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•	the extent of changes in commodity prices and the demand for our products and services, our ability to effectively limit a portion of the adverse impact of potential changes in prices through derivative financial instruments, and the potential impact of price and producers’ access to capital on natural gas drilling, demand for our services, and the volume of NGLs and condensate extracted;

•	general economic, market and business conditions;

•	our ability to hire as well as retain qualified personnel to execute our business strategy;

•	volatility in the price of our common units;

•	the level and success of natural gas drilling around our assets, the level and quality of gas production volumes around our assets and our ability to connect supplies to our gathering and processing systems in light of competition;

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

•	our ability to access the debt and equity markets and the resulting cost of capital, which will depend on general market conditions, our financial and operating results, inflation rates, interest rates, our ability to comply with the covenants in our loan agreements and our debt securities, as well as our ability to maintain our credit ratings;

•	the demand for NGL products by the petrochemical, refining or other industries;

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

•	our ability to construct facilities on budget and in a timely fashion, which is partially dependent on obtaining required construction, environmental and other permits issued by federal, state and municipal governments, or agencies thereof, the availability of specialized contractors and laborers, and the price of and demand for materials;

•	the creditworthiness of counterparties to our transactions;

•	weather, weather related conditions and other natural phenomena, including their potential impact on demand for the commodities we sell and the operation of company-owned and third party-owned infrastructure;

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

•	new, additions to and changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment, including climate change legislation, regulation of over-the-counter derivatives market and entities, and hydraulic fracturing regulations, or the increased regulation of our industry, and their impact on producers and customers served by our systems;

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

•	the amount of gas we gather, compress, treat, process, transport, sell and store, or the NGLs we produce, fractionate, transport and store, may be reduced if the pipelines and storage and fractionation facilities to which we deliver the natural gas or NGLs are capacity constrained and cannot, or will not, accept the gas or NGLs;

•	industry changes, including the impact of consolidations, alternative energy sources, technological advances and changes in competition;

•	the amount of collateral we may be required to post from time to time in our transactions; and

•	our ability to execute our asset integrity and safety programs to continue the safe and reliable operation of our assets.

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(a)	Represents total capacity or total volumes allocated to our proportionate ownership share for 2013 divided by 365 days. In 2013, we had an 80% interest in our Eagle Ford system, a 75% interest in our Piceance system and a 40% limited liability company interest in Discovery.

(b)	Represents NGL extraction plants.

(c)	Represents treating plants.

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

(e)	Our East Texas system is comprised of one gas processing complex containing four plants, as well as the Crossroads and George Gray processing plants.

(f)	Excludes our idled East Caledonia plant.

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(a)	Represents total capacity and throughput allocated to our proportionate ownership share for 2013 divided by 365 days.

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•	certification and construction of new facilities;

•	extension or abandonment of services and facilities;

•	maintenance of accounts and records;

•	acquisition and disposition of facilities;

•	initiation and discontinuation of services;

•	terms and conditions of services and service contracts with customers;

•	depreciation and amortization policies;

•	conduct and relationship with certain affiliates; and

•	various other matters.

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•	requiring the acquisition of permits to conduct regulated activities;

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

•	limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions or areas inhabited by endangered species;

•	requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operations; and

•	enjoining, or compelling changes to, the operations of facilities deemed not to be in compliance with permits issued pursuant to such environmental laws and regulations.

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•	the fees we charge and the margins we realize for our services;

•	the prices of, level of production of, and demand for natural gas, condensate and NGLs, and propane;

•	the success of our commodity and interest rate hedging programs in mitigating fluctuations in commodity prices and interest rates;

•	the volume and quality of natural gas we gather, compress, treat, process, transport and sell, and the volume of NGLs we process, transport, sell, and store and the volume of propane we transport, sell, and store;

•	the operational performance and efficiency of our assets, including our plants and equipment;

•	the operational performance and efficiency of third-party processing, fractionation or other facilities that provide services to us;

•	the relationship between natural gas, NGL and crude oil prices;

•	the level of competition from other energy companies;

•	the impact of weather conditions on the demand for natural gas, NGLs and propane;

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•	the level of our operating and maintenance and general and administrative costs; and

•	prevailing economic conditions.

•	the level of capital expenditures we make;

•	the cost and form of payment for acquisitions;

•	our debt service requirements and other liabilities;

•	fluctuations in our working capital needs;

•	our ability to borrow funds and access capital markets at reasonable rates;

•	restrictions contained in our debt agreements;

•	the timing of our producers' obligations to make volume deficiency payments to us;

•	the amount of cash distributions we receive from our equity interests;

•	the amount of cost reimbursements to our general partner;

•	the amount of cash reserves established by our general partner; and

•	new, additions to and changes in laws and regulations.

•	we have limited ability to control decisions with respect to the operations of these entities and their subsidiaries, including decisions with respect to incurrence of expenses and distributions to us;

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

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

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

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•	the impact of weather, including abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes, respectively, or extreme weather that may disrupt our operations or related upstream or downstream operations;

•	the level of domestic and offshore production;

•	a general downturn in economic conditions, including demand for NGLs;

•	the availability of natural gas, NGLs and crude oil and the demand in the U.S. and globally for these commodities;

•	actions taken by foreign oil and gas producing nations;

•	the availability of local, intrastate and interstate transportation systems;

•	the availability and marketing of competitive fuels; and

•	the extent of governmental regulation and taxation.

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•	participate in dropdown opportunities with DCP Midstream, LLC;

•	identify businesses engaged in managing, operating or owning pipelines, processing and storage assets or other midstream assets for acquisitions, joint ventures and construction projects;

•	consummate accretive acquisitions or joint ventures and complete construction projects;

•	appropriately identify liabilities associated with acquired businesses or assets;

•	integrate acquired or constructed businesses or assets successfully with our existing operations and into our operating and financial systems and controls;

•	hire, train and retain qualified personnel to manage and operate our growing business; and

•	obtain required financing for our existing and new operations at reasonable rates.

