Exhibit 99.2

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

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our consolidated financial statements and notes included elsewhere in the Form 8-K (and related exhibits). We refer to the assets, liabilities and operations of DCP Southeast Texas Holdings, GP, or Southeast Texas, prior to our 33.33% and 66.67% acquisitions from DCP Midstream, LLC in January 2011 and March 2012, respectively, and DCP SC Texas GP, or the Eagle Ford system, prior to our 33.33% and 46.67% acquisitions from DCP Midstream, LLC in November 2012 and March 2013, respectively, as our “predecessor”.

Overview

We are a Delaware limited partnership formed by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. Our operations are organized into three business segments: Natural Gas Services, NGL Logistics and Wholesale Propane Logistics.

During 2012, we expanded our Natural Gas Services and NGL Logistics segments through approximately $1 billion in dropdowns from DCP Midstream, LLC, a third party acquisition, and organic expansion opportunities. We raised $455 million through the issuance of our common units, and $839 million through the issuance of 5 and 10-year Senior Notes, which were primarily used to finance our growth. In addition, we issued $229 million of common units to DCP Midstream as partial consideration for our dropdowns.

2012 was a challenging year from a commodity price perspective, for example, the twelve-month average New York Mercantile Exchange, or NYMEX, price of natural gas futures contracts per MMBtu was $3.54, $3.24 and $4.55 as of December 31, 2012, 2011 and 2010, respectively. The twelve-month average price per gallon for NGLs was $1.08, $1.39 and $1.10 as of December 31, 2012, 2011 and 2010, respectively, and the price of crude oil per barrel was $94.16, $95.12 and $79.53 as of December 31, 2012, 2011 and 2010, respectively. Our significant fee-based business currently representing approximately 55% of our estimated margins, plus our highly hedged commodity position, mitigated a portion of our natural gas, NGL, and condensate commodity price risk. In 2013, we will continue executing our multi-faceted growth strategy, with an emphasis on dropdowns from DCP Midstream, LLC.

Our business is impacted by both commodity prices, which we partially mitigate through a multi-year hedging program, as well as volumes of throughput and sales of natural gas and NGLs. Various factors impact both commodity prices and volumes. Commodity prices historically have been volatile and continue to be volatile. Crude oil prices have generally remained at favorable levels, while NGL prices have softened in relation to crude prices. NGLs and natural gas prices are currently below levels seen in recent years due to increasing supplies and record warm weather. Although we have not experienced a significant impact to our natural gas throughput volumes as a result of decreased commodity prices, if commodity prices remain weak for a sustained period, our natural gas throughput volumes may be impacted, particularly if producers were to shut in gas. Natural gas drilling activity levels vary by geographic area, but in general, drilling remains firm in areas with liquids rich gas. Drilling remains weak in certain areas with dry gas where low commodity prices currently do not support the economics of drilling. However, advances in technology, such as horizontal drilling and hydraulic fracturing in shale plays, have led to certain geographic areas becoming increasingly accessible. Our long-term view is that commodity prices will be at levels that we believe will support sustained or increasing levels of domestic natural gas production. We use direct NGL hedges to mitigate a significant portion of our NGL price exposure, however, weakening of the relationship of natural gas liquids to crude oil prices does somewhat impact the effectiveness of our hedging program to mitigate our exposure to price fluctuations where we use crude oil to hedge our NGL price exposure.

NGL prices are also impacted by the demand from petro-chemical and refining industries. The petro-chemical industry is making significant investment in building or expanding facilities to convert chemical plants from heavier oil-based feed stock to lighter NGL-based feed stock, including ethane. This increased demand should support increasing ethane supplies. In addition, propane export facilities are also being expanded or built, which is expected to support increasing propane supply. Although there can be, and has been, near-term volatility in NGL prices, longer term we believe there will be sufficient demand in NGLs to support increasing supply.

The global economic outlook continues to be cause for concern for U.S. financial markets and businesses and investors alike. A further slowdown in global economic growth or a potential liquidity crisis may lead to further declines in commodity prices. This uncertainty may contribute to continuing volatility in financial and commodity markets.

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Increased activity levels in liquids rich gas basins are creating capacity constraint concerns. The amount of gas we gather, compress, treat, process, transport, sell and store, or the NGLs we produce, fractionate, transport, sell 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.

Increased activity levels in liquids rich gas basins combined with access to capital markets at relatively low historical cost have enabled us to continue executing our multi-faceted growth strategy, with an emphasis on dropdowns from DCP Midstream, LLC. Our multi-faceted growth strategy may take numerous forms such as accretive dropdown opportunities from DCP Midstream, LLC, third-party acquisitions, joint venture opportunities and organic build opportunities within our footprint. Dropdowns from DCP Midstream, LLC in 2012 were approximately $1 billion.

Some of our recent growth projects include the following:

• On January 3, 2012, we acquired the remaining 49.9% interest in East Texas from DCP Midstream, LLC for $165 million.

• On March 30, 2012, we acquired the remaining 66.67% interest in the Southeast Texas joint venture for $240 million.

• On April 12, 2012, we acquired a 10% ownership interest in the Texas Express Pipeline joint venture from the operator, Enterprise Products Partners, L.P., representing a total investment of approximately $85 million.

• On July 2, 2012, we acquired the minority ownership interests in two non-operated Mont Belvieu fractionators, or the Mont Belvieu fractionators, from DCP Midstream, LLC for aggregate consideration of $200 million.

• On July 3, 2012, we acquired the Crossroads processing plant and associated gathering system from Penn Virginia Resource Partners, L.P. for $63 million.

• On November 2, 2012, we acquired a 33.33% interest in DCP SC Texas, GP, or the Eagle Ford system, from DCP Midstream, LLC and fixed price commodity derivative hedges for a three-year period for aggregate consideration of $438 million. On March 29, 2013, we acquired an additional 46.67% interest in the Eagle Ford system and fixed price commodity derivative hedges for a three-year period for aggregate consideration of $626 million. Our 80% interest in the construction of the Goliad 200 MMcf/d natural gas processing plant, including a two-year direct commodity price hedge, representing a total investment of approximately $230 million, net of the non-controlling interest portion of $60 million, is expected to be online in the first quarter of 2014.

• Our construction of our wholly owned Eagle 200 MMcf/d natural gas processing plant is mechanically complete and is in the process of commencing operations. Our expansion plan for the Discovery natural gas gathering pipeline system is also progressing and is expected to be completed in mid-2014. Once completed, both projects are expected to enhance our portfolio through additional fee-based margins.

Our capital markets execution has positioned us well in terms of both liquidity and cost of capital to execute our growth plans, including dropdown opportunities with DCP Midstream, LLC. In March, we raised $234 million, net of commissions and offering costs, through a public equity offering and $346 million through a public debt offering of 4.95% 10-year Senior Notes, which were used to finance our growth opportunities and repay borrowings on our Credit Agreement. On June 14, 2012, we filed a universal shelf registration statement on Form S-3 with the SEC with an unlimited offering amount, to replace an existing shelf registration statement. The universal shelf registration statement allows us to issue additional common units and debt securities. On July 2, 2012, we sold 4,989,802 common units in a private placement at a price of $35.55 per unit, and received proceeds of $174 million net of offering costs. During the twelve months ended December 31, 2012, we issued 1,147,654 of our common units pursuant to our equity distribution agreement, and received proceeds of $47 million, net of commissions and offering costs of $2 million. Additionally, we entered into three 2-year Term Loan agreements and borrowed $135 million, $140 million and $343 million to fund the cash portions of our acquisitions of the remaining 49.9% interest in East Texas, the Mont Belvieu fractionators and the Eagle Ford system, respectively. In November 2012, we issued $500 million of 2.50% 5-year Senior Notes, resulting in net proceeds of $494 million, which were used to repay the $140 million and $343 million Term Loan agreements. As of December 31, 2012, the unused capacity under the Credit Agreement was $474 million, which was available for general working capital purposes, providing liquidity to continue to execute on our growth plans.

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Financial results and distribution growth for the year were in line with our previously provided 2012 forecast. We raised our distributions for all four quarters, resulting in a 6.2% increase in our quarterly distribution rate for the fourth quarter of 2012 over the rate declared in the fourth quarter of 2011. The distributions reflect our business results as well as our recent execution on growth opportunities.

General Trends and Outlook

In 2013, our strategic objectives will continue to focus on maintaining stable distributable cash flows from our existing assets and executing on growth opportunities to increase our long-term distributable cash flows. We believe the key elements to stable distributable cash flows are the diversity of our asset portfolio, our significant fee-based business currently representing approximately 55% of our estimated margins, plus our highly hedged commodity position, the objective of which is to protect against downside risk in our distributable cash flows.

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance capital expenditures of between $30 million and $35 million, and approved expenditures for expansion capital of approximately $500 million, for the year ending December 31, 2013. Expansion capital expenditures include construction of the Texas Express Pipeline, Discovery’s Keathley Canyon, and the Goliad plant within the Eagle Ford system, which are shown as investments in unconsolidated affiliates, construction of the Eagle plant, expansion and upgrades to our Southeast Texas complex, and acquisitions. The board of directors may, at its discretion, approve additional growth capital during the year.

In 2013, we expect to continue to pursue a multi-faceted growth strategy, which includes maximizing opportunities provided by our partnership with DCP Midstream, LLC, pursuing strategic and accretive third party acquisitions and capitalizing on organic expansion opportunities in order to grow our distributable cash flows. Given the significant level of growth opportunities currently in DCP Midstream, LLC’s footprint, we would expect substantial emphasis on our dropdown objective over the next few years.

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

Natural Gas Gathering and Processing Margins — Except for our fee-based contracts, which may be impacted by throughput volumes, our natural gas gathering and processing profitability is dependent upon commodity prices, natural gas supply, and demand for natural gas, NGLs and condensate. Commodity prices, which are impacted by the balance between supply and demand, have historically been volatile. Throughput volumes could decline, particularly in areas with lower NGL content, should natural gas prices and drilling levels continue to experience weakness. Our long-term view is that as economic conditions improve, commodity prices should remain at levels that would support continued natural gas production in the United States. During 2012, petrochemical demand remained strong for NGLs as NGLs were a lower cost feedstock when compared to crude oil derived feedstocks. We anticipate strong demand for NGLs by the petrochemical industry will continue in 2013.

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

Wholesale Propane Supply and Demand — Due to our multiple propane supply sources, propane supply contractual arrangements, significant storage capabilities, and multiple terminal locations for wholesale propane delivery, we are generally able to provide our propane distribution customers with reliable supplies of propane during peak demand periods of tight supply, usually in the winter months when their customers consume the most propane for heating.

Factors That May Significantly Affect Our Results

Transfers of net assets between entities under common control that represent a change in reporting entity are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method. Accordingly, our consolidated financial statements have been adjusted to include the historical results of our 100% interest in Southeast Texas and 80% interest in the Eagle Ford system for all periods presented, similar to the pooling method. The financial statements of our predecessor have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessor had been operated as an unaffiliated entity.

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Natural Gas Services Segment

Our results of operations for our Natural Gas Services segment are impacted by (1) increases and decreases in the volume and quality of natural gas that we gather and transport through our systems, which we refer to as throughput, (2) the associated Btu content of our system throughput and our related processing volumes, (3) the prices of and relationship between commodities such as NGLs, crude oil and natural gas, (4) the operating efficiency and reliability of our processing facilities, (5) potential limitations on throughput volumes arising from downstream and infrastructure capacity constraints, (6) the terms of our processing contract arrangements with producers, and (7) increases and decreases in the volume, price and basis differentials of natural gas associated with our natural gas storage and pipeline assets, as well as our underlying derivatives associated with this business. This is not a complete list of factors that may impact our results of operations but, rather, are those we believe are most likely to impact those results.

