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 this Form 8-K. We refer to the assets, liabilities and operations of DCP East Texas Holdings, LLC, or East Texas, prior to our acquisition of an additional 25.1% limited liability company interest from DCP Midstream, LLC in April 2009, and 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, 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.

Crude oil and natural gas liquids prices continue to be volatile, but have generally remained at favorable levels, while natural gas prices have declined substantially. Natural gas drilling activity levels vary by geographic area, but in general, drilling remains robust in areas with liquids rich gas. Drilling remains depressed in certain areas with dry gas where low natural gas prices currently do not support the economics of drilling. However, advances in technology, such as horizontal drilling and fractionation 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.

The global economic outlook, particularly the European debt crisis, has become a cause for concern for US financial markets as businesses and investors alike struggle to determine the impact these troubled nations will have domestically. A slowdown in economic growth or a potential liquidity crunch may lead to further declines in commodity prices. Until an outcome in Europe is reached, this uncertainty may contribute to continuing volatility in financial and commodity markets.

Despite a somewhat tepid economy, 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 co-investment with DCP Midstream, LLC. Co-investment opportunities announced to date are approximately $700.0 million.

On January 1, 2011, we acquired a 33.33% interest in Southeast Texas from DCP Midstream, LLC for $150.0 million. The Southeast Texas system is a fully integrated midstream business which includes 675 miles of natural gas pipelines, three natural gas processing plants totaling 400 MMcf/d of processing capacity, natural gas storage assets with 9 Bcf of existing storage capacity, and NGL market deliveries direct to Exxon Mobil and to Mont Belvieu via our Black Lake NGL pipeline. On March 30, 2012, we closed on the previously announced acquisition of the remaining 66.67% interest in the Southeast Texas joint venture for $240.0 million.

On March 24, 2011, we acquired two NGL fractionation facilities, or DJ Basin NGL Fractionators, for $30.0 million. The DJ Basin NGL Fractionators, which provide fee-based margins under a long-term contract, are co-located with and operated by DCP Midstream, LLC.

The Wattenberg NGL pipeline capital expansion project, which provides fee-based margins and is part of a larger strategic investment for DCP Midstream, LLC in the DJ Basin, was completed during the second quarter.

On August 1, 2011, we reached an agreement with DCP Midstream, LLC for us to construct a 200 MMcf/d cryogenic natural gas processing plant, or the Eagle Plant, in the Eagle Ford shale. The Eagle Plant, which represents an investment of approximately $120.0 million, will enhance DCP Midstream, LLC’s existing South Texas system comprised of 5 natural gas processing plants totaling approximately 800 MMcf/d of capacity. The Eagle Plant will be the enterprise’s most efficient plant in the Eagle Ford shale. DCP Midstream, LLC will provide upstream and downstream interconnects to the plant. In support of our construction of the Eagle Plant, we entered into a 15 year fee-based processing agreement with an affiliate of DCP Midstream, LLC, which provides us with a fixed demand charge for 150 MMcf/d along with a throughput fee on all volumes processed. The Eagle Plant is expected to be online by the fourth quarter of 2012.

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On November 4, 2011, we entered into agreements with DCP Midstream, LLC, to acquire the remaining 49.9% interest in East Texas for $165.0 million. This acquisition closed on January 3, 2012.

In addition to co-investment opportunities with DCP Midstream, LLC, we have continued to capture growth opportunities in our footprint. In January 2012, Williams Partners and DCP Midstream Partners announced a $600.0 million expansion plan for the Discovery natural gas gathering pipeline system in the deepwater Gulf of Mexico. The project, which is expected to be completed in mid-2014, is supported by long-term, fee-based contracts with producers in the Lucius and Hadrian South producing fields. Our 40% ownership interest in Discovery represents a $240.0 million capital project for the Partnership.

We successfully executed our acquisition integration efforts for the two DJ Basin acquisitions, as well as for the Marysville NGL storage facility, the Chesapeake wholesale propane terminal and the Black Lake NGL pipeline, according to plan and are achieving results in line with our expectations.

Our capital markets execution has positioned us well in terms of both liquidity and cost of capital to execute our growth plans, including co-investment opportunities with DCP Midstream, LLC. In November 2011, we entered into a new $1.0 billion, five-year revolving credit facility. In 2011, we raised $169.9 million in capital through a public equity offering and issuance of common units under our equity distribution agreement, which was used to finance a portion of our growth opportunities.

Financial results and distribution growth for the year were in line with our previously provided 2011 forecast. We raised our distributions for all four quarters, resulting in a 5.3% increase in our quarterly distribution rate over the rate declared in the fourth quarter of 2010. The distributions reflect our business results as well as our recent execution on growth opportunities.

General Trends and Outlook

In 2012, 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 representing approximately 60% 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 $15.0 million and $20.0 million, and expenditures for expansion capital of between $250.0 million and $300.0 million, for the year ending December 31, 2012. Expansion capital expenditures include construction of the Eagle Plant, Discovery’s Keathley Canyon, which is shown as investments in unconsolidated affiliates, expansion and upgrades to our East Texas complex and acquisition integration projects. The board of directors may approve additional growth capital during the year, at their discretion.

In 2012, we expect to continue to pursue a multi-faceted growth strategy, which may include executing on organic opportunities around our footprint, third party acquisitions, and investment opportunities with or from our general partner in order to grow our distributable cash flows.

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

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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 2011, petrochemical demand remained strong for NGLs as NGLs were a lower cost feedstock when compared to crude oil derived feedstocks. We anticipate this continuing in 2012.

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 retail propane distribution customers with reliable supplies of propane during peak demand periods of tight supply, usually in the winter months when their retail customers consume the most propane for home 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 25.1% limited liability company interest in East Texas and 100% interest in Southeast Texas 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.

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.

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

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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 the throughput volumes of the NGLs we transport on our NGL pipelines and the volumes of NGLs we fractionate and store in our fractionation and storage facilities. 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.

Wholesale Propane Logistics Segment

Our Wholesale Propane Logistics segment operating results are impacted by our ability to provide our retail 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 inventory value. We generally recover lower of cost or market inventory adjustments in subsequent periods through the sale of inventory. 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.

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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 3, 2012, we entered into a 2-year Term Loan Agreement with Wells Fargo Bank, National Association, SunTrust Bank and The Bank of Tokyo-Mitsubishi UFJ, Ltd. as lenders. We borrowed $135.0 million under the term loan on January 3, 2012, which was used to fund the acquisition of the remaining 49.9% interest in East Texas.

On January 3, 2012, we completed the acquisition of the remaining 49.9% interest in East Texas from DCP Midstream for aggregate consideration of $165.0 million, subject to certain working capital and other customary purchase price adjustments. The transaction was financed at closing through the execution of a term loan and the issuance of 727,520 common units to DCP Midstream, LLC. Prior to the contribution of the additional interest in East Texas, we owned a 50.1% interest which we accounted for as a consolidated subsidiary. The contribution of the remaining 49.9% interest in East Texas represents a transaction between entities under common control, but does not represent a change in reporting entity. Accordingly, we will include the results of the remaining 49.9% interest in East Texas prospectively from the date of contribution.

On January 18, 2012, we, along with Williams Partners L.P., announced a planned expansion of the Discovery natural gas gathering pipeline system in the deepwater Gulf of Mexico. Discovery intends to construct the Keathley Canyon Connector, a 20-inch diameter, 215-mile subsea natural gas gathering pipeline for production from the Keathley Canyon, Walker Ridge and Green Canyon areas in the central deepwater Gulf of Mexico. The Keathley Canyon Connector will originate in the southeast portion of the Keathley Canyon area and terminate into Discovery’s 30-inch diameter mainline near South Timbalier Block 283. The pipeline will be capable of gathering more than 400 MMcf/d of natural gas. Discovery has signed long-term fee-based agreements with the Lucius and Hadrian South owners for natural gas gathering and processing for production from those fields. Construction on the project is expected to begin in 2013, with a mid-2014 expected in-service date. Total capital expenditures for the Keathley Canyon Connector are estimated to be approximately $600.0 million, of which our portion is approximately $240.0 million.

On January 26, 2012, the board of directors of the general partner declared a quarterly distribution of $0.65 per unit, payable on February 14, 2012 to unitholders of record on February 7, 2012.

On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas for aggregate consideration of $240.0 million, subject to certain working capital and other customary purchase price adjustments. $192.0 million of the aggregate purchase price was financed with a portion of the net proceeds from our 4.95% 10-year Senior Notes offering. The remaining $48.0 million consideration was financed by the issuance at closing of an aggregate of 1,000,417 of our common units. DCP Midstream, LLC also provided fixed price NGL commodity derivatives, valued at $39.5 million, for the three year period subsequent to closing the newly acquired interest. Certain of the NGL commodity derivatives were valued at $24.6 million and represent consideration for the termination of a fee-based storage arrangement we had with DCP Midstream, LLC in conjunction with our initial 33.33% interest in Southeast Texas; the remaining portion of the commodity derivatives, valued at $14.9 million, mitigate a portion of our currently anticipated commodity price risk associated with the gathering and processing portion of the 66.67% interest in Southeast Texas acquired on March 30, 2012. Prior to the acquisition of the additional interest in Southeast Texas, we owned a 33.33% interest which we accounted for as an unconsolidated affiliate using the equity method. The acquisition of the remaining 66.67% interest in Southeast Texas represents a transaction between entities under common control and a change in reporting entity. Accordingly, our consolidated financial statements have been adjusted to retrospectively include the historical results of our 100% interest in Southeast Texas and the NGL commodity derivatives associated with the storage business for all periods presented, similar to the pooling method.

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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 4% 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.

The natural gas supply for our gathering pipelines and processing plants is derived primarily from natural gas wells located in 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, 2011. 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.

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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, we use a subsidiary of DCP Midstream, LLC as our agent to purchase natural gas from third parties at pipeline interconnect 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, Seabreeze and Wilbreeze 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 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 three primary suppliers of propane, two of which are affiliated entities, represented approximately 88% of our propane supplied during the year ended December 31, 2011. 43% of our propane supply is provided by Spectra Energy. The propane supply agreement with Spectra Energy expires April 30, 2012. We sell propane on a wholesale basis to retail propane distributors who in turn resell propane to their retail customers.