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•	perform ongoing assessments of pipeline integrity;

•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•	improve data collection, integration and analysis;

•	repair and remediate the pipeline as necessary; and

•	implement preventive and mitigating actions.

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•	mistaken assumptions about volumes, future contract terms with customers, revenues and costs, including synergies;

•	an inability to successfully integrate the businesses we acquire;

•	the assumption of unknown liabilities;

•	limitations on rights to indemnity from the seller;

•	mistaken assumptions about the overall costs of equity or debt;

•	the diversion of management’s and employees’ attention from other business concerns;

•	change in competitive landscape;

•	unforeseen difficulties operating in new product areas or new geographic areas; and

•	customer or key employee losses at the acquired businesses.

•	damage to pipelines, plants, terminals, storage facilities and related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;

•	inadvertent damage from construction, farm and utility equipment;

•	leaks of natural gas, propane, NGLs and other hydrocarbons from our pipelines, plants, terminals, or storage facilities, or losses of natural gas, propane or NGLs as a result of the malfunction of equipment or facilities;

•	contaminants in the pipeline system;

•	fires and explosions; and

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

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•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

•	an increased amount of cash flow will be required to make interest payments on our debt;

•	our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

•	our debt level may limit our flexibility in responding to changing business and economic conditions.

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•	the failure to realize expected profitability, growth or accretion;

•	an increase in indebtedness and borrowing costs;

•	potential environmental or regulatory compliance matters or liabilities;

•	potential title issues;

•	the incurrence of unanticipated liabilities and costs; and

•	the temporary diversion of management’s attention from managing the remainder of our assets to the process of integrating the acquired businesses.

•	neither our partnership agreement nor any other agreement requires DCP Midstream, LLC to pursue a business strategy that favors us. DCP Midstream, LLC’s directors and officers have a fiduciary duty to make these decisions in the best interests of the owners of DCP Midstream, LLC, which may be contrary to our interests;

•	our general partner is allowed to take into account the interests of parties other than us, such as DCP Midstream, LLC and its affiliates, in resolving conflicts of interest;

•	DCP Midstream, LLC and its affiliates, including Phillips 66 and Spectra Energy, are not limited in their ability to compete with us. Please read “DCP Midstream, LLC and its affiliates are not limited in their ability to compete with us” below;

•	once certain requirements are met, our general partner may make a determination to receive a quantity of our Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights without the approval of the special committee of our general partner or our unitholders;

•	some officers of DCP Midstream, LLC and DCP Midstream GP, LLC who provide services to us also will devote significant time to the business of DCP Midstream, LLC, and will be compensated by DCP Midstream, LLC for the services rendered to it;

•	our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

•	our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

•	our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders;

•	our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

•	our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

•	our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

•	our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

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•	our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

•	our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

•	the exercise of its right to reset the target distribution levels of its incentive distribution rights at higher levels and receive, in connection with this reset, a number of Class B units that are convertible at any time following the first anniversary of the issuance of these Class B units into common units;

•	its limited call right;

•	its voting rights with respect to the units it owns;

•	its registration rights; and

•	its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

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

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

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•	our unitholders’ proportionate ownership interest in us will decrease;

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

•	the ratio of taxable income to distributions may increase;

•	the relative voting strength of each previously outstanding unit may be diminished; and

•	the market price of the common units may decline.

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

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

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

•	provide for the proper conduct of our business;

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

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

•	plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter.

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(a)

Includes the effect of the following acquisitions prospectively from their respective dates of acquisition: (1) certain companies acquired from MichCon Pipeline Company in November 2009; (2) the Wattenberg pipeline acquired from Buckeye Partners, L.P. in January 2010; (3) an additional 5% interest in Collbran Valley Gas Gathering LLC, acquired from Delta Petroleum Company in February 2010; (4) the Raywood processing plant and Liberty gathering system acquired in June 2010; (5) an additional 50% interest in Black Lake Pipeline Company, or Black Lake, acquired from an affiliate of BP PLC in July 2010; (6) Atlantic Energy acquired from UGI Corporation in July 2010; (7) Marysville Hydrocarbons Holdings, LLC acquired in December 2010; (8) the DJ Basin NGL fractionators acquired in March 2011; (9) our 100% owned Eagle Plant in August 2011; (10) the remaining 49.9% interest in East Texas acquired from DCP Midstream, LLC in January 2012; (11) a 10% ownership interest in the Texas Express Pipeline acquired from Enterprise Products Partners, L.P. in April 2012; (12) a 12.5% interest in the Enterprise fractionator and a 20% interest in the Mont Belvieu 1 fractionator, acquired from DCP Midstream, LLC in July 2012; (13) the Crossroads processing plant and 50% interest in CrossPoint Pipeline, LLC, acquired from Penn Virginia Resource Partners, L.P. in July 2012; (14) the O'Connor plant acquired from DCP Midstream, LLC in August 2013 and (15) the Front Range pipeline acquired from DCP Midstream, LLC in August 2013.

(b)

Includes the effect of the commodity derivative hedge instruments related to the Eagle Ford system, of which 33.33% was acquired from DCP Midstream, LLC in November 2012 and 46.67% was acquired in March 2013; the Goliad plant, of which 33.33% was acquired from DCP Midstream, LLC in December 2012 and 46.67% was acquired in March 2013; the Southeast Texas storage business acquired from DCP Midstream, LLC in March 2012 and the NGL Hedge acquired from DCP Midstream, LLC in April 2009 in connection with the acquisition of a 25.1% interest in East Texas.

(c)

Prior to the acquisition of the remaining 49.9% limited liability company interest in East Texas in January 2012, we hedged our proportionate ownership of East Texas. Results shown include the unhedged portion of East Texas owned by DCP Midstream, LLC. Our consolidated results depict 75% of East Texas unhedged in all periods prior to the second quarter of 2009 and the remaining 49.9% of East Texas unhedged for all periods from the second quarter of 2009 through the fourth quarter of 2011. Our consolidated results depict 100% of the Southeast Texas system unhedged in 2009 and 2010 and 66.67% unhedged in 2011 and through March 2012 corresponding with DCP Midstream, LLC’s ownership interest in Southeast Texas. Our consolidated results depict 100% of the Eagle Ford system unhedged in 2009 and through October 2012, and 66.67% from November 2012 through March 2013, and 20% from April 2013 through December 31, 2013 corresponding with DCP Midstream, LLC’s ownership interest in the Eagle Ford system.

