classified stock-based compensation cost is measured at grant date, based on the estimated fair value of the award, and is recognized as expense over the vesting period. Liability classified stock-based compensation cost is remeasured at each reporting date and is recognized over the requisite service period. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. Awards granted to non-employees are accounted for under the provisions of EITF No. 96-18, Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services.

          Income Taxes — We are structured as a limited partnership which is a pass-through entity for federal income tax purposes.

3. New Accounting Standards

          SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS 115, or SFAS 159 — In February 2007, the Financial Accounting Standards Board, or FASB, issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 159 on our consolidated financial position.

          SFAS No. 157, Fair Value Measurements, or SFAS 157 — In September 2006, the FASB issued SFAS 157, which provides guidance for using fair value to measure assets and liabilities. The standard also responds to investors’ requests for more information about: (1) the extent to which companies measure assets and liabilities at fair value; (2) the information used to measure fair value; and (3) the effect that fair value measurements have on earnings. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 157 on our consolidated financial position.

          SFAS No. 154, Accounting Changes and Error Corrections, or SFAS 154 — In June 2005, the FASB issued SFAS 154, a replacement of APB Opinion No. 20, or APB 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. Among other changes, SFAS 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented under the new accounting principle, unless it is impracticable to do so. SFAS 154 also: (1) provides that a change in depreciation or amortization of a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle; and (2) carries forward without change the guidance within APB 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. The adoption of SFAS 154 on January 1, 2006, did not have a material impact on our consolidated financial position.

          FASB Interpretation Number, or FIN, No. 48, Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement 109, or FIN 48 — In July 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 are effective for us on January 1, 2007. The adoption of FIN 48 is not expected to have a material impact on our consolidated financial position.

          Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, or SAB 108 — In September 2006, the Securities and Exchange Commission, or SEC, issued SAB 108 to address diversity in practice in quantifying financial statement misstatements. SAB 108 requires entities to quantify misstatements based on their impact on each of their financial statements and related disclosures. SAB 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to retained earnings as of January 1, 2006 for errors that were not previously deemed material, but are material under the guidance in SAB 108. The adoption of SAB 108 did not have a material impact on our consolidated financial position.

4. Acquisition

          On November 1, 2006, we acquired our wholesale propane logistics business, from DCP Midstream, LLC for aggregate consideration consisting of approximately $82.9 million, which consisted of $77.3 million in cash ($9.9 million of which was paid in January 2007), and the issuance of 200,312 Class C units valued at approximately $5.6 million. Included in the aggregate consideration was $10.5 million of costs associated with the construction of a new propane pipeline terminal.

          The transfer of assets between DCP Midstream, LLC and us represent a transfer of assets between entities under common control. Transfers of net assets or exchanges of shares between entities under common control are accounted for as if the transfer occurred at the beginning of the period. The $26.3 million excess purchase price over the historical basis of the net acquired assets is recorded as a reduction to non-controlling interest for financial accounting purposes.

5. Agreements and Transactions with Affiliates

DCP Midstream, LLC

          DCP Midstream, LLC provided centralized corporate functions on behalf of our predecessor operations, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. The predecessor’s share of those costs was allocated based on the predecessor’s proportionate net investment (consisting of property, plant and equipment, net, equity method investment, and intangible assets, net) as compared to DCP Midstream, LLC’s net investment. In management’s estimation, the allocation methodologies used were reasonable and resulted in an allocation to the predecessors of their respective costs of doing business, which were borne by DCP Midstream, LLC.

Omnibus Agreement

          We have entered into an omnibus agreement, or the Omnibus Agreement, with DCP Midstream, LLC. Under the Omnibus Agreement, as amended, 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 of $4.8 million related to the DCP Midstream business contributed to us upon the initial public offering. The annual fee is 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, internal audit, taxes and engineering. In the second quarter of 2006, we amended the Omnibus Agreement. The amendment clarifies that the annual fee of $4.8 million under the agreement is fixed at such amount, subject to annual increases in the Consumer Price Index, and increases in connection with the expansion of our operations through the acquisition or construction of new assets or businesses. The Omnibus Agreement was further amended in November 2006, in conjunction with the acquisition of our wholesale propane logistics business from DCP Midstream, LLC. Under this amendment, we pay DCP Midstream, LLC an additional annual fee of $2.0 million related to our wholesale propane logistics business, subject to the same conditions noted above. This additional $2.0 million fee was prorated in 2006 from the date of our wholesale propane logistics business acquisition.

          The Omnibus Agreement addresses the following matters:

	•		our obligation to reimburse DCP Midstream, LLC for the payment of operating expenses, including salary and benefits of operating personnel, it incurs on our behalf in connection with our business and operations;
	•		our obligation to reimburse DCP Midstream, LLC for providing us with general and administrative services with respect to our business and operations, which is $6.8 million, subject to an increase for 2007 and 2008 based on increases in the Consumer Price Index and subject to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses with the concurrence of our special committee;
	•		our obligation to reimburse DCP Midstream, LLC for insurance coverage expenses it incurs with respect to our business and operations and with respect to director and officer liability coverage;
	•		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, including without limitation guarantees and letters of credit, for our obligations related to derivative financial instruments, such as commodity price hedging contracts, to the extent that such credit support arrangements were in effect as of the closing of the initial public offering until the earlier to occur of the fifth anniversary of the closing of the initial public offering or such time as we obtain an investment grade credit rating from either Moody’s Investor Services, Inc. or Standard & Poor’s Ratings Group with respect to any of our unsecured indebtedness; and
	•		DCP Midstream, LLC’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to commercial contracts with respect to its business or operations that were in effect at the closing of the initial public offering until the expiration of such contracts.

          Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions, will be terminable by DCP Midstream, LLC at its option if we are removed as the general partner without cause and units held by us and our affiliates are not voted in favor of that removal. The Omnibus Agreement will also terminate in the event of a change of control of DCP Partners, us or our General Partner.

Competition

          None of DCP Midstream, LLC, nor any of its affiliates, including Spectra Energy and ConocoPhillips, is restricted, under either the partnership agreement or the Omnibus Agreement, from competing with us. DCP Midstream, LLC and any of its affiliates, including Spectra Energy and ConocoPhillips, may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

  Indemnification

          Under the Omnibus Agreement, DCP Midstream, LLC will indemnify us for three years after the closing of the initial public offering against certain potential environmental claims, losses and expenses associated with the operation of the assets and occurring before the closing date of the initial public offering. DCP Midstream, LLC’s maximum liability for this indemnification obligation does not exceed $15 million and DCP Midstream, LLC does not have any obligation under this indemnification until our aggregate losses exceed $250,000. DCP Midstream, LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of the initial public offering. We have agreed to indemnify DCP Midstream, LLC against environmental liabilities related to our assets to the extent DCP Midstream, LLC is not required to indemnify us.

          Additionally, DCP Midstream, LLC will indemnify us for losses attributable to title defects, retained assets and liabilities (including preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. We will indemnify DCP Midstream, LLC for all losses attributable to the postclosing operations of the assets contributed to us, to the extent not subject to DCP Midstream, LLC’s indemnification obligations. In addition, 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 any repairs to the Black Lake pipeline that are determined to be necessary as a result of the currently ongoing pipeline integrity testing occurring from 2005 through 2007. DCP Midstream, LLC has also agreed to indemnify us for up to $4.0 million of the costs associated with any repairs to the Seabreeze pipeline that are determined to be necessary as a result of pipeline integrity testing that occurred in 2006. 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. Reimbursements related to the Seabreeze pipeline integrity repairs in 2006 were not significant.

Other Agreements and Transactions with DCP Midstream, LLC

          DCP Midstream, LLC owns certain assets and is party to certain contractual relationships around our Pelico system that are periodically used for the benefit of Pelico. DCP Midstream, LLC is able to source natural gas upstream of Pelico and deliver it to the inlet of the Pelico system, and is able to take natural gas from the outlet of the Pelico system and market it downstream of Pelico. Because of DCP Midstream, LLC’s ability to move natural gas around Pelico, there are certain contractual relationships around Pelico that define how natural gas is bought and sold between us and DCP Midstream, LLC.

          Effective December 2005, we entered into a contractual arrangement with a subsidiary of DCP Midstream, LLC that provides that DCP Midstream, LLC will purchase natural gas and transport it to the Pelico system, where we will buy the gas from DCP Midstream, LLC at its weighted-average cost delivered to the Pelico system, plus a contractually agreed-to marketing fee and other related adjustments. In addition, for a significant portion of the gas that we sell out of our Pelico system, DCP Midstream, LLC will purchase that natural gas from us and transport it to a sales point at a price equal to its net weighted-average sales price, less a contractually agreed-to marketing fee and other related adjustments.

          The above agreement was amended and restated effective February 2006 in response to DCP Midstream, LLC securing additional access to natural gas for our Pelico system. The revised agreement is described below:

•

DCP Midstream, LLC will supply Pelico’s system requirements that exceed its on-system supply. Accordingly, DCP Midstream, LLC purchases natural gas and transports it to our Pelico system, where we buy the gas from DCP Midstream, LLC at the actual acquisition cost plus transportation service charges incurred.

•

If our Pelico system has volumes in excess of the on-system demand, DCP Midstream, LLC will purchase the excess natural gas from us and transport it to sales points at an index-based price, less a contractually agreed-to marketing fee.

•

In addition, DCP Midstream, LLC may purchase other excess natural gas volumes at certain Pelico outlets for a price that equals the original Pelico purchase price from DCP Midstream, LLC, plus a portion of the index differential between upstream sources to certain downstream indices with a maximum differential and a minimum differential, plus a fixed fuel charge and other related adjustments.

          Effective December 2005, we entered into a contractual arrangement with a subsidiary of DCP Midstream, LLC that provides that for certain industrial end-user customers of the Pelico system we may sell aggregated natural gas to a subsidiary of DCP Midstream, LLC, which in turn would resell natural gas to these customers. The sales price to the subsidiary of DCP Midstream, LLC is equal to that subsidiary of DCP Midstream, LLC’s net weighted-average sales price delivered from the Pelico system less a contractually agreed-to marketing fee.

          Effective December 2005, we entered into a contractual arrangement with a subsidiary of DCP Midstream, LLC that provides that DCP Midstream, LLC will purchase the NGLs that were historically purchased by the Seabreeze pipeline, and DCP Midstream, LLC will pay us to transport the NGLs pursuant to a fee-based rate that will be applied to the volumes transported. We have entered into this fee-based contractual arrangement with the objective of generating approximately the same operating income per barrel transported that we realized when we were the purchaser and seller of NGLs. We do not take custody to the products transported on the NGL pipeline; rather, the shipper retains custody and the associated commodity price risk. DCP Midstream, LLC is the sole shipper on the Seabreeze pipeline under a 17-year transportation agreement expiring in 2022.

          In December 2006, we completed construction of our Wilbreeze pipeline, which connects a DCP Midstream, LLC gas processing plant to our Seabreeze pipeline. The project is supported by a 10-year NGL product dedication agreement with DCP Midstream, LLC.

          We sell NGLs and condensate from our Minden and Ada processing plants, and condensate from our Pelico system to a subsidiary of DCP Midstream, LLC equal to that subsidiary of DCP Midstream, LLC’s net weighted-average sales price adjusted for transportation and other charges from the tailgate of the respective asset. We also sell propane to a subsidiary of DCP Midstream, LLC.

          We anticipate continuing to purchase these commodities from and sell these commodities to DCP Midstream, LLC in the ordinary course of business.

          In the second quarter of 2006, we entered into a letter agreement with DCP Midstream, LLC whereby DCP Midstream, LLC will make capital contributions to us as reimbursement for capital projects, which were forecasted to be completed prior to the initial public offering, but were not completed by that date. Pursuant to the letter agreement, DCP Midstream, LLC made capital contributions to us of $3.4 million during 2006, to reimburse us for the capital costs we incurred, primarily for growth capital projects. At December 31, 2006, all of these projects were completed.

          We have a note receivable from DCP Midstream, LLC totaling $183.0 million. This note is due on demand; however, we do not anticipate requiring DCP Midstream, LLC to repay this amount. Accordingly we have reflected this receivable as a component of member’s equity. The note receivable bears interest at the greater of 5.00% or the applicable federal rate in effect under section 1274(d) of the Internal Revenue Code of 1986. The interest rate in effect on the note was 5.00% at December 31, 2006. All interest income earned under the note has been distributed to DCP Midstream, LLC.

          In accordance with our partnership agreement, we distribute all cash to our members according to their membership interests.