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

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

The capacity on certain downstream NGL and natural gas infrastructure has tightened in recent periods and can be further constrained seasonally or when there is severe weather. Constrained market outlets may restrict us from operating our facilities optimally.

Our Natural Gas Services segment operating results are impacted by market conditions causing variability in natural gas, crude oil and NGL prices. The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs. Although the prevailing price of residue natural gas has less short-term significance to our operating results than the price of NGLs, in the long-term, the growth and sustainability of our business depends on commodity prices being at levels sufficient to provide incentives and capital for producers to explore and produce natural gas.

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

The natural gas services business is highly competitive in our markets and includes major integrated oil and gas companies, interstate and intrastate pipelines, and companies that gather, compress, treat, process, transport, store and/or market natural gas. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices for crude oil, natural gas and/or natural gas liquids. Competition is also increased in those geographic areas where our commercial contracts with our customers are shorter in length of term and therefore must be renegotiated on a more frequent basis.

NGL Logistics Segment

Our NGL Logistics segment operating results are impacted by, among other things, the throughput volumes of the NGLs we transport on our NGL pipelines and the volumes of NGLs we fractionate and store. We transport, fractionate and store NGLs primarily on a fee basis. Throughput may be negatively impacted as a result of our customers operating their processing plants in ethane rejection mode, often as a result of low commodity prices for ethane. Factors that impact the supply and demand of NGLs, as described above in our Natural Gas Services segment, may also impact the throughput and volume for our NGL Logistics segment. Our results may also be impacted as a result of non-cash lower of cost or market inventory adjustments, which occur when the market value of NGLs decline below our carrying value.

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Wholesale Propane Logistics Segment

Our Wholesale Propane Logistics segment operating results are impacted by our ability to provide our propane distribution customers with reliable supplies of propane. We use physical inventory, physical purchase agreements and financial derivative instruments, with DCP Midstream, LLC or third parties, which typically match the quantities of propane subject to fixed price sales agreements to mitigate our commodity price risk. Our results may also be impacted as a result of non-cash lower of cost or market inventory adjustments, which occur when the market value of propane declines below our carrying value. We generally recover lower of cost or market inventory adjustments in subsequent periods through the sale of inventory, or settlement of financial derivative instruments. There may be positive or negative impacts on sales volumes and gross margin from supply disruptions and weather conditions in the mid-Atlantic, upper midwestern and northeastern areas of the United States. Our annual sales volumes of propane may decline when these areas experience periods of milder weather in the winter months. Volumes may also be impacted by conservation and reduced demand in a recessionary environment.

The wholesale propane business is highly competitive in our market areas which include the mid-Atlantic, upper midwest and northeastern areas of the United States. Our competitors include major integrated oil and gas and energy companies, and interstate and intrastate pipelines.

Weather

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

Capital Markets

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

Impact of Inflation

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

Other

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

Recent Events

On January 28, 2013, we announced that the board of directors of DCP Midstream GP, LLC declared a quarterly distribution of $0.69 per unit, which was paid on February 14, 2013, to unitholders of record on February 7, 2013.

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On March 28, 2013, we acquired an additional 46.67% interest in DCP SC Texas GP, or the Eagle Ford system, from DCP Midstream, LLC and an $87 million fixed price commodity derivative hedge for a three-year period for aggregate consideration of $626 million, plus customary working capital and other purchase price adjustments. $490 million of the consideration was financed with the net proceeds from our 3.875% 10-year Senior Notes offering, $125 million was financed by the issuance at closing of an aggregate 2,789,739 of our common units to DCP Midstream, LLC and the remaining $11 million was paid with cash on hand. The $219 million excess purchase price over the carrying value of the acquired interest in the Eagle Ford system was recorded as a decrease in limited partners’ equity. We also reimbursed DCP Midstream, LLC $50 million for 46.67% of the capital spent to date by the Eagle Ford system for the construction of the Goliad plant, plus an incremental payment of $23 million as reimbursement for 46.67% of preformation capital expenditures.

Our Operations

We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into our Natural Gas Services segment, our NGL Logistics segment and our Wholesale Propane Logistics segment.

Natural Gas Services Segment

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

• Fee-based arrangements — Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing, transporting or storing natural gas. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase 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 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 our returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. 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.

In addition to the above contract types, we have keep-whole arrangements, which are estimated to generate less than 5% of our gross margin. Our equity method investment in Discovery also has keep-whole arrangements. Under the terms of a keep-whole processing contract, natural gas is gathered from the producer for processing, the NGLs and condensate are sold and the residue natural gas is returned to the producer with a Btu content equivalent to the Btu content of the natural gas gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under this type of contract, we are exposed to the frac spread. The frac spread is the difference between the value of the NGLs and condensate extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL and condensate prices are higher relative to natural gas prices when that frac spread exceeds our operating costs. Fluctuations in commodity prices are expected to continue to impact the operating costs of these entities.

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The natural gas supply for our gathering pipelines and processing plants is derived primarily from natural gas wells located in Arkansas, Colorado, Louisiana, Michigan, Oklahoma, Texas, Wyoming and the Gulf of Mexico. The Pelico system also receives natural gas produced in Texas through its interconnect with other pipelines that transport natural gas from Texas into western Louisiana. These areas have historically experienced significant levels of drilling activity, providing us with opportunities to access newly developed natural gas supplies. We identify primary suppliers as those individually representing 10% or more of our total natural gas supply. We had one supplier of natural gas representing 10% or more of our total natural gas supply during the year ended December 31, 2012. We actively seek new supplies of natural gas, both to offset natural declines in the production from connected wells and to increase throughput volume. We obtain new natural gas supplies in our operating areas by contracting for production from new wells, connecting new wells drilled on dedicated acreage, or by obtaining natural gas that has been directly received or released from other gathering systems.

We sell natural gas to marketing affiliates of natural gas pipelines, marketing affiliates of integrated oil companies, marketing affiliates of DCP Midstream, LLC, national wholesale marketers, industrial end-users and gas-fired power plants. We typically sell natural gas under market index related pricing terms. The NGLs extracted from the natural gas at our processing plants are sold at market index prices to DCP Midstream, LLC or its affiliates, or to third parties. In addition, under our merchant arrangements, various DCP Midstream LLC affiliates purchase natural gas from third parties at wellheads, pipeline interconnect and pooling points, as well as residue gas from our Minden and Ada processing plants, and then resell the aggregated natural gas to third parties.

We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. As a service to our customers, we may enter into physical fixed price natural gas purchases and sales, utilizing financial derivatives to swap this fixed price risk back to market index. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.

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

NGL Logistics Segment

Our pipelines, fractionation facilities and storage facility provide transportation, fractionation and storage services for customers, primarily on a fee basis. We have entered into contractual arrangements with DCP Midstream, LLC and others that generally require customers to pay us to transport or store NGLs pursuant to a fee-based rate that is applied to volumes. Therefore, the results of operations for this business segment are generally dependent upon the volume of product transported, fractionated or stored and the level of fees charged to customers. We do not take title to the products transported on our NGL pipelines, fractionated in our fractionation facilities or stored in our storage facility; rather, the customer retains title and the associated commodity price risk. DCP Midstream, LLC provides 100% of volumes transported on the Wattenberg and Seabreeze pipelines. For the Black Lake pipeline, any line loss or gain in NGLs is allocated to the shipper. The volumes of NGLs transported on our pipelines are dependent on the level of production of NGLs from processing plants connected to our NGL pipelines. When natural gas prices are high relative to NGL prices, it is less profitable to process natural gas because of the higher value of natural gas compared to the value of NGLs and because of the increased cost of separating the NGLs from the natural gas. As a result, we have experienced periods in the past, in which higher natural gas or lower NGL prices reduce the volume of NGLs extracted at plants connected to our NGL pipelines and, in turn, lower the NGL throughput on our assets. In the transportation markets we serve, our pipelines are the sole pipeline facility transporting NGLs from the supply source. DCP Midstream, LLC, the largest gatherer and processor in the DJ Basin, delivers NGLs to our fractionation facilities under a long-term fractionation agreement. Our storage facility in Marysville, Michigan provides storage and related services primarily to depositories operating in the liquid hydrocarbons industry.

Wholesale Propane Logistics Segment

We operate a wholesale propane logistics business in the mid-Atlantic, upper midwest and northeastern United States. We purchase large volumes of propane supply from natural gas processing plants and fractionation facilities, and crude oil refineries, primarily located in the Texas and Louisiana Gulf Coast area, Canada and other international sources, and transport these volumes of propane supply by pipeline, rail or ship to our terminals and storage facilities in the mid-Atlantic, midwest and the northeastern areas of the United States. We identify primary suppliers as those individually representing 10% or more of our total propane supply. Our four primary suppliers of propane, two of which are affiliated entities, represented approximately 88% of our propane supplied during the year ended December 31, 2012. The propane supply agreement with Spectra Energy expired on April 30, 2012. We primarily sell propane on a wholesale basis to propane distributors who in turn resell propane to their customers. We also sell propane in the wholesale market.

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Due to our multiple propane supply sources, annual and long-term propane supply purchase arrangements, significant storage capabilities, and multiple terminal locations for wholesale propane delivery, we are generally able to provide our propane distribution customers with reliable supplies of propane during periods of tight supply, such as the winter months when their customers generally consume the most propane for home heating. In particular, we generally offer our customers the ability to obtain propane supply volumes from us in the winter months that are generally significantly greater than their purchases of propane from us in the summer. We believe these factors allow us to maintain our generally favorable relationships with our customers.

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

How We Evaluate Our Operations

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

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

Reconciliation of Non-GAAP Measures

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

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

Adjusted EBITDA — We define adjusted EBITDA as net income or loss attributable to partners less interest income, noncontrolling interest in depreciation and income tax expense and non-cash commodity derivative gains, plus interest expense, income tax expense, depreciation and amortization expense and non-cash commodity derivative losses. Our adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate this measure in the same manner.

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

Adjusted Segment EBITDA — We define adjusted segment EBITDA for each segment as segment net income or loss attributable to partners less non-cash commodity derivative gains for that segment, plus depreciation and amortization expense and non-cash commodity derivative losses for that segment, adjusted for any noncontrolling interest on depreciation and amortization expense for that segment. Our adjusted segment EBITDA may not be comparable to similarly titled measures of other companies because they may not calculate adjusted segment EBITDA in the same manner.

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

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

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

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

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

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

The accompanying schedules provide reconciliations of gross margin, segment gross margin, and adjusted segment EBITDA to its most directly comparable GAAP financial measure.

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Distributable Cash Flow — 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 (see “— Liquidity and Capital Resources” for further definition of maintenance capital expenditures). Maintenance capital expenditures are capital expenditures made where we add on to or improve capital assets owned, or acquire or construct new capital assets, if such expenditures are made to maintain, including over the long-term, our operating or earnings capacity. Non-cash mark-to-market of derivative instruments is considered to be non-cash for the purpose of computing Distributable Cash Flow because settlement will not occur until future periods, and will be impacted by future changes in commodity prices and interest rates. Distributable Cash Flow is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess our ability to make cash distributions to our unitholders and our general partner. Our Distributable Cash Flow may not be comparable to a similarly titled measure of another company because other entities may not calculate Distributable Cash Flow in the same manner.

