Summary of DCP MIDSTREAM PARTNERS, LP

Item 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 condensed consolidated financial statements and notes included elsewhere in this Form 10-Q and the consolidated financial statements and notes thereto included in our 2007 Form 10-K. We refer to our 25% limited liability company interest in DCP East Texas Holdings, LLC, or East Texas, and our 40% limited liability company interest in Discovery Producer Services LLC, or Discovery, as well as a non-trading derivative instrument, or the Swap, which DCP Midstream, LLC entered into in March 2007, which we acquired from DCP Midstream, LLC in July 2007, collectively as our "predecessor." The financial information contained herein includes, for each period presented, our accounts, and those of 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. We operate in three business segments:

• our Natural Gas Services segment, which consists of (1) our Northern Louisiana natural gas gathering, processing and transportation system;
(2) our Southern Oklahoma system acquired in May 2007; (3) our limited liability company interest in East Texas, our limited liability company interest in Discovery, and the Swap, acquired in July 2007 from DCP Midstream, LLC; and (4) our Colorado and Wyoming systems, acquired in August 2007 from DCP Midstream, LLC, which were acquired by DCP Midstream, LLC from Momentum Energy Group, Inc. in August 2007 (referred to as the MEG acquisition);

• our Wholesale Propane Logistics segment, which consists of six owned rail terminals, one of which is currently idle, one leased marine terminal, one pipeline terminal that became operational in May 2007, and access to several open-access pipeline terminals; and

• our NGL Logistics segment, which consists of our Seabreeze and Wilbreeze NGL transportation pipelines, and a non-operated 45% equity interest in the Black Lake interstate NGL pipeline.

Recent Events

As of November 3, 2008, DCP Midstream, LLC had issued and outstanding parental guarantees totaling $178.0 million to certain counterparties to our commodity derivative instruments to mitigate a portion of our collateral requirements with those counterparties. We pay DCP Midstream, LLC a fee of 0.5% per annum on $115.0 million of these guarantees. The fee on the remaining guarantees is covered under the omnibus agreement with DCP Midstream, LLC. During the second and third quarters of 2008, we issued letters of credit totaling $75.0 million to counterparties to our commodity derivative instruments, which reduce the amount of cash we may be required to post as collateral. These letters of credit were issued directly by financial institutions and do not reduce the available capacity under our credit facility.

We completed pipeline integrity testing at our Wyoming system during the second quarter of 2008 and commenced work on the pipeline to bring it back to normal operations. We are further upgrading our Wyoming system to assure future integrity, improve system reliability and reduce operating costs. We believe this work will be completed at a total cost of approximately $13.0 million, the majority of which is maintenance capital. Of the $13.0 million, approximately $1.6 million was incurred through the third quarter of 2008. We believe we will recover the costs of this work over time. The work on the pipeline will be completed in phases so that volumes will return to the system throughout the fourth quarter of 2008 and into the first quarter of 2009. We anticipate decreased operating revenues through the first quarter of 2009 as we complete this work.

Angela A. Minas was appointed vice president and chief financial officer of our general partner, effective September 8, 2008. In addition, Thomas C. O'Connor, Chief Executive Officer of DCP Midstream, LLC, replaced Fred J. Fowler as Chairman of the Board of our general partner, effective September 1, 2008. Mr. Fowler will remain a director of our general partner's board of directors.

During the third quarter of 2008, we announced that Collbran Valley Gas Gathering, LLC, or Collbran, plans to invest approximately $150.0 million over a multi-year period to construct approximately 20 miles of 24-inch diameter gathering pipeline, and compression and liquids handling facilities, to support its Colorado system, located in the Collbran Valley area of the Piceance Basin in western Colorado. We are the operator and 70% owner of Collbran. The gathering system is designed to ultimately have throughput capacity of over 600 million cubic feet per day, or MMcf/d, and is supported by long-term acreage dedications from Plains Exploration & Production Company and Delta Petroleum Corporation, which own 25% and 5% of

Table of Contents

Collbran, respectively, and a long-term dedication from a subsidiary of Enterprise Products Partners LP covering gas that it has the right to gather from a specified, dedicated area within the Piceance Basin. Collbran will invest approximately $100.0 million in 2008 and 2009 to achieve throughput capacity of approximately 300 MMcf/d by the second quarter of 2009. The remaining investment in primarily compression equipment of approximately $50.0 million will be spent in 2010 through 2013 as production volumes increase, providing total throughput capacity in excess of 600 MMcf/d. We ultimately expect to invest approximately $105.0 million in this project, in proportion to our respective ownership interest.

