds the amount of distributions made by the Partnership (as adjusted) to the partners of the Partnership with respect to such year.

In April 2015, we filed a shelf registration statement with the SEC, that became effective upon filing, which allows us to issue an unlimited amount of common units and debt securities. We have issued no common units or debt securities under this registration statement.

We also have a shelf registration statement that was declared effective in July 2014 allowing us to issue up to $500 million in common units pursuant to our 2014 equity distribution agreement. During the year ended December 31, 2016, we issued no common units and approximately $349 million of common units remained available for sale pursuant to our 2014 equity distribution agreement.

Changes in natural gas, NGL and condensate prices and the terms of our processing arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. We have mitigated a portion of our anticipated commodity price risk associated with the equity volumes from our gathering and processing activities through the first quarter of 2018 with fixed price commodity swaps. For additional information regarding our derivative activities, please read Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" in our Annual Report on Form 10-K.

When we enter into commodity swap contracts we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to the collateral thresholds are determined on a counterparty by counterparty basis, and are impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative crude oil and natural gas forward price curves, it is not practical to determine a pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same counterparty. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis.

Working Capital — Working capital is the amount by which current assets exceed current liabilities. Current assets are reduced by our quarterly distributions, which are required under the terms of our partnership agreement based on Available Cash, as defined in the partnership agreement. In general, our working capital is impacted by changes in the prices of commodities that we buy and sell, inventory levels, and other business factors that affect our net income and cash flows. Our working capital is also impacted by the timing of operating cash receipts and disbursements, borrowings of and payments on debt, capital expenditures, and increases or decreases in other long-term assets. We expect that our future working capital requirements will be impacted by these same recurring factors.

We had working capital deficits of $629 million and $95 million as of December 31, 2016 and 2015, respectively. The change in working capital is primarily attributable to current maturities of our long-term debt of $500 million as of December 31, 2016. We had a net derivative working capital deficit of $49 million as of December 31, 2016 as compared to net derivative working capital excess of $87 million as of December 31, 2015.

As of December 31, 2016, we had $1 million in cash and cash equivalents, all of which was held by consolidated subsidiaries we did not wholly own.

Cash Flow — Operating, investing and financing activities were as follows:



	Year Ended December 31,
	2016			2015			2014
	(Millions)
Net cash provided by operating activities	$	645		$	442		$	817
Net cash used in investing activities	$	(34	)	$	(711	)	$	(1,515	)
Net cash (used in) provided by financing activities	$	(613	)	$	245		$	694

Year Ended December 31, 2016 vs. Year Ended December 31, 2015

Operating Activities — Net cash provided by operating activities increased $203 million in 2016 compared to 2015 primarily as a result of the following:


•	$279 million increase in cash attributable to higher net income in 2016, after adjusting our net income for asset impairments in 2015 and other non-cash items;


•	$139 million increase in cash distributions from unconsolidated affiliates due to increased earnings. For additional information regarding fluctuations in our earnings from unconsolidated affiliates, please read "Results of Operations"; and


•	$215 million decrease in cash attributable to the timing of cash receipts and disbursements related to operations.

Investing Activities — Net cash used in investing activities decreased $677 million in 2016 compared to 2015 primarily as a result of the following:

•

$667 million decrease in capital expenditures attributable to the Lucerne 2 plant which started construction in April 2014 and was placed into service at the end of the second quarter of 2015, the Zia II plant which was placed into service in August 2015, the National Helium plant which was expanded and was placed into service in September 2015 and the Grand Parkway gathering project which began construction in the first quarter of 2015 and was completed in the first quarter of 2016; and

•

$11 million decrease in cash contributions to our unconsolidated affiliates. For the year ended December 31, 2016, we primarily made contributions to the expansion projects at our Sand Hills and Southern Hills pipelines and the construction of our Panola pipeline. For the year ended December 31, 2015, we primarily made contributions to the Keathley Canyon project at Discovery, our Panola pipeline and to the expansion projects at our Sand Hills pipeline.


•	$1 million of lower proceeds received from the sale of assets in 2016.

Financing Activities — Net cash used in financing activities increased $858 million in 2016 compared to 2015 primarily as a result of the following:


•	$1,540 million decrease in advances from DCP Midstream, LLC primarily attributable to the $1,500 million contribution received from Phillips 66 in 2015;


•	$31 million decrease in proceeds from the issuance of common units to the public. We issued no common units to the public during the year ended December 31, 2016 as compared to approximately 1 million common units that were issued during the year ended December 31, 2015;


•	$2 million increase in distributions to non-controlling interests primarily due to Collbran; and


•	$1 million increase in distributions to limited and general partners.