Our gross margin, segment gross margin, adjusted segment gross margin and adjusted segment EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate these measures in the same manner. The following table sets forth our reconciliation of certain non-GAAP measures:

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Reconciliation of Non-GAAP Measures

	Year Ended December 31,
	2012			2011			2010
	(Millions)
Reconciliation of net income attributable to partners to gross margin:
Net income attributable to partners	$	198		$	163		$	101
Interest expense		42			34			29
Income tax expense		1			1			2
Operating and maintenance expense		193			188			155
Depreciation and amortization expense		89			133			115
General and administrative expense		74			75			66
Other income		—			(1	)		(2	)
Other income — affiliate		—			—			(3	)
Step acquisition — equity interest re-measurement gain		—			—			(9	)
Earnings from unconsolidated affiliates		(26	)		(23	)		(23	)
Net income attributable to noncontrolling interests		13			30			12
Gross margin	$	584		$	600		$	443
Non-cash commodity derivative mark-to-market (a)	$	21		$	42		$	(10	)
Reconciliation of segment net income attributable to partners to segment gross margin:
Natural Gas Services segment:
Segment net income attributable to partners	$	237		$	211		$	164
Operating and maintenance expense		162			157			138
Depreciation and amortization expense		81			122			111
Other income		—			—			(2	)
Earnings from unconsolidated affiliates		(15	)		(23	)		(22	)
Net income attributable to noncontrolling interests		13			30			12
Segment gross margin	$	478		$	497		$	401
Non-cash commodity derivative mark-to-market (a)	$	20		$	42		$	(9	)
NGL Logistics segment:
Segment net income attributable to partners	$	53		$	29		$	17
Operating and maintenance expense		16			16			4
Depreciation and amortization expense		6			8			2
Step acquisition – equity interest re-measurement gain		—			—			(9	)
Other income		—			(1	)		—
Earnings from unconsolidated affiliates		(11	)		—			(1	)
Segment gross margin	$	64		$	52		$	13
Wholesale Propane Logistics segment:
Segment net income attributable to partners	$	25		$	33		$	17
Operating and maintenance expense		15			15			13
Depreciation and amortization expense		2			3			2
Other income — affiliate		—			—			(3	)
Segment gross margin	$	42		$	51		$	29
Non-cash commodity derivative mark-to-market (a)	$	1		$	—		$	(1	)

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

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	Year Ended December 31,
	2012			2011			2010
	(Millions)
Reconciliation of segment net income attributable to partners to adjusted segment EBITDA:
Natural Gas Services segment:
Segment net income attributable to partners	$	237		$	211		$	164
Non-cash commodity derivative mark-to-market		(20	)		(42	)		9
Depreciation and amortization expense		81			122			111
Noncontrolling interest on depreciation and income tax		(7	)		(20	)		(19	)
Adjusted segment EBITDA	$	291		$	271		$	265
NGL Logistics segment:
Segment net income attributable to partners	$	53		$	29		$	17
Depreciation and amortization expense		6			8			2
Adjusted segment EBITDA	$	59		$	37		$	19
Wholesale Propane Logistics segment:
Segment net income attributable to partners	$	25		$	33		$	17
Non-cash commodity derivative mark-to-market		(1	)		—			1
Depreciation and amortization expense		2			3			2
Adjusted segment EBITDA	$	26		$	36		$	20

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

	Year Ended December 31,
	2012		2011		2010
	(Millions)
General and administrative expense	$	17	$	19	$	14
General and administrative expense – affiliate:
Omnibus Agreement		26		10		10
Other — DCP Midstream, LLC		31		46		42
Total affiliate		57		56		52
Total	$	74	$	75	$	66

We have entered into an omnibus agreement, as amended, or the Omnibus Agreement, with DCP Midstream, LLC. Under the Omnibus Agreement, we are required to reimburse DCP Midstream, LLC for salaries of operating personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also pay DCP Midstream, LLC an annual fee under the Omnibus Agreement for centralized corporate functions performed by DCP Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering.

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On January 3, 2012, we extended the omnibus agreement through December 31, 2012 for an annual fee of $18 million, with the primary increase resulting from the acquisition of the remaining 49.9% interest in East Texas. On March 30, 2012, in conjunction with our acquisition of the remaining 66.67% interest in Southeast Texas, we increased the annual fee we pay to DCP Midstream, LLC under the agreement by $10 million, prorated for the remainder of the 2012 calendar year. These fees were previously allocated to East Texas and Southeast Texas. In July 2012, in conjunction with our acquisition of the minority ownership interests in the Mont Belvieu fractionators, we increased the annual fee we pay to DCP Midstream, LLC by less than $1 million, prorated for the remainder of the 2012 calendar year. As a result of these transactions, the annual fee payable in future years to DCP Midstream, LLC will be $29 million. The Omnibus Agreement also addresses the following matters:

• DCP Midstream, LLC’s obligation to indemnify us for certain liabilities and our obligation to indemnify DCP Midstream, LLC for certain liabilities;

• DCP Midstream, LLC’s obligation to continue to maintain its credit support for our obligations related to commercial contracts with respect to its business or operations that were in effect at December 7, 2005 until the expiration of such contracts; and

• Our general partner will have the right to agree to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses, with the concurrence of the special committee of DCP Midstream GP, LLC’s board of directors.

Before the addition of East Texas and Southeast Texas to the Omnibus Agreement, East Texas and Southeast Texas incurred general and administrative expenses directly from DCP Midstream, LLC. During each of the years ended December 31, 2011 and 2010, East Texas incurred $8 million, and during the years ended December 31, 2012, 2011 and 2010, Southeast Texas incurred $3 million, $10 million and $12 million, respectively, which includes expenses for our predecessor operations. General and administrative expenses incurred by East Texas and Southeast Texas effective January 3, 2012 and March 30, 2012, respectively, are covered by the Omnibus Agreement.

In addition to the Omnibus Agreement and amounts incurred by East Texas and Southeast Texas, we incurred other fees with DCP Midstream, LLC, which includes expenses for our predecessor operations, of $1 million for each of the years ended December 31, 2012 and 2011, and $2 million for the year ended December 31, 2010. These amounts include allocated expenses, including professional services, insurance, internal audit and various other corporate functions. The Eagle Ford system incurred $27 million in general and administrative expenses directly from DCP Midstream, LLC for each of the years ended December 31, 2012 and 2011, and $20 million in general and administrative expenses directly from DCP Midstream, LLC for the year ended December 31, 2010.

On February 14, 2013, we entered into a Services Agreement with DCP Midstream, LLC, which replaces the Omnibus Agreement, whereby DCP Midstream, LLC will continue to provide us with the general and administrative services previously provided under the Omnibus Agreement. The annual fee payable in future years to DCP Midstream, LLC under the Services Agreement will be consistent with the fee structure previously payable under the Omnibus Agreement, and will be $29 million for 2013. Pursuant to the Services Agreement, we will reimburse DCP Midstream, LLC for expenses and expenditures incurred or payments made on our behalf.

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

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Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2012, 2011 and 2010. The results of operations by segment are discussed in further detail following this consolidated overview discussion:

	Year Ended December 31,									Variance 2012 vs. 2011						Variance 2011 vs. 2010
	2012 (a)(b)			2011 (a)(b)(c)			2010 (a)(b)(c)			Increase (Decrease)			Percent			Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues (d):
Natural Gas Services (e)	$	2,282		$	3,012		$	2,710		$	(730	)		(24	)%	$	302			11	%
NGL Logistics		64			57			18			7			12	%		39			217	%
Wholesale Propane Logistics		415			633			473			(218	)		(34	)%		160			34	%
Intra-segment eliminations		—			(2	)		—			2			100	%		(2	)		(100	)%
Total operating revenues		2,761			3,700			3,201			(939	)		(25	)%		499			16	%
Gross margin (f):
Natural Gas Services		478			497			401			(19	)		(4	)%		96			24	%
NGL Logistics		64			52			13			12			23	%		39			300	%
Wholesale Propane Logistics		42			51			29			(9	)		(18	)%		22			76	%
Total gross margin		584			600			443			(16	)		(3	)%		157			35	%
Operating and maintenance expense		(193	)		(188	)		(155	)		5			3	%		33			21	%
Depreciation and amortization expense		(89	)		(133	)		(115	)		(44	)		(33	)%		18			16	%
General and administrative expense		(74	)		(75	)		(66	)		(1	)		(1	)%		9			14	%
Step acquisition — equity interest remeasurement gain		—			—			9			—			—	%		(9	)		(100	)%
Other income		—			1			2			(1	)		(100	)%		(1	)		(50	)%
Other income — affiliates		—			—			3			—			—	%		(3	)		(100	)%
Earnings from unconsolidated affiliates (h)		26			23			23			3			13	%		—			—	%
Interest expense		(42	)		(34	)		(29	)		8			24	%		5			17	%
Income tax expense		(1	)		(1	)		(2	)		—			—	%		(1	)		(50	)%
Net income attributable to noncontrolling interests		(13	)		(30	)		(12	)		(17	)		(57	)%		18			150	%
Net income attributable to partners	$	198		$	163		$	101		$	35			21	%	$	62			61	%
Other data:
Non-cash commodity derivative mark-to-market	$	21		$	42		$	(10	)	$	(21	)		(50	)%	$	52				*
Natural gas throughput (MMcf/d) (g)		2,322			1,951			1,976			371			19	%		(25	)		(1	)%
NGL gross production (Bbls/d) (g)		112,032			85,917			82,433			26,115			30	%		3,484			4	%
NGL pipelines throughput (Bbls/d) (g)		78,508			62,555			38,282			15,953			26	%		24,273			63	%
Propane sales volume (Bbls/d)		19,111			24,743			22,350			(5,632	)		(23	)%		2,393			11	%

* Percentage change is not meaningful.

(a) Includes the results of the Raywood processing plant and Liberty gathering system since June 29, 2010, the date of acquisition, the remaining 49.9% interest in East Texas, since January 3, 2012, the date of acquisition, and the Crossroads processing plant since July 3, 2012, the date of acquisition, in our Natural Gas Services segment.

Includes the results of Atlantic Energy, since July 30, 2010, the date of acquisition, in our Wholesale Propane Logistics segment.

Includes the results of our Wattenberg pipeline acquired from Buckeye Partners, L.P, since January 28, 2010, the date of acquisition, and an additional 50% interest in Black Lake acquired from an affiliate of BP PLC, since July 30, 2010, the date of acquisition, in our NGL Logistics segment. The acquisition of an additional 50% interest in Black Lake brought our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary.

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Includes the results of our Marysville NGL storage facility, our DJ Basin NGL fractionators and the Mont Belvieu fractionators since the dates of acquisition of December 30, 2010, March 24, 2011, and July 2, 2012, respectively, in our NGL Logistics segment.

(b) On January 1, 2011, we acquired an initial 33.33% interest in Southeast Texas for $150 million. On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas, and commodity derivative hedge instruments related to the Southeast Texas storage business, for aggregate consideration of $240 million, subject to certain working capital and other customary purchase price adjustments. On November 2, 2012, we acquired an initial 33.33% interest in DCP SC Texas GP, or the Eagle Ford system, for $438 million. On March 28, 2013, we acquired an additional 46.67% interest in the Eagle Ford system for $626 million. Transfers of net assets between entities under common control that represent a change in reporting entity are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method. Accordingly, our consolidated financial statements have been adjusted to include the historical results of our 80% interest in the Eagle Ford system and 100% interest in Southeast Texas for the years ended December 31, 2012, 2011 and 2010.