(d)	Includes our proportionate share of the earnings of our unconsolidated affiliates. Earnings include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the entities.

(e)

Includes the net income attributable to an additional 25.1% limited liability company interest in East Texas prior to the date of our acquisition from DCP Midstream, LLC in April 2009; the initial 33.33% interest in Southeast Texas prior to the date of our acquisition from DCP Midstream, LLC in January 2011; the remaining 66.67% interest in Southeast Texas and commodity derivative hedge instruments prior to the date of our acquisition from DCP Midstream, LLC in March 2012; the initial 33.33% interest in the Eagle Ford system prior to the date of our acquisition from DCP Midstream, LLC in November 2012; and the additional 46.67% interest in the Eagle Ford system prior to the date of our acquisition from DCP Midstream, LLC in March 2013.

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On February 25, 2014, we entered into various transaction documents with DCP Midstream, LLC for the contribution or acquisition of (i) the remaining 20% interest in DCP SC Texas GP; (ii) a 33.33% membership interest in each DCP Southern Hills Pipeline, LLC, which owns the Southern Hills pipeline, and DCP Sand Hills Pipeline, LLC, which owns the Sand Hills pipeline; (iii) a 35 MMcf/d cryogenic natural gas processing plant located in Weld County, Colorado, or the Lucerne 1 plant; and (iv) a 200 MMcf/d cryogenic natural gas processing plant also located in Weld County, Colorado, which is currently under construction, or the Lucerne 2 plant. Total consideration for this transaction at closing is $1,220 million, subject to certain working capital and other customary adjustments. This transaction is expected to close in March 2014, subject to customary closing conditions, and components of the transaction may close separately.

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On August 5, 2013, we entered into a purchase and sale agreement with a 100% owned subsidiary of DCP Midstream, LLC pursuant to which the Partnership acquired all of the membership interests in DCP LaSalle Plant LLC, or the LaSalle Transaction, for consideration of $209 million, subject to certain customary purchase price adjustments. DCP LaSalle Plant LLC owns the O'Connor plant, a cryogenic natural gas processing plant with initial capacity of 110 MMcf/d, previously known as the LaSalle plant, in the DJ Basin in Weld County, Colorado. In connection with the LaSalle Transaction, we also entered into a 15-year fee-based processing agreement with an affiliate of DCP Midstream, LLC pursuant to which such affiliate agreed to pay us (i) a fixed demand charge of 75% of the plant's capacity, and (ii) a throughput fee on all volumes processed for such affiliate at the O'Connor plant. The processing agreement commenced with commercial operations of the new plant in October 2013. As of February 2014, the O'Connor plant expansion to 160 MMcf/d is mechanically complete.

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On August 5, 2013, we entered into a purchase and sale agreement with a 100% owned subsidiary of DCP Midstream, LLC pursuant to which the Partnership acquired all of the membership interests in DCP Midstream Front Range LLC, or Front Range, for consideration of $86 million, subject to certain customary purchase price adjustments. Front Range owns a 33.33% equity interest in Front Range Pipeline LLC, a joint venture with affiliates of Enterprise and Anadarko Petroleum Corporation, which was formed to construct the Front Range pipeline, a new raw NGL mix pipeline that originates in the DJ Basin and extends approximately 435 miles to Skellytown, Texas. Enterprise is the operator of the pipeline, which was placed into service in February 2014.

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On March 28, 2013, we acquired an additional 46.67% interest in the Eagle Ford system from DCP Midstream, LLC and fixed price commodity derivative hedges for a three-year period for aggregate consideration of $626 million. We have an 80% interest in the construction of the Goliad 200 MMcf/d natural gas processing plant, including fixed price commodity price hedges, representing a total investment of approximately $290 million, which was placed into service in February 2014.

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The construction of the Texas Express pipeline, of which we own a 10% interest, is complete and commenced operations in the fourth quarter of 2013. Originating near Skellytown in Carson County, Texas, the 20-inch diameter Texas Express pipeline extends approximately 580 miles to Enterprise’s natural gas liquids fractionation and storage complex at Mont Belvieu, Texas, and provides access to other third party facilities in the area.

•	Our construction of our 100% owned Eagle 200 MMcf/d natural gas processing plant is complete and commenced operations in the first quarter of 2013.

•	Our expansion plan for Discovery's Keathley Canyon natural gas gathering pipeline system is progressing and is expected to be completed in the fourth quarter of 2014.

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Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas. Our fee-based arrangements include natural gas arrangements pursuant to which we obtain natural gas at the wellhead or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the transportation fees we would otherwise charge for transportation of natural gas from the wellhead location to the delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced.

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

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

•	our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing methods or capital structure;

•	viability and performance of acquisitions and capital expenditure projects and the overall rates of return on investment opportunities; and

•	in the case of Adjusted EBITDA, the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, make cash distributions to our unitholders and general partner, and finance maintenance capital expenditures.

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

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(a)	Includes $2 million, $4 million and $5 million of lower of cost or market adjustments for the years ended December 31, 2013, 2012, and 2011, respectively.

(b)	Includes $2 million, $15 million and $1 million of lower of cost or market adjustments for the years ended December 31, 2013, 2012, and 2011, respectively.

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(a)	Includes our 80% interest in the Eagle Ford system, retrospectively adjusted. We acquired a 33.33% interest in the Eagle Ford system on November 2, 2012, and a 46.67% interest on March 28, 2013.

(b)	Includes our 100% interest in Southeast Texas, retrospectively adjusted. We acquired a 33.33% interest in Southeast Texas on January 1, 2011, and a 66.67% interest on March 30, 2012.