These events were partially offset by:


•	$716 million decrease in net debt payments primarily attributable to the repayment of outstanding commercial paper in 2015.

Year Ended December 31, 2015 vs. Year Ended December 31, 2014

Operating Activities — Net cash provided by operating activities decreased $375 million in 2015 compared to 2014 primarily as a result of the following:


•	$76 million increase in cash distributions from unconsolidated affiliates primarily due to increased earnings. For additional information regarding fluctuations in our earnings from unconsolidated affiliates, please read "Results of Operations";


•	$301 million increase in cash attributable to the timing of cash receipts and disbursements related to operations; and


•	$752 million decrease in cash attributable to higher net income in 2014, after adjusting our net income for asset impairments and other non-cash items.

Investing Activities — Net cash used in investing activities decreased $804 million in 2015 compared to 2014 primarily as a result of the following:

•

$573 million decrease in capital expenditures attributable to the completion of the Goliad plant and the O'Connor plant expansion, both of which were completed in the first quarter of 2014, the Lucerne 2 plant which started construction in April 2014 and was placed into service at the end of the second quarter of 2015, the Zia II plant which was placed into service in the August 2015, the National Helium plant which was expanded and placed into service in the September 2015, partially offset by the Grand Parkway gathering project which began construction in the first quarter of 2015;

•

$97 million decrease in cash contributions to our unconsolidated affiliates. In 2014, we primarily made contributions to the Keathley Canyon project at Discovery, which was placed into service in the first quarter of 2015, and Front Range, which was placed into service in February 2014. In 2015, we primarily made contributions to the Keathley Canyon project at Discovery, our Panola pipeline and to the expansion projects at our Sand Hills pipeline; and


•	$134 million of higher proceeds received from the sale of certain gas processing plants and gathering systems assets in 2015.

Financing Activities — Net cash provided by financing activities decreased $449 million in 2015 compared to 2014 primarily as a result of the following:


•	$970 million decrease in proceeds from the issuance of common units to the public. We issued approximately 1 million common units to the public during the year ended December 31, 2015 as compared to approximately 20 million units during the year ended December 31, 2014;


•	$1,415 million decrease in net debt borrowings primarily attributable to the higher repayments of outstanding commercial paper in 2015. In 2014, we received $719 million of proceeds from senior notes associated with the March 2014 Transactions; and


•	$62 million increase in cash distributions to our limited and general partners primarily attributable to units issued during 2014 and an increase in our quarterly distribution rate over the rate paid for the year ended December 31, 2014.

These events were partially offset by:


•	$1,998 million increase in advances from DCP Midstream, LLC primarily attributable to the $1,500 million contribution received from Phillips 66 in 2015 and $222 million paid related to our March 2014 Transactions.

Capital Requirements — The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of the following:


•	maintenance capital expenditures, which are cash expenditures to maintain our cash flows, operating or earnings capacity. These 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

•

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).

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance capital expenditures of between $100 million and $145 million, and approved expansion capital expenditures of between $325 million and $375 million, for the year ending December 31, 2017. Expansion capital expenditures include the construction of the Mewbourn 3 plant and construction of Grand Parkway Phase 2 in our DJ Basin system, and the capacity expansion of the Sand Hills pipeline, which is shown as an investment in unconsolidated affiliates in our consolidated statements of cash flows.

The following table summarizes our maintenance and expansion capital expenditures for our consolidated entities:



	Year Ended December 31, 2016							Year Ended December 31, 2015
	Maintenance Capital Expenditures		Expansion Capital Expenditures			Total Consolidated Capital Expenditures		Maintenance Capital Expenditures			Expansion Capital Expenditures		Total Consolidated Capital Expenditures
	(Millions)
Our portion	$	86	$	57		$	143	$	181		$	633	$	814
Non-controlling interest portion and reimbursable projects (a)	3		(2		)	1		(3		)	—		(3		)
Total	$	89	$	55		$	144	$	178		$	633	$	811



		Year Ended December 31, 2014
		Maintenance Capital Expenditures		Expansion Capital Expenditures			Total Consolidated Capital Expenditures
	(Millions)
Our portion		$	344	$	1,039		$	1,383
Non-controlling interest portion and reimbursable projects (a)		2		(1		)	1
Total		$	346	$	1,038		$	1,384


(a)	Represents the non-controlling 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.

In addition, we invested cash in unconsolidated affiliates of $53 million and $64 million during the years ended December 31, 2016 and 2015, respectively, to fund our share of capital expansion projects.

We intend to make cash distributions to our unitholders and our general partner. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon internal and external financing sources, to fund future acquisitions and capital expenditures.