Duke Energy and Spectra Energy

          Prior to December 31, 2006, we charged transportation fees, sold a portion of our residue gas to, and purchased raw natural gas from, Duke Energy and its affiliates. We anticipate continuing to purchase and sell these commodities to Spectra Energy and its affiliates in the ordinary course of business.

ConocoPhillips

          We have multiple agreements whereby we provide a variety of services to ConocoPhillips and its affiliates. The agreements include fee-based and percentage-of-proceeds gathering and processing arrangements, and gas purchase and gas sales agreements. We anticipate continuing to purchase from and sell these commodities to ConocoPhillips and its affiliates in the ordinary course of business. In addition, we may be reimbursed by ConocoPhillips for certain capital projects where the work is performed by us. We received $3.9 million of capital reimbursements during the year ended December 31, 2006.

          We had accounts receivable and accounts payable with affiliates as follows as of December 31, 2006 ($ in millions):

DCP Midstream, LLC:
Accounts receivable		$	30.0
Accounts payable		$	46.6
Duke Energy:
Accounts receivable		$	0.2
Accounts payable		$	1.8
ConocoPhillips:
Accounts receivable		$	4.6
Accounts payable		$	2.0

6. Property, Plant and Equipment

          A summary of property, plant and equipment by classification is as follows as of December 31, 2006 ($ in millions):

		Depreciable
		Life
Gathering systems		15 — 30 Years				$	107.3
Processing plants		25 — 30 Years					53.2
Terminals		25 — 30 Years					8.2
Transportation		25 — 30 Years					139.6
General plant		3 — 5 Years					3.6
Construction work in progress							16.2
Property, plant and equipment							328.1
Accumulated depreciation							(133.4	)
Property, plant and equipment, net						$	194.7

          Asset Retirement Obligations — Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust our asset retirement obligation each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The asset retirement obligation, included in other long-term liabilities in the consolidated balance sheet, was $0.5 million at December 31, 2006.

7. Goodwill and Intangible Assets

          Goodwill consists of the amount that was recognized by DCP Midstream, LLC when it acquired certain assets which are now included in our Wholesale Propane Logistics segment, and was allocated based on fair value to the wholesale propane logistics business in order to present historical information about the assets we acquired in November 2006. As this was a transaction among entities under common control, our financial information includes the results of our wholesale propane logistics business for the entire period presented. There were no changes in the $29.3 million carrying amount of goodwill during the year ended December 31, 2006. We perform an annual goodwill impairment test, and update the test during interim periods if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We use a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. Our annual goodwill impairment test indicated that our reporting unit’s fair value exceeded its carrying or book value; therefore, we have determined that there is no indication of impairment.

          Intangible assets consist primarily of commodity purchase contracts. The gross carrying amount and accumulated amortization for the commodity purchase contracts and other intangible assets are included in the accompanying consolidated balance sheet as intangible assets, and are as follows as of December 31, 2006 ($ in millions):

Gross carrying amount		$	4.4
Accumulated amortization			(1.6	)
Intangible assets, net		$	2.8

          As of December 31, 2006, the remaining amortization periods for these contracts range from approximately two to 20 years, with a weighted-average remaining period of approximately 15 years.

8. Equity Method Investments

          We have two investments accounted for using the equity method. The following table includes our percentage of ownership and the carrying value of our investments as of December 31, 2006 ($ in millions):

		Percentage of
		Ownership				Carrying Value
Black Lake Pipe Line Company			45	%		$	5.7
Other			50	%			0.2

          Black Lake owns a 317-mile NGL pipeline, with a throughput capacity of approximately 40 MBbls/d. The pipeline receives NGLs from a number of gas plants in Louisiana and Texas. There was a deficit between the carrying amount of the investment and the underlying equity of Black Lake of $6.7 million at December 31, 2006, which is associated with, and is being accreted over, the life of the underlying long-lived assets of Black Lake.

          The following summarizes balance sheet information of our equity method investments as of December 31, 2006 ($ in millions):

Balance sheet:
Current assets		$	4.0
Non-current assets.			18.3
Current liabilities			0.8
Net assets		$	21.5

9. Estimated Fair Value of Financial Instruments

          We have determined the following fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts. The following summarizes the estimated fair value of financial instruments as of December 31, 2006 ($ in millions):

						Estimated
		Carrying				Fair
		Amount				Value
Restricted investments		$	102.0			$	102.0
Accounts receivable		$	78.2			$	78.2
Accounts payable		$	117.3			$	117.3
Unrealized gains (losses) on non-trading derivative and hedging instruments		$	7.3			$	7.3
Long-term debt		$	268.0			$	268.0

          The fair value of restricted investments, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short term nature of these instruments or the stated rates approximating market rates. Unrealized gains and unrealized losses on mark-to-market and hedging instruments are carried at fair value.

          The carrying value of long-term debt approximates fair value, as the interest rate is variable and reflects current market conditions.

10. Debt

          Credit Facility with Financial Institutions — On December 7, 2005, we entered into a 5-year credit agreement, or the Credit Agreement, providing a $250.0 million revolving and a $100.1 million term loan facility. The unused portion of the revolving credit facility may be used for letters of credit. The Credit Agreement matures on December 7, 2010. The Credit Agreement prohibits us from making distributions of Available Cash to unitholders if any default or event of default (as defined in the Credit Agreement) exists. The Credit Agreement requires us to maintain at all times (commencing with the quarter ended March 31, 2006) a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as is defined by the Credit Agreement) of less than or equal to 4.75 to 1.0 (and on a temporary basis for not more than three consecutive quarters following the acquisition of assets in the midstream energy business of not more than 5.25 to 1.0); and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the Credit Agreement to be earnings before interest, taxes and depreciation and amortization and other non-cash adjustments, for the four most recent quarters to interest expense for the same period) of greater than or equal to 3.0 to 1.0.

          The revolving credit facility bears interest at a rate equal to the London Interbank Offered Rate, or LIBOR, plus an applicable margin, which ranges from 0.27% to 1.025%, based on leverage level or credit rating, or at the higher of the federal funds rate plus 0.50% or Wachovia Bank’s prime rate plus an applicable margin of 0% to 0.025%, based on leverage level. The weighted-average interest rate on the revolving credit facility was 5.86% at December 31, 2006. The revolving credit facility incurs an annual facility fee of 0.08% to 0.35%, depending on the applicable leverage level or debt rating. This fee is paid on drawn and undrawn portions of the revolving credit facility. The term loan bears interest at a rate equal to either the London Interbank Offered Rate, or LIBOR, plus 0.15%, the federal funds rate plus 0.5%, or the Wachovia Bank prime rate. The interest rate on the term loan was 5.47% at December 31, 2006.

          At December 31, 2006, there was $168.0 million outstanding on the revolving credit facility, and $100.0 million outstanding on the term loan facility. The term loan facility is fully collateralized by high-grade securities, which are classified as restricted investments on the consolidated balance sheet. As of December 31, 2006, $1.1 million was recorded as accrued interest payable in the consolidated balance sheet. At December 31, 2006 there were $0.2 million letters of credit outstanding. In December 2005, we incurred $0.7 million of debt issuance costs associated with the Credit Agreement. These expenses are deferred as other non-current assets in the consolidated balance sheet and will be amortized over the term of the Credit Agreement.

          Long-term debt at December 31, 2006 was as follows ($ in millions):

		Principal
		Amount
Revolving credit facility, weighed-average interest rate of 5.86% at December 31, 2006, due December 7, 2010		$	168.0
Term loan facility, interest rate of 5.47% at December 31, 2006, due December 7, 2010			100.0
Total long-term debt		$	268.0

11. Non-Controlling Interest

          Non-controlling interest represents the ownership interests of DCP Partners’ public unitholders in net assets of DCP Partners through DCP Partners’ publicly traded common units, as well as affiliate ownership interests in common units and in all of the class C and subordinated units. We own a 2% general partner interest in DCP Partners. For financial reporting purposes, the assets and liabilities of DCP Partners are consolidated with those of our own, with any third party and affiliate investors’ interest in our consolidated balance sheet amounts shown as non-controlling interest. Distributions to and contributions from non-controlling interests represent cash payments and cash contributions, respectively, from such third-party and affiliate investors.

          At December 31, 2006, DCP Partners had outstanding 10,357,143 common units, 200,312 class C units and 7,142,857 subordinated units.

          General — DCP Partners’ partnership agreement requires that, within 45 days after the end of each quarter, DCP Partners distribute all Available Cash (defined below) to unitholders of record on the applicable record date, as determined by us as the general partner.

          Definition of Available Cash — Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

•

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

	•		provide for the proper conduct of our business;
	•		comply with applicable law, any of our debt instruments or other agreements; or
	•		provide funds for distributions to the unitholders and to us as the general partner for any one or more of the next four quarters;

•

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

          General Partner Interest and Incentive Distribution Rights — We as the general partner are entitled to 2% of all quarterly distributions that DCP Partners makes prior to their liquidation. We have the right, but not the obligation, to contribute a proportionate amount of capital to DCP Partners to maintain our current general partner interest. Our 2% interest in these distributions will be reduced if DCP Partners issues additional units in the future and we do not contribute a proportionate amount of capital to DCP Partners to maintain our 2% general partner interest.

          The incentive distribution rights held by us entitle us to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. Our incentive distribution rights are not reduced if DCP Partners issues additional units in the future and we do not contribute a proportionate amount of capital to DCP Partners to maintain our 2% general partner interest. Please read the Distributions of Available Cash during the Subordination Period and Distributions of Available Cash after the Subordination Period sections below for more details about the distribution targets and their impact on our incentive distribution rights.

          Class C Units — The Class C units have the same liquidation preference, rights to cash distributions and voting rights as the common units. The Class C units will automatically convert to common units once the Class C units represent less than 1% of the total outstanding limited partner units. After two years, if the Class C units are not converted into common units, either automatically or by common unitholder approval, they will receive 115% of the distribution amount for common units.

          Subordinated Units — All of the subordinated units are held by DCP Midstream, LLC. Our partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of Available Cash each quarter in an amount equal to $0.35 per common unit, or the Minimum Quarterly Distribution, plus any arrearages in the payment of the Minimum Quarterly Distribution on the common units from prior quarters, before any distributions of Available Cash may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the Minimum Quarterly Distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one for one basis, when certain distribution requirements, as defined in the partnership agreement, have been met. The earliest date at which the subordination period may end is December 31, 2008 and 50% of the subordinated units may convert to common units as early as December 31, 2007. The rights of the subordinated unitholders, other than the distribution rights described above, are substantially the same as the rights of the common unitholders.

          Distributions of Available Cash during the Subordination Period — The partnership agreement requires that DCP Partners make distributions of Available Cash for any quarter during the subordination period in the following manner:

	•		first, 98% to the common unitholders, pro rata, and 2% to us as the general partner, until DCP Partners distributes for each outstanding common unit an amount equal to the Minimum Quarterly Distribution for that quarter;
	•		second, 98% to the common unitholders, pro rata, and 2% to us as the general partner, until DCP Partners distributes for each outstanding common unit an amount equal to any arrearages in payment of the Minimum Quarterly Distribution on the common units for any prior quarters during the subordination period;
	•		third, 98% to the subordinated unitholders, pro rata, and 2% to us as the general partner, until DCP Partners distributes for each subordinated unit an amount equal to the Minimum Quarterly Distribution for that quarter; and
	•		fourth, 98% to all unitholders, pro rata, and 2% to us as the general partner, until each unitholder receives a total of $0.4025 per unit for that quarter (the First Target Distribution);
	•		fifth, 85% to all unitholders, pro rata, and 15% to us as the general partner, until each unitholder receives a total of $0.4375 per unit for that quarter (the Second Target Distribution);

	•		sixth, 75% to all unitholders, pro rata, and 25% to us the general partner, until each unitholder receives a total of $0.525 per unit for that quarter (the Third Target Distribution); and
	•		thereafter, 50% to all unitholders, pro rata, and 50% to us as the general partner (the Fourth Target Distribution).

          Distributions of Available Cash after the Subordination Period — DCP Partners’ partnership agreement requires that they make distributions of Available Cash from operating surplus for any quarter after the subordination period in the following manner:

	•		first, 98% to all unitholders, pro rata, and 2% to us as the general partner, until each unitholder receives a total of $0.4025 per unit for that quarter;
	•		second, 85% to all unitholders, pro rata, and 15% to us as the general partner, until each unitholder receives a total of $0.4375 per unit for that quarter;
	•		third, 75% to all unitholders, pro rata, and 25% to us as the general partner, until each unitholder receives a total of $0.525 per unit for that quarter; and
	•		thereafter, 50% to all unitholders, pro rata, and 50% to us as the general partner.

