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Delaware		4922		03-0567133
(State or Other Jurisdiction of Incorporation or Organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)

Thomas P. Mason Douglas E. McWilliams Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2300 Houston, Texas 77002 (713) 758-2222		Joshua Davidson Christopher J. Arntzen Baker Botts L.L.P. 910 Louisiana Street Houston, Texas 77002 (713) 229-1234

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

	•	We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.
	•	Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of supplies of natural gas and natural gas liquids, which are dependent on certain factors beyond our control. Any decrease in supplies of natural gas or natural gas liquids could adversely affect our business and operating results.
	•	The cash flow from our Natural Gas Services segment is affected by natural gas, natural gas liquid and condensate prices, and decreases in these prices could adversely affect our ability to make distributions to holders of our common units and subordinated units.
	•	We depend on certain natural gas producer customers for a significant portion of our supply of natural gas and natural gas liquids. The loss of any of these customers could result in a decline in our volumes, revenues and cash available for distribution.
	•	Duke Energy Field Services, LLC controls our general partner, which has sole responsibility for conducting our business and managing our operations. Duke Energy Field Services, LLC has conflicts of interest, which may permit it to favor its own interests to your detriment.
	•	Cost reimbursements due to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to you.
	•	Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
	•	Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
	•	Control of our general partner may be transferred to a third party without unitholder consent.
	•	You will experience immediate and substantial dilution of $14.32 in tangible net book value per common unit.
	•	You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

		Per Common Unit		Total
Initial public offering price		$		$
Underwriting discount (1)		$		$
Proceeds to DCP Midstream Partners, LP (before expenses)		$		$

(1)	Excludes structuring fee of $         payable to Lehman Brothers Inc. and Citigroup Global Markets Inc.

Lehman Brothers	Citigroup

UBS Investment Bank	Wachovia Securities

A.G. Edwards	KeyBanc Capital Markets

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			Page
SUMMARY				1
	Overview			1
	Formation Transactions and Partnership Structure			5
	The Offering			10
	Summary Historical and Pro Forma Financial and Operating Data			14
	Non-GAAP Financial Measures			16
RISK FACTORS				18
	Risks Related to Our Business			18
	Risks Inherent in an Investment in Us			30
	Tax Risks to Common Unitholders			36
USE OF PROCEEDS				39
CAPITALIZATION				40
DILUTION				41
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS				43
	General			43
	Our Initial Distribution Rate			44
	Unaudited Pro Forma Available Cash for Year Ended December 31, 2004 and Twelve Months Ended September 30, 2005			46
	Financial Forecast for the Twelve Months Ending December 31, 2006			49
	Assumptions and Considerations			52
	Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2006			55
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS				57
	Distributions of Available Cash			57
	Operating Surplus and Capital Surplus			58
	Subordination Period			59
	Distributions of Available Cash from Operating Surplus during the Subordination Period			60
	Distributions of Available Cash from Operating Surplus after the Subordination Period			60
	General Partner Interest and Incentive Distribution Rights			60
	General Partner’s Right to Reset Incentive Distribution Levels			61
	Percentage Allocations of Available Cash from Operating Surplus			63
	Distributions from Capital Surplus			64
	Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels			65
	Distributions of Cash Upon Liquidation			65
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA				68
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				70
	Overview			70
	Factors That Significantly Affect Our Results			70
	General Trends and Outlook			71
	Our Operations			72
	How We Evaluate Our Operations			74
	Critical Accounting Policies and Estimates			76
	Results of Operations			80

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	Liquidity and Capital Resources			88
	Capital Requirements			89
	Recent Accounting Pronouncements			92
	Quantitative and Qualitative Disclosures about Market Risk			93
BUSINESS				99
	Our Partnership			99
	Business Strategies			99
	Competitive Strengths			100
	Our Relationship with Duke Energy Field Services and its Parents			101
	Natural Gas and NGLs Overview			101
	Natural Gas Services Segment			103
	NGL Logistics Segment			108
	Safety and Maintenance Regulation			111
	Regulation of Operations			112
	Environmental Matters			114
	Title to Properties and Rights-of-Way			117
	Employees			117
	Legal Proceedings			117
MANAGEMENT				118
	Management of DCP Midstream Partners, LP			118
	Directors and Executive Officers			119
	Reimbursement of Expenses of Our General Partner			121
	Executive Compensation			121
	Compensation of Directors			121
	Long-Term Incentive Plan			121
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT				124
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS				125
	Distributions and Payments to Our General Partner and its Affiliates			125
	Agreements Governing the Transactions			126
	Omnibus Agreement			126
	Contracts with Affiliates			128
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES				130
	Conflicts of Interest			130
	Fiduciary Duties			135
DESCRIPTION OF THE COMMON UNITS				138
	The Units			138
	Transfer Agent and Registrar			138
	Transfer of Common Units			138
THE PARTNERSHIP AGREEMENT				139
	Organization and Duration			139
	Purpose			139
	Power of Attorney			139
	Cash Distributions			139
	Capital Contributions			139