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 retail propane distribution customers with reliable supplies of propane during periods of tight supply, such as the winter months when their retail 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 purchase of propane from us in the summer. We believe these factors allow us to maintain our generally favorable relationships with our customers.

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We manage our wholesale propane margins by selling propane to retail 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; and (5) distributable cash flow. Gross margin, segment gross margin, adjusted segment gross margin, adjusted 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.

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, 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.

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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 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; and

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

• 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 adjusted segment EBITDA to its most directly comparable GAAP financial measure.

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.

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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:

Reconciliation of Non-GAAP Measures	Year Ended December 31,
	2011			2010			2009
	(Millions)
Reconciliation of net income attributable to partners to gross margin:
Net income attributable to partners	$	120.8		$	91.2		$	6.1
Interest expense		33.9			29.1			28.3
Income tax expense		0.5			1.5			1.0
Operating and maintenance expense		125.7			98.3			84.2
Depreciation and amortization expense		100.6			88.1			76.9
General and administrative expense		48.3			45.8			43.1
Other (income) expense		(0.5	)		(2.0	)		0.5
Other income — affiliate		—			(3.0	)		—
Step acquisition — equity interest re-measurement gain		—			(9.1	)		—
Interest income		—			—			(0.3	)
Earnings from unconsolidated affiliates		(22.7	)		(23.8	)		(18.5	)
Net income attributable to noncontrolling interests		18.8			9.2			8.3
Gross margin	$	425.4		$	325.3		$	229.6
Non-cash commodity derivative mark-to-market (a)	$	42.1		$	(9.8	)	$	(83.4	)
Reconciliation of segment net income attributable to partners to segment gross margin:
Natural Gas Services segment:
Segment net income attributable to partners	$	142.0		$	133.8		$	34.3
Operating and maintenance expense		94.7			82.0			72.7
Depreciation and amortization expense		89.5			83.5			73.9
Other (income) expense		—			(2.0	)		0.5
Earnings from unconsolidated affiliates		(22.7	)		(23.0	)		(16.6	)
Net income attributable to noncontrolling interests		18.8			9.2			8.3
Segment gross margin	$	322.3		$	283.5		$	173.1
Non-cash commodity derivative mark-to-market (a)	$	41.8		$	(8.8	)	$	(84.2	)
NGL Logistics segment:
Segment net income attributable to partners	$	28.4		$	16.5		$	6.9
Operating and maintenance expense		15.9			3.7			1.2
Depreciation and amortization expense		8.2			2.6			1.4
Step acquisition – equity interest re-measurement gain		—			(9.1	)		—
Other income		(0.5	)		—			—
Earnings from unconsolidated affiliates		—			(0.8	)		(1.9	)
Segment gross margin	$	52.0		$	12.9		$	7.6
Wholesale Propane Logistics segment:
Segment net income attributable to partners	$	33.1		$	17.4		$	37.2
Operating and maintenance expense		15.1			12.6			10.3
Depreciation and amortization expense		2.9			1.9			1.4
Other income — affiliate		—			(3.0	)		—
Segment gross margin	$	51.1		$	28.9		$	48.9
Non-cash commodity derivative mark-to-market (a)	$	0.3		$	(1.0	)	$	0.8

(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,
	2011			2010			2009
	(Millions)
Reconciliation of segment net income attributable to partners to adjusted segment EBITDA:
Natural Gas Services segment:
Segment net income attributable to partners	$	142.0		$	133.8		$	34.3
Non-cash commodity derivative mark-to-market		(41.8	)		8.8			84.2
Depreciation and amortization expense		89.5			83.5			73.9
Noncontrolling interest on depreciation and income tax		(13.8	)		(13.3	)		(11.6	)
Adjusted segment EBITDA	$	175.9		$	212.8		$	180.8
NGL Logistics segment:
Segment net income attributable to partners	$	28.4		$	16.5		$	6.9
Depreciation and amortization expense		8.2			2.6			1.4
Adjusted segment EBITDA	$	36.6		$	19.1		$	8.3
Wholesale Propane Logistics segment:
Segment net income attributable to partners	$	33.1		$	17.4		$	37.2
Non-cash commodity derivative mark-to-market		(0.3	)		1.0			(0.8	)
Depreciation and amortization expense		2.9			1.9			1.4
Adjusted segment EBITDA	$	35.7		$	20.3		$	37.8

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,
	2011		2010		2009
	(Millions)
General and administrative expense	$	18.9	$	14.3	$	11.9
General and administrative expense – affiliate:
Omnibus Agreement		10.2		9.9		9.7
Other — DCP Midstream, LLC		18.9		21.4		21.2
Other — affiliate		0.3		0.2		0.3
Total affiliate		29.4		31.5		31.2
Total	$	48.3	$	45.8	$	43.1

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 $17.6 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 $10.3 million, prorated for the remainder of the 2012 calendar year. These fees were previously allocated to East Texas and Southeast Texas. As a result of these transactions, the annual fee payable in future years to DCP Midstream, LLC will be $27.9 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.

East Texas and Southeast Texas incur general and administrative expenses directly from DCP Midstream, LLC. During the years ended December 31, 2011, 2010 and 2009, East Texas incurred $7.5 million, $7.8 million and $8.5 million, respectively, and during the years ended December 31, 2011, 2010 and 2009, Southeast Texas incurred $10.0 million, $12.1 million and $10.8 million, respectively, for general and administrative expenses from DCP Midstream, LLC, 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, will be 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 $1.4 million, $1.5 million and $1.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. These amounts include allocated expenses, including professional services, insurance, internal audit and various other corporate functions.

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, 2011, 2010 and 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion:

	Year Ended December 31,									Variance 2011 vs. 2010						Variance 2010 vs. 2009
	2011 (a)(b)(c)			2010 (a)(b)(c)			2009 (a)(b)(c)			Increase (Decrease)			Percent			Increase (Decrease)			Percent
	(Millions, except as indicated)
Operating revenues:
Natural Gas Services (d)	$	1,670.4		$	1,617.6		$	1,119.2		$	52.8			3	%	$	498.4			45	%
NGL Logistics		56.6			17.6			10.5			39.0			222	%		7.1			68	%
Wholesale Propane Logistics		633.6			473.2			348.2			160.4			34	%		125.0			36	%
Intra-segment eliminations		(2.2	)		—			—			(2.2	)		*			—			—	%
Total operating revenues		2,358.4			2,108.4			1,477.9			250.0			12	%		630.5			43	%
Gross margin (e):
Natural Gas Services		322.3			283.5			173.1			38.8			14	%		110.4			64	%
NGL Logistics		52.0			12.9			7.6			39.1			303	%		5.3			70	%
Wholesale Propane Logistics		51.1			28.9			48.9			22.2			77	%		(20.0	)		(41	)%
Total gross margin		425.4			325.3			229.6			100.1			31	%		95.7			42	%
Operating and maintenance expense		(125.7	)		(98.3	)		(84.2	)		27.4			28	%		14.1			17	%
Depreciation and amortization expense		(100.6	)		(88.1	)		(76.9	)		12.5			14	%		11.2			15	%
General and administrative expense		(48.3	)		(45.8	)		(43.1	)		2.5			5	%		2.7			6	%
Step acquisition — equity interest remeasurement gain		—			9.1			—			(9.1	)		(100	)%		9.1			100	%
Other income (expense)		0.5			2.0			(0.5	)		(1.5	)		(75	)%		2.5			500	%
Other income — affiliates		—			3.0			—			(3.0	)		(100	)%		3.0			100	%
Earnings from unconsolidated affiliates (f)		22.7			23.8			18.5			(1.1	)		(5	)%		5.3			29	%
Interest income		—			—			0.3			—			—	%		(0.3	)		(100	)%
Interest expense		(33.9	)		(29.1	)		(28.3	)		4.8			16	%		0.8			3	%
Income tax expense		(0.5	)		(1.5	)		(1.0	)		1.0			67	%		(0.5	)		(50	)%
Net income attributable to noncontrolling interests		(18.8	)		(9.2	)		(8.3	)		9.6			104	%		0.9			11	%
Net income attributable to partners	$	120.8		$	91.2		$	6.1		$	29.6			32	%	$	85.1			*
Other data:
Non-cash commodity derivative mark-to-market	$	42.1		$	(9.8	)	$	(83.4	)	$	51.9			*		$	73.6			88	%
Natural gas throughput (MMcf/d) (f)		1,415			1,481			1,311			(66	)		(4	)%		170			13	%
NGL gross production (Bbls/d) (f)		53,064			55,845			46,464			(2,781	)		(5	)%		9,381			20	%
NGL pipelines throughput (Bbls/d) (f)		62,555			38,282			30,160			24,273			63	%		8,122			27	%
Propane sales volume (Bbls/d)		24,743			22,350			22,278			2,393			11	%		72			—	%

* Percentage change is not meaningful.

(a) Includes the results of certain companies that held natural gas gathering and treating assets purchased from MichCon Pipeline Company since November 24, 2009, the date of acquisition, and the Raywood processing plant and Liberty gathering system since June 29, 2010, 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 and our DJ Basin NGL Fractionators since the dates of acquisition of December 30, 2010 and March 24, 2011, respectively.

(b) On January 1, 2011, we acquired an initial 33.33% interest in Southeast Texas for $150.0 million. On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas and commodity derivative instruments associated with the Southeast Texas storage business for aggregate consideration of $240.0 million, subject to certain working capital and other customary purchase price adjustments. These transactions were among entities under common control. The transfers of net assets between entities under common control were accounted for as if the transfers occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method. Accordingly, our consolidated financial statements have been adjusted to include the historical results of our 100% interest in Southeast Texas for the years ended December 31, 2011, 2010 and 2009.