During the third quarter of 2008, we announced plans, along with DCP Midstream, LLC, to invest approximately $56.0 million in East Texas to construct a gathering pipeline to support the East Texas system. Our interest in this pipeline is 25%. The pipeline is scheduled to be operational during the second quarter of 2009.

During the third quarter of 2008, we announced plans to pursue development of a natural gas pipeline in the Haynesville shale in northern Louisiana. Development of a potential pipeline project is highly dependent upon drilling and development plans in the area, securing appropriate levels of shipper contractual commitments and securing financing.

In October 2008, due to executive management rotational changes at ConocoPhillips, Willie C.W. Chiang and Sigmund L. Cornelius resigned as directors of the board of directors of our general partner, and John E. Lowe and Gregory J. Goff were appointed as the ConocoPhillips representatives to the board of directors. Mr. Lowe currently serves as assistant to the Chief Executive Officer of ConocoPhillips, an affiliate of our general partner and Mr. Goff currently serves as Senior Vice President, Commercial of ConocoPhillips.

In October 2008, we acquired Michigan Pipeline & Processing, LLC, a privately held company engaged in natural gas gathering and treating services for natural gas produced from the Antrim Shale of northern Michigan and natural gas transportation within Michigan. Under the terms of the acquisition, we paid a purchase price of $145.0 million, plus net working capital and other adjustments of $3.1 million, subject to additional customary purchase price adjustments, plus up to an additional $15.0 million to the sellers depending on the earnings of the assets after a three-year period. We financed the acquisition with liquidation of a portion of our restricted investments. In addition, we entered into a separate agreement that provides the seller with available treating capacity on certain Michigan assets. The seller will pay us up to $1.5 million annually for up to nine years for this service; however, this agreement may be terminated earlier if certain performance criteria of Michigan assets are satisfied. We hold a $25.0 million letter of credit to secure the seller's performance under this agreement and to secure the seller's indemnification obligation under the acquisition agreement. The fees under the omnibus agreement with DCP Midstream, LLC increased $0.4 million per year effective October 1, 2008, in connection with the acquisition.

On October 23, 2008, the board of directors of the General Partner declared a quarterly distribution of $0.60 per unit, payable on November 14, 2008 to unitholders of record on November 7, 2008. This distribution of $0.60 per unit places us in the Fourth Target Distribution level (see Note 8 of the Notes to Condensed Consolidated Financial Statements in Item 1. "Financial Statements" for discussion of distributions of available cash).

In October 2008, we received distributions of $7.2 million from Discovery and paid contributions of $3.6 million to Discovery to fund capital expansion, of which $2.2 million was reimbursed by DCP Midstream, LLC. In September 2008 we received distributions of $3.3 million from East Texas and paid a contribution of $1.3 million to East Texas to fund capital expansion.

Factors That Significantly Affect Our Results

Capital Markets

Beginning in the third quarter of 2008, the capital markets experienced volatility, uncertainty and interventions by various governments around the globe. The effects of these market conditions include significant changes in the valuation of equity securities and overnight and longer-term borrowing rates. The availability of credit through traditional sources of funding such as the commercial paper, bank lending and the private and public placement debt markets also decreased dramatically. The uncertainty 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 grow our operations through acquisitions or organic growth projects. These events may impact our counterparties' ability to perform under their credit or commercial obligations. We have not observed any change in the routine payment patterns of our customers, and where possible we have obtained additional collateral agreements, letters of credit from highly rated banks, or have managed credit lines. To date, our counterparties to our existing derivative instruments have fully performed under their commitments. Due to the financial troubles of one of the lenders to our Credit Agreement, however, the availability of borrowings under this facility has been reduced by approximately $21.1 million as of November 3, 2008.