(c) We utilize commodity derivative instruments to provide stability to distributable cash flows for our proportionate ownership in East Texas, Southeast Texas and the Eagle Ford system. We did not utilize commodity derivative instruments for the proportionate interest in East Texas, Southeast Texas and the Eagle Ford system owned by DCP Midstream, LLC prior to our acquisition of the remaining 49.9% interest in January 2012, the remaining 66.67% interest in March 2012 and the initial 33.33% interest in November 2012, respectively. As such, the portion of East Texas, Southeast Texas and the Eagle Ford system owned by DCP Midstream, LLC in the periods presented is unhedged. Our consolidated results depict 49.9% of East Texas unhedged in 2011 and 2010 corresponding with DCP Midstream, LLC’s ownership interest in East Texas. Our consolidated results depict 100% of Southeast Texas unhedged in 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 2010 and through October 2012, and 66.67% from November 2012 through December 31, 2012, corresponding with DCP Midstream, LLC’s ownership interest in the Eagle Ford system.

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

(e) Includes the effect of the acquisition of the NGL commodity derivative hedge instruments associated with the Southeast Texas storage business, the Eagle Ford system and the Goliad plant acquired from DCP Midstream, LLC in March, November and December 2012, respectively.

(f) Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas, propane and NGLs, and segment gross margin for each segment consists of total operating revenues for that segment, less commodity purchases for that segment. Please read “How We Evaluate Our Operations” above.

(g) Includes our proportionate share of the throughput volumes and NGL production of Collbran, Jackson Pipeline Company, or Jackson, Discovery, and the Eagle Ford system.

For periods prior to July 30, 2010, includes our 50% share of the throughput volumes for Black Lake.

(h) Earnings from unconsolidated affiliates include our proportionate earnings of Discovery, the Mont Belvieu fractionators, and Crosspoint, which includes the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.

For periods prior to July 30, 2010, includes earnings for Black Lake, which include the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.

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Included in the consolidated results of operations are the noncontrolling interests which represent the third party or affiliate interests in the non-wholly-owned entities that we consolidate, which include East Texas, for the years ended December 31, 2011 and 2010, and Collbran, for the years ended December 31, 2012, 2011 and 2010, among others. Our results of operations reflect 100% of all consolidated assets, including noncontrolling interests.

Year Ended December 31, 2012 vs. Year Ended December 31, 2011

Total Operating Revenues — Total operating revenues decreased $939 million in 2012 compared to 2011 primarily as a result of the following:

• $758 million decrease primarily attributable to lower NGL and natural gas prices;

• $237 million decrease attributable to reduced Wholesale Propane Logistics segment volumes as a result of a lack of demand due to the industry’s excess inventory resulting from record warm weather last heating season, and lower propane prices; and

• $33 million decrease primarily due to lower volumes, lower gas storage revenue and the East Texas recovery settlement in 2011, partially offset by increased volumes at our Eagle Ford system and our acquisition of the Crossroads system in July 2012.

These decreases were partially offset by:

• $27 million increase in fee revenue primarily attributable to contractual amendments such that certain revenues changed from a gross presentation to a net fee presentation in our Natural Gas Services segment, as well as a result of increased throughput and rates on certain of our pipelines, the completion of the Wattenberg capital expansion project, and our acquisition of the DJ Basin NGL fractionators, partially offset by lower throughput volumes due to ethane rejection at certain connected processing facilities, in our NGL Logistics segment.

• $62 million increase related to commodity derivative activity including $83 million increase in settled derivatives offset by $21 million change in non-cash derivative mark-to-market losses. 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.

Gross Margin — Gross margin decreased $16 million in 2012 compared to 2011, primarily as a result of the following:

• $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, increased volumes at our Eagle Ford system and our acquisition of the Crossroads system in July 2012; and

• $9 million decrease for our Wholesale Propane Logistics segment primarily from a lack of demand due to the industry’s excess inventory resulting from record warm weather last heating season.

These decreases were partially offset by:

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

Operating and Maintenance Expense — Operating and maintenance expense increased in 2012 compared to 2011 primarily as a result of our acquisition of the Crossroads system in July 2012, turnaround activity at our Eagle Ford system and increased costs associated with the organic growth projects completed in 2011 at our Eagle Ford system.

Depreciation and Amortization Expense — Depreciation and amortization expense decreased in 2012 compared to 2011 primarily as a result of a change in the estimated useful lives of our assets.

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Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, representing our 40% ownership of Discovery, 20% ownership of the Mont Belvieu 1 Fractionator, 12.5% ownership of the Mont Belvieu Enterprise Fractionator, and 50% ownership in CrossPoint, increased in 2012 compared to 2011 primarily as a result of our acquisition of the Mont Belvieu Fractionators in July 2012. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin.

Net income attributable to noncontrolling interests — Net income attributable to noncontrolling interests decreased in 2012 compared to 2011 as a result of our acquisition of the remaining 49.9% of East Texas.

Year Ended December 31, 2011 vs. Year Ended December 31, 2010

Total Operating Revenues — Total operating revenues increased in 2011 compared to 2010 primarily as a result of the following:

• $290 million increase primarily attributable to higher crude and NGL prices, increased volumes on our Eagle Ford system as a result of completed organic growth projects allowing access to volumes from the Eagle Ford shale, and the East Texas recovery settlement, partially offset by reduced volumes on our Southeast Texas and Pelico systems;

• $161 million increase primarily as a result of our acquisition of Atlantic Energy, as well as higher propane prices for our Wholesale Propane Logistics segment;

• $43 million increase in transportation, processing and other revenue, which represents our fee-based revenues, primarily as a result of our acquisitions of the Marysville NGL storage facility, the DJ Basin NGL fractionators and an additional 50% interest in Black Lake, and the Wattenberg capital expansion project; and

• $5 million increase related to commodity derivative activity. This includes an increase of $54 million in unrealized gains due to movements in forward prices of commodities, offset by an increase in cash settlement losses of $49 million.

Gross Margin — Gross margin increased in 2011 compared to 2010, primarily as a result of the following:

• $96 million increase for our Natural Gas Services segment primarily as a result of higher crude oil and NGL prices, increased volumes on our Eagle Ford system as a result of completed organic growth projects allowing access to volumes from the Eagle Ford shale, the East Texas recovery settlement, commodity derivative activities, and increased volumes and NGL production across certain assets, partially offset by decreased margins in our Southeast Texas storage business, planned turnaround activity at East Texas and an extended planned third party outage at our Wyoming asset;

• $39 million increase for our NGL Logistics segment primarily as a result of our acquisitions of the Marysville NGL storage facility, the DJ Basin NGL fractionators and an additional 50% interest in Black Lake, and the Wattenberg capital expansion project; and

• $22 million increase for our Wholesale Propane Logistics segment primarily as a result of higher unit margins, increased volumes and our acquisition of Atlantic Energy. 2010 results reflect a planned outage related to our Providence terminal inspection.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2011 compared to 2010, primarily as a result of our acquisitions of the Marysville NGL storage facility, Atlantic Energy, an additional 50% interest in Black Lake and the DJ Basin NGL fractionators, the Wattenberg capital expansion project, and planned turnaround activity and environmental remediation at East Texas.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2011 compared to 2010, primarily as a result of a full year of depreciation related to the Raywood processing plant and Liberty gathering system acquired in June 2010, completion of organic growth projects allowing access to volumes from the Eagle Ford shale, and our acquisitions of the Marysville NGL storage facility, an additional 50% interest in Black Lake, the DJ Basin NGL fractionators, Atlantic Energy, and the Wattenberg capital expansion project.

17

Step acquisition — equity interest re-measurement gain — The non-cash step acquisition — equity interest re-measurement gain in 2010 resulted from our acquisition of an additional 50% interest in Black Lake bringing our ownership interest in Black Lake to 100% in our NGL Logistics segment. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we remeasured our initial 50% equity interest in Black Lake to its fair value, and recognized a non-cash gain of $9 million.

Other income — Other income in 2010 related to our reassessment of the fair value of contingent consideration for our acquisition of the Raywood processing plant and Liberty gathering system in June 2010, and an additional 5% interest in Collbran from Delta Petroleum Company, or Delta, in February 2010.

Other income — affiliates — Other income — affiliates results for 2010 reflect a $3 million payment received in the second quarter from Spectra Energy, a supplier for our Wholesale Propane Logistics segment, related to an amendment of a supply agreement to shorten the term of the agreement by two years.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates decreased in 2011 compared to 2010 primarily due to our additional interest in Black Lake. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction, we account for Black Lake as a consolidated subsidiary. Commodity derivative activity related to our unconsolidated affiliates is included in segment gross margin.

Net income attributable to noncontrolling interests — Net income attributable to noncontrolling interests increased in 2011 compared to 2010 primarily as a result of increased earnings from our Eagle Ford system and $5 million due to the East Texas recovery settlement.

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Results of Operations — Natural Gas Services Segment

This segment consists of our Northern Louisiana system, the Southern Oklahoma system, a 40% interest in Discovery, our Southeast Texas system, a 75% operating interest in our Colorado system, our Wyoming system, our East Texas system, our Michigan system, and an 80% interest in our Eagle Ford system:

	Year Ended December 31,									Variance 2012 vs. 2011						Variance 2011 vs. 2010
	2012 (a)(b)(c)			2011 (a)(b)(c)			2010 (a)(b)(c)			Increase (Decrease)			Percent			Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	2,062		$	2,850		$	2,560		$	(788	)		(28	)%	$	290			11	%
Transportation, processing and other		168			153			147			15			10	%		6			4	%
Gains from commodity derivative activity (d)		52			9			3			43			478	%		6			200	%
Total operating revenues		2,282			3,012			2,710			(730	)		(24	)%		302			11	%
Purchases of natural gas and NGLs		1,804			2,515			2,309			(711	)		(28	)%		206			9	%
Segment gross margin (e)		478			497			401			(19	)		(4	)%		96			24	%
Operating and maintenance expense		(162	)		(157	)		(138	)		5			3	%		19			14	%
Depreciation and amortization expense		(81	)		(122	)		(111	)		(41	)		(34	)%		11			10	%
Other income (expense)		—			—			2			—			—	%		(2	)		(100	)%
Earnings from unconsolidated affiliates (g)		15			23			22			(8	)		(35	)%		1			5	%
Segment net income		250			241			176			9			4	%		65			37	%
Segment net income attributable to noncontrolling interests		(13	)		(30	)		(12	)		(17	)		(57	)%		18			150	%
Segment net income attributable to partners	$	237		$	211		$	164		$	26			12	%	$	47			29	%
Other data:
Non-cash commodity derivative mark-to-market		20			42			(9	)		(22	)		(52	)%		51				*
Natural gas throughput (MMcf/d) (f)		2,322			1,951			1,976			371			19	%		(25	)		(1	)%
NGL gross production (Bbls/d) (f)		112,032			85,917			82,433			26,115			30	%		3,484			4	%

(a) Includes the results of the Raywood processing plant and Liberty gathering system since June 29, 2010, the date of acquisition, and the Crossroads processing plant since July 3, 2012, the date of acquisition.

(b) On January 1, 2011, we acquired an initial 33.33% interest in Southeast Texas for $150 million. On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas, and commodity derivative hedge instruments related to the Southeast Texas storage business, for aggregate consideration of $240 million, subject to certain working capital and other customary purchase price adjustments. On November 2, 2012, we acquired an initial 33.33% interest in DCP SC Texas GP, or the Eagle Ford system, for $438 million. On March 28, 2013, we acquired an additional 46.67% interest in the Eagle Ford system for $626 million. Transfers of net assets between entities under common control that represent a change in reporting entity are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the pooling method. Accordingly, our consolidated financial statements have been adjusted to include the historical results of our 80% interest in the Eagle Ford system and 100% interest in Southeast Texas for the years ended December 31, 2012, 2011 and 2010.