(c) We utilize commodity derivative instruments to provide stability to distributable cash flows for our proportionate ownership in East Texas as well as all other natural gas services assets. We did not utilize commodity derivative instruments for the proportionate interest in East Texas owned by DCP Midstream, LLC prior to our acquisition of the remaining 49.9% interest in January 2012. As such, the portion of East Texas owned by DCP Midstream, LLC in the periods presented is unhedged. Our consolidated results depict 75% of East Texas unhedged in all periods prior to the second quarter of 2009 and 49.9% of East Texas unhedged for all periods subsequent to the first quarter of 2009 corresponding with DCP Midstream, LLC’s ownership interest in East Texas in each respective period.

(d) Includes the effect of the acquisition of the NGL Hedge, contributed by DCP Midstream, LLC, in April 2009, and the NGL commodity derivative instruments associated with the Southeast Texas storage business acquired from DCP Midstream, LLC in March 2012. The NGL Hedge was a fixed price natural gas liquids derivative by NGL component, which commenced in April 2009 and expired in March 2010. The NGL Hedge was for a total of 1.9 million barrels at $66.72 per barrel.

(e) 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.

(f) Includes our proportionate share of the throughput volumes and NGL production of Collbran, Jackson Pipeline Company, or Jackson, East Texas and Discovery.

Earnings from unconsolidated affiliates include our proportionate earnings of Discovery, 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 our 50% share of the throughput volumes and earnings for Black Lake. Black Lake’s earnings include the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.

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 East Texas and Collbran, among others. Our results of operations reflect 100% of all consolidated assets, including noncontrolling interests.

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

• $160.7 million increase primarily as a result of our acquisition of Atlantic Energy, as well as higher propane prices for our Wholesale Propane Logistics segment;

• $44.4 million increase primarily attributable to higher crude and NGL prices and the East Texas recovery settlement, partially offset by reduced volumes on our Southeast Texas and Pelico systems;

• $40.1 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

• $4.8 million increase related to commodity derivative activity. This includes an increase of $54.2 million in unrealized gains due to movements in forward prices of commodities, offset by an increase in cash settlement losses of $49.4 million.

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

• $38.8 million increase for our Natural Gas Services segment primarily as a result of higher crude oil and NGL prices, commodity derivative activities, the East Texas recovery settlement, 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;

• $39.1 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

• $22.2 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, 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.

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 $9.1 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 $3.0 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.

15

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 the East Texas recovery settlement.

Year Ended December 31, 2010 vs. Year Ended December 31, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:

• $126.6 million increase primarily attributable to higher propane prices and our acquisition of Atlantic Energy in July 2010, which impact both sales and purchases, partially offset by a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather;

• $419.3 million increase primarily attributable to higher commodity prices, which impact both sales and purchases, an increase in NGL production, and increased volumes on our Southeast Texas system, partially offset by changes in contract mix, increased fuel consumption, differences in gas quality, the impact of volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter, as well as a decrease in natural gas sales volumes across certain assets. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project;

• $59.2 million increase related to commodity derivative activity. This increase includes a decrease in unrealized losses of $70.8 million due to movements in forward prices of commodities, partially offset by a decrease in realized cash settlement gains of $11.6 million due to generally higher average prices of commodities in 2010; and

• $25.4 million increase in transportation, processing and other revenue, which represents our fee-based revenues, primarily as a result of increased throughput volumes due to our Michigan and Wattenberg acquisitions, our acquisition of an additional 50% interest in Black Lake, our organic growth project in the Piceance Basin, as well as the renegotiation of commodity sensitive contracts to fee-based contracts.

Gross Margin — Gross margin increased in 2010 compared to 2009, primarily as a result of the following:

• $110.4 million increase for our Natural Gas Services segment, primarily related to commodity derivative activity as explained in the operating revenue section above, higher commodity prices, increased volumes on our Southeast Texas system, increased fee-based throughput volumes resulting from the Michigan acquisition, our organic growth project in the Piceance Basin and the renegotiation of commodity sensitive contracts to fee-based contracts, partially offset by reduced natural gas basis spreads, increased fuel consumption, decreased natural gas volumes and differences in gas quality across certain of our assets, as well as the impact of volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and operational downtime; and

• $5.3 million increase for our NGL Logistics segment as a result of higher volumes from our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

These increases were partially offset by:

• $20.0 million decrease for our Wholesale Propane Logistics segment. 2010 results reflect a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather. 2009 results reflect increased spot sales volumes and significantly higher per unit margins, approximately $6.0 million of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008.

16

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009 primarily as a result of our Michigan acquisition and integration costs, increased costs at our Southeast Texas system as a result of the acquisition of the Raywood processing plant and Liberty gathering system in June 2010, turnaround activities at certain assets, our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of our capital projects completed in 2009, our Michigan acquisition, the acquisition of the Raywood processing plant and Liberty gathering system in June 2010, our Atlantic Energy acquisition, our Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

Step acquisition — equity interest re-measurement gain — Step acquisition — equity interest re-measurement gain results 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 gain of $9.1 million.

Other income — Other income in 2010 relates 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 increased due to a $3.0 million payment received in the second quarter of 2010 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 increased in 2010 compared to 2009, primarily as a result of increased earnings from Discovery. Settlements related to our commodity derivatives on unconsolidated affiliates are included in segment gross margin.

Net income attributable to noncontrolling interests — Net income attributable to noncontrolling interests includes the impact of organic growth from our Piceance Basin expansion project, offset by volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather in the first quarter, increased fuel consumption and differences in gas quality at East Texas in 2010. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas.

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Results of Operations — Natural Gas Services Segment

This segment consists of our Northern Louisiana system, our Southern Oklahoma system, our Wyoming system, our Michigan system, our Southeast Texas system, our 50.1% interest in the East Texas system, our 75% interest in the Colorado system, and our 40% limited liability company interest in Discovery:

	Year Ended December 31,									Variance 2011 vs. 2010						Variance 2010 vs. 2009
	2011 (a)(b)(c)			2010 (a)(b)(c)			2009 (a)(b)(c)			Increase (Decrease)			Percent			Increase (Decrease)		Percent
	(Millions, except as indicated)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	1,541.3		$	1,496.7		$	1,079.1		$	44.6			3	%	$	417.6		39	%
Transportation, processing and other		120.2			117.1			97.0			3.1			3	%		20.1		21	%
Gains (losses) from commodity derivative activity (d)		8.9			3.8			(56.9	)		5.1			134	%		60.7		107	%
Total operating revenues		1,670.4			1,617.6			1,119.2			52.8			3	%		498.4		45	%
Purchases of natural gas and NGLs		1,348.1			1,334.1			946.1			14.0			1	%		388.0		41	%
Segment gross margin (e)		322.3			283.5			173.1			38.8			14	%		110.4		64	%
Operating and maintenance expense		(94.7	)		(82.0	)		(72.7	)		12.7			15	%		9.3		13	%
Depreciation and amortization expense		(89.5	)		(83.5	)		(73.9	)		6.0			7	%		9.6		13	%
Other income (expense)		—			2.0			(0.5	)		(2.0	)		(100	)%		2.5		500	%
Earnings from unconsolidated affiliates (f)		22.7			23.0			16.6			(0.3	)		(1	)%		6.4		39	%
Segment net income		160.8			143.0			42.6			17.8			12	%		100.4		236	%
Segment net income attributable to noncontrolling interests		(18.8	)		(9.2	)		(8.3	)		9.6			104	%		0.9		11	%
Segment net income attributable to partners	$	142.0		$	133.8		$	34.3		$	8.2			6	%	$	99.5		290	%
Other data:
Natural gas throughput (MMcf/d) (f)		1,415			1,481			1,311			(66	)		(4	)%		170		13	%
NGL gross production (Bbls/d) (f)		53,064			55,845			46,464			(2,781	)		(5	)%		9,381		20	%

* Percentage change is not meaningful.

(a) Includes the results of certain companies that held natural gas gathering and treating assets purchased from MichCon Pipeline Company since November 24, 2009, the date of acquisition, and the Raywood processing plant and Liberty gathering system since June 29, 2010, the date of acquisition.

(b) On January 1, 2011, we acquired an initial 33.33% interest in Southeast Texas for $150.0 million. On March 30, 2012, we acquired the remaining 66.67% interest in Southeast Texas and commodity derivatives associated with the Southeast Texas storage business for aggregate consideration of $240.0 million, subject to certain working capital and other customary purchase price adjustments. These transactions were among entities under common control. The transfers of net assets between entities under common control were accounted for as if the transfers occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information similar to the pooling method. Accordingly, our consolidated financial statements have been adjusted to include the historical results of our 100% interest in Southeast Texas for the years ended December 31, 2011, 2010 and 2009.

(c) We utilize commodity derivative instruments to provide stability to distributable cash flows for our proportional ownership in East Texas as well as all other natural gas services assets. We did not utilize commodity derivative instruments for the proportionate interest in East Texas owned by DCP Midstream, LLC prior to our acquisition of the remaining 49.9% interest in January 2012. As such, the portion of East Texas owned by DCP Midstream, LLC in the periods presented is unhedged. Our consolidated results depict 75% of East Texas unhedged in all periods prior to the second quarter of 2009 and 49.9% of East Texas unhedged for all periods subsequent to the first quarter of 2009 corresponding with DCP Midstream, LLC’s ownership interest in East Texas in each respective period.

(d) Includes the effect of the acquisition of the NGL Hedge, contributed by DCP Midstream, LLC in April

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2009, and the NGL commodity derivative instruments associated with the Southeast Texas storage business acquired from DCP Midstream, LLC in March 2012. The NGL Hedge is a fixed price natural gas liquids derivative by NGL component, which commenced in April 2009 and expired in March 2010.

(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, East Texas and Discovery.

Earnings from unconsolidated affiliates include our proportionate share of the earnings of Discovery, 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 our 50% share of the throughput volumes and earnings for Black Lake. Black Lake’s earnings include the accretion of the net difference between the carrying amount of the investment and the underlying equity of the investment.