We expect to fund future capital expenditures with funds generated from our operations, borrowings under our Amended and Restated Credit Agreement, the issuance of additional partnership units and the issuance of long-term debt.

Cash Distributions to Unitholders — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all Available Cash, as defined in the partnership agreement. We made cash distributions to our unitholders and general partner of $483 million and $482 million during the years ended December 31, 2016 and 2015, respectively. We intend to continue making quarterly distribution payments to our unitholders and general partner to the extent we have sufficient cash from operations after the establishment of reserves.

We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders and general partner. See Note 14. "Partnership Equity and Distributions" in the Notes to Consolidated Financial Statements in Exhibit 99.4 “Financial Statements.” in this Form 8-K.

Total Contractual Cash Obligations

A summary of our total contractual cash obligations as of December 31, 2016, is as follows:



	Payments Due by Period
	Total		Less than 1 year		1-3 years		3-5 years		Thereafter
	(Millions)
Debt (a)	$	8,740	$	786	$	1,491	$	1,494	$	4,969
Operating lease obligations	225		61		72		50		42
Purchase obligations (b)	2,911		619		768		674		850
Other long-term liabilities (c)	145		—		11		8		126
Total	$	12,021	$	1,466	$	2,342	$	2,226	$	5,987


(a)	Includes interest payments on debt securities that have been issued. These interest payments are $286 million, $521 million, $394 million, and $2,119 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, 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.

(c)

Other long-term liabilities include asset retirement obligations, long-term environmental remediation liabilities, gas purchase liabilities, right of way liabilities and other miscellaneous liabilities recognized in the December 31, 2016 condensed consolidated balance sheet. The table above excludes non-cash obligations as well as $28 million of deferred state income taxes, $26 million of Executive Deferred Compensation Plan contributions and $12 million of long-term incentive plans as the amount and timing of any payments are not subject to reasonable estimation.

Off-Balance Sheet Obligations

As of December 31, 2016, we had no items that were classified as off-balance sheet obligations.

Reconciliation of Non-GAAP Measures

Gross Margin and Segment Gross Margin — In addition to net income, we view our gross margin as an important performance measure of the core profitability of our operations. We review our gross margin monthly for consistency and trend analysis.

We define gross margin as total operating revenues, including commodity derivative activity, less purchases of natural gas and NGLs, and we define segment gross margin for each segment as total operating revenues, including commodity derivative activity, for that segment less commodity purchases for that segment. Our gross margin equals the sum of our segment gross margins. Gross margin and segment gross margin are primary performance measures used by management, as these measures represent the results of product sales and purchases, a key component of our operations. As an indicator of our operating performance, gross margin and segment gross margin should not be considered an alternative to, or more meaningful than, operating revenues, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with accounting principles generally accepted in the United States of America, or GAAP.

Adjusted EBITDA —We define adjusted EBITDA as net income or loss attributable to partners adjusted for (i) distributions from unconsolidated affiliates, net of earnings (ii) depreciation and amortization expense, (iii) net interest expense, (iv) noncontrolling interest in depreciation and income tax expense, (v) unrealized gains and losses from commodity derivatives (vi) income tax expense or benefit, (vii) impairment expense and (viii) certain other non-cash items. Adjusted EBITDA further excludes items of income or loss that we characterize as unrepresentative of our ongoing operations.. Management believes these measures provide investors meaningful insight into results from ongoing operations.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations.

Adjusted EBITDA is used as a supplemental liquidity and performance measure and adjusted segment EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others to assess:


•	financial performance of our assets without regard to financing methods, capital structure or historical cost basis;


•	our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard 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.

Adjusted Segment EBITDA — We define adjusted segment EBITDA for each segment as segment net income or loss attributable to partners adjusted for (i) distributions from unconsolidated affiliates, net of earnings (ii) depreciation and amortization expense, (iii) net interest expense, (iv) non-controlling interest in depreciation and income tax expense, (v) unrealized gains and losses from commodity derivatives (vi) income tax expense or benefit, (vii) impairment expense and (viii) certain other non-cash items. Adjusted segment EBITDA further excludes items of income or loss that we characterize as unrepresentative of our ongoing operations for that segment. Our adjusted segment EBITDA may not be comparable to similarly titled measures of other companies because they may not calculate adjusted segment EBITDA in the same manner.

Adjusted segment EBITDA should not be considered in isolation or as an alternative to our financial measures presented in accordance with GAAP, including operating revenues, net income or loss attributable to partners, or any other measure of performance presented in accordance with GAAP.