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(c) We utilize commodity derivative instruments to provide stability to distributable cash flows for our proportionate ownership in East Texas, Southeast Texas and the Eagle Ford system. We did not utilize commodity derivative instruments for the proportionate interest in East Texas, Southeast Texas and the Eagle Ford system owned by DCP Midstream, LLC prior to our acquisition of the remaining 49.9% interest in January 2012, the remaining 66.67% interest in March 2012 and the initial 33.33% interest in November 2012, respectively. As such, the portion of East Texas, Southeast Texas and the Eagle Ford system owned by DCP Midstream, LLC in the periods presented is unhedged. Our consolidated results depict 49.9% of East Texas unhedged in 2011 and 2010 corresponding with DCP Midstream, LLC’s ownership interest in East Texas. Our consolidated results depict 100% of Southeast Texas unhedged in 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 2010 and through October 2012, and 66.67% from November 2012 through December 31, 2012, corresponding with DCP Midstream, LLC’s ownership interest in the Eagle Ford system.

(d) Includes the effect of the acquisition of the NGL Hedge, contributed by DCP Midstream, LLC in April 2009. The NGL Hedge is a fixed price natural gas liquids derivative by NGL component, which commenced in April 2009 and expired in March 2010. Also included is the effect of the NGL commodity derivative hedge instruments associated with the Eagle Ford system, including the Goliad plant, acquired from DCP Midstream, LLC in November and December 2012, respectively, and commodity derivative hedge instruments associated with the Southeast Texas storage business acquired from DCP Midstream, LLC in March 2012.

(e) Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural gas and NGLs. Please read “How We Evaluate Our Operations” above.

(f) Includes our proportionate share of the throughput volumes and NGL production of Collbran, Jackson, Discovery, and the Eagle Ford system.

(g) Earnings from unconsolidated affiliates include our proportionate earnings of Discovery, and Crosspoint, which includes the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.

Year Ended December 31, 2012 vs. Year Ended December 31, 2011

Total Operating Revenues — Total operating revenues decreased $730 million in 2012 compared to 2011 primarily as a result of the following:

• $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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These decreases were partially offset by:

• $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 East Texas.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs decreased $711 million in 2012 compared to 2011 primarily as a result of lower commodity prices and decreased volumes across certain assets, partially offset by our acquisition of the Crossroads system in July 2012.

Segment Gross Margin — Segment gross margin decreased $19 million in 2012 compared to 2011, primarily as a result of the following:

• $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.

These decreases were partially offset by:

• $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 East Texas.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2012 compared to 2011 primarily as a result of our acquisition of the Crossroads system in July 2012, turnaround activity at our Eagle Ford system and increased costs associated with the organic growth projects completed in 2011 at our Eagle Ford system.

Depreciation and Amortization Expense — Depreciation and amortization expense decreased in 2012 compared to 2011 primarily as a result of a change in the estimated useful lives of our assets.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, representing our 40% ownership of Discovery and 50% ownership of CrossPoint, decreased in 2012 compared to 2011 primarily as a result of lower commodity prices and reduced throughput volumes on Discovery, partially offset by the timing of expenditures at Discovery. Settlements related to our commodity derivatives on our unconsolidated affiliates are included in segment gross margin.

Segment net income attributable to noncontrolling interests — Segment net income attributable to noncontrolling interests decreased in 2012 compared to 2011 as a result of the acquisition of the remaining 49.9% of East Texas.

Natural Gas Throughput — Natural gas transported, processed and/or treated increased in 2012 compared to 2011 primarily as a result of our acquisition of the remaining 49.9% of East Texas and the Crossroads system, partially offset by decreased volumes across certain assets and turnaround at East Texas.

NGL Gross Production — NGL production increased in 2012 compared to 2011 primarily as a result of our acquisition of the remaining 49.9% of East Texas and the Crossroads system, partially offset by decreased volumes and differences in gas quality across certain assets and turnaround at East Texas.

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Year Ended December 31, 2011 vs. Year Ended December 31, 2010

Included in the consolidated results of operations are the noncontrolling interests which represent the third party or affiliate interests in the non-wholly-owned entities that we consolidate, which include the Eagle Ford system, East Texas and Collbran, among others. Our results of operations reflect 100% of all consolidated assets, including noncontrolling interests.

Total Operating Revenues — Total operating revenues increased in 2011 compared to 2010, primarily as a result of the following:

• $271 million increase attributable to higher crude and NGL prices, which impact both sales and purchases;

• $130 million increase attributable to increased volumes on our Eagle Ford system as a result of completed organic growth projects allowing access to volumes from the Eagle Ford shale;

• $7 million increase attributable to the East Texas recovery settlement; and

• $5 million increase related to commodity derivative activity. This includes an increase of $53 million in unrealized gains due to movements in forward prices of commodities, offset by an increase in cash settlement losses of $48 million.

These increases were partially offset by:

• $111 million decrease attributable to reduced volumes on our Southeast Texas and Pelico systems, partially offset by increased volumes across certain assets and an increase in transportation, processing and other revenue.

Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs increased in 2011 compared to 2010, primarily as a result of increases in commodity prices and increased volumes across certain assets, partially offset by reduced volumes on our Southeast Texas system, which impact both purchases and sales.

Segment Gross Margin — Segment gross margin increased in 2011 compared to 2010, primarily as a result of the following:

• $76 million increase as a result of higher crude oil and NGL prices;

• $15 million increase primarily attributable to increased volumes on our Eagle Ford system as a result of completed organic growth projects allowing access to volumes from the Eagle Ford shale;

• $7 million increase attributable to the East Texas recovery settlement; and

• $5 million increase related to commodity derivative activity as discussed in the Operating Revenues section above.

These increases were partially offset by:

• $7 million decrease primarily attributable to decreased margins in our Southeast Texas storage business, planned turnaround activity at East Texas and an extended planned third party outage at our Wyoming asset, partially offset by increased volumes and NGL production across certain assets and changes in contract terms.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2011 compared to 2010 due to planned turnaround activity and environmental remediation at East Texas.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2011 compared to 2010 primarily due to a full year of depreciation related to the Raywood processing plant and Liberty gathering system acquired in June 2010, completion of organic growth projects allowing access to volumes from the Eagle Ford shale and other completed capital projects.

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Other income — Other income in 2010 related to our reassessment of the fair value of contingent consideration for our acquisition of the Raywood processing plant and Liberty gathering system in June 2010, and an additional 5% interest in Collbran from Delta Petroleum Company, or Delta, in February 2010.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, representing our 40% ownership of Discovery, remained relatively constant in 2011 compared to 2010. Commodity derivative activity related to our unconsolidated affiliates is included in segment gross margin.

Segment net income attributable to noncontrolling interests — Segment net income attributable to noncontrolling interests increased in 2011 compared to 2010 primarily as a result of increased earnings from our Eagle Ford system and $5 million due to the East Texas recovery settlement.

Natural Gas Throughput — Natural gas transported, processed and/or treated decreased in 2011 compared to 2010 primarily as a result of reduced volumes on our Pelico system; partially offset by increased volumes on our Eagle Ford system.

NGL Gross Production — NGL production increased in 2011 compared to 2010 primarily as a result of increased volumes on our Eagle Ford system, partially offset by differences in gas quality.

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Results of Operations — NGL Logistics Segment

This segment includes our Seabreeze, Wilbreeze, Wattenberg and Black Lake transportation pipelines, our 10% interest in the Texas Express NGL pipeline, our Marysville NGL storage facility, our DJ Basin NGL fractionators and our minority ownership interests in the Mont Belvieu fractionators:

	Year Ended December 31,									Variance 2012 vs. 2011						Variance 2011 vs. 2010
	2012 (b)(c)			2011 (b)(c)			2010 (c)			Increase (Decrease)			Percent			Increase (Decrease)			Percent
	(Millions, except operating data)
Operating revenues:
Sales of NGLs	$	—		$	5		$	5		$	(5	)		(100	)%	$	—			—	%
Transportation, processing and other		64			52			13			12			23	%		39			300	%
Total operating revenues		64			57			18			7			12	%		39			217	%
Purchases of NGLs		—			5			5			(5	)		(100	)%		—			—	%
Segment gross margin (a)		64			52			13			12			23	%		39			300	%
Operating and maintenance expense		(16	)		(16	)		(4	)		—			—	%		12			300	%
Depreciation and amortization expense		(6	)		(8	)		(2	)		(2	)		(25	)%		6			300	%
Step acquisition – equity interest re-measurement gain		—			—			9			—			—	%		(9	)		(100	)%
Other income		—			1			—			—			—	%		1			100	%
Earnings from unconsolidated affiliates (d)		11			—			1			11			100	%		(1	)		(100	)%
Segment net income attributable to partners	$	53		$	29		$	17		$	24			83	%	$	12			71	%
Operating data:
NGL pipelines throughput (Bbls/d) (c)		78,508			62,555			38,282			15,953			26	%		24,273			63	%

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

(b) Includes the results of our Marysville NGL storage facility and our DJ Basin NGL fractionators since the dates of acquisition of December 30, 2010 and March 24, 2011, respectively.

(c) Includes the results of our Wattenberg pipeline and our Black Lake pipeline since the dates of acquisition of January 28, 2010 and July 30, 2010, respectively.

(d) Includes our share, based on our ownership percentage, of the throughput volumes and earnings of the Mont Belvieu fractionators.

For periods prior to July 30, 2010, includes our 50% share of the throughput volumes and earnings for Black Lake. Black Lake’s earnings included the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.

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Year Ended December 31, 2012 vs. Year Ended December 31, 2011

Total Operating Revenues — Total operating revenues increased in 2012 compared to 2011 as result of increased throughput and rates on certain of our pipelines, the completion of the Wattenberg capital expansion project, and our acquisition of the DJ Basin NGL fractionators, partially offset by lower throughput volumes due to ethane rejection at certain connected processing facilities.

Segment Gross Margin — Segment gross margin increased in 2012 compared to 2011 as result of increased throughput and rates on certain of our pipelines, the completion of the Wattenberg capital expansion project, and our acquisition of the DJ Basin NGL fractionators, partially offset by lower throughput volumes due to ethane rejection at certain connected processing facilities.

Operating and Maintenance Expense — Operating and maintenance expense remained relatively constant in 2012 compared to 2011 due to the completion of the Wattenberg capital expansion project, and our acquisition of the DJ Basin NGL fractionators, offset by timing of expenditures.

Depreciation and Amortization Expense — Depreciation and amortization expense decreased in 2012 compared to 2011 primarily as a result of a change in the estimated useful lives of our assets.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, representing 20% ownership of the Mont Belvieu 1 Fractionator and 12.5% ownership of the Mont Belvieu Enterprise Fractionator, increased in 2012 compared to 2011 as a result the acquisition of the Mont Belvieu Fractionators in July 2012.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2012 compared to 2011 as a result of volume growth on our pipelines and the completion of the Wattenberg capital expansion project, partially offset by lower throughput volumes due to ethane rejection at certain connected processing facilities.

Year Ended December 31, 2011 vs. Year Ended December 31, 2010

Total Operating Revenues — Total operating revenues increased in 2011 compared to 2010, primarily as a result of our acquisitions of the Marysville NGL storage facility, the DJ Basin NGL fractionators and an additional 50% interest in Black Lake, and the Wattenberg capital expansion project.