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 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:

• $154.4 million increase attributable to higher crude and NGL prices, which impact both sales and purchases;

• $5.1 million increase related to commodity derivative activity. This includes an increase of $52.9 million in unrealized gains due to movements in forward prices of commodities, offset by an increase in cash settlement losses of $47.8 million; and

• $6.6 million increase attributable to the East Texas recovery settlement.

These increases were partially offset by:

• $113.3 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, 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:

• $34.3 million increase as a result of higher crude oil and NGL prices;

• $6.6 million increase attributable to the East Texas recovery settlement; and

• $5.1 million increase related to commodity derivative activity as discussed in the Operating Revenues section above.

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These increases were partially offset by:

• $7.2 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 and completed capital projects.

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, with $4.6 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.

NGL Gross Production — NGL production decreased in 2011 compared to 2010 primarily as a result of differences in gas quality.

Year Ended December 31, 2010 vs. Year Ended December 31, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:

• $295.7 million increase attributable to increased commodity prices, which impact both sales and purchases;

• $91.9 million increase due primarily to increased volumes on our Southeast Texas system, partially offset by the impact of changes in contract mix, increased fuel consumption, differences in gas quality, a decrease in natural gas sales volume across certain of assets, as well as volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas, and our Wyoming pipeline integrity and system enhancement project;

• $60.7 million increase related to commodity derivative activity. This increase includes a decrease in unrealized losses of $72.7 million due to movements in forward prices of commodities, partially offset by a decrease in realized cash settlement gains of $12.0 million due to generally higher average prices of commodities in 2010;

• $30.0 million increase as a result of increased NGL production and a change to a contract with an affiliate in the Piceance Basin, such that certain revenues changed from a net presentation in transportation, processing and other to a gross presentation in sales of natural gas, NGLs and condensate; and

• $20.1 million increase primarily as a result of increased fee-based throughput volumes resulting from the Michigan acquisition, our organic growth project in the Piceance Basin, as well as the renegotiation of commodity sensitive contracts to fee-based contracts partially offset by decreases across certain assets.

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Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs increased in 2010 compared to 2009, primarily as a result of increased commodity prices, which impact both sales and purchases, as well as a change to a contract with an affiliate in the Piceance Basin, such that certain purchases changed from a net presentation in transportation, processing and other to a gross presentation in purchases of natural gas and NGLs.

Segment Gross Margin — Segment gross margin increased in 2010 compared to 2009, primarily as a result of the following:

• $60.7 million increase related to commodity derivative activities as discussed in the Operating Revenues section above;

• $38.4 million increase as a result of higher commodity prices; and

• $20.1 million increase as a result of increased fee-based throughput volumes resulting from the Michigan acquisition, our organic growth project in the Piceance Basin, as well as the renegotiation of commodity sensitive contracts to fee-based contracts partially offset by decreases across certain assets.

These increases were partially offset by:

• $8.8 million decrease attributable to reduced natural gas basis spreads, increased fuel consumption, the impact of changes in contract mix, differences in gas quality, the impact of volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter and other natural gas volume reductions across certain of our assets, partially offset by increased volumes on our Southeast Texas system. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009 primarily as a result of our Michigan acquisition and integration costs, increased costs at our Southeast Texas system as a result of the acquisition of the Raywood processing plant and Liberty gathering system in June 2010, turnaround activities at certain assets, repairs as a result of near record cold weather and efficiency projects.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009 primarily as a result of our capital projects completed in 2009, the Michigan acquisition and the acquisition of the Raywood processing plant and Liberty gathering system in June 2010.

Other income — Other income in 2010 relates 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, primarily representing our 40% ownership of Discovery, increased in 2010 compared to 2009 primarily due to higher prices and increased NGL production. 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 includes the impact of organic growth from our Piceance Basin expansion project, offset by volume curtailments due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather in the first quarter, increased fuel consumption, differences in gas quality and turnarounds at East Texas in 2010. 2009 results include the first quarter impact of a third party owned pipeline rupture, resulting in a fire at East Texas.

Natural Gas Throughput — Natural gas transported, processed and/or treated increased in 2010 compared to 2009, as a result of increased fee-based throughput volumes from our Michigan acquisition, increased volumes at Southeast Texas as a result of the acquisition of the Raywood processing plant and Liberty gathering system in June 2010 and increased volumes at Discovery, partially offset by decreased volumes across certain assets. 2010 results include the impact of volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter. 2009 results include the first quarter impact of operational downtime following the hurricanes, a third party owned pipeline rupture resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.

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NGL Gross Production — NGL production increased in 2010 compared to 2009, due primarily to increased volumes from our Piceance Basin expansion project, increased volumes at Southeast Texas as a result of the acquisition of the Raywood processing plant and Liberty gathering system in June 2010 and increased NGL production at Discovery. 2010 results include the impact of volume curtailment due to plant shutdowns and producer wellhead freeze offs as a result of near record cold weather at East Texas and North Louisiana in the first quarter. 2009 results include the first quarter impact of operational downtime following the hurricanes, a third party owned pipeline rupture resulting in a fire at East Texas and our Wyoming pipeline integrity and system enhancement project.

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Results of Operations — NGL Logistics Segment

The segment consists of the Seabreeze and Wilbreeze intrastate NGL pipelines, the Wattenberg and Black Lake interstate NGL pipelines, the NGL storage facility in Michigan and the DJ Basin NGL Fractionators in Colorado:

	Year Ended December 31,									Variance 2011 vs. 2010						Variance 2010 vs. 2009
	2011 (b)			2010 (c)(d)			2009 (d)			Increase (Decrease)			Percent			Increase (Decrease)			Percent
	(Millions, except operating data)
Operating revenues:
Sales of NGLs	$	4.8		$	4.7		$	3.0		$	0.1			2	%	$	1.7			57	%
Transportation, processing and other		51.8			12.9			7.5			38.9			302	%		5.4			72	%
Total operating revenues		56.6			17.6			10.5			39.0			222	%		7.1			68	%
Purchases of NGLs		4.6			4.7			2.9			(0.1	)		(2	)%		1.8			62	%
Segment gross margin (a)		52.0			12.9			7.6			39.1			303	%		5.3			70	%
Operating and maintenance expense		(15.9	)		(3.7	)		(1.2	)		12.2			330	%		2.5			208	%
Depreciation and amortization expense		(8.2	)		(2.6	)		(1.4	)		5.6			215	%		1.2			86	%
Step acquisition – equity interest re-measurement gain		—			9.1			—			(9.1	)		(100	)%		9.1			100	%
Other income		0.5			—			—			0.5			100	%		—			—	%
Earnings from unconsolidated affiliates (d)		—			0.8			1.9			(0.8	)		(100	)%		(1.1	)		(58	)%
Segment net income attributable to partners	$	28.4		$	16.5		$	6.9		$	11.9			72	%	$	9.6			139	%
Operating data:
NGL pipelines throughput (Bbls/d) (c)		62,555			38,282			30,160			24,273			63	%		8,122			27	%

(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) 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.

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.

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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 $9.1 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.

Year Ended December 31, 2010 vs. Year Ended December 31, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition, our acquisition of an additional 50% interest in Black Lake. 2009 results include the first quarter impact of decreased throughput volumes resulting from ethane rejection and lower volumes at certain connected processing plants.

Segment Gross Margin — Segment gross margin increased in 2010 compared to 2009, as a result of higher volumes from the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake, as well as higher per unit margins.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake.

Step acquisition — equity interest re-measurement gain — Step acquisition — equity interest re-measurement gain results 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 gain of $9.1 million.

NGL Pipelines Throughput — NGL pipelines throughput increased in 2010 compared to 2009, as a result of increased volumes from the Wattenberg pipeline acquisition and our acquisition of an additional 50% interest in Black Lake. 2009 results include the first quarter impact of ethane rejection and lower volumes at certain connected processing plants.

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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 import terminal, one leased marine terminal, one pipeline terminal and access to several open-access propane pipeline terminals:

	Year Ended December 31,									Variance 2011 vs. 2010						Variance 2010 vs. 2009
	2011			2010 (b)			2009			Increase (Decrease)			Percent			Increase (Decrease)			Percent
	(Millions, except operating data)
Operating revenues:
Sales of propane	$	634.6		$	473.8		$	347.2		$	160.8			34	%	$	126.6			36	%
Transportation, processing and other		0.2			0.3			0.4			(0.1	)		(33	)%		(0.1	)		(25	)%
(Losses) gains from commodity derivative activity		(1.2	)		(0.9	)		0.6			(0.3	)		(33	)%		(1.5	)		*
Total operating revenues		633.6			473.2			348.2			160.4			34	%		125.0			36	%
Purchases of propane		582.5			444.3			299.3			138.2			31	%		145.0			48	%
Segment gross margin (a)		51.1			28.9			48.9			22.2			77	%		(20.0	)		(41	)%
Operating and maintenance expense		(15.1	)		(12.6	)		(10.3	)		2.5			20	%		2.3			22	%
Depreciation and amortization expense		(2.9	)		(1.9	)		(1.4	)		1.0			53	%		0.5			36	%
Other income – affiliates		—			3.0			—			(3.0	)		(100	)%		3.0			100	%
Segment net income attributable to partners	$	33.1		$	17.4		$	37.2		$	15.7			90	%	$	(19.8	)		(53	)%
Operating Data:
Propane sales volume (Bbls/d)		24,743			22,350			22,278			2,393			11	%		72			—	%

* 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, 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:

• $106.8 million increase attributable to higher propane prices, which impacts both purchases and sales; and

• $53.9 million increase primarily as a result of our acquisition of Atlantic Energy.

These increases were partially offset by:

• $0.3 million decrease related to commodity derivative activity.

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.

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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 $3.0 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.

Year Ended December 31, 2010 vs. Year Ended December 31, 2009

Total Operating Revenues — Total operating revenues increased in 2010 compared to 2009, primarily as a result of the following:

• $111.7 million increase attributable to higher propane prices, which impact both sales and purchases; and

• $35.4 million increase attributable to our acquisition of Atlantic Energy in July 2010.

This increase was partially offset by:

• $20.5 million decrease attributable to a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather;

• $1.5 million decrease due to commodity derivative activity.