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

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

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(e)

Includes our share, based on our ownership percentage, of the earnings of all unconsolidated affiliates which include our 40% ownership of Discovery, 20% ownership of the Mont Belvieu 1 fractionator, 12.5% ownership of the Mont Belvieu Enterprise fractionator and 10% ownership of Texas Express. Earnings for Discovery, the Mont Belvieu 1 fractionator and Texas Express include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the entities.

(f)	Includes our share, based on our ownership percentage, of the throughput volumes and NGL production of unconsolidated affiliates.

•	$245 million increase for our Natural Gas Services segment primarily due to higher volumes, an increase attributable to commodity prices and an increase in fee revenue, partially offset by a decrease in commodity derivative activity related to hedge settlement timing on our natural gas storage and pipeline assets; and

•	$9 million increase for our NGL Logistics segment primarily due to increased throughput on certain of our pipelines and increased activity at our NGL storage facility.

•	$35 million decrease for our Wholesale Propane Logistics segment primarily due to lower propane prices and commodity derivative activity related to favorable hedge settlement timing in 2012, partially offset by increased volumes.

•	$10 million increase for our Wholesale Propane Logistics segment, primarily due to increased unit margins and exporting of propane, partially offset by a decrease related to commodity derivative activity. 2012 results reflect a non-cash lower of cost or market inventory adjustment and reduced demand; and

•	$8 million increase for our NGL Logistics segment as a result of increased throughput on certain of our pipelines and increased activity at our NGL storage facility.

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$3 million decrease for our Natural Gas Services segment, primarily related to decreased commodity derivative activity, lower commodity prices and lower volumes across certain assets, partially offset by improved NGL recoveries and an annual minimum volume commitment fee at our Eagle Ford system, a decrease in a lower of cost or market adjustment recognized in 2013 and extensive turnaround activity at our East Texas system in 2012.

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•	$730 million decrease for our Natural Gas Services segment primarily due to lower commodity prices in 2012 and the East Texas recovery settlement in 2011, partially offset by increases related to commodity derivative activity, fee revenue and volumes; and

•	$218 million decrease for our Wholesale Propane Logistics segment due to lower volumes and prices, partially offset by an increase related to commodity derivative activity.

•	$9 million increase for our NGL Logistics segment due to an increase in volumes.

•	$19 million decrease for our Natural Gas Services segment, primarily related to lower commodity prices, the East Texas recovery settlement in 2011 and decreased volumes and differences in gas quality across certain assets, partially offset by increased commodity derivative activity and increased volumes across certain assets; and

•	$9 million decrease for our Wholesale Propane Logistics segment primarily from a lack of demand.

•	$12 million increase for our NGL Logistics segment primarily as a result of increased throughput and rates on certain of our assets and our acquisition of the DJ Basin NGL fractionators, partially offset by lower volumes at certain connected processing facilities due to ethane rejection.

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(a)	Includes our 80% interest in the Eagle Ford system, retrospectively adjusted. We acquired a 33.33% interest in the Eagle Ford system on November 2, 2012, and a 46.67% interest on March 28, 2013.

(b)	Includes our 100% interest in Southeast Texas, retrospectively adjusted. We acquired a 33.33% interest in Southeast Texas on January 1, 2011, and a 66.67% interest on March 30, 2012.

(c)	Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas and NGLs. Please read “Reconciliation of Non-GAAP Measures” above.

(d)	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.

(e)	Includes our share, based on our ownership percentage, of the throughput volumes and NGL production of unconsolidated affiliates.

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•	$208 million increase primarily attributable to higher volumes and improved NGL recoveries at our Eagle Ford and East Texas systems, partially offset by lower volumes across certain assets, primarily our Southeast Texas system, and a plant turnaround at our Eagle Ford system. 2012 results reflect extensive turnaround activity at our East Texas system;

•	$176 million increase attributable to increased natural gas prices;

•	$83 million increase attributable to increased prices related to our natural gas storage and pipeline assets at our Southeast Texas and Northern Louisiana systems; and

•	$28 million increase in fee revenue primarily attributable to higher volumes at our Eagle Ford and East Texas systems, and the operation of our O'Connor plant.

•	$144 million decrease attributable to decreased NGL prices;

•	$70 million decrease attributable to decreased volumes related to our natural gas storage and pipeline assets at our Southeast Texas and Northern Louisiana systems; and

•	$36 million decrease related to commodity derivative activity. This includes unrealized commodity derivative losses in 2013 compared to gains in 2012 due to movements in forward prices of commodities for a net impact of $56 million, partially offset by an increase in realized cash settlement gains in 2013 compared to 2012 of $20 million.

•	$36 million decrease related to commodity derivative activity as discussed above;

•	$24 million decrease as a result of lower NGL prices, which primarily reflects the unhedged portion of the Eagle Ford system associated with DCP Midstream, LLC’s ownership during the year ended December 31, 2013; and

•	$2 million decrease attributable to lower volumes associated with our natural gas storage and pipeline assets at our Southeast Texas and Northern Louisiana systems; partially offset by a decrease in the lower of cost or market adjustment recognized in 2013 as compared to 2012.

•	$59 million increase as a result of growth from the operation of our fee-based O'Connor plant, higher volumes and improved NGL recoveries at our Eagle Ford and East Texas systems and an annual minimum volume commitment fee at our Eagle Ford system, partially offset by lower volumes across certain assets. 2012 results reflected extensive turnaround activity at our East Texas system.

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•	$623 million decrease attributable to the impact of lower commodity prices on our gathering and processing business;

•	$167 million decrease primarily attributable to decreased prices for physical sales related to our natural gas storage and pipeline assets, as well as a decrease in volumes; and

•	$6 million decrease as a result of the East Texas recovery settlement in 2011.

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$43 million increase related to commodity derivative activity. This includes a change in unrealized commodity derivative activity in 2012 compared to 2011 of $22 million due to movements in forward prices of commodities, and realized cash settlement gains in 2012 compared to realized cash settlement losses in 2011 for a net increase of $65 million. Included in our derivative activity are an increase in unrealized losses of $38 million and an increase in realized gains of $33 million from the predecessor’s Southeast Texas storage business;

•	$15 million in fee revenue primarily attributable to contractual amendments such that certain revenues changed from a gross presentation to a net fee presentation; and

•	$8 million increase primarily attributable to increased volumes at our Eagle Ford system, partially offset by decreased volumes across certain assets, differences in gas quality and extensive turnaround activity at our East Texas system.