Table of Contents

Impact of Hurricanes

As a result of hurricanes during the third quarter of 2008, certain of our owned and operated facilities were fully or partially curtailed pending resumption of operations at downstream third party NGL facilities in some cases and restoration of electric power service. All of our operated assets have been returned to service. There could be some temporary impact to demand as third party NGL facilities are fully returned to service. Additionally, Discovery's offshore gathering system sustained damage as a result of hurricanes and is not accepting gas from offshore producers while repairs are being made. Inspections of the system revealed that an 18-inch lateral was severed from its connection to the 30-inch mainline in approximately 250 feet of water. Williams expects the 30-inch line to be repaired and returned to service by December 2008. Due to ongoing damage assessments, the repair schedule for the 18-inch lateral has not yet been finalized. The net income impact of hurricane-related damages and lost margins due to curtailed operations for the third quarter of 2008 was approximately $5.0 to $6.0 million, including losses from our equity method investment in Discovery. We estimate a net income impact of hurricane-related damages and lost margins due to curtailed operations for the fourth quarter of 2008 of approximately $7.0 million to $12.0 million. We do not anticipate receiving a distribution from Discovery during the first quarter of 2009 reflecting fourth quarter activity.

Other Factors

Deterioration in commodity prices did not cause a goodwill or asset impairment charge as of September 30, 2008. Future deterioration in commodity prices, unit prices or other market declines may increase the likelihood of a goodwill or asset impairment charge. An impairment charge would arise if the fair value is less than the carrying value. 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. 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 or asset impairment charges.

In July 2007, we acquired a 25% limited liability company interest in East Texas, a 40% limited liability company interest in Discovery and the Swap, which are collectively referred to as our predecessor, from DCP Midstream, LLC, in a transaction among entities under common control. Accordingly, our financial information includes the historical results of our predecessor for each period presented. Prior to July 2007, our financial statements do not give effect to various items that affected our results of operations and liquidity following this acquisition, including the indebtedness we incurred in conjunction with the closing of this acquisition, which increased our interest expense from the interest expense reflected in our historical financial statements.

Our results of operations for our Natural Gas Services segment are impacted by increases and decreases in the volume of natural gas that we gather and transport through our systems, which we refer to as throughput. Throughput and capacity utilization rates generally are driven by wellhead production and our competitive position on a regional basis, and more broadly by demand for natural gas, NGLs and condensate.

Our results of operations for our Natural Gas Services segment are also impacted by the fees we receive and the margins we generate. 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 and commodity pricing environment at the time the contract is executed and customer requirements. 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, our expansion in regions where certain types of contracts are more common and other market factors.

Additionally, our results of operations for our Natural Gas Services segment 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, which in turn has been generally correlated 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 natural gas prices being at levels sufficient to provide incentives and capital, for producers to increase natural gas exploration and production. The prices of NGLs, crude oil and natural gas can be extremely volatile for periods of time, and may not always have a close correlation. Changes in the correlation of the price of NGLs and crude oil may cause our commodity price sensitivities to vary significantly.

Based on historical trends, however, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe 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. We believe that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather, and the level of worldwide economic growth. Drilling activity can be

Table of Contents

adversely affected as natural gas prices decrease. Energy market uncertainty could also reduce North American drilling activity in the future. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

We have mitigated a portion of the anticipated commodity price risk associated with the equity volumes from our gathering and processing operations, for both our consolidated entities and our proportionate share of exposure from our equity method investments, through 2013 with natural gas and crude oil swaps. We also mitigate a portion of the anticipated commodity price risk associated with fixed price propane sales by entering into either offsetting physical purchase agreements or financial derivative instruments, with DCP Midstream, LLC or third parties, which typically match the quantities of propane subject to these fixed price sales agreements. We mark these derivative instruments to market through current period earnings based upon their fair value. While the swaps may mitigate the variability of our future cash flows resulting from changes in commodity prices, the mark-to-market method of accounting significantly increases the volatility of our net income because we recognize, in current period operating revenues, all non-cash gains and losses from the changes in the fair value of these derivatives.

We primarily use crude oil swaps to mitigate our NGL and condensate commodity price risk. As a result, the volatility of our future cash flows and net income may increase if there is a change in the pricing relationship between crude oil and NGLs. We also continue to have price risk exposure related to the portion of our equity volumes that are not covered by these derivatives and we have financial risk exposure to the extent our actual equity volumes differ from our projections. In addition, we will be required to provide cash collateral or letters of credit if the fair value of a derivative exceeds the collateral threshold set by the counterparty. Our collateral requirements may be significant.