          In February 2006, we paid a cash distribution of $0.095 per unit, to unitholders of record on February 3, 2006. That distribution represented the pro rata portion of our Minimum Quarterly Distribution of $0.35 per unit for the period December 7, 2005, the closing of our initial public offering, through December 31, 2005. During 2006, we paid additional quarterly cash distributions aggregating $1.135 per unit.

12. Member’s Equity

          At December 31, 2006, member’s equity consisted of our capital account, a note receivable from DCP Midstream, LLC and accumulated other comprehensive income.

           As of December 31, 2006, we had a deficit balance of $5.0 million in our member’s equity account. This negative balance does not represent an asset to us and does not represent obligations by us to contribute cash or other property. The member’s equity account generally consists of our cumulative share of net income less cash distributions made plus capital contributions made. Cash distributions that we receive during a period from DCP Partners may exceed our interest in DCP Partners’ net income for the period. DCP Partners makes quarterly cash distributions of all of its Available Cash, defined above. Future cash distributions that exceed net income and contributions made will result in an increase in the deficit balance in the member’s equity account.

13. Risk Management and Hedging Activities, Credit Risk and Financial Instruments

          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 the effects of the identified risks. In general, we attempt to hedge 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. We have established a comprehensive risk management policy, or the Risk Management Policy, and a risk management committee, to monitor and manage market risks associated with commodity prices and interest rates. Our Risk Management Policy prohibits the use of derivative instruments for speculative purposes.

          Commodity Price Risk — Our operations of gathering, processing, and transporting natural gas, and the accompanying operations of transporting and marketing of NGLs create commodity price risk due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. As an owner and operator of natural gas processing and other midstream assets, we have an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts to purchase and process raw natural gas. Risk is also dependent on the types and mechanisms for sales of natural gas and NGLs, and related products produced, processed, transported or stored.

          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. To the extent that we carry propane inventories or our sales and supply arrangements are not aligned we are exposed to market variables and commodity price risk. The amount and type of price risk is dependent on the mechanisms and locations for purchases, sales, transportation and storage of propane.

          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.

          Credit Risk — In the Natural Gas Services segment, 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. In the Wholesale Propane Logistics segment, we sell primarily to retail propane distributors. In the NGL Logistics segment, our principal customers include an affiliate of DCP Midstream, LLC, producers and marketing companies. Concentration of credit risk may affect our overall credit risk, in that 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 and guidelines. The 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.

          Commodity Cash Flow Hedges — We executed a series of derivative financial transactions, referred to as swap contracts. In 2005 we entered into natural gas swap contracts with a combined notional volume of approximately 4,000 MMBtu/day for a term of January 2006 through December 2010. These contracts are intended to hedge the risk of weakening natural gas prices. In 2005 we also entered into crude oil swap contracts with a combined notional volume of approximately 650 Bbls/day for a term of January 2006 through December 2010. These contracts are intended to hedge the risk of weakening NGL and condensate prices. In 2006 we entered into crude oil swap contracts with a notional volume of 350 Bbls/day for a term of January 2011 through December 2011. These contracts are intended to hedge the risk of weakening condensate prices. Each of these swap contracts has been designated as a cash flow hedge. As a result of these transactions, we have hedged a significant portion of our expected natural gas and NGL commodity price risk relating to our percentage-of-proceeds gathering and processing contracts through 2010, and of our expected condensate commodity price risk relating to condensate recovered from gathering operations through 2011.

          We use natural gas and crude oil swaps to hedge the impact of market fluctuations in the price of NGLs, natural gas and condensate. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is accumulated in AOCI, and the ineffective portion is recorded in the consolidated statement of operations as sales of natural gas, propane, NGLs and condensate. For the year ended December 31, 2006, we recognized losses of $0.3 million due to the ineffectiveness of these cash flow hedges. For the year ended December 31, 2006, gains of $2.6 million were reclassified into earnings as a result of settlements. For the year ended December 31, 2006, no derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring, or due to a derivative no longer qualifying as an effective hedge. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.

          During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction will be reclassified to earnings. As of December 31, 2006, there were net deferred gains of $0.1 million related to commodity cash flow hedge derivative contracts in AOCI. As of December 31, 2006, $0.1 million of deferred net gains on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.

          Commodity Fair Value Hedges — We use fair value hedges to hedge exposure to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to fixed price risk. We may hedge producer price locks (fixed price gas purchases) to reduce our exposure to fixed price risk by swapping the fixed price risk for a floating price position (New York Mercantile Exchange or index-based).

          All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. During the year ended December 31, 2006, there were no firm commitments that no longer qualified as fair value hedge items and, therefore, we did not recognize an associated gain or loss.

          Normal Purchases and Normal Sales — If a contract qualifies and is designated as a normal purchase or normal sale, no recognition of the contract’s fair value in the consolidated balance sheet is required until the associated delivery period impacts earnings. We have applied this accounting election for contracts involving the purchase or sale of physical natural gas, propane or NGLs in future periods.

          Commodity Non-Trading Derivative Activity — Our operations of gathering, processing, and transporting natural gas, and the accompanying operations of transporting and marketing of NGLs create commodity price risk due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. To the extent possible, we match the pricing of our supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial transactions. We occasionally will enter into financial derivatives to lock in price differentials across the Pelico system to maximize the value of pipeline capacity. These financial derivatives are accounted for using mark-to-market accounting with changes in fair value recognized in current period earnings.

          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 them 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. These financial derivatives are accounted for using mark-to-market accounting with changes in fair value recognized in current period earnings. We manage our asset-based activities in accordance with our Risk Management Policy which limits exposure to market risk and requires regular reporting to management of potential financial exposure. In addition, we may on occasion use financial derivatives to manage the value of our propane inventories.

          Interest Rate Cash Flow Hedge — During 2006, we entered into interest rate swap agreements to hedge the variable interest rate on $125.0 million of the indebtedness outstanding under their revolving credit facility. The interest rate swap agreements have been designated as cash flow hedges, and effectiveness 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 sheet. For the year ended December 31, 2006, gains reclassified into earnings as a result of settlements were insignificant. As of December 31, 2006, gains deferred in AOCI related to these swaps were insignificant. As of December 31, 2006, an insignificant amount of these deferred net gains on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings however, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings. Ineffective portions of changes in fair value are recognized in earnings. The agreements reprice prospectively approximately every 90 days, and expire on December 7, 2010. Under the terms of the interest rate swap agreements, we pay fixed rates ranging from 4.68% to 5.08%, and receive interest payments based on the three-month LIBOR. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense. The agreements are with major financial institutions, which are expected to fully perform under the terms of the agreements.

14. Equity-Based Compensation

          On November 28, 2005, the board of directors of our General Partner adopted the LTIP for employees, consultants and directors of our General Partner and its affiliates who perform services for us, effective as of December 7, 2005. Under the LTIP, equity-based instruments may be granted to our key employees. The LTIP provides for the grant of limited partner units, or LPUs, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of DERs. Subject to adjustment for certain events, an aggregate of 850,000 LPUs may be delivered pursuant to awards under the LTIP. Awards that are canceled, forfeited or are withheld to satisfy our General Partner’s tax withholding obligations are available for delivery pursuant to other awards. The LTIP is administered by the compensation committee of our General Partner’s board of directors. We first granted awards under the LTIP during 2006.

          Performance Units — During the year ended December 31, 2006, we awarded 40,560 phantom LPUs pursuant to the LTIP, or Performance Units, to certain employees. Performance Units generally vest in their entirety at the end of a three year performance period. The number of Performance Units which will ultimately vest range from 0% to 150% of the outstanding Performance Units, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of the board of directors of our General Partner. Each Performance Unit includes a DER, which will be paid in cash at the end of the performance period. At December 31, 2006, there was approximately $0.6 million of unrecognized compensation expense related to the Performance Units that is expected to be recognized over a weighted-average period of 2.0 years. The following table presents information related to the Performance Units:

						Grant Date				Measurement
						Weighted-				Date
						Average				Weighted-
						Price per				Average Price
		Units				Unit				per Unit
Outstanding at December 31, 2005			—			$	—
Granted			40,560			$	26.96
Forfeited			(17,470	)		$	26.96
Outstanding at December 31, 2006			23,090			$	26.96			$	34.55
Expected to vest			23,090			$	26.96			$	34.55

          The estimate of Performance Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in earnings.

          IPO Phantom Units — In conjunction with the initial public offering, in January 2006 our General Partner’s board of directors awarded phantom LPUs, or IPO Phantom Units, to key employees, and to directors who are not officers or employees of affiliates of our General Partner. Of these IPO Phantom Units, 16,700 units will vest upon the three year anniversary of the grant date, and 8,000 units vest ratably over three years. Each IPO Phantom Unit includes a DER, which is paid quarterly in arrears. At December 31, 2006, there was approximately $0.5 million of unrecognized compensation expense related to the IPO Phantom Units that is expected to be recognized over a weighted-average period of 1.7 years. The following table presents information related to the IPO Phantom Units:

						Grant Date				Measurement
						Weighted-				Date
						Average				Weighted-
						Price per				Average Price
		Units				Unit				per Unit
Outstanding at December 31, 2005			—			$	—
Granted			35,900			$	24.05
Forfeited			(11,200	)		$	24.05
Outstanding at December 31, 2006			24,700			$	24.05			$	34.55
Expected to vest			24,700			$	24.05			$	34.55

          The estimate of IPO Phantom Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in earnings.

          We intend to settle the awards issued under the LTIP in cash upon vesting. Compensation expense is recognized ratably over each vesting period, and will be remeasured quarterly for all awards outstanding until the units are vested. The fair value of all awards is determined based on the closing price of our common units at each measurement date. During the year ended December 31, 2006, no awards were vested or settled.

15. Income Taxes

          We are structured as a limited partnership, which is a pass-through entity for U.S. income tax purposes. Accordingly, we had no deferred tax balances as of December 31, 2006.

          In May 2006, the State of Texas enacted a new margin-based franchise tax into law that replaces the existing franchise tax. This new tax is commonly referred to as the Texas margin tax. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the new tax. The tax is considered an income tax for purposes of adjustments to the deferred tax liability. The tax is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax becomes effective for franchise tax reports due on or after January 1, 2008. The tax, which is assessed at 1% of taxable margin apportioned to Texas, will be based on the margin earned during the prior calendar year.

          The Texas margin tax is considered an income tax for purposes of calculating the deferred tax liability. GAAP requires that deferred taxes be adjusted upon enactment of new tax law, which occurred in 2006. The deferred tax liabilities associated with the Texas margin tax were insignificant.

16. Commitments and Contingent Liabilities

          Litigation — We are not a party to any significant legal proceedings but are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of business. Management currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect upon our consolidated financial position.

          In June 2006, a DCP Midstream, LLC customer whose plant is served by our Seabreeze pipeline notified DCP Midstream, LLC that off specification NGLs had been received into their facility. Our Seabreeze pipeline transports NGLs owned by DCP Midstream, LLC that are delivered to the customer under the terms of a transportation agreement. The customer sent a letter to DCP Midstream, LLC claiming that the off specification NGLs delivered to their facility caused damage to their plant facility. On December 29, 2006 we entered into a settlement agreement with the customer to settle all issues regarding this matter, and their portion of the settlement was $0.3 million.

          In December 2006, El Paso E&P Company, L.P., or El Paso, filed a lawsuit against one of our subsidiaries in District Court, Harris County, Texas. The litigation stems from an ongoing commercial dispute involving our Minden processing plant that dates back to August 2000, which is prior to our acquisition of this asset from DCP Midstream, LLC. El Paso claims damages, including interest, in the amount of $5.7 million in the litigation, the bulk of which stems from audit claims under our commercial contract for historical periods prior to our ownership of this asset. We will only be responsible for potential payments, if any, for claims that involve periods of time after the date we acquired this asset from DCP Midstream, LLC in December 2005. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated financial position.