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•	$92 million decrease as a result of lower commodity prices; and

•	$6 million decrease as a result of the East Texas recovery settlement in 2011.

•	$43 million increase related to commodity derivative activities as discussed in the Operating Revenues section above; and

•	$36 million increase primarily attributable to increased volumes at our Eagle Ford system, partially offset by decreased volumes and differences in gas quality across certain assets, and extensive turnaround activity at our East Texas system.

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(a)	Segment gross margin consists of total operating revenues less purchases of NGLs. Please read “Reconciliation of Non-GAAP Measures” above.

(b)

Includes our share, based on our ownership percentage, of the earnings of all unconsolidated affiliates which include our 20% ownership of the Mont Belvieu 1 fractionator, 12.5% ownership of the Mont Belvieu Enterprise fractionator and 10% ownership of Texas Express. Earnings for 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.

(c)	Includes our share, based on our ownership percentage, of the throughput volumes of unconsolidated affiliates.

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

•	$25 million decrease attributable to lower propane prices; and

•	$17 million decrease related to commodity derivative activity. This includes a decrease in realized cash settlement gains in 2013 compared to 2012 of $16 million, and unrealized commodity derivative losses in 2013 of $1 million due to movements in forward prices of commodities.

•	$7 million increase attributable to increased volumes in part due to the export of propane from our Chesapeake terminal in the first quarter of 2013. 2012 results reflect a lack of demand due to the industry’s excess inventory resulting from near record warm weather.

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•	$152 million decrease attributable to reduced sales volumes primarily as a result of a lack of demand due to the industry’s excess inventory resulting from record warm weather last heating season; and

•	$85 million decrease attributable to lower propane prices.

•	$19 million increase related to a change in unrealized commodity derivative activity of $1 million and a change in realized commodity derivative activity of $18 million.

•	cash generated from operations;

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•	cash distributions from our unconsolidated affiliates;

•	borrowings under our revolving Credit Agreement;

•	issuance of commercial paper under our Commercial Paper Program;

•	borrowings under term loans;

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

•	debt offerings; and

•	letters of credit.

•	quarterly distributions to our unitholders and general partner;

•	capital expenditures;

•	contributions to our unconsolidated affiliates to finance our share of their capital expenditures;

•	business and asset acquisitions, including transactions with DCP Midstream, LLC; 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, and letters of credit we have posted.

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•	$494 million repayment financed by the issuance of 12,650,000 common units in March 2013;

•	$434 million repayment financed by the issuance of 9,000,000 common units in August 2013; and

•	$335 million repayment financed by borrowings under our Commercial Paper Program; partially offset by

•	$209 million borrowings to fund the acquisition of the O'Connor plant;

•	$363 million net borrowings for general working capital purposes;

•	$86 million borrowings to fund the acquisition of the Front Range pipeline; and

•	$80 million borrowings primarily to reimburse DCP Midstream, LLC for its proportionate share of the capital spent to date, at closing, by the Eagle Ford system for the construction of the Goliad plant and for preformation capital expenditures.

•	$63 million borrowing to fund the acquisition of the Crossroads system; and

•	$199 million net borrowings for general working capital purposes; partially offset by

•	$234 million repayment with proceeds from the issuance of 5,148,500 common units in March 2012.

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•	$150 million borrowing to fund the acquisition of our initial 33.33% interest in Southeast Texas;

•	$30 million borrowing to fund the purchase of the DJ Basin NGL fractionators;

•	$30 million borrowing to fund the Marysville tax payment;

•	$23 million borrowing to fund the purchase of certain tangible assets and land located in the Eagle Ford Shale; and

•	$6 million net borrowings; partially offset by

•	$140 million repayment financed by the issue of 3,596,636 common units in March 2011.

•	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).

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(a)	In conjunction with our acquisitions of our East Texas and Southeast Texas systems, we entered into agreements with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse us for certain expenditures on capital projects. These reimbursements are for certain capital projects which have commenced within three years from the respective acquisition dates.

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(a)

Includes interest payments on debt securities that have been issued. These interest payments are $57 million, $107 million, $86 million, and $148 million for less than one year, one to three years, three to five years, and thereafter, respectively. The above table does not include estimated payments associated with our interest rate swaps as the repayment date and/or future interest rate are indeterminable.

(b)

Our operating lease obligations are contractual obligations, and primarily consist of our leased marine propane terminal and railcar leases, both of which provide supply and storage infrastructure for our Wholesale Propane Logistics business. Operating lease obligations also include natural gas storage in our Northern Louisiana system. The natural gas storage arrangement enables us to maximize the value between the current price of natural gas and the futures market price of natural gas.

(c)

Our purchase obligations are contractual obligations and include purchase orders for capital expenditures, various non-cancelable commitments to purchase physical quantities of propane supply for our Wholesale Propane Logistics business and other items. For contracts where the price paid is based on an index, the amount is based on the forward market prices as of December 31, 2013. Purchase obligations exclude accounts payable, accrued interest payable and other current liabilities recognized in the consolidated balance sheets. Purchase obligations also exclude current and long-term unrealized losses on derivative instruments included in the consolidated balance sheet, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity. In addition, many of our gas purchase contracts include short and long-term commitments to purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from the table.

(d)

Other long-term liabilities include $24 million of asset retirement obligations, $1 million of environmental reserves and $2 million of firm transportation commitments recognized in the December 31, 2013 consolidated balance sheet. In addition, $11 million of deferred state income taxes was excluded as cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year.

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(a)	The Inside FERC index price for natural gas delivered into the Colorado Interstate Gas (CIG) pipeline.

(b)	The Inside FERC index price for natural gas delivered into the Texas Gas Transmission pipeline in the North Louisiana area.

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

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

(e)	The Inside FERC monthly published index price for Houston Ship Channel.