Our gross margin, segment gross margin, adjusted EBITDA and adjusted segment EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate these measures in the same manner. The accompanying schedules provide reconciliations of gross margin, segment gross margin and adjusted segment EBITDA to their most directly comparable GAAP financial measures.

Distributable Cash Flow — We define Distributable Cash Flow as adjusted EBITDA, as defined above, less maintenance capital expenditures, net of reimbursable projects, less interest expense and certain other items. Maintenance capital expenditures are cash expenditures made 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. Non-cash mark-to-market of derivative instruments is considered to be non-cash for the purpose of computing Distributable Cash Flow because settlement will not occur until future periods, and will be impacted by future changes in commodity prices and interest rates. We compare the Distributable Cash Flow we generate to the cash distributions we expect to pay our partners. Using this metric, we compute our distribution coverage ratio. Distributable Cash Flow is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess our ability to make cash distributions to our unitholders and our general partner.

Our Distributable Cash Flow may not be comparable to a similarly titled measure of another company because other entities may not calculate Distributable Cash Flow in the same manner.

The following table sets forth our reconciliation of certain non-GAAP measures:



		Year Ended December 31,
		2016			2015			2014
Reconciliation of Non-GAAP Measures	(Millions)

Reconciliation of net income attributable to partners to gross margin:

Net income (loss) attributable to partners		$	88		$	(871	)	$	547
Interest expense		321			320			287
Income tax expense (benefit)		46			(102		)	11
Operating and maintenance expense		670			732			773
Depreciation and amortization expense		378			377			348
General and administrative expense		292			281			277
Asset impairments		—			912			18
Other (income) expense, net		(65		)	10			7
Earnings from unconsolidated affiliates		(282		)	(184		)	(82		)
(Gain) loss on sale of assets, net		(35		)	(42		)	7
Restructuring costs		13			11			—
Net income attributable to non-controlling interests		6			5			4
Gross margin		$	1,432		$	1,449		$	2,197
Non-cash commodity derivative mark-to-market (a)		$	(139	)	$	46		$	43

Reconciliation of segment net income attributable to partners to segment gross margin:

Gathering and Processing Segment:
Segment net income (loss) attributable to partners		$	417		$	(606	)	$	875
Operating and maintenance expense		611			668			725
Depreciation and amortization expense		344			343			315
General and administrative		14			22			27
Other (income) expense, net		(73		)	1			5
Earnings from unconsolidated affiliates		(73		)	(54		)	(5		)
(Gain) loss on sale of assets, net		(19		)	(42		)	7
Asset impairments		—			876			18
Net income attributable to non-controlling interests		6			5			4
Segment gross margin		$	1,227		$	1,213		$	1,971
Non-cash commodity derivative mark-to-market (a)		$	(119	)	$	47		$	39


Logistics and Marketing Segment:
Segment net income attributable to partners		$	358		$	273		$	228
Operating and maintenance expense		43			49			44
Depreciation and amortization expense		15			16			17
General and administrative		9			11			14
Other expense, net		5			8			—
Earnings from unconsolidated affiliates		(209		)	(130		)	(77		)
Gain on sale of assets, net		(16		)	—			—
Asset impairments		—			9			—
Segment gross margin		$	205		$	236		$	226
Non-cash commodity derivative mark-to-market (a)		$	(20	)	$	(1	)	$	4


(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.



		Year Ended December 31,
		2016			2015			2014
	(Millions)
Reconciliation of net income attributable to partners to adjusted segment EBITDA:
Gathering and Processing segment:
Segment net income (loss) attributable to partners		$	417		$	(606	)	$	875
Non-cash commodity derivative mark-to-market		119			(47		)	(39		)
Depreciation and amortization expense		344			343			315
Distributions from unconsolidated affiliates, net of earnings		21			15			14
Asset impairments		—			876			18
(Gain) loss on sale of assets, net		(19		)	(42		)	7
Discontinued construction projects		14			2			5
Non-controlling interest portion of depreciation and income tax		(1		)	(1		)	(1		)
Adjusted segment EBITDA		$	895		$	540		$	1,194

Logistics and Marketing segment:
Segment net income attributable to partners (a)		$	358		$	273		$	228
Non-cash commodity derivative mark-to-market		20			1			(4		)
Depreciation and amortization expense		15			16			17
Distributions from unconsolidated affiliates, net of earnings		53			18			45
Asset impairments		—			9			—
Gain on sale of assets, net		(16		)	—			—
Discontinued construction projects		—			—			2
Adjusted segment EBITDA		$	430		$	317		$	288


(a)	Includes $3 million, $8 million and $24 million in the lower of cost or market adjustments for the years ended December 31, 2016, 2015 and 2014, respectively.