Segment Gross Margin — Segment gross margin increased in 2011 compared to 2010, primarily as a result of our acquisitions of the Marysville NGL storage facility, the DJ Basin NGL fractionators and an additional 50% interest in Black Lake, the Wattenberg capital expansion project, and increased throughput on our pipelines.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2011 compared to 2010, primarily as a result of our acquisitions of the Marysville NGL storage facility, an additional 50% interest in Black Lake and the DJ Basin NGL fractionators, and the Wattenberg capital expansion project.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2011 compared to 2010, primarily as a result of our acquisitions of the Marysville NGL storage facility, the DJ Basin NGL fractionators, an additional 50% interest in Black Lake, and the Wattenberg capital expansion project.

Step acquisition — equity interest re-measurement gain — The non-cash step acquisition — equity interest re-measurement gain in 2010 resulted from our acquisition of an additional 50% interest in Black Lake bringing our ownership interest in Black Lake to 100%. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction we account for Black Lake as a consolidated subsidiary. As a result of acquiring an additional 50% interest in Black Lake, we remeasured our initial 50% equity interest in Black Lake to its fair value, and recognized a non-cash gain of $9 million.

Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates decreased in 2011 compared to 2010 reflecting the impact of our additional interest in Black Lake. Prior to our acquisition of an additional 50% interest in Black Lake, we accounted for Black Lake under the equity method of accounting. Subsequent to this transaction, we account for Black Lake as a consolidated subsidiary.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2011 compared to 2010 as a result of the Wattenberg capital expansion project, volume growth on our pipelines and our acquisition an additional 50% interest in Black Lake.

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Results of Operations — Wholesale Propane Logistics Segment

This segment consists of our propane terminals, which include six owned and operated rail terminals, one owned marine terminal, one leased marine terminal, one pipeline terminal and access to several open-access propane pipeline terminals:

	Year Ended December 31,									Variance 2012 vs. 2011						Variance 2011 vs. 2010
	2012 (b)			2011 (b)			2010 (b)			Increase (Decrease)			Percent			Increase (Decrease)			Percent
	(Millions, except operating data)
Operating revenues:
Sales of propane	$	397		$	634		$	474		$	(237	)		(37	)%	$	160			34	%
Transportation, processing and other		—			—			—			—			—	%		—			—	%
Gain (losses) from commodity derivative activity		18			(1	)		(1	)		19	*					—			—	%
Total operating revenues		415			633			473			(218	)		(34	)%		160			34	%
Purchases of propane		373			582			444			(209	)		(36	)%		138			31	%
Segment gross margin (a)		42			51			29			(9	)		(18	)%		22			76	%
Operating and maintenance expense		(15	)		(15	)		(13	)		—			—	%		2			15	%
Depreciation and amortization expense		(2	)		(3	)		(2	)		(1	)		(33	)%		1			50	%
Other income – affiliates		—			—			3			—			—	%		(3	)		(100	)%
Segment net income attributable to partners	$	25		$	33		$	17		$	(8	)		(24	)%	$	16			94	%
Other Data:
Non-cash commodity derivative mark-to-market		1			—			(1	)		1			100	%		1			100
Propane sales volume (Bbls/d)		19,111			24,743			22,350			(5,632	)		(23	)%		2,393			11	%

* Percentage change is not meaningful.

(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.

(b) Includes the results of our Chesapeake terminal, acquired July 30, 2010 from Atlantic Energy.

Year Ended December 31, 2012 vs. Year Ended December 31, 2011

Total Operating Revenues — Total operating revenues decreased $218 million in 2012 compared to 2011, primarily as a result of the following:

• $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.

These decreases were partially offset by:

• $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.

Purchases of Propane — Purchases of propane decreased in 2012 compared to 2011 primarily due to reduced volumes as a result of inventory build resulting from record warm weather last heating season and lower propane prices, partially offset by a non-cash lower of cost or market inventory adjustment of $15 million in 2012, offset by a significant recovery through the sale of inventory.

Segment Gross Margin — Segment gross margin decreased in 2012 compared to 2011 primarily from a lack of demand due to the industry’s excess inventory resulting from record warm weather last heating season and lower per unit margins. A non-cash lower of cost or market inventory adjustment of $15 million was offset by a significant recovery through the sale of inventory and hedging activity.

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Operating and Maintenance Expense — Operating and maintenance expense remained relatively constant in 2012 compared to 2011.

Depreciation and Amortization Expense — Depreciation and amortization expense remained relatively constant in 2012 compared to 2011.

Propane Sales Volume — Propane sales volumes decreased in 2012 compared to 2011 as a result of a lack of demand due to the industry’s excess inventory resulting from record warm weather last heating season.

Year Ended December 31, 2011 vs. Year Ended December 31, 2010

Total Operating Revenues — Total operating revenues increased in 2011 compared to 2010, primarily as a result of the following:

• $106 million increase attributable to higher propane prices, which impacts both purchases and sales; and

• $54 million increase primarily as a result of our acquisition of Atlantic Energy.

Purchases of Propane — Purchases of propane increased in 2011 compared to 2010 due to higher propane prices, which impact both sales and purchases, and our acquisition of Atlantic Energy.

Segment Gross Margin — Segment gross margin increased in 2011 compared to 2010, primarily as a result of higher unit margins, increased volumes and our acquisition of Atlantic Energy. 2010 results reflect a planned outage related to our Providence terminal inspection.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2011 compared to 2010, primarily as a result of our acquisition of Atlantic Energy.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2011 compared to 2010, primarily as a result of our acquisition of Atlantic Energy.

Other income — affiliates — Other income — affiliates results for 2010 reflect a $3 million payment received in the second quarter from Spectra Energy, a supplier for our Wholesale Propane Logistics segment, related to an amendment of a supply agreement to shorten the term of the agreement by two years.

Propane Sales Volume — Propane sales volumes increased in 2011 compared to 2010, primarily as a result of our acquisition of Atlantic Energy. 2010 results reflect a planned outage related to our Providence terminal inspection.

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Liquidity and Capital Resources

We expect our sources of liquidity to include:

• cash generated from operations;

• cash distributions from our unconsolidated affiliates;

• borrowings under our revolving Credit Agreement;

• borrowings under term loans;

• issuance of additional common units;

• debt offerings;

• guarantees issued by DCP Midstream, LLC, which reduce the amount of collateral we may be required to post with certain counterparties to our commodity derivative instruments; and

• letters of credit.

We anticipate our more significant uses of resources to include:

• capital expenditures;

• quarterly distributions to our unitholders and general partner;

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

• business and asset acquisitions; and

• collateral with counterparties to our swap contracts to secure potential exposure under these contracts, which may, at times, be significant depending on commodity price movements, and which is required to the extent we exceed certain guarantees issued by DCP Midstream, LLC and letters of credit we have posted.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure and acquisition requirements, and quarterly cash distributions for the next twelve months. In the event these sources are not sufficient, we would reduce our discretionary spending.

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

On November 10, 2011, we entered into a senior unsecured revolving credit agreement with capacity of $1 billion, which matures on November 10, 2016 (Credit Agreement). The Credit Agreement replaced our Amended and Restated Credit Agreement dated as of June 21, 2007 (the Prior Credit Agreement), which had a total borrowing capacity of $850 million. The initial borrowing under the Credit Agreement was used to repay the Partnership’s indebtedness under the Prior Credit Agreement. The Credit Agreement will be used for ongoing working capital requirements and for other general partnership purposes including acquisitions.

As of December 31, 2012, the outstanding balance on the Credit Agreement was $525 million resulting in unused revolver capacity of $474 million, which was available for general working capital purposes.

Our borrowing capacity is currently limited by the Credit Agreement’s financial covenant requirements. Except in the case of a default, which would make the borrowings under the Credit Agreement fully callable, amounts borrowed under the Credit Agreement will not mature prior to the November 10, 2016 maturity date. As of February 22, 2013, we had approximately $424 million of unused capacity under the Credit Agreement.

In November 2012, we issued $500 million of 2.50% 5-year Senior Notes due December 1, 2017. We received proceeds of $494 million, net of underwriters’ fees, related expenses and unamortized discount.

In November 2012, we entered into a 2-year Term Loan Agreement and borrowed $343 million to fund the cash portion of the acquisition of an initial 33.33% interest in the Eagle Ford system. In July 2012, we entered into a 2-year Term Loan Agreement and borrowed $140 million to fund the cash portion of the acquisition of the Mont Belvieu fractionators. In November 2012, we repaid both term loans with proceeds from our 2.50% 5-year Senior Notes.

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In March 2012, we issued $350 million of 4.95% 10-year Senior Notes due April 1, 2022. We received proceeds of $346 million, net of underwriters’ fees, related expenses and unamortized discount, which we used to fund the cash portion of the acquisition of the remaining 66.67% interest in Southeast Texas and to repay funds borrowed under our Credit Agreement and our January 3, 2012 Term Loan.

In January 2012, we entered into a 2-year Term Loan Agreement and borrowed $135 million which was used to fund the cash portion of the acquisition of the remaining 49.9% interest in East Texas. In March 2012, we repaid the term loan with proceeds from our 4.95% 10-year Senior Notes.

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

Changes in natural gas, NGL and condensate prices and the terms of our processing arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. We have mitigated a portion of our anticipated commodity price risk associated with the equity volumes from our gathering and processing activities through 2016 with fixed price commodity swaps and collar arrangements. For additional information regarding our derivative activities, please read Item 7A “— Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk — Commodity Cash Flow Protection Activities” in our Annual Report on Form 10-K for the year ended December 31, 2012 as filed with the Securities and Exchange Commission on February 27, 2013.

In August 2011, we entered into an equity distribution agreement with a financial institution, as sales agent. The agreement provides for the offer and sale from time to time, through our sales agent, common units having an aggregate offering amount of up to $150 million. As of December 31, 2012, approximately $70 million aggregate offering price of our common units remains available for sale pursuant to this equity distribution agreement. During the three months ended December 31, 2012, we issued 254,265 of our common units pursuant to the equity distribution agreement, and received proceeds of $10 million, net of commissions and offering costs of $1 million. During the year ended December 31, 2012, we issued 1,147,654 of our common units pursuant to the equity distribution agreement, and received proceeds of $47 million, net of commissions and offering costs of $2 million. During the year ended December 31, 2011, we issued 761,285 of our common units pursuant to this equity distribution agreement, and received proceeds of $30 million from the issuance of these common units, net of commissions and offering costs of $1 million.

In November 2012, we issued 1,912,663 common units to DCP Midstream, LLC as partial consideration for the acquisition of an initial 33.33% interest in the Eagle Ford system.

In July 2012, we issued 1,536,098 common units to DCP Midstream, LLC as partial consideration for the Mont Belvieu fractionators.

In July 2012, we closed a private placement of equity with a group of institutional investors in which we sold 4,989,802 common units at a price of $35.55 per unit, for a total of $177 million, and received proceeds of $174 million net of offering costs.

In June 2012, we filed a universal shelf registration statement on Form S-3 with the SEC with an unlimited offering amount, to replace an existing shelf registration statement. The universal shelf registration statement allows us to issue additional common units and debt securities. As of February 22, 2013, we have issued no equity securities under this registration statement. Our 2.50% 5-year Senior Notes were issued under this registration statement.

In March 2012, we issued 5,148,500 common units at $47.42 per unit. We received proceeds of $234 million, net of offering costs.

In March 2012, we issued 1,000,417 common units to DCP Midstream, LLC as partial consideration for the remaining 66.67% interest in Southeast Texas.

In January 2012, we issued 727,520 common units to DCP Midstream, LLC as partial consideration for the remaining 49.9% interest in East Texas.