          Insurance — For a portion of 2006, we obtained property and excess liability insurance coverage through DCP Midstream, LLC. In 2006, DCP Midstream, LLC carried our property and excess liability insurance coverage with an affiliate of Duke Energy and an affiliate of ConocoPhillips. DCP Midstream, LLC provides our remaining insurance coverage with a third party insurer. DCP Midstream, LLC’s insurance coverage includes: (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) excess liability insurance above the established primary limits for commercial general liability and automobile liability insurance; (5) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, windstorms, earthquake, flood damage and business interruption/extra expense; and (6) directors and officers insurance covering our directors and officers for acts related to our activities. All coverages are subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations. Effective August 2006, we contracted with a third party insurer for their property and primary liability insurance coverage.

          Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated financial position.

          Indemnification — DCP Midstream, LLC has indemnified us for three years after the closing of the initial public offering against certain potential environmental claims, losses and expenses associated with the operation of the assets and occurring before the closing of the initial public offering, on December 7, 2005. DCP Midstream, LLC’s maximum liability for this indemnification obligation is $15.0 million and DCP Midstream, LLC does not have any obligation under this indemnification until our aggregate losses exceed $250,000. DCP Midstream, LLC has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of the initial public offering. We have

20

agreed to indemnify DCP Midstream, LLC against environmental liabilities related to our assets to the extent DCP Midstream, LLC is not required to indemnify us.

          Additionally, DCP Midstream, LLC will indemnify us for three years after the closing for losses attributable to title defects, certain retained assets and liabilities (including preclosing legal actions relating to contributed assets) and income taxes attributable to pre-closing operations. We will indemnify DCP Midstream, LLC for all losses attributable to the postclosing operations of the assets contributed to us, to the extent not subject to DCP Midstream, LLC’s indemnification obligations. In addition, 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 any repairs to the Black Lake pipeline that are determined to be necessary as a result of the ongoing pipeline integrity testing occurring from 2005 through 2007. DCP Midstream, LLC has also agreed to indemnify us for up to $4.0 million of the costs associated with any repairs to the Seabreeze pipeline that are determined to be necessary as a result of pipeline integrity testing that occurred in 2006. 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. Reimbursements related to the Seabreeze pipeline integrity repairs in 2006 were not significant.

          Other Commitments and Contingencies — We utilize assets under operating leases in several areas of operation. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.

          Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2006 ($ in millions):

2007		$	9.7
2008			7.8
2009			5.8
2010			5.1
2011			4.3
Thereafter			10.4
Total minimum rental payments		$	43.1

17. Business Segments

          Our operations are located in the United States and are organized into three reporting segments: (1) Natural Gas Services; (2) Wholesale Propane Logistics; and (3) NGL Logistics.

          Natural Gas Services — The Natural Gas Services segment consists of the North Louisiana system assets, an integrated gas gathering, compression, treating, processing, and transportation system located in northern Louisiana and southern Arkansas that includes the Minden and Ada natural gas processing plants and gathering systems and the Pelico intrastate natural gas gathering and transportation pipeline.

          Wholesale Propane Logistics — The Wholesale Propane Logistics segment consists of six owned propane rail terminals located in the Midwest and northeastern United States, one leased propane marine terminal located in Providence, Rhode Island, one propane terminal pipeline under construction in Midland, Pennsylvania and access to several open access pipeline terminals.

          NGL Logistics — The NGL Logistics segment consists of the Seabreeze and Wilbreeze NGL transportation pipelines, which are located along the Gulf Coast area of southeastern Texas, and a non-operated 45% equity interest in the Black Lake interstate NGL pipeline located in northern Louisiana and southeastern Texas, and regulated by the Federal Energy Regulatory Commission, or FERC. DCP Midstream, LLC owns a 5% interest in Black Lake, effective with the date of the initial public offering, and an affiliate of BP PLC owns the remaining interest and is the operator of Black Lake.

          These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to monitor the business of each segment. The accounting policies for the segments are the same as those described in Note 2.

          The following table sets forth our total assets segment information as of December 31, 2006 ($ in millions):

Segment non-current assets:
Natural Gas Services		$	147.4
Wholesale Propane Logistics			50.2
NGL Logistics			35.1
Other (a)			109.3
Total non-current assets			342.0
Current assets			159.6
Total assets		$	501.6

18. Subsequent Events

          In April 2007, we acquired certain gathering and compression assets located in North Louisiana for approximately $10.2 million. This acquisition was financed via the redemption of existing securities held as restricted investments.

          In March 2007, we entered into a definitive agreement to acquire certain gathering and compression assets located in southern Oklahoma from Anadarko Petroleum Corporation for approximately $180.3 million, subject to customary closing conditions and certain regulatory approvals. We paid an earnest deposit of $9.0 million when we entered into this agreement. If Anadarko Petroleum Corporation terminates because we materially breach our representations, warranties or covenants under this agreement, they may retain this earnest deposit as liquidated damages. This transaction is expected to close in the second quarter of 2007. We expect to fund the purchase price by the issuance of partnership units and by proceeds from our credit facility.

          On January 24, 2007, the board of directors of our General Partner declared a quarterly distribution of $0.43 per unit, payable on February 14, 2007, to unitholders of record on February 7, 2007.

Exhibit 99.2

 

 

DCP Midstream, LLC
(formerly Duke Energy Field Services, LLC)
Consolidated Balance Sheet
As of December 31, 2006

 

 

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Members of
DCP Midstream, LLC
Denver, Colorado:

We have audited the accompanying consolidated balance sheet of DCP Midstream, LLC (formerly Duke Energy Field Services, LLC) and subsidiaries (the “Company”) as of December 31, 2006. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of DCP Midstream, LLC as of December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Denver, Colorado
March 14, 2007

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
CONSOLIDATED BALANCE SHEET
(millions)

		December 31,
		2006
ASSETS
Current assets:
Cash and cash equivalents		$	68
Short-term investments			437
Accounts receivable:
Customers, net of allowance for doubtful accounts of $3 million			933
Affiliates			283
Other			56
Inventories			87
Unrealized gains on mark-to-market and hedging instruments			242
Other			23
Total current assets			2,129
Property, plant and equipment, net			3,869
Restricted investments			102
Investments in unconsolidated affiliates			204
Intangible assets:
Commodity sales and purchases contracts, net			58
Goodwill			421
Total intangible assets			479
Unrealized gains on mark-to-market and hedging instruments			29
Deferred income taxes			4
Other non-current assets			33
Other non-current assets—affiliates			47
Total assets		$	6,896
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable:
Trade		$	1,490
Affiliates			92
Other			42
Unrealized losses on mark-to-market and hedging instruments			216
Distributions payable to members			127
Accrued interest payable			47
Accrued taxes			27
Other			136
Total current liabilities			2,177
Deferred income taxes			17
Long-term debt			2,115
Unrealized losses on mark-to-market and hedging instruments			33
Other long-term liabilities			226
Non-controlling interests			71
Commitments and contingent liabilities
Members’ equity:
Members’ interest			2,107
Retained earnings			153
Accumulated other comprehensive loss			(3	)
Total members’ equity			2,257
Total liabilities and members’ equity		$	6,896

See Notes to Consolidated Balance Sheet.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET
As of December 31, 2006

1. General and Summary of Significant Accounting Policies

     Basis of Presentation — DCP Midstream, LLC, formerly Duke Energy Field Services, LLC, with its consolidated subsidiaries, us, we, our, or the Company, is a joint venture owned 50% by Duke Energy Corporation, or Duke Energy, and 50% by ConocoPhillips. We operate in the midstream natural gas industry. Our primary operations consist of natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as marketing, from which we generate revenues primarily by trading and marketing natural gas and NGLs. The Second Amended and Restated LLC Agreement dated July 5, 2005, as amended, or the LLC Agreement, limits the scope of our business to the midstream natural gas industry in the United States and Canada, the marketing of NGLs in Mexico, and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our board of directors.

     To support and facilitate our continued growth, we formed DCP Midstream Partners, LP, a master limited partnership, or DCP Partners, of which our subsidiary, DCP Midstream GP, LP, acts as general partner. In September 2005, DCP Partners filed a Registration Statement on Form S-1 with the Securities and Exchange Commission, or SEC, to register the initial public offering of its limited partnership units to the public. The initial public offering closed in December 2005. We own approximately 41% of the limited partnership interests in DCP Partners and a 2% general partnership interest. As the general partner of DCP Partners, we have responsibility for its operations. DCP Partners is accounted for as a consolidated subsidiary.

     In July 2005, Duke Energy transferred a 19.7% interest in our Company to ConocoPhillips in exchange for direct and indirect monetary and non-monetary consideration, effectively decreasing Duke Energy’s membership interest in our Company to 50% and increasing ConocoPhillips’ membership interest in our Company to 50%, referred to as “the 50-50 Transaction.”

     On June 28, 2006, Duke Energy’s board of directors approved a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses, including its 50% ownership interest in us, to Duke Energy shareholders. This transaction occurred on January 2, 2007. As a result of this transaction, we are no longer 50% owned by Duke Energy. Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy Corp, or Spectra Energy. This transaction is referred to in this report as “the Spectra spin.” For the historical period included in this report, references to Spectra Energy are interchangeable with Duke Energy. On a prospective basis, Spectra Energy refers to the newly formed public company.

     We are governed by a five member board of directors, consisting of two voting members from each parent and our Chief Executive Officer and President, a non-voting member. All decisions requiring board of directors’ approval are made by simple majority vote of the board, but must include at least one vote from both a Spectra Energy (or Duke Energy prior to January 2, 2007) and ConocoPhillips board member. In the event the board cannot reach a majority decision, the decision is appealed to the Chief Executive Officers of both Spectra Energy and ConocoPhillips.

     The consolidated balance sheet includes the accounts of the Company and all majority-owned subsidiaries where we have the ability to exercise control, variable interest entities where we are the primary beneficiary, and undivided interests in jointly owned assets. We also consolidate DCP Partners, which we control as the general partner and where the limited partners do not have substantive kick-out or participating rights. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.

     Use of Estimates — Conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the consolidated balance sheet and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

     Acquisitions — We consolidate assets and liabilities from acquisitions as of the purchase date, and include earnings from acquisitions in consolidated earnings subsequent to the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. If the acquisition constitutes a business, any excess purchase price over the estimated fair value of the acquired assets and liabilities is recorded as goodwill.

     Cash and Cash Equivalents — Cash and cash equivalents includes all cash balances and highly liquid investments with an original maturity of three months or less.

     Short-Term and Restricted Investments — We invest available cash balances in various financial instruments, such as tax-exempt debt securities, that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through features, which allow for the redemption of the investment at its face amount plus earned income. As we generally intend to sell these instruments within one year or less from the balance sheet date, and as they are available for use in current operations, they are classified as current assets, unless otherwise restricted. We have classified all short-term and restricted debt investments as available-for-sale under Statement of Financial Accounting Standards, or SFAS, No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and they are carried at fair market value. Unrealized gains and losses on available-for-sale securities are recorded in the consolidated balance sheet as accumulated other comprehensive loss, or AOCI. No such gains or losses were deferred in AOCI at December 31, 2006. The cost, including accrued interest on investments, approximates fair value, due to the short-term, highly liquid nature of the securities held by us and as interest rates are re-set on a daily, weekly or monthly basis.

     Inventories — Inventories consist primarily of natural gas and NGLs held in storage for transportation and processing and sales commitments. Inventories are valued at the lower of weighted average cost or market. Transportation costs are included in inventory on the consolidated balance sheet.

     Accounting for Risk Management and Hedging Activities and Financial Instruments — Each derivative not qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” or SFAS 133, as amended, is recorded on a gross basis in the consolidated balance sheet at its fair value as unrealized gains or unrealized losses on mark-to-market and hedging instruments. Derivative assets and liabilities remain classified in the consolidated balance sheet as unrealized gains or unrealized losses on mark-to-market and hedging instruments at fair value until the contractual delivery period impacts earnings.

     We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or normal sale contract, while certain non-trading derivatives, which are related to asset based activity, are non-trading mark-to-market derivatives.

     Cash Flow and Fair Value Hedges — For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge in accordance with SFAS 133. In addition, we formally assess, both at the inception of the hedge and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.

     The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheet as unrealized gains or unrealized losses on mark-to-market and hedging instruments. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheet as AOCI and the ineffective portion is recorded in earnings. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to earnings. We discontinue hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheet at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

     Valuation — 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 correlations 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.

     Property, Plant and Equipment — Property, plant and equipment are recorded at original cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.

     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 increases due to the passage of time based on the time value of money until the obligation is settled. We recognize a liability for conditional asset retirement obligations as soon as the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity.

     Impairment of Unconsolidated Affiliates — We evaluate our unconsolidated affiliates for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investments may have experienced an other than temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether any impairment has occurred. Management assesses 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, internally developed discounted cash flow analysis and analysis from outside advisors. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss.