(f)	The inside FERC monthly published index price for Henry Hub.

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

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•	significant adverse change in legal factors or business climate;

•	a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;

•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

•	significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;

•	a significant adverse change in the market value of an asset; or

•	a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

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(a)

Hedge method - An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations for the effective portion until the service is provided or the associated delivery period impacts earnings. For fair value hedges, the change in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations in the same category as the related hedged item.

(b)	Accrual method - An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations for changes in fair value of a contract until the service is provided or the associated delivery period impacts earnings.

(c)	Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations in gains and losses from commodity derivative activity during the current period.

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•

Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas; and fractionating, storing and transporting NGLs. Our fee-based arrangements include natural gas arrangements pursuant to which we obtain natural gas at the wellhead or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the transportation fees we would otherwise charge for transportation of natural gas from the wellhead location to the delivery point. 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

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

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

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

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

•

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

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(a)	Amounts as previously reported with 33.33% of the Eagle Ford system presented within investments in unconsolidated affiliates.

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(b)	Adjustments to present the Eagle Ford system on a consolidated basis with a 20% noncontrolling interest.

(c)	Adjustments to remove our 33.33% investment in unconsolidated affiliates.

(a)	Amounts as previously reported with 33.33% of the Eagle Ford system presented within earnings from unconsolidated affiliates.

(b)	Adjustments to present the Eagle Ford system on a consolidated basis with a 20% noncontrolling interest.

(c)	Adjustments to remove the Eagle Ford system equity earnings at 33.33% from the date of acquisition through December 31, 2012.

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(a)	Adjustments to present the Eagle Ford system on a consolidated basis with a 20% noncontrolling interest.

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(a)	The year ended December 31, 2012 includes the financial results of Crossroads for the period from January 1, 2012 through July 2, 2012.

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(a)	In connection with Phillips 66's separation from ConocoPhillips, ConocoPhillips is not considered to be a related party for periods after April 30, 2012 and Phillips 66 is considered a related party for periods starting May 1, 2012.

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

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Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.

•

Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.

•	Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.

•	Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

•	Level 3 — inputs are unobservable and considered significant to the fair value measurement.

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(a)	Included in current unrealized gains on derivative instruments in our consolidated balance sheets.

(b)	Includes short-term money market securities included in cash and cash equivalents in our consolidated balance sheets.

(c)	Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets.

(d)	Included in current unrealized losses on derivative instruments in our consolidated balance sheets.

(e)	Included in long-term unrealized losses on derivative instruments in our consolidated balance sheets.

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(a)	There were no issuances or sales of derivatives for the years ended December 31, 2013 and 2012.

(b)	Amounts transferred in and amounts transferred out are reflected at fair value as of the end of the period.

(c)	Represents the amount of total gains or losses for the year, included in gains or losses from commodity derivative activity, net, attributable to changes in unrealized gains or losses relating to assets and liabilities classified as Level 3.

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(a)	$150 million was swapped to a fixed rate obligation with fixed rates ranging from 2.94% to 2.99%, for a net effective rate of 2.25% on the $525 million of outstanding debt under our revolving credit facility as of December 31, 2012.

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•	If we were to have an effective event of default under our Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions.

•	In the event that we or DCP Midstream, LLC were to be downgraded below investment grade by at least one of the major credit rating agencies, certain of our ISDA counterparties have the right to reduce our collateral threshold to zero, potentially requiring us to fully collateralize any commodity contracts in a net liability position.

•

Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under those agreements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Credit Agreement. As of December 31, 2013, we are not a party to any agreements that would be subject to these provisions other than our Credit Agreement.

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

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(a)	Relates to Discovery, our unconsolidated affiliate.

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

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

(b)	For the year ended December 31, 2012, less than $1 million of derivative losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

(c)	Relates to Discovery, our unconsolidated affiliate.

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

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

•	plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter.

•	first, to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives a total of $0.4025 per unit for that quarter;

•	second, 13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.4375 per unit for that quarter;

•	third, 23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro rata until each unitholder receives a total of $0.525 per unit for that quarter; and

•	thereafter, 48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders.

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(a)	Includes the impact of conversion of the underlying securities, in connection with Phillip 66's separation from ConocoPhillips, granted under the 2012 LTIP.

(b)	The units vested at 150%.

(c)	Based on our December 31, 2013 estimated achievement of specified performance targets, the performance estimate for units granted in both 2013 and 2012 is 100%. The estimated forfeiture rate for units granted in both 2013 and 2012 is 10%.

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(a)	Includes the impact of conversion of the underlying securities, in connection with Phillip 66's separation from ConocoPhillips, granted under the 2012 LTIP.

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(a)

Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

(b)	For the year ended December 31, 2011, income tax expense relates primarily to the Texas margin tax and the Michigan business tax. The Michigan business tax was repealed in 2012; accordingly, income tax expense for the years ended December 31, 2013 and 2012 relates primarily to the Texas margin tax.

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

(d)

The segment information as of and for the years ended December 31, 2013, 2012 and 2011, includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas. Transfers of net assets between entities under common control 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.

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

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

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(a)	The financial information as of December 31, 2012 includes the results of our 80% interest in the Eagle Ford system, a transfer of net assets between entities under common control that was 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.

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(a)	The financial information for the year ended December 31, 2013 includes the results of our 80% interest in the Eagle Ford system, a transfer of net assets between entities under common control that was 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.

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(a)	The financial information for the year ended December 31, 2013 includes the results of our 80% interest in the Eagle Ford system, a transfer of net assets between entities under common control that was 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.

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(a)

The financial information for the year ended December 31, 2012 includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were 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.

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(a)

The financial information for the year ended December 31, 2012 includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were 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.

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(a)

The financial information for the year ended December 31, 2011 includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were 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.

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(a)

The financial information for the year ended December 31, 2011 includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were 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.

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(a)	The financial information for the year ended December 31, 2013 includes the results of our 80% interest in the Eagle Ford system, a transfer of net assets between entities under common control that was 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.

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(a)

The financial information during the year ended December 31, 2012 includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were 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.