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In March 2011, we issued 3,596,636 common units at $40.55 per unit. We received proceeds of $140 million, net of offering costs.

The counterparties to each of our commodity swap contracts are investment-grade rated financial institutions. Under these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The assessment of our position with respect to the collateral thresholds are determined on a counterparty by counterparty basis, and are impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the interrelation between the representative crude oil and natural gas forward price curves, it is not practical to determine a single pricing point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same counterparty. As of February 22, 2013, DCP Midstream, LLC had issued and outstanding parental guarantees totaling $25 million in favor of certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with these counterparties. We pay DCP Midstream, LLC a fee of 0.50% per annum on these guarantees. These parental guarantees reduce the amount of cash we may be required to post as collateral. As of February 22, 2013, we had no cash collateral posted with counterparties. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis. Predetermined collateral thresholds for commodity derivative instruments guaranteed by DCP Midstream, LLC are generally dependent on DCP Midstream, LLC’s credit rating and the thresholds would be reduced to zero in the event DCP Midstream, LLC’s credit rating were to fall below investment grade.

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

We had working capital of $23 million as of December 31, 2012, compared to a working capital deficit of $169 million as of December 31, 2011 as a result of timing of payments for trade payables. Included in these working capital amounts are net derivative working capital assets of $18 million and net derivative working capital liabilities of $19 million as of December 31, 2012 and December 31, 2011, respectively. The change in working capital is primarily attributable to the factors described above. We expect that our future working capital requirements will be impacted by these same factors.

As of December 31, 2012, we had $2 million in cash and cash equivalents. Of this balance, $1 million was held by subsidiaries we do not wholly own, which we consolidate in our financial results. Other than the cash held by these subsidiaries, this cash balance was available for general partnership purposes.

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

	Year Ended December 31,
	2012			2011			2010
	(Millions)
Net cash provided by operating activities	$	82		$	387		$	205
Net cash used in investing activities	$	(1,383	)	$	(537	)	$	(454	)
Net cash provided by financing activities	$	1,295		$	151		$	254

Our predecessor’s sources of liquidity, prior to its acquisition by us, included cash generated from operations and funding from DCP Midstream, LLC. Our predecessor’s cash receipts were deposited in DCP Midstream, LLC’s bank accounts and all cash disbursements were made from these accounts. Cash transactions for our predecessor were handled by DCP Midstream, LLC and were reflected in partners’ equity as net changes in parent advances to predecessors from DCP Midstream, LLC.

Net Cash Provided by Operating Activities — The changes in net cash provided by operating activities are attributable to our net income adjusted for non-cash charges as presented in the consolidated statements of cash flows and changes in working capital as discussed above.

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We received net cash for settlement of our commodity derivative instruments of approximately $49 million and $34 million for the years ended December 31, 2012 and 2011, respectively, and received cash of $15 million for the year ended December 31, 2010, approximately $6 million of which was associated with rebalancing our portfolio. During the year ended December 31, 2012, we made state tax payments of $1 million, and no federal tax payments. During the year ended December 31, 2011, we made federal and state tax payments of $29 million and $1 million, respectively, related to our acquisition of Marysville and the conversion of the entity’s organizational structure from a corporation to a limited liability company. In addition, we received $4 million from DCP Midstream, LLC, related to the sale of surplus equipment, for the year ended December 31, 2010.

We and our predecessors received cash distributions from unconsolidated affiliates of $24 million, $25 million and $30 million during the years ended December 31, 2012, 2011 and 2010, respectively. Earnings exceeded distributions by $2 million for the year ended December 31, 2012.

Net Cash Used in Investing Activities — Net cash used in investing activities during 2012 was comprised of: (1) acquisition expenditures of $745 million, of which $282 million is related to our acquisition of an initial 33.33% interest in the Eagle Ford system, $193 million is related to our acquisition of the remaining 66.67% interest in Southeast Texas, $120 million related to our acquisition of the remaining 49.9% interest in East Texas, $63 million related to our acquisition of Crossroads, $57 million related to the acquisition of the Goliad plant by the Eagle Ford system, and $30 million related to our acquisition of the Mont Belvieu fractionators; (2) capital expenditures of $483 million (of which our portion was $410 million and the noncontrolling interest holders’ portion and the reimbursable projects portion was $73 million); and (3) investments in unconsolidated affiliates of $158 million; partially offset by (4) proceeds from sales of assets of $2 million; and (5) a return of investment from unconsolidated affiliate of $1 million.

Net cash used in investing activities during 2011 was comprised of: (1) capital expenditures of $384 million (our portion of which was $321 million and the noncontrolling interest holders’ portion was $63 million), which includes $23 million of capital expenditures related to our Eagle Plant construction; (2) acquisition expenditures of $114 million, representing the carrying value of the net assets acquired, related to our acquisition of an initial 33.33% interest in Southeast Texas; (3) acquisition expenditures of $30 million related to our acquisition of our DJ Basin NGL fractionators and a payment of $8 million to the seller of Michigan Pipeline & Processing, LLC in relation to our contingent payment agreement; and (4) investments in unconsolidated affiliates of $8 million; partially offset by (5) proceeds from sales of assets of $5 million; and (6) a return of investment from unconsolidated affiliates of $2 million.

Net cash used in investing activities during 2010 was comprised of: (1) acquisition expenditures of $282 million related to our acquisition of Atlantic Energy, the Wattenberg NGL pipeline, Marysville, the Raywood processing plant and Liberty gathering system, and an additional 55% interest in Black Lake; (2) capital expenditures of $185 million (our portion of which was $148 million and the noncontrolling interest holders’ portion was $37 million); and (3) investments in unconsolidated affiliates of $2 million; partially offset by (4) net proceeds from sale of available-for-sale securities of $10 million; (5) proceeds from sale of assets of $4 million; and (6) a return of investment from Discovery of $1 million.

Net Cash Provided By Financing Activities — Net cash provided by financing activities during 2012 was comprised of: (1) proceeds from debt of $2,665 million, offset by repayments of $1,792 million, for net borrowing of debt of $873 million; (2) proceeds from the issuance of common units net of offering costs of $455 million; (3) net change in advances to predecessor from DCP Midstream, LLC of $355 million; (4) contributions from noncontrolling interest of $25 million; and (5) contributions from DCP Midstream, LLC of $10 million; partially offset by (6) excess purchase price over acquired assets of $225 million; (7) distributions to our unitholders and general partner of $181 million; (8) distributions to noncontrolling interests of $9 million; and (9) payment of deferred financing costs of $8 million.

During 2012, total outstanding indebtedness under our $1 billion Credit Agreement, which includes borrowings under our revolving credit facility and letters of credit issued under the Credit Agreement, was not less than $268 million and did not exceed $576 million. The weighted-average indebtedness outstanding under the Agreement Facility was $496 million, $369 million, $321 million and $455 million for the first, second, third and fourth quarters of 2012, respectively.

We had unused capacity, which is available for commitments under the Credit Agreement, of $732 million, $649 million, $699 million and $474 million at the end of the first, second, third and fourth quarters of 2012, respectively.

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During 2012, we had the following net movements on our revolving credit facility:

• $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.

Net cash provided by financing activities during 2011 was comprised of: (1) proceeds from the issuance of common units, net of offering costs, of $170 million; (2) net borrowing of debt of $99 million; (3) net change in advances to predecessor from DCP Midstream, LLC of $81 million; and (4) contributions from noncontrolling interests of $18 million; partially offset by (5) distributions to our unitholders and general partner of $132 million; (6) distributions to noncontrolling interests of $45 million; (7) excess purchase price over the acquired net assets of Southeast Texas of $36 million; and (8) payment of deferred financing costs of $4 million.

During 2011, total outstanding indebtedness under our $1 billion Credit Agreement, which includes borrowings under our revolving credit facility and letters of credit issued under the Credit Agreement, was not less than $426 million and did not exceed $591 million. The weighted-average indebtedness outstanding under the revolving credit facility was $519 million, $454 million, $484 million and $517 million for the first, second, third and fourth quarters of 2011, respectively.

We had unused capacity, which is available for commitments under the Credit Agreement of $424 million, $388 million, $373 million and $502 million at the end of the first, second, third and fourth quarters of 2011, respectively.

During 2011, we had the following net movements on our revolving credit facility:

• $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.

Net cash provided by financing activities during 2010 was comprised of: (1) borrowings of $868 million; (2) proceeds from the issuance of common units net of offering costs of $189 million; (3) net change in advances to predecessor from DCP Midstream, LLC of $151 million; (4) contributions from noncontrolling interests of $14 million; and (5) contributions from DCP Midstream, LLC of $1 million; partially offset by (6) repayments of debt of $835 million; (7) distributions to our unitholders and general partner of $102 million; (8) distributions to noncontrolling interests of $26 million; (9) purchase of additional interest in a subsidiary of $4 million; and (10) payment of deferred financing costs of $2 million.

During 2010, total outstanding indebtedness under our $850 million Prior Credit Agreement, which includes borrowings under our revolving credit facility, our term loan and letters of credit issued under the Prior Credit Agreement, was not less than $301 million and did not exceed $722 million. The weighted-average indebtedness outstanding under the revolving credit facility was $623 million, $626 million, $635 million and $348 million for the first, second, third and fourth quarters of 2010, respectively.

We had unused capacity, which is available commitments under the Prior Credit Agreement of $209 million, $235 million, $487 million and $420 million at the end of the first, second, third and fourth quarters of 2010, respectively.

During 2010, we had the following net movements on our revolving credit facility:

• $248 million repayment financed by the issue of $250 million of 3.25% Senior Notes due October 1, 2015;

• $93 million repayment financed by the issue of 2,990,000 common units in August 2010; and

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• $96 million repayment financed by the issue of 2,875,000 common units in November 2010; partially offset by

• $66 million borrowing to fund the acquisition of Atlantic Energy, which includes $17 million for propane inventory and working capital;

• $16 million net borrowings for general corporate purposes;

• $22 million borrowing to fund the acquisition of the Wattenberg pipeline;

• $17 million borrowing to fund the acquisition of an additional 55% interest in Black Lake;

• $101 million borrowing to fund the acquisition of Marysville, which includes $6 million for inventory and working capital; and

• $10 million borrowing to fund repayment of our term loan.

During 2010, we had a repayment of $10 million on our term loan under the Prior Credit Agreement and released $10 million of restricted investments which were required as collateral for the facility.

We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders and general partner. See Note 12 of the Notes to Consolidated Financial Statements in Exhibit 99.3 to this Form 8-K.

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

• maintenance capital expenditures, which are cash expenditures where we add on to or improve capital assets owned, including certain system integrity and safety improvements, or acquire or construct new capital assets if such expenditures are made to maintain, including over the long-term, our operating or earnings capacity; and

• expansion capital expenditures, which are cash expenditures for acquisitions or capital improvements (where we add on to or improve the capital assets owned, or acquire or construct new gathering lines, 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) in each case if such addition, improvement, acquisition or construction is made to increase our operating or earnings capacity.

We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance capital expenditures of between $30 million and $35 million, and approved expenditures for expansion capital of approximately $500 million, for the year ending December 31, 2013. Expansion capital expenditures include construction of the Texas Express Pipeline, Discovery’s Keathley Canyon, and the Goliad plant within the Eagle Ford system, which are shown as investments in unconsolidated affiliates, construction of the Eagle plant, expansion and upgrades to our Southeast Texas complex, and acquisitions. The board of directors may, at its discretion, approve additional growth capital during the year.