For the nine months ended September 30, 2008, the net loss recorded in operating revenues for commodity derivatives was $81.7 million. Of the loss, $37.8 million was related to cash settlements during 2008. The fair value of commodity derivatives was a net liability of $126.7 million as of September 30, 2008. Prior to our initial public offering, DCP Midstream provided parental guarantees, totaling $63.0 million, to certain counterparties to our commodity derivative instruments. In July 2008, DCP Midstream provided additional parental guarantees totaling $200.0 million to certain counterparties to our commodity derivative instruments. These parental guarantees totaled $178.0 million as of November 3, 2008. As of November 3, 2008, we had letters of credit totaling $75.0 million. These parental guarantees and letters of credit reduce the amount of cash we may be required to post as collateral. As of November 3, 2008, we had no cash collateral posted with counterparties.

Discovery has signed definitive agreements with Chevron Corporation, Royal Dutch Shell plc, and StatoilHydro ASA to construct an approximate 35-mile gathering pipeline lateral to connect Discovery's existing pipeline system to these producers' production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. The Tahiti pipeline lateral expansion is expected to have a design capacity of approximately 200 MMcf/d. In October 2007, Chevron announced that it will face delays and that first production will commence in the third quarter of 2009. In conjunction with our acquisition of a 40% limited liability company interest in Discovery from DCP Midstream, LLC in July 2007, we entered into a letter agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will make capital contributions to us as reimbursement for remaining costs for the Tahiti pipeline lateral expansion.

Our results of operations for our Wholesale Propane Logistics segment are impacted by our ability to balance our purchases and sales of propane, which may increase our exposure to commodity price risks, and by the impact on volume and pricing from weather conditions in the Midwest and northeastern areas of the United States. Our sales of propane may decline when these areas experience periods of milder weather in the winter months, which is when the demand for propane is generally at its highest.

Our results of operations for our NGL Logistics segment are impacted by the throughput volumes of the NGLs we transport on our NGL pipelines. Our NGL pipelines transport NGLs exclusively on a fee basis.

The Black Lake pipeline has experienced increased operating costs due to pipeline integrity testing that commenced in 2005 and was completed during the second quarter of 2008. Testing revealed irregularities, the more severe of which were repaired in October 2008 and the less severe of which are scheduled for repair in 2009. DCP Midstream, LLC has agreed to indemnify us for up to $5.3 million of our pro rata share of any capital contributions required to be made by us to Black Lake associated with repairing the Black Lake pipeline that are determined to be necessary as a result of the pipeline integrity testing. We anticipate

Table of Contents

repairs of approximately $0.5 million on the pipeline. Pipeline integrity testing and repairs are our responsibility and are recognized as operating and maintenance expense. Any reimbursement of these expenses from DCP Midstream, LLC will be recognized by us as a capital contribution. We have not made any capital contributions to Black Lake associated with repairing the Black Lake pipeline.

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 Wholesale Propane Logistics segment and our NGL 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 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 or transporting natural gas; and transporting NGLs. 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/index arrangements - Under percent-of-proceeds/index 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 and NGLs 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 and NGLs, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. 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. Our revenues under percent-of-proceeds/index arrangements correlate directly with the price of natural gas and/or NGLs.

In addition to the above contract types, our equity method investments also generate equity earnings for our Natural Gas Services segment under keep-whole arrangements. Under the terms of a keep-whole processing contract, we gather raw natural gas from the producer for processing, sell the NGLs and return to the producer residue natural gas with a Btu content equivalent to the Btu content of the raw natural gas gathered. This arrangement keeps the producer whole to the thermal value of the raw 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 extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL prices are higher relative to natural gas prices when that frac spread exceeds the operating costs of our equity method investments. Fluctuations in commodity prices are expected to continue to impact the operating costs of these entities.

We have mitigated a portion of our anticipated natural gas, NGL and condensate commodity price risk associated with the equity volumes from our gathering and processing operations through 2013 with natural gas and crude oil swaps. With these swaps, we expect our cash flow exposure to commodity price movements to be reduced. For additional information regarding our derivative activities, please read "- Quantitative and Qualitative Disclosures about Market Risk - Commodity Price Risk - Commodity Cash Flow Protection Activities" in our 2007 Form 10-K and "Item 3. Quantitative and Qualitative Disclosures about Market Risk" in this Quarterly Report on Form 10-Q.

Effective July 1, 2007, we elected to discontinue using the hedge method of accounting for our commodity cash flow hedges. We are using the mark-to-market method of accounting for all commodity derivative financial 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.

. . .