Purchases of Propane — Purchases of propane increased in 2010 compared to 2009 as a result of higher propane prices, which impact both sales and purchases, and our acquisition of Atlantic Energy in July 2010, partially offset by decreased propane sales volumes.

Segment Gross Margin — Segment gross margin decreased in 2010 compared to 2009. 2010 results reflect a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather, partially offset by our acquisition of Atlantic Energy in July 2010. 2009 results reflect a late winter, increased spot sales volumes and significantly higher per unit margins, approximately $6.0 million of which was attributable to the sale of inventory that was written down at the end of the fourth quarter of 2008.

Operating and Maintenance Expense — Operating and maintenance expense increased in 2010 compared to 2009, primarily as a result of our acquisition of Atlantic Energy.

Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2010 compared to 2009, primarily as a result of our acquisition of Atlantic Energy.

Other income — affiliates — Other income — affiliates increased due to a $3.0 million payment received in the second quarter of 2010 from Spectra Energy, related to an amendment of a supply agreement to shorten the term of the agreement by two years.

Propane Sales Volume — Propane sales volumes were stable in 2010 compared to 2009. 2010 results reflect increased volumes due to our acquisition of Atlantic Energy, offset by a planned outage related to our Providence terminal inspection and reduced demand as a result of an early spring and warmer weather. 2009 results reflect a late winter and increased spot sales volume.

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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 facility;

• issuance of additional partnership 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;

• 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 August 17, 2011, we entered into an equity distribution agreement with Citigroup Global Markets Inc., or Citi. The agreement provides for the offer and sale from time to time through Citi, our sales agent, common units having an aggregate offering amount of up to $150 million. During the year ended December 31, 2011, we issued 761,285 of our common units pursuant to this equity distribution agreement. We received proceeds of $30.2 million from the issuance of these common units, net of commissions and offering costs of $1.2 million, which were used to finance growth opportunities.

In March 2011, we executed a public equity offering which generated net proceeds of $139.7 million. The proceeds from the equity issuance were used primarily to fund our growth strategy, including acquisitions and organic expansion. The 2011 acquisitions include our purchase of an initial 33.33% interest in Southeast Texas for total cash consideration of $150.0 million and the DJ Basin NGL Fractionators for total cash consideration of $30.0 million. Our portion of expansion capital expenditures for 2011 was $133.6 million.

In 2010, we executed two public equity offerings which generated net proceeds $189.3 million. The proceeds from the equity issuances were used primarily to fund our growth strategy, including acquisitions and organic expansion. The 2010 acquisitions included our purchase of the Wattenberg NGL pipeline, the Chesapeake marine terminal, an additional interest in our Black Lake NGL pipeline and the Marysville NGL storage facility for total cash consideration, net of cash acquired of $203.3 million. Our portion of expansion capital expenditures for 2010 was $30.3 million. Additionally, we used the proceeds to fund our January 2011 $150.0 million acquisition of an initial 33.33% interest in Southeast Texas from DCP Midstream, LLC. The balance of the capital requirements were funded through borrowing on our revolving credit facility.

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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. Our sources of funding could include additional borrowings under our Credit Agreement, the placement of public and private debt, and the issuance of our common units.

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 “— Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk — Commodity Cash Flow Protection Activities.”

On November 10, 2011, we entered into a new Credit Agreement consisting of a senior unsecured revolving credit facility (credit facility) with capacity of $1.0 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 $850.0 million and would have matured on June 21, 2012. The initial borrowing under the revolving credit facility was used to repay the Company’s indebtedness under the Prior Credit Agreement. The revolving credit facility provided by the Credit Agreement will be used for ongoing working capital requirements and for other general partnership purposes including acquisitions.

As of December 31, 2011, the outstanding balance on the revolving credit facility was $497.0 million resulting in unused revolver capacity of $501.9 million, of which approximately $279.5 million 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 23, 2012, we had approximately $431.9 million of unused capacity under the Credit Agreement.

On January 3, 2012, we entered into a 2-year Term Loan Agreement with Wells Fargo Bank, National Association, SunTrust Bank and The Bank of Tokyo-Mitsubishi UFJ, Ltd. as lenders. We borrowed $135.0 million under the term loan on January 3, 2012, which was used to fund the acquisition of the remaining 49.9% interest in East Texas. According to terms of the agreement, the proceeds of any subsequent indebtedness issued with a maturity date after January 3, 2014 must be used to prepay the term loan.

On May 26, 2010, we filed a universal shelf registration statement on Form S-3 with the SEC with a maximum aggregate offering price of $1.5 billion, to replace an existing shelf registration statement. The universal shelf registration statement will allow us to issue additional common units and debt securities.

In August 2010, we issued 2,990,000 common units at $32.57 per unit. We received proceeds of $93.1 million, net of offering costs, which we used to repay funds borrowed under the revolver portion of our Credit Facility.

In September 2010, we issued $250.0 million of 3.25% Senior Notes due October 1, 2015. We received net proceeds, after deducting underwriting discounts and offering expenses, of $247.7 million, which we used to repay funds borrowed under the revolver portion of our Credit Facility.

In November 2010, we issued 2,875,000 common units at $34.96 per unit. We received proceeds of $96.2 million, net of offering costs, which we used to fund the Southeast Texas acquisition.

In March 2011, we issued 3,596,636 common limited partner units at $40.55 per unit. We received proceeds of $139.7 million, net of offering costs.

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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 23, 2012, DCP Midstream, LLC had issued and outstanding parental guarantees totaling $70.0 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. As of February 23, 2012, we had a contingent letter of credit facility for up to $10.0 million, on which we pay a fee of 0.50% per annum. As of February 23, 2012, we had no letters of credit issued on this facility; we will pay a net fee of 1.75% per annum on letters of credit issued on this facility. This contingent letter of credit facility was issued directly by a financial institution and does not reduce the available capacity under our credit facility. These parental guarantees and contingent letter of credit facility reduce the amount of cash we may be required to post as collateral. As of February 23, 2012, 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.

Discovery is owned 40% by us and 60% by Williams Partners, LP. Discovery is managed by a two-member management committee, consisting of one representative from each owner. The members of the management committee have voting power corresponding to their respective ownership interests in Discovery. All actions and decisions relating to Discovery require the unanimous approval of the owners except for a few limited situations. Discovery must make quarterly distributions of available cash (generally, cash from operations less required and discretionary reserves) to its owners. The management committee, by majority approval, will determine the amount of the distributions. In addition, the owners are required to offer to Discovery all opportunities to construct pipeline laterals within an “area of interest.” Calls for capital contributions are determined by a vote of the management committee and require unanimous approval of both owners in most instances.

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 a working capital deficit of $26.8 million as of December 31, 2011, compared to working capital of $35.1 million as of December 31, 2010. Included in these working capital amounts are net derivative working capital liabilities of $18.7 million and $42.1 million as of December 31, 2011 and December 31, 2010, 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, 2011, we had $7.6 million in cash and cash equivalents. Of this balance, as of December 31, 2011, $5.1 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 corporate purposes. In 2010, Congress passed Dodd Frank, which has the potential to impact our cash collateral and reporting requirements for our derivative positions depending on the final regulations adopted by the United States Commodity Futures Trading Commission and the U.S. Securities and Exchange Commission.

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

	Year Ended December 31,
	2011			2010			2009
	(Millions)
Net cash provided by operating activities	$	260.8		$	162.4		$	152.7
Net cash used in investing activities	$	(340.7	)	$	(345.5	)	$	(180.1	)
Net cash provided by (used in) financing activities	$	80.8		$	187.7		$	(32.4	)

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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.

We paid net cash for settlement of our commodity derivative instruments of approximately $34.6 million for the year ended December 31, 2011, and received cash of $14.8 million for the year ended December 31, 2010, approximately $6.2 million of which was associated with rebalancing our portfolio. We received cash for settlement of our commodity derivative instruments for the year ended December 31, 2009 of $26.4 million, approximately $4.8 million of which was associated with rebalancing our portfolio. During the year ended December 31, 2011, we made federal and state tax payments of $29.3 million and $0.3 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 $3.6 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 $25.3 million, $30.0 million and $20.2 million during the years ended December 31, 2011, 2010 and 2009, respectively. Distributions exceeded earnings by $2.6 million for the year ended December 31, 2011.

Net Cash Used in Investing Activities — Net cash used in investing activities during 2011 was comprised of: (1) capital expenditures of $165.7 million (our portion of which was $146.5 million and the noncontrolling interest holders’ portion was $19.2 million), which includes $25.2 million of capital expenditures related to our Eagle Plant construction; (2) acquisition expenditures of $114.3 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 $29.6 million related to our acquisition of our DJ Basin NGL Fractionators, $23.4 million related to our acquisition of Eagle Plant construction work in progress, and a payment of $7.5 million to the seller of Michigan Pipeline & Processing, LLC in relation to our contingent payment agreement; and (4) investments in unconsolidated affiliates of $7.0 million; partially offset by (5) proceeds from sales of assets of $5.2 million; and (6) a return of investment from unconsolidated affiliates of $1.6 million.

Net cash used in investing activities during 2010 was comprised of: (1) acquisition expenditures of $282.1 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 $75.9 million (our portion of which was $61.1 million and the noncontrolling interest holders’ portion was $14.8 million); and (3) investments in unconsolidated affiliates of $2.3 million; partially offset by (4) net proceeds from sale of available-for-sale securities of $10.1 million; (5) proceeds from sale of assets of $3.5 million; and (6) a return of investment from Discovery of $1.2 million.

Net cash used in investing activities during 2009 was primarily used for: (1) capital expenditures of $182.2 million (our portion of which was $97.1 million and the noncontrolling interest holders’ portion was $85.1 million), which primarily consisted of expenditures for installation of compression and expansion of our East Texas system, expansion of our Colorado system, expansion of the Southeast Texas gathering system and storage facilities, and the completion of pipeline integrity system upgrades to our Wyoming system; (2) acquisition expenditure of $44.5 million, primarily related to the acquisition of certain companies that held natural gas gathering and treating assets from MichCon Pipeline Company of $45.1 million; and (3) investments in Discovery of $7.0 million, partially offset by (4) net proceeds from sale of available-for-sale securities of $50.0 million; (5) a return of investment from Discovery of $2.2 million; and (6) proceeds from sale of assets of $1.4 million.

