¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under Exchange Act (17 CFR 240.14d-2(b))

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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(d)	Exhibits.

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(a)	The financial information for the years ended December 31, 2013, 2012, 2011, 2010 and 2009 includes the results of our Lucerne 1 plant, 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)

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;

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(b)

Includes the effect of the commodity derivative hedge instruments related to the Eagle Ford system, of which 33.33% was acquired from DCP Midstream, LLC in November 2012 and 46.67% was acquired in March 2013; the Goliad plant, of which 33.33% was acquired from DCP Midstream, LLC in December 2012 and 46.67% was acquired in March 2013; 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; the additional 46.67% interest in the Eagle Ford system prior to the date of our acquisition from DCP Midstream, LLC in March 2013; and the Lucerne 1 plant prior to the date of our acquisition from DCP Midstream, LLC in March 2014.

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On February 25, 2014, we entered into various transaction documents with DCP Midstream, LLC and its affiliates 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 these transactions at closing was $1,220 million, subject to certain working capital and other customary adjustments. These transactions closed in March 2014.

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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

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•	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 Lucerne 1 plant, retrospectively adjusted. We acquired the Lucerne 1 plant on March 28, 2014.

(b)	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.

(c)	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.

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

(e)	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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(f)

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.

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

•	$253 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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$2 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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•	$757 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.

•	$29 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 Lucerne 1 plant, retrospectively adjusted. We acquired the Lucerne 1 plant on March 28, 2014.

(b)	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.

(c)	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.

(d)	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.

(e)	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.

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

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•	$209 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;

•	$183 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

•	$29 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.

•	$145 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.

•	$60 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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•	$645 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;

•	$14 million in fee revenue primarily attributable to contractual amendments such that certain revenues changed from a gross presentation to a net fee presentation; and

•	$4 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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•	$102 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;

•	cash distributions from our unconsolidated affiliates;

•	borrowings under our revolving Credit Agreement;

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•	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

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

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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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•	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.

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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

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

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

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

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

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

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(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.

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

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

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

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

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

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

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

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

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

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(a)	There were no 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.

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Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under 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 Lucerne 1 plant, 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, 2013 includes the results of our Lucerne 1 plant and an 80% interest in the Eagle Ford system, transfers of net assets between entities under common control that 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, 2012 includes the results of our Lucerne 1 plant and our 80% interest in the Eagle Ford system, transfers of net assets between entities under common control that 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 Lucerne 1 plant and our 80% interest in the Eagle Ford system, transfers of net assets between entities under common control that 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 Lucerne 1 plant and our 80% interest in the Eagle Ford system, transfers of net assets between entities under common control that 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 Lucerne 1 plant, 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 Lucerne 1 plant, 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 Lucerne 1 plant, 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 Lucerne 1 plant, 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 Lucerne 1 plant and our 80% interest in the Eagle Ford system, transfers of net assets between entities under common control that 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 during the year ended December 31, 2012 includes the results of our Lucerne 1 plant, 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 Lucerne 1 plant, 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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(a)	The financial information for the three months ended March 31, 2014 includes the results of our Lucerne 1 plant, 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.

(a)

The financial information during the three months ended March 31, 2013 includes the results of our Lucerne 1 plant and an 80% interest in the Eagle Ford system. 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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