     Intangible Assets — Intangible assets consist of goodwill, and commodity sales and purchases contracts. Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. Commodity sales and purchases contracts are amortized on a straight-line basis over the term of the contract, ranging from one to 25 years.

     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. Impairment testing of goodwill consists of a two-step process. The first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves comparing the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.

     Impairment of Long-Lived Assets, Assets Held for Sale and Discontinued Operations — We evaluate whether the carrying value of long-lived assets, excluding goodwill, has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:

	•		A significant adverse change in legal factors or business climate;
	•		A current period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;
	•		An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
	•		Significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

	•		A significant adverse change in the market value of an asset; and
	•		A current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

     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. Management assesses 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, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.

     We use the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” or SFAS 144, to determine when an asset is classified as held for sale. Upon classification as held for sale, the long-lived asset is measured at the lower of its carrying amount or fair value less cost to sell, depreciation is ceased and the asset is separately presented on the consolidated balance sheet.

     Unamortized Debt Premium, Discount and Expense — Premiums, discounts and expenses incurred with the issuance of long-term debt are amortized over the terms of the debt using the effective interest method. These premiums and discounts are recorded on the consolidated balance sheet as an offset to long-term debt. These expenses are recorded on the consolidated balance sheet as other non-current assets.

     Distributions — Under the terms of the LLC Agreement, we are required to make quarterly distributions to Spectra Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement provides for taxable income to be allocated in accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member with a minimum of each members’ tax, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 50% for both Spectra Energy and ConocoPhillips. Prior to January 2, 2007, the capital accounts were maintained at 50% for both Duke Energy and ConocoPhillips. During the year ended December 31, 2006, we paid distributions of $650 million based on estimated annual taxable income allocated to the members according to their respective ownership percentages at the date the distributions became due.

     Our board of directors determines the amount of the quarterly dividend to be paid to Spectra Energy (or Duke Energy prior to January 2, 2007) and ConocoPhillips, by considering net income, cash flow or any other criteria deemed appropriate. During the year ended December 31, 2006, we paid total dividends of $801 million, comprised of proportionate distributions to Duke Energy and ConocoPhillips, which were allocated in accordance with our partners’ respective ownership percentages. The LLC Agreement restricts payment of dividends except with the approval of both members.

     DCP Partners considers the payment of a quarterly distribution to the holders of its common units and subordinated units, to the extent DCP Partners has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner, a wholly-owned subsidiary of ours. There is no guarantee, however, that DCP Partners will pay the minimum quarterly distribution on the units in any quarter. DCP Partners will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under its credit agreement. Our 41% limited partner interest in DCP Partners primarily consists of subordinated units. The subordinated units are entitled to receive the minimum quarterly distribution only after DCP Partners’ common unitholders have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. The subordination period will end on December 31, 2010 if certain distribution tests are met and earlier if certain more stringent tests are met. At such time that the subordination period ends, the subordinated units will be converted to common units. During the year ended December 31, 2006, DCP Partners paid distributions of approximately $13 million to its public unitholders. We hold general partner incentive distribution rights, which entitle us to receive an increasing share of available cash when pre-defined distribution targets are achieved.

     Gas and NGL Imbalance Accounting — Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using current market prices or the weighted average prices of natural gas or NGLs at the plant or system. These balances are settled with

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

deliveries of natural gas or NGLs, or with cash. Included in the consolidated balance sheet as accounts receivable — other as of December 31, 2006 were imbalances totaling $45 million. Included in the consolidated balance sheet as accounts payable — other, as of December 31, 2006 were imbalances totaling $42 million.

     Environmental Expenditures — Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not generate current or future revenue, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Environmental liabilities as of December 31, 2006, included in the consolidated balance sheet, totaled $6 million recorded as other current liabilities, and totaled $6 million recorded as other long-term liabilities.

     Stock-Based Compensation — Under our 2006 Long Term Incentive Plan, or 2006 Plan, equity instruments may be granted to our key employees. The 2006 Plan provides for the grant of Relative Performance Units, or RPU’s, Strategic Performance Units, or SPU’s, and Phantom Units. Prior to January 2, 2007, each of the above units constitutes a notional unit equal to the weighted average fair value of a common share or unit of ConocoPhillips, Duke Energy and DCP Partners, weighted 45%, 45% and 10%, respectively. Upon the Spectra spin, the 45% weighting attributable to Duke Energy will be valued as one common share of Duke Energy and one-half of one common share of Spectra Energy. The 2006 Plan also provides for the grant of DCP Partners’ Phantom Units, which constitute a notional unit equal to the fair value of DCP Partners’ common units. Each unit provides for the grant of dividend or distribution equivalent rights. The 2006 Plan is administered by the compensation committee of our board of directors. We first granted awards under the 2006 Plan during the second quarter of 2006.

     Under DCP Partners’ Long Term Incentive Plan, or DCP Partners’ Plan, equity instruments may be granted to DCP Partners’ key employees. DCP Midstream GP, LLC adopted the DCP Partners’ Plan for employees, consultants and directors of DCP Midstream GP, LLC and its affiliates who perform services for DCP Partners. The DCP Partners’ Plan provides for the grant of unvested units, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of distribution equivalent rights. Subject to adjustment for certain events, an aggregate of 850,000 common units may be delivered pursuant to awards under the DCP Partners’ Plan. Awards that are canceled, forfeited or withheld to satisfy DCP Midstream GP, LLC’s tax withholding obligations are available for delivery pursuant to other awards. The DCP Partners’ Plan is administered by the compensation committee of DCP Midstream GP, LLC’s board of directors. DCP Partners first granted awards under this plan during the first quarter of 2006.

     Under its 1998 Long-Term Incentive Plan, or 1998 Plan, Duke Energy granted certain of our key employees stock options, phantom stock awards, stock-based performance awards and other stock awards to be settled in shares of Duke Energy’s common stock. Upon execution of the 50-50 Transaction in July 2005, certain of our employees who had been issued awards under the 1998 Plan incurred a change in status from Duke Energy employees to non-employees. As a result, all outstanding stock-based awards were required to be remeasured as of July 2005 under Emerging Issues Task Force, or EITF, Issue No. 96-18, or EITF 96-18, “Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services,” using the fair value method prescribed in SFAS No. 123, “Accounting for Stock-Based Compensation,” or SFAS 123. Compensation expense is recognized prospectively beginning at the date of the change in status over the remaining vesting period based on the fair value of each award at each reporting date. The fair value of stock options is determined using the Black-Scholes option pricing model and the fair value of all other awards is determined based on the closing equity price at each measurement date.

     Effective January 1, 2006, we adopted the provisions of SFAS No. 123(R) (Revised 2004) “Share-Based Payment,” or SFAS 123R, which establishes accounting for stock-based awards exchanged for employee and non-employee services. Accordingly, equity classified stock-based compensation cost is measured at grant date, based on the fair value of the award, and is recognized as expense over the requisite service period. Liability classified stock-based compensation cost is remeasured at each reporting date, and is recognized over the requisite service period.

     Accounting for Sales of Units by a Subsidiary — In December 2005, we formed DCP Partners through the contribution of certain assets and investments in unconsolidated affiliates in exchange for common units, subordinated units and a 2% general partner interest. Concurrent with the formation, we sold approximately 58% of DCP Partners to the public, through an initial public offering, for proceeds of approximately $206 million, net of offering costs. We account for sales of units by a subsidiary under Staff Accounting Bulletin No. 51, or SAB 51, “Accounting for Sales of Stock of a Subsidiary.” Under SAB 51, companies may elect, via an

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

accounting policy decision, to record a gain or loss on the sale of common equity of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the units sold. Under SAB 51, a gain on the sale of subsidiary equity cannot be recognized until multiple classes of outstanding securities convert to common equity. As a result, we have deferred approximately $150 million of gain on sale of common units in DCP Partners as other long-term liabilities in the consolidated balance sheet. We will recognize this gain in earnings upon conversion of all of our subordinated units in DCP Partners to common units.

     Income Taxes — We are structured as a limited liability company, which is a pass-through entity for U.S. income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation is included in our income tax expense, along with state, local, franchise and margin taxes of the limited liability company and other subsidiaries.

     We follow the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities.

     New Accounting Standards — SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS 115,” or SFAS 159. In February 2007, the Financial Accounting Standards Board, or FASB, issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 159 on our consolidated financial position.

     SFAS No. 157 “Fair Value Measurements,” or SFAS 157. In September 2006, the FASB issued SFAS 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Under SFAS 157, fair value measurements are disclosed by level within that hierarchy. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 157 on our consolidated financial position.

     SFAS No. 154 “Accounting Changes and Error Corrections,” or SFAS 154. In June 2005, the FASB issued SFAS 154, a replacement of APB Opinion No. 20, or APB 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” Among other changes, SFAS 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented under the new accounting principle, unless it is impracticable to do so. SFAS 154 also (1) provides that a change in depreciation or amortization of a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) carries forward without change the guidance within APB 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. The adoption of SFAS 154 on January 1, 2006, did not have a material impact on our consolidated financial position.

     FASB Interpretation Number, or FIN, No. 48 “Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement 109,” or FIN 48. In July 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 are effective for us on January 1, 2007. The adoption of FIN 48 is not expected to have a material impact on our consolidated financial position.

     EITF Issue No. 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” or EITF 04-13. In September 2005, the FASB ratified the EITF’s consensus on Issue 04-13, which requires an entity to treat sales and purchases of inventory between the entity and the same counterparty as one transaction for purposes of applying APB Opinion No. 29 when such transactions are entered into in contemplation of each other. When such transactions are legally contingent on each other, they are considered to have been entered into in contemplation of each other. The EITF also agreed on other factors that should be considered

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

in determining whether transactions have been entered into in contemplation of each other. EITF 04-13 was applied to new arrangements that we entered into after March 31, 2006. The adoption of EITF 04-13 did not have a material impact on our consolidated financial position.

     Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, or SAB 108 — In September 2006, the SEC issued SAB 108 to address diversity in practice in quantifying financial statement misstatements. SAB 108 requires entities to quantify misstatements based on their impact on each of their financial statements and related disclosures. SAB 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to retained earnings as of January 1, 2006 for errors that were not previously deemed material, but are material under the guidance in SAB 108. The adoption of SAB 108 did not have a material impact on our consolidated financial position.

2. Acquisitions and Dispositions

   Acquisitions

     Acquisition of Various Gathering, Transmission and Processing Assets – In the fourth quarter of 2005, we entered into an agreement to purchase certain Federal Energy Regulatory Commission, or FERC, regulated pipeline and compressor station assets in Kansas, Oklahoma and Texas for approximately $50 million. We did not receive regulatory approval from the FERC to purchase the assets as non-jurisdictional gathering, but we are proceeding to file with the FERC for a certificate to operate these assets as intrastate pipeline. This acquisition is expected to close in the second half of 2007.

     Acquisition of Additional Equity Interests — In December 2006, we acquired an additional 33.33 % interest in Main Pass Oil Gathering Company, or Main Pass, for approximately $30 million. We now own 66.67% of Main Pass with one other partner. Main Pass is a joint venture whose primary operation is a crude oil gathering pipeline system in the Gulf of Mexico.

     In November 2006, we purchased the remaining 16% minority interest in Dauphin Island Gathering Partners, or DIGP, for $7 million. DIGP was owned 84% by us prior to this transaction, and subsequent to this transaction, is owned 100% by us. DIGP owns gathering and transmission assets in the Gulf Coast.

3. Agreements and Transactions with Affiliates

Spectra Energy and Duke Energy

     Services Agreement — Under a services agreement, Duke Energy and certain of its subsidiaries provided us with various staff and support services, including information technology products and services, payroll, employee benefits, property taxes, media relations, printing and records management. Additionally, we used other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments.

     In connection with the Spectra spin, we will need to transfer responsibility for all services previously provided to us by Duke Energy to our corporate operations, or transition these services either to Spectra or to third party service providers.

     Included on the consolidated balance sheet in other non-current assets—affiliates as of December 31, 2006, are insurance recovery receivables of $47 million, and included in accounts receivable—affiliates as of December 31, 2006, are other receivables of $8 million from an insurance provider that is a subsidiary of Duke Energy.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

     Commodity Transactions — We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to Duke Energy and Spectra Energy and their subsidiaries. Management anticipates continuing to purchase and sell these commodities and provide these services to Spectra Energy in the ordinary course of business.