Net Cash Provided By (Used in) Financing Activities — Net cash provided by financing activities during 2011 was comprised of: (1) proceeds from the issuance of common units, net of offering costs, of $169.7 million; (2) net borrowing of debt of $99.0 million; (3) contributions from noncontrolling interests of $18.3 million; and (4) net change in advances to predecessor from DCP Midstream, LLC of $10.9 million; partially offset by (5) distributions to our unitholders and general partner of $132.4 million; (6) distributions to noncontrolling interests of $44.8 million; (7) excess purchase price over the acquired net assets of Southeast Texas of $35.7 million; and (8) payment of deferred financing costs of $4.2 million.

During 2011, total outstanding indebtedness under our $1.0 billion Credit Agreement, which includes borrowings under our revolving credit facility and letters of credit issued under the Credit Agreement, was not less than $425.5 million and did not exceed $591.1 million. The weighted-average indebtedness outstanding under the revolving credit facility was $519.1 million, $454.1 million, $483.8 million and $517.1 million for the first, second, third and fourth quarters of 2011, respectively.

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We had unused revolver capacity, which is available for commitments under the Prior Credit Agreement or the Credit Agreement, of $423.5 million, $387.9 million, $372.9 million and $501.9 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:

• $150.0 million borrowing to fund the acquisition of our initial 33.33% interest in Southeast Texas;

• $30.0 million borrowing to fund the purchase of the DJ Basin NGL Fractionators;

• $29.6 million borrowing to fund the Marysville tax payment;

• $23.4 million borrowing to fund the purchase of certain tangible assets and land located in the Eagle Ford Shale; and

• $5.7 million net borrowings; partially offset by

• $139.7 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 $868.2 million; (2) proceeds from the issuance of common units net of offering costs of $189.3 million; (3) net change in advances to predecessor from DCP Midstream, LLC of $82.3 million; (4) contributions from noncontrolling interests of $13.8 million; and (5) contributions from DCP Midstream, LLC of $0.6 million; partially offset by (6) repayments of debt of $833.4 million; (7) distributions to our unitholders and general partner of $101.9 million; (8) distributions to noncontrolling interests of $25.6 million; (9) purchase of additional interest in a subsidiary of $3.5 million; and (10) payment of deferred financing costs of $2.1 million.

During 2010, total outstanding indebtedness under our $850.0 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 $300.5 million and did not exceed $722.4 million. The weighted-average indebtedness outstanding under the revolving credit facility was $622.5 million, $625.9 million, $634.7 million and $347.9 million for the first, second, third and fourth quarters of 2010, respectively.

We had unused revolver capacity, which is available commitments under the Prior Credit Agreement of $209.3 million, $234.6 million, $486.5 million and $419.9 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:

• $247.7 million repayment financed by the issue of $250.0 million of 3.25% Senior Notes due October 1, 2015;

• $93.1 million repayment financed by the issue of 2,990,000 common units in August 2010; and

• $96.2 million repayment financed by the issue of 2,875,000 common units in November 2010; partially offset by

• $66.3 million borrowing to fund the acquisition of Atlantic Energy, which includes $17.3 million for propane inventory and working capital;

• $16.3 million net borrowings for general corporate purposes;

• $22.0 million borrowing to fund the acquisition of the Wattenberg pipeline;

• $16.6 million borrowing to fund the acquisition of an additional 55% interest in Black Lake;

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• $100.8 million borrowing to fund the acquisition of Marysville, which includes $6.0 million for inventory and working capital; and

• $10.0 million borrowing to fund repayment of our term loan.

During 2010, we had a repayment of $10.0 million on our term loan and released $10.0 million of restricted investments which were required as collateral for the facility.

Net cash used in financing activities during 2009 was comprised of: (1) repayments of debt of $280.5 million; (2) distributions to our unitholders and general partner of $85.3 million; (3) distributions to noncontrolling interests of $27.0 million; and (4) net change in advances to predecessor from DCP Midstream, LLC of $25.5 million, partially offset by (5) borrowings of $237.0 million; (6) contributions from noncontrolling interests of $78.7 million; (7) the issuance of common units for $69.5 million, net of offering costs; and (8) contributions from DCP Midstream, LLC of $0.7 million.

During 2009, total outstanding indebtedness under our $850.0 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 $608.3 million and did not exceed $656.8 million. The weighted average indebtedness outstanding was $656.7 million, $644.4 million, $638.3 million and $620.4 million for the first, second, third and fourth quarters of 2009, respectively.

We had liquidity, which is available commitments under the Prior Credit Agreement of $239.3 million, $221.3 million, $221.3 million and $221.3 million at the end of the first, second, third and fourth quarters of 2009, respectively.

During 2009, we had the following net movements on our Prior Credit Agreement:

• $50.0 million borrowing under our revolving credit facility to fund a partial repayment of our term loan; partially offset by

• $43.5 million repayment under our revolving credit facility.

We expect to continue to use cash in financing activities for the payment of distributions to our unitholders and general partner. See Note 13 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 $15.0 million and $20.0 million, and expenditures for expansion capital of between $250.0 million and $300.0 million, for the year ending December 31, 2012. Expansion capital expenditures include construction of the Eagle Plant, Discovery’s Keathley Canyon, which is shown as investments in unconsolidated affiliates, expansion and upgrades to our East Texas complex and acquisition integration projects. The board of directors may approve additional growth capital during the year, at their discretion.

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

	Year Ended December 31, 2011						Year Ended December 31, 2010
	Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures		Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures
	(Millions)						(Millions)
Our portion	$	12.9	$	133.6	$	146.5	$	6.9	$	54.2	$	61.1
Noncontrolling interest portion		5.5		13.7		19.2		6.4		8.4		14.8
Total	$	18.4	$	147.3	$	165.7	$	13.3	$	62.6	$	75.9

	Year Ended December 31, 2009
	Maintenance Capital Expenditures		Expansion Capital Expenditures		Total Consolidated Capital Expenditures
	(Millions)
Our portion	$	13.6	$	83.5	$	97.1
Noncontrolling interest portion		21.3		63.8		85.1
Total	$	34.9	$	147.3	$	182.2

In addition, we invested cash in unconsolidated affiliates of $7.0 million, $2.3 million and $7.0 million during the years ended December 31, 2011, 2010 and 2009, respectively, of which $2.3 million and $2.8 million was to fund our share of capital expansion projects during the years ended December 31, 2010 and 2009, respectively. $4.2 million in 2009, was to fund repairs to Discovery following damage caused by Hurricane Ike in 2008 (of which $1.2 and $2.2 million was returned to us by Discovery during 2010 and 2009, respectively).

Capital expenditures increased in 2011 compared to 2010 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 could 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 facility, issuance of long-term debt and the issuance of additional partnership units. 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 $132.4 million, $101.9 million and $85.3 million during 2011, 2010 and 2009, 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 into a Credit Agreement providing for a $1.0 billion revolving credit facility that matures November 10, 2016. The Credit Agreement replaced the Prior Credit Agreement, which had a total borrowing capacity of $850.0 million and would have matured on June 21, 2012. As of December 31, 2011, the outstanding balance on the revolving credit facility was $497.0 million resulting in unused revolver capacity of $501.9 million, of which approximately $279.5 million was available for general working capital purposes.

Our obligations under the revolving credit facility are unsecured. The unused portion of the revolving credit facility may be used for letters of credit. At December 31, 2011 and 2010, we had outstanding letters of credit issued under the Credit Agreement and Prior Credit Agreement of $1.1 million and $32.1 million, respectively.

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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 revolving credit facility bears interest at either: (1) LIBOR, plus an applicable margin ranging from 0.85% to 1.65% depending on our 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 ranging from 0% to 0.65% depending on our credit rating. As of December 31, 2011, the weighted-average interest rate on the $497.0 million of borrowings outstanding under the revolving credit facility was 1.69% per annum, excluding the impact of interest swaps. The revolving credit facility incurs an annual facility fee of 0.15% to 0.35% depending on our 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 the Term Loan Agreement — On January 3, 2012, we entered into a 2-year Term Loan Agreement with Wells Fargo Bank, National Association, SunTrust Bank and The Bank of Tokyo-Mitsubishi UFJ, Ltd. as lenders. We borrowed $135.0 million under the term loan on January 3, 2012, which was used to fund the acquisition of the remaining 49.9% interest in East Texas.

The term loan will mature on January 3, 2014. The proceeds of any subsequent indebtedness issued with a maturity date after January 3, 2014 must be used to prepay the term loan. Indebtedness under the term loan bears interest at either: (1) LIBOR, plus an applicable margin ranging from 1.0% to 1.75% depending on our credit rating; or (2) the higher of Wells Fargo Bank’s prime rate plus an applicable margin ranging from 0% to 0.75% depending on our credit rating, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus 1%.

The Term Loan 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 Term Loan 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 September 30, 2010, we issued $250.0 million of our 3.25% Senior Notes due October 1, 2015. We received net proceeds of $247.7 million, net of underwriters’ fees, related expense and unamortized discounts of $1.5 million, $0.6 million and $0.2 million, respectively, which we used to repay funds borrowed under the revolver portion of our Credit Facility. Interest on the notes will be 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 Facility. We are not required to make mandatory redemption or sinking fund payments with respect to these notes. The securities are redeemable at a premium at our option.

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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, 2011, is as follows:

	Payments Due by Period
	Total		2012		2013-2014		2015-2016		2017 and Thereafter
	(Millions)
Long-term debt (a)	$	805.2	$	23.9	$	26.1	$	755.2	$	—
Operating lease obligations (b)		30.4		12.5		13.6		3.3		1.0
Purchase obligations (c)		471.3		295.9		82.5		72.5		20.4
Other long-term liabilities (d)		13.6		—		0.6		0.2		12.8
Total	$	1,320.5	$	332.3	$	122.8	$	831.2	$	34.2

(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 $23.9 million, $26.1 million and $8.2 million for 2012, 2013-2014 and 2015-2016, 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, 2011. 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 $12.4 million of asset retirement obligations and $1.2 million of environmental reserves recognized in the consolidated balance sheet at December 31, 2011.