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

	Year Ended December 31, 2012						Year Ended December 31, 2011
	Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures		Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures
	(Millions)						(Millions)
Our portion	$	22	$	388	$	410	$	18	$	303	$	321
Noncontrolling interest portion and reimbursable projects (a)		8		65		73		6		57		63
Total	$	30	$	453	$	483	$	24	$	360	$	384

	Year Ended December 31, 2010
	Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures
	(Millions)
Our portion	$	11	$	137	$	148
Noncontrolling interest portion and reimbursable projects (a)		7		30		37
Total	$	18	$	167	$	185

(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.

In addition, we invested cash in unconsolidated affiliates of $158 million, $8 million and $2 million during the years ended December 31, 2012, 2011 and 2010, respectively.

Capital expenditures increased in 2012 compared to 2011 primarily as a result of construction of our Eagle Plant and acquisition integration costs.

We intend to make cash distributions to our unitholders and our general partner. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, which will include debt and common unit issuances, to fund our acquisition and expansion capital expenditures.

We expect to fund future capital expenditures with funds generated from our operations, borrowings under our Credit Agreement, the issuance of additional partnership units and the issuance of long-term debt. If these sources are not sufficient, we will reduce our discretionary spending.

Cash Distributions to Unitholders — Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all Available Cash, as defined in the partnership agreement. We made cash distributions to our unitholders and general partner, including payment to our general partner related to our incentive distribution rights, of $181 million, $132 million and $102 million during 2012, 2011 and 2010, respectively. We intend to continue making quarterly distribution payments to our unitholders and general partner to the extent we have sufficient cash from operations after the establishment of reserves.

Description of the Credit Agreement —On November 10, 2011, we entered a senior unsecured revolving credit agreement with capacity of $1 billion, which matures on November 10, 2016 (Credit Agreement). The Credit Agreement replaced our Amended and Restated Credit Agreement dated as of June 21, 2007 (the Prior Credit Agreement), which had a total borrowing capacity of $850 million. As of December 31, 2012, the outstanding balance on the Credit Agreement was $525 million resulting in unused capacity of $474 million, which was available for general working capital purposes.

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Our obligations under the Credit Agreement are unsecured. The unused portion of the Credit Agreement may be used for letters of credit up to a maximum of $500 million of outstanding letters of credit. At December 31, 2012 and 2011, we had outstanding letters of credit issued under the Credit Agreement and Prior Credit Agreement of $1 million.

We may prepay all loans at any time without penalty, subject to the reimbursement of lender breakage costs in the case of prepayment of London Interbank Offered Rate, or LIBOR, borrowings. Indebtedness under the Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.25% based on our current credit rating; or (2) (a) the base rate which shall be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1%, plus (b) an applicable margin of 0.25% based on our current credit rating. The revolving credit facility incurs an annual facility fee of 0.25% based on our current credit rating. This fee is paid on drawn and undrawn portions of the revolving credit facility.

The Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Credit Agreement) of not more than 5.0 to 1.0, and on a temporary basis for not more than three consecutive quarters (including the quarter in which such acquisition is consummated) following the consummation of asset acquisitions in the midstream energy business of not more than 5.5 to 1.0.

Description of Debt Securities — On November 27, 2012, we issued $500 million of our 2.50% 5-year Senior Notes due December 1, 2017. We received net proceeds of $494 million, net of underwriters’ fees, related expenses and unamortized discounts of $6 million, which net proceeds were used to repay our then-outstanding term loans. Interest on the notes will be paid semi-annually on June 1 and December 1 of each year, commencing June 1, 2013. The notes will mature on December 1, 2017, unless redeemed prior to maturity. The underwriters’ fees and related expenses are deferred in other long-term assets in our consolidated balance sheets and will be amortized over the term of the notes.

On March 13, 2012, we issued $350 million of our 4.95% 10-year Senior Notes due April 1, 2022. We received net proceeds of $346 million, net of underwriters’ fees, related expenses and unamortized discounts of $4 million, which we used to fund the cash portion of the acquisition of the remaining 66.67% interest in Southeast Texas and to repay funds borrowed under our Term Loan and Credit Agreement. Interest on the notes is paid semi-annually on April 1 and October 1 of each year. The notes will mature on April 1, 2022, unless redeemed prior to maturity. The underwriters’ fees and related expenses are deferred in other long-term assets in our consolidated balance sheets and will be amortized over the term of the notes.

On September 30, 2010, we issued $250 million of our 3.25% Senior Notes due October 1, 2015. We received net proceeds of $248 million, net of underwriters’ fees, related expense and unamortized discounts of $2 million, which we used to repay funds borrowed under the revolver portion of our Credit Agreement. Interest on the notes is paid semi-annually on April 1 and October 1 of each year. The notes will mature on October 1, 2015, unless redeemed prior to maturity. The underwriters’ fees and related expense are deferred in other long-term assets in our consolidated balance sheets and will be amortized over the term of the notes.

The notes are senior unsecured obligations, ranking equally in right of payment with our existing unsecured indebtedness, including indebtedness under our Credit Agreement. We are not required to make mandatory redemption or sinking fund payments with respect to any of these notes, and they are redeemable at a premium at our option.

Description of Term Loan Agreements — On November 2, 2012, we borrowed $343 million on a 2-year Term Loan Agreement (the $343 million Term Loan) to fund the cash portion of the acquisition of an initial 33.33% interest in the Eagle Ford system. On July 2, 2012, we entered into a 2-year Term Loan Agreement and borrowed $140 million (the $140 million Term Loan) to fund the cash portion of the acquisition of the Mont Belvieu fractionators. In November 2012, we repaid both the term loans with proceeds from our 2.50% 5-year Senior Notes.

On January 3, 2012, we entered into a 2-year Term Loan Agreement and borrowed $135 million which was used to fund the cash portion of the acquisition of the remaining 49.9% interest in East Texas. In March 2012, we repaid the term loan with proceeds from our 4.95% 10-year Senior Notes.

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Total Contractual Cash Obligations and Off-Balance Sheet Obligations — A summary of our total contractual cash obligations as of December 31, 2012, is as follows:

	Payments Due by Period
	Total		2013		2014-2015		2016-2017		2018 and Thereafter
	(Millions)
Long-term debt (a)	$	1,886	$	44	$	329	$	1,085	$	428
Operating lease obligations (b)		24		11		9		3		1
Purchase obligations (c)		321		213		63		45		—
Other long-term liabilities (d)		24		—		1		—		23
Total	$	2,255	$	268	$	402	$	1,133	$	452

(a) Includes interest payments on debt that has been swapped to a fixed-rate obligation and on debt securities that have been issued. These interest payments are $44 million, $79 million, $60 million, and $78 million for 2013, 2014-2015, 2016-2017, and 2018 and thereafter, respectively. Interest payments on debt that has not been swapped to a fixed-rate obligation are not included as these payments are based on floating interest rates and we cannot determine with accuracy the periodic repayment dates or the amounts of the interest payments.

(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 firm transportation arrangements and natural gas storage for our Pelico system. The firm transportation arrangements supply off-system natural gas to Pelico and 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, 2012. 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 $23 million of asset retirement obligations and $1 million of environmental reserves recognized in the consolidated balance sheet at December 31, 2012.

Off-Balance Sheet Arrangements

We have no items that are classified as off balance sheet obligations.

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Critical Accounting Policies and Estimates

Our financial statements reflect the selection and application of accounting policies that require management to make estimates and assumptions. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations. These accounting policies are described further in Note 2 of the Notes to Consolidated Financial Statements in Exhibit 99.3 to this Form 8-K.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
Inventories
Inventories, which consist of NGLs and natural gas, are recorded at the lower of weighted-average cost or market value.	Judgment is required in determining the market value of inventory, as the geographic location impacts market prices, and quoted market prices may not be available for the particular location of our inventory.	If the market value of our inventory is lower than the cost, we may be exposed to losses that could be material. If commodity prices were to decrease by 10% below our December 31, 2012 weighted-average cost, our net income would be affected by approximately $8 million.
Impairment of Goodwill
We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount.	We determine fair value using widely accepted valuation techniques, namely discounted cash flow and market multiple analyses. These techniques are also used when allocating the purchase price to acquired assets and liabilities. These types of analyses require us to make assumptions and estimates regarding industry and economic factors and the profitability of future business strategies. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations.	We completed our impairment testing of goodwill using the methodology described herein, and determined there was no impairment. We primarily use a discounted cash flow analysis to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. For certain reporting units, we may elect to first assess qualitative factors to determine whether it is more likely than not that the fair value of our reporting units is less than the carrying value. We have not recorded any impairment charges on goodwill during the year ended December 31, 2012.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
Impairment of Long-Lived Assets
We periodically evaluate whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections expected to be realized over the remaining useful life of the primary asset. The carrying amount is not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value.	Our impairment analyses may require management to apply judgment in estimating future cash flows as well as asset fair values, including forecasting useful lives of the assets, assessing the probability of different outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. These techniques are also used when allocating the purchase price to acquired assets and liabilities.	Using the impairment review methodology described herein, we have not recorded any impairment charges on long-lived assets during the year ended December 31, 2012. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge.
Impairment of Investments in Unconsolidated Affiliates
We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced a decline in value. When evidence of loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred.	Our impairment loss calculations require management to apply judgment in estimating future cash flows and asset fair values, including forecasting useful lives of the assets, assessing the probability of differing estimated outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. We assess the fair value of our unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models.	Using the impairment review methodology described herein, we have not recorded any impairment charges on investments in unconsolidated affiliates during the year ended December 31, 2012. If the estimated fair value of our unconsolidated affiliates is less than the carrying value, we would recognize an impairment loss for the excess of the carrying value over the estimated fair value.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
Accounting for Risk Management Activities and Financial Instruments
Each derivative not qualifying for the normal purchases and normal sales exception is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on derivative instruments. Derivative assets and liabilities remain classified in our consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments at fair value until the contractual settlement period impacts earnings. Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions.	When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical and the expected relationship with quoted market prices.	If our estimates of fair value are inaccurate, we may be exposed to losses or gains that could be material. A 10% difference in our estimated fair value of derivatives at December 31, 2012 would have affected net income by approximately $9 million based on our net derivative position for the year ended December 31, 2012.
Accounting for Equity-Based Compensation
Our long-term incentive plan permits for the grant of restricted units, phantom units, unit options and substitute awards. Equity-based compensation expense is recognized over the vesting period or service period of the related awards. We estimate the fair value of each award, and the number of awards that will ultimately vest, at the end of each period.	Estimating the fair value of each award, the number of awards that will ultimately vest, and the forfeiture rate requires management to apply judgment to estimate the tenure of our employees and the achievement of certain performance targets over the performance period.	If actual results are not consistent with our assumptions and judgments or our assumptions and estimates change due to new information, we may experience material changes in compensation expense.
Accounting for Asset Retirement Obligations
Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit adjusted risk free interest rate, and increases due to the passage of time based on the time value of money until the obligation is settled.	Estimating the fair value of asset retirement obligations requires management to apply judgment to evaluate the necessary retirement activities, estimate the costs to perform those activities, including the timing and duration of potential future retirement activities, and estimate the risk free interest rate. When making these assumptions, we consider a number of factors, including historical retirement costs, the location and complexity of the asset and general economic conditions.	If actual results are not consistent with our assumptions and judgments or our assumptions and estimates change due to new information, we may experience material changes in our asset retirement obligations. Establishing an asset retirement obligation has no initial impact on net income. A 10% change in depreciation and accretion expense associated with our asset retirement obligations during the year ended December 31, 2012 would have no impact on our net income.

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