ConocoPhillips

     Long-term NGLs Purchases Contract and Transactions — We sell a portion of our residue gas and NGLs to ConocoPhillips and CP Chem, a 50% equity investment of ConocoPhillips (see Note 1). In addition, we purchase raw natural gas from ConocoPhillips. Under the NGL Output Purchase and Sale Agreement, or the CP Chem NGL Agreement, between us and CP Chem, CP Chem has the right to purchase at index-based prices substantially all NGLs produced by our various processing plants located in the Mid-Continent and Permian Basin regions, and the Austin Chalk area, which include approximately 40% of our total NGL production. The CP Chem NGL Agreement also grants CP Chem the right to purchase at index-based prices certain quantities of NGLs produced at processing plants that are acquired and/or constructed by us in the future in various counties in the Mid-Continent and Permian Basin regions, and the Austin Chalk area. The primary term of the agreement is effective until January 1, 2015. We anticipate continuing to purchase and sell these commodities and provide these services to ConocoPhillips and CP Chem in the ordinary course of business.

     There was $1 million in current unrealized gains on mark-to-market and hedging instruments with ConocoPhillips disclosed on the consolidated balance sheet as of December 31, 2006.

Transactions with other unconsolidated affiliates

     We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to, unconsolidated affiliates. We anticipate continuing to purchase and sell these commodities and provide these services to unconsolidated affiliates in the ordinary course of business.

Estimates related to affiliates

     Accounts receivable and accounts payable related to goods and services provided but not invoiced to affiliates is estimated each month and recorded along with accounts receivable and accounts payable related to goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. Actual invoices for the current month are issued in the following month and differences from estimated amounts are recorded. There are no material differences from the actual amounts invoiced subsequent to year end relating to estimated accounts receivable and accounts payable recorded at December 31, 2006.

4. Marketable Securities

     Short-term and restricted investments — At December 31, 2006, we had $437 million of short-term investments. These instruments are classified as available-for-sale securities under SFAS 115 as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. The carrying value of these instruments approximates their fair value as the interest rates re-set on a daily, weekly or monthly basis.

     At December 31, 2006, we had restricted investments of $102 million, consisting of collateral for DCP Partners’ term loan.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

5. Inventories

     Inventories were as follows as of December 31, 2006:

		(millions)
Natural gas held for resale		$	34
NGLs			53
Total inventories		$	87

6. Property, Plant and Equipment

     Property, plant and equipment was as follows as of December 31, 2006:

		Depreciable
		Life				(millions)
Gathering		15 - 30 years				$	2,641
Processing		25 - 30 years					1,904
Transportation		25 - 30 years					1,217
Underground storage		20 - 50 years					119
General plant		3 - 5 years					146
Construction work in progress							203
							6,230
Accumulated depreciation							(2,361	)
Property, plant and equipment, net						$	3,869

7. Goodwill and Other Intangibles

     The carrying amount of goodwill remained consistent at $421 million as of both December 31, 2006 and December 31, 2005. We perform an annual goodwill impairment test, and update the test during interim periods if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We use a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices.

     We completed our annual goodwill impairment test as of August 31, 2006. This goodwill impairment test was performed by comparing our reporting units’ estimated fair values to their carrying, or book, values. These valuations indicated our reporting units’ fair values were in excess of their carrying, or book, values; therefore, we have determined that there is no indication of impairment. There were no impairments of goodwill for the year ended December 31, 2006.

     The gross carrying amount and accumulated amortization for commodity sales and purchases contracts are as follows as of December 31, 2006:

		(millions)
Commodity sales and purchases contracts		$	132
Accumulated amortization			(74	)
Commodity sales and purchases contracts, net		$	58

     The remaining amortization periods for these intangibles range from less than one year to 20 years with a weighted average remaining period of approximately 7 years.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

8. Investments in Unconsolidated Affiliates

     We have investments in the following unconsolidated affiliates accounted for using the equity method:

						December 31,
		Ownership				2006
						(millions)
Discovery Producer Services LLC			40.00	%		$	114
Main Pass Oil Gathering Company			66.67	%			47
Sycamore Gas System General Partnership			48.45	%			12
Mont Belvieu I			20.00	%			11
Tri-States NGL Pipeline, LLC			16.67	%			9
Black Lake Pipe Line Company			50.00	%			6
Other unconsolidated affiliates		Various					5
Total investments in unconsolidated affiliates						$	204

     Discovery Producer Services LLC — Discovery Producer Services LLC, or Discovery, owns and operates a 600 MMcf/d interstate pipeline, a condensate handling facility, a cryogenic gas processing plant, and other gathering assets in deepwater offshore Louisiana. The deficit between the carrying amount of the investment and the underlying equity of Discovery of $49 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Discovery.

     Main Pass Oil Gathering Company — In December 2006, we acquired an additional 33.33% interest in Main Pass, a joint venture whose primary operation is a crude oil gathering pipeline system in the Main Pass East and Viosca Knoll Block areas in the Gulf of Mexico. We now own 66.67% of Main Pass with one other partner. Since Main Pass is not a variable interest entity, and we do not have the ability to exercise control, we continue to account for Main Pass under the equity method. The excess of the carrying amount of the investment over the underlying equity of Main Pass of $12 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Main Pass.

     Sycamore Gas System General Partnership — Sycamore Gas System General Partnership, or Sycamore, is a partnership formed for the purpose of constructing, owning and operating a gas gathering and compression system in Carter County, Oklahoma. The excess of the carrying amount of the investment over the underlying equity of Sycamore of $9 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Sycamore.

     Mont Belvieu I — Mont Belvieu I owns a 150 MBbl/d fractionation facility in the Mont Belvieu, Texas Market Center. The deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu I of $11 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Mont Belvieu I.

     Tri-States NGL Pipeline, LLC — Tri-States NGL Pipeline, LLC, or Tri-States, owns 169 miles of NGL pipeline, extending from a point near Mobile Bay, Alabama to a point near Kenner, Louisiana. The deficit between the carrying amount of the investment and the underlying equity of Tri-States of $3 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Tri-States. We own less than 20% interest in this Partnership, however, we exercise significant influence, therefore, this investment is accounted for under the equity method of accounting in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”

     Black Lake Pipe Line Company — Black Lake Pipe Line Company, or Black Lake, owns a 317 mile long NGL pipeline, with a current capacity of approximately 40 MBbl/d. The pipeline receives NGLs from a number of gas plants in Louisiana and Texas. The NGLs are transported to Mont Belvieu fractionators. The deficit between the carrying amount of the investment and the underlying equity of Black Lake of $7 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Black Lake.

     Fox Plant, LLC — In May 2006, we purchased the remaining 50% interest in Fox Plant, LLC, a limited liability company formed for the purpose of constructing, owning, and operating a gathering facility and gas processing plant in Carter County, Oklahoma. Subsequent to May 2006, Fox Plant, LLC was accounted for as a consolidated subsidiary.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

     The following summarizes combined balance sheet information of unconsolidated affiliates as of December 31, 2006:

		(millions)
Balance sheet:
Current assets		$	115
Non-current assets			724
Current liabilities			61
Non-current liabilities			7
Net assets		$	771

9. Estimated Fair Value of Financial Instruments

     We have determined the following fair value amounts using available market information and appropriate valuation methodologies. Considerable judgment is required, however, in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

		December 31, 2006
		Carrying				Estimated Fair
		Amount				Value
		(millions)
Short-term investments		$	437			$	437
Restricted investments			102				102
Accounts receivable			1,272				1,272
Accounts payable			(1,624	)			(1,624	)
Net unrealized gains and losses on mark-to-market and hedging instruments			22				22
Long-term debt			(2,115	)			(2,258	)

     The fair value of short-term investments, restricted investments, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Unrealized gains and unrealized losses on mark-to-market and hedging instruments are carried at fair value.

     The estimated fair values of current debt, including current maturities of long-term debt, and long-term debt, with the exception of DCP Partners’ long-term debt, are determined by prices obtained from market quotes. The carrying value of DCP Partners’ long-term debt approximates fair value, as the interest rate is variable and reflects current market conditions.

10. Asset Retirement Obligations

     Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.

     We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.

     The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.

11. Financing

     Long-term debt was as follows at December 31, 2006:

		Principal/Discount
		(millions)
Debt securities:
Issued August 2000, interest at 7.875% payable semiannually, due August 2010		$	800
Issued January 2001, interest at 6.875% payable semiannually, due February 2011			250
Issued October 2005, interest at 5.375% payable semiannually, due October 2015			200
Issued August 2000, interest at 8.125% payable semiannually, due August 2030			300
Issued October 2006, interest at 6.450% payable semiannually, due November 2036			300
DCP Partners’ credit facility revolver, weighted average interest rate of 5.86% at December 31, 2006, due December 2010			168
DCP Partners’ credit facility term loan, interest rate of 5.47% at December 31, 2006, due December 2010			100
Fair value adjustments related to interest rate swap fair value hedges (a)			4
Unamortized discount			(7	)
Long-term debt		$	2,115

     Debt Securities — In October 2006, we issued $300 million principal amount of 6.45% Senior Notes due 2036, or the 6.45% Notes, for proceeds of approximately $297 million (net of related offering costs). The 6.45% Notes mature and become due and payable on November 3, 2036. We will pay interest semiannually on May 3 and November 3 of each year, commencing May 3, 2007. The proceeds from this offering were used to repay our 5.75% Senior Notes that matured on November 15, 2006.

     The debt securities mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. Interest is payable semiannually. The debt securities are unsecured and are redeemable at our option.

     Credit Facilities with Financial Institutions — On April 29, 2005, we entered into a credit facility, or the Facility, to replace a $250 million 364-day facility that was terminated on April 29, 2005. The Facility is used to support our commercial paper program, and for working capital and other general corporate purposes. In December 2005, we amended the Facility to amend the definition of consolidated capitalization to include minority interest, which is referred to in this balance sheet as non-controlling interest. In October 2006, we amended the Facility to modify the change of control provisions to allow for the Spectra spin, to extend the maturity April 29, 2012, to amend the pricing, to remove the interest coverage covenant and to incorporate other minor revisions. Any outstanding borrowings under the Facility at maturity may, at our option, be converted to an unsecured one-year term loan. The Facility is a $450 million revolving credit facility, all of which can be used for letters of credit. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 60%. Draws on the Facility bear interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 0.35% per year for the initial 50% usage or LIBOR plus 0.45% per year if usage is greater than 50% or (2) the higher of (a) the Wachovia Bank prime rate per year and (b) the Federal Funds rate plus 0.5% per year. The Facility incurs an annual facility fee of 0.1% based on our credit rating on the drawn and undrawn portions. As of December 31, 2006, there were no borrowings or commercial paper outstanding, and there was approximately $5 million in letters of credit drawn against the Facility.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

     On December 7, 2005, DCP Partners entered into a 5-year credit agreement, or the DCP Partners’ Credit Agreement, with a $250 million revolving credit facility and a $100 million term loan facility. The DCP Partners’ Credit Agreement matures on December 7, 2010. At December 31, 2006, there was $168 million outstanding on the revolving credit facility and $100 million outstanding on the term loan facility. The term loan facility is fully collateralized by investments in high-grade securities, which are classified as restricted investments on the accompanying consolidated balance sheet. Outstanding letters of credit on the DCP Partners’ Credit Agreement were less than $1 million as of December 31, 2006. The DCP Partners’ Credit Agreement requires DCP Partners to maintain at all times (commencing with the quarter ending March 31, 2006) a leverage ratio (the ratio of DCP Partners’ consolidated indebtedness to its consolidated EBITDA, in each case as is defined by the DCP Partners’ Credit Agreement) of less than or equal to 4.75 to 1.0 (and on a temporary basis for not more than three consecutive quarters following the acquisition of assets in the midstream energy business of not more than 5.25 to 1.0); and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the DCP Partners’ Credit Agreement to be earnings before interest, taxes and depreciation and amortization and other non-cash adjustments, for the four most recent quarters to interest expense for the same period) of greater than or equal to 3.0 to 1.0. Indebtedness under the revolving credit facility bears interest, at our option, at either (1) the higher of Wachovia Bank’s prime rate or the federal funds rate plus 0.50% or (2) LIBOR plus an applicable margin, which ranges from 0.27% to 1.025% dependent upon the leverage level or credit rating. As of December 31, 2006, the $100 million term loan facility bears interest at LIBOR plus a rate per annum of 0.15%. The revolving credit facility incurs an annual facility fee of 0.08% to 0.35%, depending on the applicable leverage level or debt rating. This fee is paid on drawn and undrawn portions of the revolving credit facility.

     Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2006:

		Debt Maturities
		(millions)
2010		$	1,068
2011			250
Thereafter			804
			2,122
Unamortized discount			(7	)
Long-term debt		$	2,115

12. Risk Management and Hedging Activities, Credit Risk and Financial Instruments

     Commodity price risk — Our principal operations of gathering, processing, compression, transportation and storage of natural gas, and the accompanying operations of fractionation, transportation, gathering, treating, processing, storage and trading and marketing of NGLs create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. As an owner and operator of natural gas processing and other midstream assets, we have an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts entered into to purchase and process raw natural gas. Risk is also dependent on the types and mechanisms for sales of natural gas and NGLs, and related products produced, processed, transported or stored.

     Energy trading (market) risk — Certain of our subsidiaries are engaged in the business of trading energy related products and services, including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and we may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments.

     Interest rate risk — We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to hedge interest rate risk associated with our debt. Our primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

     Credit risk — Our principal customers range from large, natural gas marketing services to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 40% of our NGL production is committed to ConocoPhillips and CP Chem under an existing 15-year contract, which expires in 2015. This concentration of credit risk may affect our overall credit risk, in that 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 may use master collateral agreements to mitigate credit exposure. Collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form.

     As of December 31, 2006, we held cash or letters of credit of $83 million to secure future performance of financial or physical contracts, and had deposited with counterparties $7 million of such collateral to secure our obligations to provide future services or to perform under financial contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, trading and hedging contracts. In many cases, we and our counterparties’ publicly disclose credit ratings, which may impact the amounts of collateral requirements.

     Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.

     Commodity hedging strategies — Historically, we have used commodity cash flow hedges, as specifically defined in SFAS 133, to reduce the potential negative impact that commodity price changes could have on our earnings and our ability to adequately plan for cash needed for debt service, capital expenditures and tax distributions. Our current strategy is to use cash flow hedges only for commodity price risk related to DCP Partners’ operations. Some of the assets operated by DCP Partners generate cash flows that are subject to volatility from fluctuating commodity prices. As a publicly traded master limited partnership, an important component of the strategy of DCP Partners is to generate consistent cash flow from its operations in order to pay distributions to its unitholders. For operations other than those of DCP Partners, we do not currently anticipate using cash flow hedges in the near future, because management believes cash flows will be sufficient to fund our business.

     Commodity cash flow hedges — We have executed a series of derivative financial instruments, which have been designated as cash flow hedges of the price risk associated with forecasted sales of natural gas, NGLs and condensate through 2010, and the price risk associated with forecasted sales of condensate during 2011, related to assets of DCP Partners. Because of the strong correlation between NGL prices and crude oil prices, and the lack of liquidity in the NGL financial market, we have used crude oil swaps to hedge NGL price risk.

     No derivative gains or losses were reclassified from AOCI to current period earnings as a result of a change in the probability of forecasted transactions occurring, which would cause us to discontinue hedge treatment. The deferred balance in AOCI was a gain of $3 million at December 31, 2006. As of December 31, 2006, $1 million of deferred net gains on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.

     Commodity fair value hedges — We use fair value hedges to hedge exposure to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to fixed price risk. We may hedge producer price locks (fixed price gas purchases) and market locks (fixed price gas sales) to reduce our exposure to fixed price risk via swapping the fixed price risk for a floating price position (New York Mercantile Exchange or index based).

     All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. We did not have any firm commitments that no longer qualified as fair value hedge items.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

     Interest rate cash flow hedges — During 2006, DCP Partners entered into interest rate swap agreements to convert $125 million of the indebtedness on their revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All interest rate swaps expire on December 7, 2010 and re-price prospectively approximately every 90 days. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense. The interest rate swap agreements have been designated as cash flow hedges, and effectiveness 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 accompanying consolidated balance sheet. At December 31, 2006, the gains deferred in AOCI related to these swaps were insignificant. At December 31, 2006, the amount of deferred net gains on derivative instruments in AOCI that are expected to be reclassified into earnings during the next 12 months as the hedged transactions occur are insignificant; however, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.

     Prior to issuing fixed rate debt in August 2000, we entered into, and terminated, treasury locks and interest rate swaps to lock in the interest rate prior to it being fixed at the time of debt issuance. The losses realized on these agreements, which were terminated in 2000, are deferred into AOCI and amortized against interest expense over the life of the respective debt. The deferred balance was a loss of $7 million at December 31, 2006. Approximately $1 million of deferred net losses related to these instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the underlying hedged interest expense transaction occurs.

     Interest rate fair value hedges — In October 2001, we entered into an interest rate swap to convert $250 million of fixed-rate debt securities, which were issued in August 2000, to floating rate debt. The interest rate fair value hedge was at a floating rate based on a six-month LIBOR, which was re-priced semiannually through the date of maturity, August 2005.

     In August 2003, we entered into two additional interest rate swaps to convert $100 million of fixed-rate debt securities issued in August 2000 to floating rate debt. These interest rate fair value hedges are at a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet conditions, which permit the assumption of no ineffectiveness, as defined by SFAS 133. As of December 31, 2006, the fair value of the interest rate swaps was a $4 million asset, which is included in the consolidated balance sheet as unrealized gains or losses on mark-to-market and hedging instruments with offsets to the underlying debt included in current maturities of long-term debt and long-term debt.

     Commodity derivatives — trading and marketing — Our trading and marketing program is designed to realize margins related to fluctuations in commodity prices and basis differentials, and to maximize the value of certain storage and transportation assets. Certain of our subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. We manage our trading and marketing portfolio with strict policies, which limit exposure to market risk, and require daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate daily value at risk.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

13. Stock-Based Compensation

     DCP Midstream, LLC Long-Term Incentive Plan, or 2006 Plan — Relative Performance Units — RPU’s generally cliff vest at the end of eight years, consisting of a three year performance period and a five year deferral period. The number of RPU’s that will ultimately vest range from 0% to 200% of the outstanding RPU’s, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of our board of directors. At the end of the performance period, based on the market value of the RPU’s, we will create an account for each grantee in our deferred compensation plan. Payment of the grantee’s deferred compensation account will occur after a five year deferral period, the value of which is based on the value of the participant’s investment elections during the deferral period. Each RPU includes a dividend or distribution equivalent right, which will be paid in cash at the end of the performance period. At December 31, 2006, there was approximately $1 million of unrecognized compensation expense related to the RPU’s, which was calculated using an estimated forfeiture rate of 64%, and is expected to be recognized over a weighted-average period of 7.0 years. The following tables presents information related to RPUs:

										Measurement
						Grant Date				Date
						Weighted-				Weighted-
						Average Price				Average Price
		Units				Per Unit				Per Unit
Outstanding at December 31, 2005			—			$	—
Granted			44,080			$	42.89
Outstanding at December 31, 2006			44,080			$	42.89			$	50.78
Expected to vest			15,869			$	42.89			$	50.78

     Strategic Performance Units — SPU’s generally cliff vest at the end of three years. The number of SPU’s that will ultimately vest range from 0% to 150% of the outstanding SPU’s, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of our board of directors. Each SPU includes a dividend or distribution equivalent right, which will be paid in cash at the end of the performance period. At December 31, 2006 there was approximately $3 million of unrecognized compensation expense related to the SPU’s, which was calculated using estimated forfeiture rates ranging from 12% to 32%, and is expected to be recognized over a weighted-average period of 2.0 years. The following tables presents information related to SPUs:

										Measurement
						Grant Date				Date
						Weighted-				Weighted-
						Average Price				Average Price
		Units				Per Unit				Per Unit
Outstanding at December 31, 2005			—			$	—
Granted			84,960			$	42.92
Outstanding at December 31, 2006			84,960			$	42.92			$	50.78
Expected to vest			65,949			$	42.92			$	50.78

     The estimate of RPU’s and SPU’s that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amounts of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in earnings.

     Phantom Units — Phantom Units generally cliff vest at the end of five years. Each Phantom Unit includes a dividend or distribution equivalent right, which is paid quarterly in arrears. At December 31, 2006 there was approximately $1 million of unrecognized compensation expense related to the Phantom Units, which was calculated using an estimated forfeiture rate of 19%, and is expected to be recognized over a weighted-average period of 4.0 years. The following table presents information related to Phantom Units:

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

										Measurement
						Grant Date				Date
						Weighted-				Weighted-
						Average Price				Average Price
		Units				Per Unit				Per Unit
Outstanding at December 31, 2005			—			$	—
Granted			17,460			$	42.95
Outstanding at December 31, 2006			17,460			$	42.95			$	50.78
Expected to vest			14,143			$	42.95			$	50.78

     DCP Partners’ Phantom Units — The DCP Partners’ Phantom Units constitute a notional unit equal to the fair value of a common unit of DCP Partners, which generally cliff vest at December 31, 2008. Each DCP Partners’ Phantom Unit includes a distribution equivalent right, which is paid quarterly in arrears. At December 31, 2006 there was approximately $1 million of unrecognized compensation expense related to the DCP Partners’ Phantom Units, which was calculated using estimated forfeiture rates ranging from 12% to 32%, and is expected to be recognized over a weighted-average period of 2.0 years. The following table presents information related to the DCP Partners’ Phantom Units:

										Measurement
						Grant Date				Date
						Weighted-				Weighted-
						Average Price				Average Price
		Units				Per Unit				Per Unit
Outstanding at December 31, 2005			—			$	—
Granted			47,750			$	28.60
Outstanding at December 31, 2006			47,750			$	28.60			$	34.55
Expected to vest			34,920			$	28.60			$	34.55

     During the year ended December 31, 2006, no awards under the 2006 Plan were forfeited, vested or settled.

     DCP Partners’ Long-Term Incentive Plan, or DCP Partners’ Plan — Performance Units — Performance Units generally cliff vest at the end of a three year performance period. The number of Performance Units that will ultimately vest range from 0% to 150% of the outstanding Performance Units, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance percentage payout is determined by the compensation committee of DCP Partners’ board of directors. Each Performance Unit includes a distribution equivalent right, which will be paid in cash at the end of the performance period. At December 31, 2006, there was approximately $1 million of unrecognized compensation expense related to the Performance Units, which is expected to be recognized over a weighted-average period of 2.0 years. The following tables presents information related to the Performance Units:

										Measurement
						Grant Date				Date
						Weighted-				Weighted-
						Average Price				Average Price
		Units				Per Unit				Per Unit
Outstanding at December 31, 2005			—			$	—
Granted			40,560			$	26.96
Forfeited			(17,470	)		$	26.96
Outstanding at December 31, 2006			23,090			$	26.96			$	34.55
Expected to vest			23,090			$	26.96			$	34.55

     The estimate of Performance Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in earnings.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

     Phantom Units — Of the Phantom Units, 16,700 units will vest upon the three year anniversary of the grant date and 8,000 units vest ratably over three years. Each Phantom Unit includes a distribution equivalent right which is paid quarterly in arrears. At December 31, 2006, estimated unrecognized compensation expense related to the Phantom Units was not significant. The following tables presents information related to the Phantom Units:

										Measurement
						Grant Date				Date
						Weighted-				Weighted-
						Average Price				Average Price
		Units				Per Unit				Per Unit
Outstanding at December 31, 2005			—			$	—
Granted			35,900			$	24.05
Forfeited			(11,200	)		$	24.05
Outstanding at December 31, 2006			24,700			$	24.05			$	34.55
Expected to vest			24,700			$	24.05			$	34.55

     The estimate of Phantom Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in earnings.

     All awards issued under the 2006 Plan and the DCP Partners’ Plan are intended to be settled in cash upon vesting. Compensation expense is recognized ratably over each vesting period, and will be remeasured quarterly for all awards outstanding until the units are vested. The fair value of all awards is determined based on the closing price of the relevant underlying securities at each measurement date. During the year ended December 31, 2006, no awards were vested or settled.

     Duke Energy 1998 Plan — Under its 1998 Plan, Duke Energy granted certain of our key employees stock options, phantom stock awards, stock-based performance awards and other stock awards to be settled in shares of Duke Energy’s common stock. Upon execution of the 50-50 Transaction in July 2005, our employees incurred a change in status from Duke Energy employees to non-employees. As a result, we ceased accounting for these awards under APB 25 and FIN 44, and began accounting for these awards in accordance with EITF 96-18, using the fair value method prescribed in SFAS 123. No awards have been and we do not expect to settle any awards granted under the 1998 Plan with cash.