Operating and Maintenance and General and Administrative Expense

Pursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into the Services and Employee Secondment Agreement (the “Services Agreement”), which replaced the services agreement between the Partnership and DCP Midstream, LLC, dated February 14, 2013, as amended. Under the Services Agreement, we are required to reimburse DCP Midstream, LLC for salaries of personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. There is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for other expenses and expenditures incurred or payments made on our behalf.

Operating and maintenance expenses are costs associated with the operation of a specific asset and are primarily comprised of direct labor, ad valorem taxes, repairs and maintenance, lease expenses, utilities and contract services. These expenses fluctuate depending on the activities performed during a specific period.

General and administrative expense represents costs incurred to manage the business. This expense includes cost of centralized corporate functions performed by DCP Midstream, LLC, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll and engineering and all other expenses necessary or appropriate to the conduct of the business.

We also incurred third party general and administrative expenses, which were primarily related to compensation and benefit expenses of the personnel who provide direct support to our operations. Also included are expenses associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, due diligence and acquisition costs, costs associated with the Sarbanes-Oxley Act of 2002, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and director compensation.

Critical Accounting Policies and Estimates

Our financial statements reflect the selection and application of accounting policies that require management to make estimates and assumptions. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations. These accounting policies are described further in Note 2 of the Notes to Consolidated Financial Statements in Exhibit 99.4 "Financial Statements and Supplementary Data." in this Form 8-K.



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions

Impairment of Goodwill
We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount.	We determine fair value using widely accepted valuation techniques, namely discounted cash flow and market multiple analyses. These techniques are also used when assigning the purchase price to acquired assets and liabilities. These types of analyses require us to make assumptions and estimates regarding industry and economic factors and the profitability of future business strategies. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations.	We primarily use a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information (including forecasted commodity prices and volumes), as well as historical and other factors. If our assumptions are not appropriate, or future events indicate that our goodwill is impaired, our net income would be impacted by the amount by which the carrying value exceeds the fair value of the reporting unit, to the extent of the balance of goodwill. The two of the three reporting units that contain goodwill are not significantly impacted by the prices of commodities. Rather, they are volume based businesses that have the potential to be impacted by commodity prices should such prices remain depressed for a period of such duration that NGLs cease to be produced at levels requiring storage and distribution to end users. We did not record any goodwill impairment during the year ended December 31, 2016.



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions

Impairment of Long-Lived Assets
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. For purposes of this evaluation, long-lived assets with recovery periods in excess of the weighted average remaining useful life of our fixed assets are further analyzed to determine if a triggering event occurred. If it is determined that a triggering event has occurred, we prepare a quantitative evaluation based on undiscounted cash flow projections expected to be realized over the remaining useful life of the primary asset. The carrying amount is not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value.	Our impairment analyses require management to apply judgment in estimating future cash flows as well as asset fair values, including forecasting useful lives of the assets, future commodity prices, volumes, and operating costs, assessing the probability of different outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. If the carrying value is not recoverable, we assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models.	Using the impairment review methodology described herein, we have not recorded any impairment charges on long-lived assets during the year ended December 31, 2016. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge. If our forecast indicates lower commodity prices in future periods at a level and duration that results in producers curtailing or redirecting drilling in areas where we operate this may adversely affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.

Impairment of Investments in Unconsolidated Affiliates
We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced a decline in value. When evidence of loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We would then evaluate if the impairment is other than temporary.	Our impairment analyses require management to apply judgment in estimating future cash flows and asset fair values, including forecasting useful lives of the assets, assessing the probability of differing estimated outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. When there is evidence of an other than temporary loss in value, we assess the fair value of our unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models.	Using the impairment review methodology described herein, we have not recorded any significant impairment charges on investments in unconsolidated affiliates during the year ended December 31, 2016. If the estimated fair value of our unconsolidated affiliates is less than the carrying value, we would recognize an impairment loss for the excess of the carrying value over the estimated fair value only if the loss is other than temporary. A period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions

Accounting for Risk Management Activities and Financial Instruments
Each derivative not qualifying for the normal purchases and normal sales exception is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on derivative instruments. Derivative assets and liabilities remain classified in our consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments at fair value until the end of the contractual settlement period. Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions.	When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical information and the expected relationship with quoted market prices.	If our estimates of fair value are inaccurate, we may be exposed to losses or gains that could be material. A 10% difference in our estimated fair value of derivatives at December 31, 2016 would have affected net income by approximately $4 million based on our net derivative position for the year ended December 31, 2016.

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