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, 2011 weighted-average cost, our net income would be affected by approximately $8.8 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. Key assumptions in the analysis include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices and throughput volumes. 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 goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. We have not recorded any impairment charges on goodwill during the year ended December 31, 2011.

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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, 2011. 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, 2011. 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, 2011 would have affected net income by approximately $2.4 million for the year ended December 31, 2011.
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, 2011 would impact our net income by approximately $0.1 million.

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Recent Accounting Pronouncements

Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2011-11 “Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities,” or ASU 2011-11 — In December 2011, the FASB issued ASU 2011-11, which amends Accounting Standards Codification, or ASC, Topic 210 “Balance Sheet.” ASU 2011-11 will require entities to disclose information about offsetting and related arrangements to enable financial statement users to understand the effect of such arrangements on the statement of financial position. The provisions of ASU 2011-11 are effective for us in interim and annual reporting periods beginning on or after January 1, 2013 and we are currently assessing the impact of adoption on our consolidated results of operations, cash flows and financial position.

ASU 2011-08 “Intangibles – Goodwill and Other (Topic 350),” or ASU 2011-08 — In September 2011, the FASB issued ASU 2011-08, which amends Accounting Standards Codification, or ASC, Topic 350 “Intangibles — Goodwill and Other.” ASU 2011-08 provides additional guidance on the two-step test for goodwill impairment as previously described in Topic 350 “Intangibles — Goodwill and Other.” Under the new guidance, entities may elect to first assess qualitative factors instead of calculating the fair value of a reporting unit unless the entity determines that it is more likely than not the fair value of the reporting unit is less than its carrying value. This ASU is effective for interim and annual goodwill impairment tests performed for fiscal years beginning after December 15, 2011, with early adoption permitted. We elected to adopt ASU 2011-08 for our 2011 annual goodwill impairment test. There was no impact from the adoption of ASU 2011-08 on our consolidated results of operations, cash flows and financial position.

ASU 2011-04 “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs”, or ASU 2011-04 — In May 2011, the FASB issued ASU 2011-04 which amends ASC, Topic 820 “Fair Value Measurements and Disclosures” to change the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements, clarify the FASB’s intent about the application of existing fair value measurement requirements, and change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The provisions of ASU 2011-04 are effective for us for interim and annual periods beginning after December 15, 2011 and we are currently assessing the impact of adoption on our consolidated results of operations, cash flows and financial position.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse change in market prices and rates. We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as forward contracts, swaps and futures to mitigate a portion of the effects of identified risks. In general, we attempt to mitigate a portion of the risks related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements.

Risk Management Policy

We have established a comprehensive risk management policy, or Risk Management Policy, and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. Our Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.

See Note 12, Risk Management and Hedging Activities, of the Notes to Consolidated Financial Statements in Exhibit 99.3 to this Form 8-K for further discussion of the accounting for derivative contracts.

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Credit Risk

Our principal customers in the Natural Gas Services segment are large, natural gas marketers and industrial end-users. Our principal customers in the Wholesale Propane Logistics segment are primarily retail propane distributors. In the NGL Logistics Segment, our principal customers include an affiliate of DCP Midstream, LLC, producers and marketing companies. Substantially all of our natural gas, propane and NGL sales are made at market-based prices. This concentration of credit risk may affect our overall credit risk, as these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits, and monitor the appropriateness of these limits on an ongoing basis. We operate under DCP Midstream, LLC’s corporate credit policy. DCP Midstream, LLC’s corporate credit policy, as well as the standard terms and conditions of our agreements, prescribe the use of financial responsibility and reasonable grounds for adequate assurances. These provisions allow our credit department to request that a counterparty remedy credit limit violations by posting cash or letters of credit for exposure in excess of an established credit line. The credit line represents an open credit limit, determined in accordance with DCP Midstream, LLC’s credit policy. Our standard agreements also provide that the inability of a counterparty to post collateral is sufficient cause to terminate a contract and liquidate all positions. The adequate assurance provisions also allow us to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment to us in a satisfactory form.

Interest Rate Risk

Interest rates on future credit facility draws and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

We mitigate a portion of our interest rate risk with interest rate swaps and forward-starting interest rate swaps that reduce our exposure to market rate fluctuations by converting variable interest rates on our existing debt to fixed interest rates and locking in rates on our anticipated future fixed-rate debt, respectively. The interest rate swap agreements convert the interest rate associated with the indebtedness outstanding under our revolving credit facility to a fixed-rate obligation, thereby reducing the exposure to market rate fluctuations. The forward-starting interest rate swap agreements lock in the interest rate associated with our anticipated future fixed-rate debt, thereby reducing the exposure to market rate fluctuations prior to issuance.

At December 31, 2011, we had interest rate swap agreements totaling $450.0 million, of which we have designated $425.0 million as cash flow hedges and account for the remaining $25.0 million under the mark-to-market method of accounting. As we generally expect to have variable-rate debt levels equal to or exceeding our swap positions during their term, the entire $450.0 million of these arrangements mitigate our interest rate risk through June 2012, with $150.0 million extending from June 2012 through June 2014. Based on our current operations we believe our interest rate swap agreements mitigate our interest rate risk associated with our variable-rate debt. As of February 23, 2012, we had interest rate swap agreements totaling $450.0 million, of which we have designated $425.0 million as cash flow hedges and account for the remaining $25.0 million under the mark-to-market method of accounting.

At December 31, 2011, we had forward-starting interest rate swap agreements totaling $195.0 million, which we have designated as cash flow hedges. As we anticipate entering into future fixed-rate debt at levels equal to or exceeding our forward-starting swap positions during their term, the entire $195.0 million of these arrangements mitigate a portion of our interest rate risk through the term of our anticipated debt into 2022. Under the terms of the forward-starting interest rate swap agreements, we will pay fixed-rates ranging from 2.15% to 2.598%, and receive interest payments approximating 10-year U.S. Treasury rates. Based on our current operations we believe our forward-starting interest rate swap agreements mitigate a portion of our interest rate risk associated with our anticipated future fixed-rate debt.

Effectiveness of our interest rate swap agreements designated as cash flow hedges is determined by matching the principal balance and terms with that of the specified obligation. The effective portions of changes in fair value are recognized in AOCI in the consolidated balance sheets and are reclassified into earnings as the hedged transactions impact earnings. Ineffective portions of changes in fair value are recognized in earnings.

At December 31, 2010, we had interest rate swap agreements totaling $450.0 million, of which we had designated $275.0 million as cash flow hedges and accounted for the remaining $175.0 million under the mark-to-market method of accounting. This resulted in $450.0 million of these swap agreements mitigating our interest rate risk through June 2012, with $150.0 million extending from June 2012 through June 2014.

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At December 31, 2011, the effective weighted-average interest rate on our outstanding debt was 4.45%, taking into account our interest rate swap agreements totaling $450.0 million.

Based on the annualized unhedged borrowings under our credit facility of $72.0 million as of December 31, 2011, a 0.5% movement in the base rate or LIBOR rate would result in an approximately $0.4 million annualized increase or decrease in interest expense.

Commodity Price Risk

We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering services, we receive fees or commodities from producers to bring the natural gas from the wellhead to the processing plant. For processing and storage services, we either receive fees or commodities as payment for these services, depending on the types of contracts. We employ established policies and procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including forward contracts, swaps, costless collars and futures.

Commodity Cash Flow Protection Activities — We closely monitor the risks associated with commodity price changes on our future operations and, where appropriate, use various fixed price swaps and collar arrangements to mitigate a portion of the effect pricing fluctuations may have on the value of our assets and operations. Depending on our risk management objectives, we may periodically settle a portion of these instruments prior to their maturity.

We enter into derivative financial instruments to mitigate a portion of the cash flow risk of decreased natural gas, NGL and condensate prices associated with our percent-of-proceeds arrangements and gathering operations. We also may enter into natural gas derivatives to lock in margin around our transportation or storage assets. Historically, there has been a strong relationship between NGL prices and crude oil prices, with some recent exceptions. Given the limited liquidity and tenor of the NGL financial market, we have historically used crude oil swaps and costless collars to mitigate a portion of our NGL price risk. For the nearer tenor where there is greater liquidity in the NGL derivatives market, we have periodically also utilized NGL derivatives. When the relationship of NGL prices to crude oil prices is at a discount to historical ranges, we experience additional exposure as a result of the relationship where we utilize crude oil swaps and costless collars to mitigate NGL price exposure. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps, a portion of which are with DCP Midstream, LLC. As a result of these transactions, we have mitigated a portion of our expected natural gas, NGL and condensate commodity price risk through 2016.

The derivative financial instruments we have entered into are typically referred to as “swap” contracts and “collar” arrangements. The swap contracts entitle us to receive payment at settlement from the counterparty to the contract to the extent that the reference price is below the swap price stated in the contract, and we are required to make payment at settlement to the counterparty to the extent that the reference price is higher than the swap price stated in the contract.

We also use commodity collar arrangements, which entitle us to receive payment at settlement from the counterparty to the contract to the extent that the reference price is below the floor price stated in the contract. Conversely, if the reference price is above the ceiling price stated in the contract, we are required to make payment at settlement to the counterparty. If the reference price is between the floor price and the ceiling price, no payment will be made at the settlement of the contract.

We are using the mark-to-market method of accounting for all commodity derivative instruments, which has significantly increased the volatility of our results of operations as we recognize, in current earnings, all non-cash gains and losses from the mark-to-market on derivative activity.