     Stock Options — Under the 1998 Plan, the exercise price of each option granted could not be less than the market price of Duke Energy’s common stock on the date of grant. Vesting periods range from immediate to four years with a maximum option term of 10 years.

     The following tables show information regarding options to purchase Duke Energy’s common stock granted to our employees.

						Weighted-				Weighted-Average				Aggregate
						Average				Remaining Life				Intrinsic Value
		Shares				Exercise Price				(years)				(millions)
Outstanding at December 31, 2005			2,592,567			$	29.46				5.2
Exercised			(367,088	)		$	21.15
Forfeited			(124,417	)		$	29.96
Outstanding at December 31, 2006			2,101,062			$	30.89				4.1			$	12
Exercisable at December 31, 2006			1,941,212			$	32.30				4.0			$	9
Expected to vest			155,630			$	13.77				6.2			$	3

     The total intrinsic value of options exercised during the year ended December 31, 2006, was approximately $3 million. As of December 31, 2006, all compensation expense related to these awards has been recognized.

     There were no options granted during the year ended December 31, 2006.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

     Stock-Based Performance Awards — Stock-based performance awards outstanding under the 1998 Plan vest over three years if certain performance targets are achieved. There were no stock-based performance awards granted during the year ended December 31, 2006.

     The following table summarizes information about stock-based performance awards activity during the year ended December 31, 2006:

										Measurement
						Grant Date				Date
						Weighted-				Weighted-
						Average Price				Average Price
		Shares				Per Unit				Per Unit
Outstanding at December 31, 2005			342,453			$	23.88
Forfeited			(40,835	)		$	23.85
Outstanding at December 31, 2006			301,618			$	23.90			$	33.21
Expected to vest			289,161			$	23.90			$	33.21

     As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was approximately $1 million, which is expected to be recognized over a weighted-average period of less than 1 year. No awards were granted, vested or canceled during the year ended December 31, 2006.

     Phantom Stock Awards — Phantom stock awards outstanding under the 1998 Plan vest over periods from one to five years. There were no phantom stock awards granted during the year ended December 31, 2006.

     The following table summarizes information about phantom stock awards activity during the year ended December 31, 2006:

										Measurement
						Grant Date				Date
						Weighted-				Weighted-
						Average Price				Average Price
		Shares				Per Unit				Per Unit
Outstanding at December 31, 2005			241,216			$	24.22
Vested			(54,150	)		$	23.90
Forfeited			(22,378	)		$	24.29
Outstanding at December 31, 2006			164,688			$	24.34			$	33.21
Expected to vest			157,886			$	24.34			$	33.21

     The total fair value of the phantom stock awards that vested during the year ended December 31, 2006 was approximately $2 million. As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was approximately $1 million, which is expected to be recognized over a weighted-average period of 2.7 years. No awards were granted or canceled during the year ended December 31, 2006.

     Other Stock Awards — Other stock awards outstanding under the 1998 Plan vest over periods from one to five years. There were no other stock awards granted during the year ended December 31, 2006.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

     The following table summarizes information about other stock awards activity during the year ended December 31, 2006:

										Measurement
						Grant Date				Date
						Weighted-				Weighted-
						Average Price				Average Price
		Shares				Per Unit				Per Unit
Outstanding at December 31, 2005			45,400			$	21.73
Vested			(10,600	)		$	21.73
Forfeited			(13,200	)		$	21.73
Outstanding at December 31, 2006			21,600			$	21.73			$	33.21
Expected to vest			20,038			$	21.73			$	33.21

     The total fair value of the other stock awards that vested during the year ended December 31, 2006 was not significant. As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was not significant, and is expected to be recognized over a weighted-average period of less than 1 year. No awards were granted or canceled during the year ended December 31, 2006.

14. Benefits

     All Company employees who are 18 years old and work at least 20 hours per week are eligible for participation in our 401(k) and retirement plan, to which we contributed 4% of each eligible employee’s qualified earnings, through December 31, 2006. Effective January 1, 2007, we began contributing a range of 4% to 7% of each eligible employee’s qualified earnings, based on years of service. Additionally, we match employees’ contributions in the plan up to 6% of qualified earnings.

     We offer certain eligible executives the opportunity to participate in the DCP Midstream LP’s Non-Qualified Executive Deferred Compensation Plan. This plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that we can contribute to the 401(k) plan on the participant’s behalf. All amounts contributed to or earned by the plan’s investments are held in a trust account for the benefit of the participants. The trust and the liability to the participants are part of our general assets and liabilities, respectively.

15. Income Taxes

     We are structured as a limited liability company, which is a pass-through entity for United States income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns.

     In May 2006, the State of Texas enacted a new margin-based franchise tax law that replaces the existing franchise tax. This new tax is commonly referred to as the Texas margin tax. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the new tax.

     As a result of the change in Texas franchise law, our tax status in the state of Texas has changed from non-taxable to taxable. The tax is considered an income tax for purposes of adjustments to the deferred tax liability. The tax is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax becomes effective for franchise tax reports due on or after January 1, 2008. The 2008 tax will be based on revenues earned during the 2007 fiscal year.

     The Texas margin tax is assessed at 1% of taxable margin apportioned to Texas. We have computed taxable margin as total revenue less cost of goods sold. Based on information currently available, we recorded a deferred tax liability of $18 million in 2006. The deferred tax liability is recorded as non-current in the consolidated balance sheet as of December 31, 2006.

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

     Temporary differences for our gross deferred tax assets of $4 million primarily relate to basis differences between property, plant and equipment, and investments in unconsolidated affiliates. Temporary differences for our gross deferred tax liabilities of $17 million primarily relate to basis differences between property, plant and equipment.

     Our effective tax rate differs from statutory rates, primarily due to our being structured as a limited liability company, which is a pass-through entity for United States income tax purposes, while being treated as a taxable entity in certain states.

16. Commitments and Contingent Liabilities

     Litigation — The midstream industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. A number of these cases are now being brought as class actions. We are currently named as defendants in some of these cases. Management believes we have meritorious defenses to these cases and, therefore, will continue to defend them vigorously. These class actions, however, can be costly and time consuming to defend. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.

     In December 2006, El Paso E&P Company, L.P., or El Paso, filed a lawsuit against one of our subsidiaries, DCP Assets Holding, LP and an affiliate of DCP Midstream GP, LP, in District Court, Harris County, Texas. The litigation stems from an ongoing commercial dispute involving DCP Midstream Partners’ Minden processing plant that dates back to August 2000. El Paso claims damages, including interest, in the amount of $6 million in the litigation, the bulk of which stems from audit claims under our commercial contract. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated financial position.

     In November 2006, we received a demand associated with the alleged migration of acid gas from a storage formation into a third party producing formation. The plaintiff seeks a broad array of remedies, including a purchase of the plaintiff’s lease rights. We conducted an investigation using a geotechnical consulting firm and believe that acid gas is migrating from the storage formation into the producing formation. We could be liable for damages related to the diminution in market value to the leases, if any, caused by the migration of the acid gas. At this time, it is not possible to predict the ultimate damages, if any, that we might incur in connection with this matter.

     Management currently believes that these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage and other indemnification arrangements, will not have a material adverse effect upon our consolidated financial position.

     General Insurance — In 2005, we carried all of our insurance coverage with an affiliate of Duke Energy. Beginning in 2006, we elected to carry only property and excess liability insurance coverage with an affiliate of Duke Energy and an affiliate of ConocoPhillips, however, effective August 2006, we no longer carry insurance coverage with an affiliate of Duke Energy. Our remaining insurance coverage is with an affiliate of ConocoPhillips and a third party insurer. Our insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations. Property insurance deductibles are currently $1 million for onshore or non-hurricane related incidents or up to $5 million per occurrence for hurricane related incidents. We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Casualty insurance deductibles are currently $1 million per occurrence. The cost of our general insurance coverages increased over the past year reflecting the adverse conditions of the insurance markets.

     During the third quarter of 2004, certain assets, located in the Gulf Coast, were damaged as a result of hurricane Ivan. The resulting losses are expected to be covered by insurance, subject to applicable deductibles for property and business interruption. Insurance recovery receivables related to hurricane Ivan included on the consolidated balance sheet in other non-current assets—

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

affiliates as of December 31, 2006, are $25 million, and included in accounts receivable—affiliates as of December 31, 2006, are $3 million, from an insurance provider that is a subsidiary of Duke Energy.

     During the third quarter of 2005, hurricanes Katrina and Rita forced us to temporarily shut down our operations at certain assets located in Alabama, Louisiana, Texas and New Mexico, however, substantially all of our facilities have resumed pre-hurricane levels of capacity utilization. Several of our assets sustained property damage, including some of our operating equipment on a platform in the Gulf of Mexico. A portion of the resulting lost revenues and property damages are covered by our insurance, subject to applicable deductibles. The financial impact of recent hurricanes has increased market rates for insurance coverage; however, these increases did not have a material adverse effect on our consolidated financial position. Insurance recovery receivables related to hurricane Katrina included on the consolidated balance sheet in other non-current assets—affiliates as of December 31, 2006 are $21 million, and included in accounts receivable—affiliates as of December 31, 2006, are $2 million, from an insurance provider that is a subsidiary of Duke Energy. Included in other non-current assets—affiliates as of December 31, 2006, are insurance recovery receivables related to hurricane Rita of $1 million at December 31, 2006.

     Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated financial position.

     On July 20, 2006, the State of New Mexico Environment Department issued Compliance Orders to us that list air quality violations during the past five years at three of our owned or operated facilities in New Mexico. The orders allege a number of violations related to excess emissions from January 2001 to date and further require us to install flares for smokeless operations and to use the flares only for emergency purposes. The Compliance Orders seek a civil penalty but did not request a specific amount. We intend to contest these allegations. Management does not believe this will result in a material impact on our consolidated financial position.

     Other Commitments and Contingencies — We utilize assets under operating leases in several areas of operations. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term. Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2006:

Minimum Rental Payments
(millions)

2007		$	25
2008			19
2009			14
2010			14
2011			12
Thereafter			39
Total gross payments			123
Sublease receipts			(2	)
Total net payments		$	121

DCP MIDSTREAM, LLC
(formerly Duke Energy Field Services, LLC)
NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)
As of December 31, 2006

17. Guarantees and Indemnifications

     In September 2005, we signed a corporate guaranty, which was amended in December 2005 upon our purchase of an additional interest in the related unconsolidated affiliate, pursuant to which we are the guarantor of a maximum of $10 million of construction obligations. The original guaranty was $22 million as of December 31, 2005, and was reduced by construction payments of $12 million during the year ended December 31, 2006. The guaranty will expire upon completion and payment for construction of a pipeline expected to be completed during 2007. The fair value of this guarantee is not significant to our consolidated financial position.

     We periodically enter into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities related to the assets being acquired or divested. Claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The effective periods on these indemnification provisions generally have terms of one to five years, although some are longer. Our maximum potential exposure under these indemnification agreements can vary depending on the nature of the claim and the particular transaction. We are unable to estimate the total maximum potential amount of future payments under indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities. At December 31, 2006, we had a liability of approximately $1 million recorded for known liabilities related to outstanding indemnification provisions.

18. Subsequent Events

     In March 2007, DCP Midstream Partners entered into a definitive agreement to acquire certain gathering and compression assets located in southern Oklahoma from Anadarko Petroleum Corporation, or Anadarko, for approximately $180 million, subject to customary closing conditions and certain regulatory approvals. DCP Midstream Partners paid an earnest deposit of $9 million when they entered into this agreement. If Anadarko terminates because DCP Midstream Partners materially breaches their representations, warranties or covenants under this agreement, Anadarko may retain this earnest deposit as liquidated damages. This transaction is expected to close in the second quarter of 2007. We expect to fund the purchase price by the issuance of DCP Midstream Partners’ partnership units and by proceeds from DCP Midstream Partners’ credit facility.

     On January 24, 2007, DCP Partners announced the declaration of a cash distribution of $0.43 per unit, payable on February 14, 2007, to unitholders of record on February 7, 2007.

     On January 2, 2007, Duke Energy created two separate publicly traded companies by spinning off their natural gas businesses, including their 50% ownership interest in us, to Duke Energy shareholders. As a result of this transaction, we are no longer 50% owned by Duke Energy. Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy. We do not expect this transaction to have a material effect on our operations.

     On January 1, 2007, we changed our name from Duke Energy Field Services, LLC to DCP Midstream, LLC, to coincide with the Spectra spin.