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(a)

The financial information as of December 31, 2011, includes the results of our 80% interest in the Eagle Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the Southeast Texas storage business. These transfers of net assets between entities under common control were accounted for as if the transfers occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method.

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(a)	Principally consists of allowance for doubtful accounts, reserves against other long-term assets, which are included in other long-term assets, and other contingency liabilities, which are included in other current liabilities.

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•	reviewed and discussed the audited financial statements in this annual report on Form 10-K with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements;

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

•	received the written disclosures and the letter required by standard No. 1 of the independence standards board (independence discussions with audit committees) provided to the audit committee by Deloitte & Touche, LLP;

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•	discussed with Deloitte & Touche, LLP its independence from management and us and considered the compatibility of the provision of nonaudit service by the independent auditors with the auditors’ independence;

•	discussed with Deloitte & Touche, LLP the matters required to be discussed by statement on auditing standards No. 16 (PCAOB Auditing Standard No. 16, Communications With Audit Committees, Related Amendments to PCAOB Standards and Transitional Amendments to AU Section 380);

•	discussed with our internal auditors and Deloitte & Touche, LLP the overall scope and plans for their respective audits. The audit committee meets with the internal auditors and Deloitte & Touche, LLP, with and without management present, to discuss the results of their examinations, their evaluations of our internal controls and the overall quality of our financial reporting;

•	based on the foregoing reviews and discussions, recommended to the board of directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2013, for filing with the Securities and Exchange Commission; and

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

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•	annually review the Partnership’s goals and objectives relevant to compensation of the NEOs;

•	annually evaluate the NEO’s performance in light of the Partnership’s goals and objectives, and approve the compensation levels for the NEOs;

•	periodically evaluate the terms and administration of the Partnership’s short-term and long-term incentive plans to assure that they are structured and administered in a manner consistent with the Partnership’s goals and objectives;

•	periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;

•	retain and terminate any compensation consultant to be used to assist in the evaluation of director and NEO compensation; and

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

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

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

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

•	reward individual performance.

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(a)	Mr. van Kempen worked less than 10% of his time on the operations and management of the Partnership and the Partnership reimbursed DCP Midstream, LLC for his services under the Services Agreement.

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(a)	Mr. van Kempen worked less than 10% of his time on the operations and management of the Partnership and the Partnership reimbursed DCP Midstream, LLC for his services under the Services Agreement. Mr. van Kempen did not participate in the Partnership's STI for 2013.

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1.

Distributable Cash Flow in 2013 Budget. The achievement of our budget for distributable cash flow excluding any one-time transactions and financing costs and results from any non-budgeted acquisitions or dropdowns. We define distributable cash flow as net cash provided by or used in operating activities, less maintenance capital expenditures, net of reimbursable projects, plus or minus adjustments for non-cash mark-to-market of derivative instruments, proceeds from divestiture of assets, net income attributable to noncontrolling interest net of depreciation and income tax, net changes in operating assets and liabilities, and other adjustments to reconcile net cash provided by or used in operating activities. As a publicly traded limited partnership, our performance is generally judged on our ability to pay cash distributions to our unitholders. We use distributable cash flow because we believe it permits management to focus on the long-term sustainability and development of our assets. For this Partnership objective, the target level of performance is distributable cash flow in the 2013 budget of $255 million; the maximum level of performance is distributable cash flow in the 2013 budget of $300 million; and the minimum level of performance is distributable cash flow in the 2013 budget of $210 million. This objective accounts for 40% of each NEO's total STI.

2.

EBIT ROCE. An objective intended to capture the constant price EBIT (earnings before interest and taxes) ROCE (return on capital employed) of DCP Midstream, LLC, the owner of our General Partner. For this objective, the target level of performance is EBIT ROCE of 10.8%, the maximum level of performance is EBIT ROCE of 13.6% and the minimum level of performance is EBIT ROCE of 8.1%. This objective accounts for 25% of each NEO's total STI.

3.

Recordable Injury Rate (RIR). A safety objective covering both our assets and the assets of DCP Midstream, LLC, the owner of our General Partner and the operator of our assets. For this objective, the target level of performance during the year is an RIR of 0.52, the maximum level of performance is an RIR of 0.30 and a minimum level of performance is an RIR of 0.90. This objective accounts for 10% of each NEO's total STI.

4.

Title V Environmental Deviations. An environmental objective of non-routine air emissions, natural gas vented or flared, covering both our assets and the assets of DCP Midstream, LLC, the owner of our General Partner and operator of our assets. For this objective, we have established certain levels of emissions at the assets of DCP Midstream, LLC and the Partnership that comprise the minimum, target and maximum level of performance for this objective. This objective accounts for 5% of each NEO's total STI.

1)	Enterprise Growth. Continue to execute on the 5-year enterprise growth plan. This objective accounts for 5% of each NEO's total STI.

2)	Capital Markets. Effectively manage and adjust financial strategies and tactics to balance growth and continued near-term challenges in the industry fundamentals. This objective accounts for 5% of each NEO's total STI.

3)	Safety & Environmental Leadership. Continue to drive the safety and environmental performance culture at the DCP enterprise to an industry leading position. This objective accounts for 5% of each NEO's total STI.

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4)	Stakeholder Effectiveness. Ensure a seamless transition into a DCP enterprise management structure. This objective accounts for 5% of each NEO's total STI.

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(a)	Mr. van Kempen worked less than 10% of his time on the operations and management of the Partnership and the Partnership reimbursed DCP Midstream, LLC for his services under the Services Agreement. Mr. van Kempen did not participate in the Partnership's LTIP for 2013.

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(a)	Mr. Waldheim’s employment with the General Partner commenced on September 1, 2012. The 2012 compensation amounts represent the General Partner’s pro rata share of Mr. Waldheim’s salary, which was paid by DCP Midstream, LLC, the owner of the General Partner, and participation in DCP Midstream, LLC’s STI program.

(b)	Ms. Robeson’s employment with the General Partner commenced on May 11, 2012.