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The following tables set forth additional information about our fixed price swaps, and our collar arrangements used to mitigate a portion of our natural gas and NGL price risk associated with our percent-of-proceeds arrangements and our condensate price risk associated with our gathering operations, as of February 23, 2012:

Commodity Swaps

Period	Commodity	Notional Volume - (Short)/ Long Positions	Reference Price	Price Range
January 2012 — December 2012	Natural Gas	(1,181) MMBtu/d	Monthly Average for Carthage Gas Daily Daily (e)	$4.34/MMBtu
January 2012 — December 2014	Natural Gas	(500) MMBtu/d	IFERC Monthly Index Price for Colorado Interstate Gas Pipeline (a)	$5.06/MMBtu
January 2012 — December 2014	Natural Gas	(1000) MMBtu/d	Texas Gas Transmission Price (b)	$4.87/MMBtu
January 2012 — December 2012	NGL’s	(805) Bbls/d	Mt.Belvieu Non-TET (d)	$1.40-$2.24/Gal
January 2012 — March 2012	NGL’s	(1,869) Bbls/d	Mt.Belvieu Non-TET (d)	$1.48-$2.19/Gal
April 2012 — December 2012	NGL’s	(702) Bbls/d	Mt.Belvieu Non-TET (d)	$2.20/Gal
January 2012 — December 2012	Crude Oil	(2,325) Bbls/d	Asian-pricing of NYMEX crude oil futures (c)	$66.72 - $99.85/Bbl
January 2013 — December 2013	Crude Oil	(2,250) Bbls/d	Asian-pricing of NYMEX crude oil futures (c)	$67.60 - $99.85/Bbl
January 2014 — December 2014	Crude Oil	(1,500) Bbls/d	Asian-pricing of NYMEX crude oil futures (c)	$74.90 - $96.08/Bbl
January 2015 — December 2015	Crude Oil	(1,000) Bbls/d	Asian-pricing of NYMEX crude oil futures (c)	$92.00-$100.04/Bbl
January 2016 — December 2016	Crude Oil	(500) Bbls/d	Asian-pricing of NYMEX crude oil futures (c)	$101.30/Bbl
January 2012 — December 2014	Natural Gas	500 MMBtu/d	Texas Gas Transmission Price (b)	$4.93/MMBtu
January 2012 — March 2012	Crude Oil	1,350 Bbls/d	Asian-pricing of NYMEX crude oil futures (c)	$86.45/Bbl
April 2012 — December 2012	Crude Oil	700 Bbls/d	Asian-pricing of NYMEX crude oil futures (c)	$92.00/Bbl

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

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

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

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

(e) The average monthly natural gas price for Carthage Gas Daily Daily.

Commodity Collar Arrangements

Period	Commodity	Notional Volume	Reference Price	Collar Price Range
January 2012 — December 2012	Crude Oil	600 Bbls/d (a)	Asian-pricing of NYMEX crude oil futures (b)	$80.00 - $97.40/Bbl
January 2013 — December 2013	Crude Oil	400 Bbls/d (a)	Asian-pricing of NYMEX crude oil futures (b)	$80.00 - $96.50/Bbl

(a) Reflects separate purchased put and sold call contracts, resulting in a collar arrangement.

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

At December 31, 2011, the aggregate fair value of the fixed price commodity swaps and collar arrangements described above was a net loss of $40.1 million.

Our annual sensitivities for 2012 as shown in the table below, exclude the impact from non-cash mark-to-market on our commodity derivatives. We utilize crude oil and NGL derivatives to mitigate a portion of our commodity price exposure for NGLs, and show our sensitivity to changes in the relationship between the pricing of NGLs and crude oil. For fixed price natural gas and crude oil, the sensitivities are associated with our unhedged volumes. For our NGL to crude oil price relationship, the sensitivity is associated with both hedged and unhedged equity volumes.

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Commodity Sensitivities Excluding Non-Cash Mark-To-Market

	Per Unit Decrease		Unit of Measurement	Estimated Decrease in Annual Net Income Attributable to Partners
				(Millions)
Natural gas prices	$	1.00	MMBtu	$	1.7
Crude oil prices (a)	$	5.00	Barrel	$	3.6
NGL to crude oil price relationship (b)		5 percentage point change	Barrel	$	7.2

(a) Assuming 60% NGL to crude oil price relationship. At crude oil prices outside of our collar range of approximately $80.00 to $97.40, this sensitivity decreases by $0.8 million.

(b) Assuming 60% NGL to crude oil price relationship and $90.00 /Bbl crude oil price. Generally, this sensitivity changes by $0.8 million for each $10.00/Bbl change in the price of crude oil. As crude oil prices increase from $90.00 /Bbl, we become slightly more sensitive to the change in the relationship of NGL prices to crude oil prices. As crude oil prices decrease from $90.00 /Bbl, we become less sensitive to the change in the relationship of NGL prices to crude oil prices.

In addition to the linear relationships in our commodity sensitivities above, additional factors cause us to be less sensitive to commodity price declines. A portion of our net income is derived from fee-based contracts and a certain percentage of liquids processing arrangements that contain minimum fee clauses in which our processing margins convert to fee-based arrangements as NGL prices decline.

The above sensitivities exclude the impact from arrangements where producers on a monthly basis may elect to not process their natural gas in which case we retain a portion of the customers’ natural gas in lieu of NGLs as a fee. The above sensitivities also exclude certain related processing arrangements where we control the processing or by-pass of the production based upon individual economic processing conditions. Under each of these types of arrangements, our processing of the natural gas would yield favorable processing margins. Less than 10% of our gas throughput is associated with these arrangements.

We estimate the following non-cash sensitivities in 2012 related to the mark-to-market on our commodity derivatives associated with our commodity cash flow protection activities:

Non-Cash Mark-To-Market Commodity Sensitivities

	Per Unit Increase		Unit of Measurement	Estimated Mark-to- Market  Impact (Decrease in Net Income Attributable to Partners)
				(Millions)
Natural gas prices	$	1.00	MMBtu	$	1.5
Crude oil prices	$	5.00	Barrel	$	12.0
NGL prices	$	0.10	Gallon	$	2.4

While the above commodity price sensitivities are indicative of the impact that changes in commodity prices may have on our annualized net income, changes during certain periods of extreme price volatility and market conditions or changes in the relationship of the price of NGLs and crude oil may cause our commodity price sensitivities to vary significantly from these estimates.

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The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which in turn has been generally related to the price of crude oil. 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 increase natural gas exploration and production. To minimize potential future commodity-based pricing and cash flow volatility, we have entered into a series of derivative financial instruments. As a result of these transactions, we have mitigated a portion of our expected natural gas, NGL and condensate commodity price risk relating to the equity volumes associated with our gathering and processing activities through 2016.

Given the historical relationship between NGL prices and crude oil prices and the limited liquidity and tenor of the NGL financial market, we have generally used crude oil derivative instruments to mitigate a portion of NGL price risk. For the nearer tenor where there is greater liquidity in the NGL derivatives market, we have periodically also utilized NGL derivatives. When the relationship of NGL prices to crude oil prices is at a discount to historical ranges, we experience additional exposure as a result of the relationship where we utilize crude oil swaps to mitigate NGL price exposure. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps.

Based on historical trends, we generally expect NGL prices to directionally follow changes in crude oil prices over the long-term. However, the pricing relationship between NGLs and crude oil may vary, as we believe crude oil prices will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy, whereas NGL prices are more correlated to supply and U.S. petrochemical demand. We believe that future natural gas prices will be influenced by North American supply deliverability, the severity of winter and summer weather, the level of North American production and drilling activity of exploration and production companies. Drilling activity can be adversely affected as natural gas prices decrease. Energy market uncertainty could also further reduce North American drilling activity. Limited access to capital could also decrease drilling. Lower drilling levels over a sustained period would reduce natural gas volumes gathered and processed, but could increase commodity prices, if supply were to fall relative to demand levels.

Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. 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. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our condensed consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.

The following tables set forth additional information about our derivative instruments used to mitigate a portion of our natural gas price risk associated with our Southeast Texas storage operations, as of December 31, 2011:

Inventory
Period	Commodity	Notional Volume - (Short)/Long Positions	Fair Value (millions)			Weighted Average Price
December 31, 2011	Natural Gas	7,624,126 MMBtu’s	$	23.2		$3.04/MMBtu
Commodity Swaps
Period	Commodity	Notional Volume - (Short)/Long Positions	Fair Value (millions)			Price Range
January 2012-April 2012	Natural Gas	(28,877,500) MMBtu	$	34.1		$3.12-$4.81/MMBtu
January 2012-October 2012	Natural Gas	20,537,500 MMBtu	$	(16.3	)	$3.07-$4.81/MMBtu

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Our wholesale propane logistics business is generally designed to establish stable margins by entering into supply arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide for floating prices that are tied to our variable supply costs plus a margin. Occasionally, we may enter into fixed price sales agreements in the event that a retail propane distributor desires to purchase propane from us on a fixed price basis. We manage this risk with both physical and financial transactions, sometimes using non-trading derivative instruments, which generally allow us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories.

We manage our commodity derivative activities in accordance with our Risk Management Policy which limits exposure to market risk and requires regular reporting to management of potential financial exposure.

Valuation — Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. 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 expected relationship with quoted market prices.

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. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

The fair value of our interest rate swaps and commodity non-trading derivatives is expected to be realized in future periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events that could impact the amount and/or realization of these values.

	Fair Value of Contracts as of December 31, 2011
Sources of Fair Value	Total			Maturity in 2012			Maturity in 2013-2014			Maturity in 2015-2016		Maturity in 2017 and Thereafter
	(Millions)
Prices supported by quoted market prices and other external sources	$	(46.2	)	$	(19.1	)	$	(30.8	)	$	3.7	$	—
Prices based on models or other valuation techniques	$	1.1		$	0.4		$	0.7		$	—	$	—
Total	$	(45.1	)	$	(18.7	)	$	(30.1	)	$	3.7	$	—

The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, our New York Mercantile Exchange, or NYMEX, positions in natural gas, NGLs and crude oil. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from SunGard Kiodex and then validated through an internal process which includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which over-the-counter, or OTC, broker quotes for similar assets or liabilities are available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate.

The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point.

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