(c)

The amounts in this column reflect the grant date fair value of LTIP awards in accordance with the provisions of the FASB Accounting Standards Codification 718, Compensation - Stock Compensation, or ASC 718. PPU awards are subject to performance conditions. For PPUs granted in 2013, 2012 and 2011, the performance conditions are between 0% if the minimum level of performance is not achieved and 200% if the maximum level of performance is achieved. The maximum value of the PPUs, based on the grant date fair value, for Mr. Waldheim was $490,097 for units granted during 2013. The maximum value of the PPUs, based on the grant date fair value, for Ms. Robeson was $293,892 for units granted during 2013. The maximum value of the PPUs, based on the grant date fair value, for Mr. Richards was $175,236, $171,869 and $163,020 for units granted during 2013, 2012 and 2011, respectively.

(d)	The amounts in this column were paid during the fiscal year, with the exception of $12,001 for Mr. Richards which was payable during the year but was deferred at Mr. Richard's election.

(e)	Includes DERs, company retirement and non-qualified deferred compensation program contributions by the Partnership, the value of life insurance premiums paid by the Partnership on behalf of an executive and other deminimus compensation, which are detailed below.

(a)	Paid by the Partnership on behalf of Mr. Waldheim.

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(a)	Paid by the Partnership on behalf of Ms. Robeson.

(a)	Paid by the Partnership on behalf of Mr. Richards.

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(a)	Amounts shown represent amounts under the STI. If minimum levels of performance are not met, then the payout for one or more of the components of the STI may be zero.

(b)	The number of units shown represents units awarded under the LTIP. If minimum levels of performance are not met, then the payout may be zero.

(c)	The number of units shown represents units awarded under the LTIP and these units vest at the end of the Vesting Period provided the individual is still employed by the Partnership.

(a)

PPUs awarded February 14, 2013 and February 15, 2012; units vest in their entirety over a range of 0% to 200% on December 31, 2015 and December 31, 2014, respectively, if the specified performance conditions are satisfied. RPUs awarded February 14, 2013 and February 15, 2012, vest in their entirety on December 31, 2015 and December 31, 2014, respectively. To determine the number of unearned units and the market value, the calculation of the number of PPU’s granted on February 14, 2013 and February 15, 2012, that are expected to vest, is based on assumed performance of 200%, as the previous fiscal year performance has exceeded target performance.

(b)	Value calculated based on the closing price at December 31, 2013 of our common units at $50.35, the closing price of Spectra Energy’s common units at $35.62, and Phillips 66’s common units at $77.13.

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

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(a)

These amounts are included in the “Summary Compensation” table for the year 2013 with the exception of $33,211 for Mr. Waldheim and $7,904 for Mr. Richards, which were included in the “Summary Compensation” table for the year 2012 as they related to deferrals of 2012 STI, and $116,285 for Mr. Richards, which was included in the “Summary Compensation” table for the year 2010 as it related to deferrals of 2010 PPU and RPU.

(b)	These amounts are included in the “Summary Compensation” table for the year 2012.

(c)	The performance of executive officers non-qualified deferred compensation is linked to certain mutual funds or to the average rating of the BBB bond index at the election of the participant.

(a)	In the event that the recipient is severed or if the recipient’s job is lower in status within twelve months of the change of control.

(b)	In the event of termination for reasons of death, disability, early or normal retirement, or if the recipient is terminated by the General Partner for reasons other than cause, at least one year after the grant date.

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a)	The amounts in this column reflect the grant date fair value of LTIP awards in accordance with the provisions of ASC 718.

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•	each person who beneficially owns 5% or more of our outstanding units as of February 20, 2014;

•	all of the directors of DCP Midstream GP, LLC;

•	each Named Executive Officer of DCP Midstream GP, LLC; and

•	all directors and executive officers of DCP Midstream GP, LLC as a group.

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(a)	Unless otherwise indicated, the address for all beneficial owners in this table is 370 17th Street, Suite 2500, Denver, Colorado 80202.

(b)

DCP Midstream, LLC is the managing member of DCP LP Holdings, LLC and may, therefore, be deemed to indirectly beneficially own the units held by DCP LP Holdings, LLC. DCP Midstream, LLC disclaims beneficial ownership of all of the units owned by DCP LP Holdings, LP except to the extent of its pecuniary interest therein. The address of DCP LP Holdings, LLC and DCP Midstream, LLC is 370 17th Street, Suite 2500, Denver, Colorado 80202.

(c)	As set forth in a Schedule 13G filed on February 12, 2014. The address of Kayne Anderson Capital Advisors, L.P. is 1800 Avenue of the Stars, Third Floor, Los Angeles, California 90067.

(d)	As set forth in a Schedule 13G filed on February 10, 2014. The address of Tortoise Capital Advisors L.L.C. is 11550 Ash Street, Suite 300, Leawood, Kansas 66211.

(e)	As set forth in a Schedule 13G filed on February 4, 2014. The address of ClearBridge Investments, LLC is 620 8th Avenue New York, New York 10018

(1)	The long-term incentive plan currently permits the grant of awards covering an aggregate of 850,000 units. For more information on our long-term incentive plan, which did not require approval by our limited partners, refer to Item 11. “Executive Compensation-Components of Compensation.”

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•	approved by the conflicts committee;

•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•	fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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(a)

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

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(a)

The financial information for the year ended December 31, 2013, and the years ended December 31, 2012, 2011, 2010 and 2009 includes the results of our 80% interest in the Eagle Ford system, a transfer of net assets between entities under common control that was 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.

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1.	I have reviewed this annual report on Form 10-K of DCP Midstream Partners, LP for the year ended December 31, 2013;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

1.	I have reviewed this annual report on Form 10-K of DCP Midstream Partners, LP for the year ended December 31, 2013;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

(a)	the annual report on Form 10-K of the Partnership for the year ended December 31, 2013, filed on the date hereof with the Securities and Exchange Commission (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(b)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

(a)	the annual report on Form 10-K of the Partnership for the year ended December 31, 2013, filed on the date hereof with the Securities and Exchange Commission (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(b)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.