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	Voting Rights			140
	Limited Liability			141
	Issuance of Additional Securities			142
	Amendment of the Partnership Agreement			142
	Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			144
	Termination and Dissolution			145
	Liquidation and Distribution of Proceeds			145
	Withdrawal or Removal of the General Partner			146
	Transfer of General Partner Units			147
	Transfer of Ownership Interests in the General Partner			147
	Transfer of Incentive Distribution Rights			147
	Change of Management Provisions			148
	Limited Call Right			148
	Meetings; Voting			148
	Status as Limited Partner			149
	Non-Citizen Assignees; Redemption			149
	Indemnification			149
	Reimbursement of Expenses			150
	Books and Reports			150
	Right to Inspect Our Books and Records			150
	Registration Rights			151
UNITS ELIGIBLE FOR FUTURE SALE				152
MATERIAL TAX CONSEQUENCES				153
	Partnership Status			153
	Limited Partner Status			154
	Tax Consequences of Unit Ownership			155
	Tax Treatment of Operations			159
	Disposition of Common Units			160
	Uniformity of Units			162
	Tax-Exempt Organizations and Other Investors			163
	Administrative Matters			163
	State, Local, Foreign and Other Tax Considerations			165
SELLING UNITHOLDER				166
INVESTMENT IN DCP MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS				167
UNDERWRITING				168
	Commissions and Expenses			168
	Option to Purchase Additional Common Units			169
	Lock-Up Agreements			169
	Offering Price Determination			169
	Indemnification			170
	Directed Unit Program			170
	Stabilization, Short Positions and Penalty Bids			170
	Electronic Distribution			171
	New York Stock Exchange			171

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			Page
	Discretionary Sales			171
	Stamp Taxes			171
	Relationships			171
	NASD Conduct Rules			171
VALIDITY OF THE COMMON UNITS				172
EXPERTS				172
WHERE YOU CAN FIND MORE INFORMATION				172
FORWARD-LOOKING STATEMENTS				172
INDEX TO FINANCIAL STATEMENTS				F-1
Appendix A — Form of First Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP				A-1
Appendix B — Glossary of Terms				B-1
Form of Underwriting Agreement
Form of Amended and Restated Limited Partnership Agreement
Certificate of Formation of DCP Midstream GP, LLC
Form of Amended and Restated Limited Liability Agreement
Opinion of Vinson & Elkins L.L.P. - legality of securities
Opinion of Vinson & Elkins L.L.P. - relating to tax matters
Form of Credit Agreement
Form of Long-Term Incentive Plan
Form of Contribution, Conveyance and Assumption Agreement
Form of Omnibus Agreement
Natural Gas Gathering Agreement
List of Subsidiaries
Consent of Deloitte & Touche LLP
Consent of Deloitte & Touche LLP
Consent of Deloitte & Touche LLP
Consent of Nominee for Director
Consent of Nominee for Director
Consent of Nominee for Director
Consent of Nominee for Director

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	•	the fees we charge and the margins we realize for our services;
	•	the prices of, level of production of, and demand for, natural gas, natural gas liquids, or NGLs, and condensate;
	•	the volume of natural gas we gather, treat, compress, process, transport and sell, and the volume of NGLs we transport and sell;
	•	the relationship between natural gas and NGL prices;
	•	the level of competition from other midstream energy companies;
	•	the level of our operating and maintenance and general and administrative costs; and
	•	prevailing economic conditions.

	•	the level of capital expenditures we make;
	•	the cost of acquisitions;
	•	our debt service requirements and other liabilities;
	•	fluctuations in our working capital needs;
	•	our ability to borrow funds and access capital markets;
	•	restrictions contained in our debt agreements; and
	•	the amount of cash reserves established by our general partner.

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	•	the impact of weather;
	•	the level of domestic and offshore production;
	•	the availability of imported natural gas, NGLs and crude oil;
	•	actions taken by foreign oil and gas producing nations;
	•	the availability of local, intrastate and interstate transportation systems;
	•	the availability and marketing of competitive fuels;
	•	the impact of energy conservation efforts; and
	•	the extent of governmental regulation and taxation.

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	•	identify businesses engaged in managing, operating or owning pipelines, processing and storage assets or other midstream assets for acquisitions, joint ventures and construction projects;
	•	consummate accretive acquisitions or joint ventures and complete construction projects;
	•	appropriately identify any liabilities associated with any acquired businesses or assets;
	•	integrate any acquired or constructed businesses or assets successfully with our existing operations and into our operating and financial systems and controls;
	•	hire, train and retain qualified personnel to manage and operate our growing business; and
	•	obtain required financing for our existing and new operations.

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	•	perform ongoing assessments of pipeline integrity;
	•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
	•	improve data collection, integration and analysis;
	•	repair and remediate the pipeline as necessary; and
	•	implement preventive and mitigating actions.

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	•	mistaken assumptions about volumes, revenues and costs, including synergies;
	•	an inability to integrate successfully the businesses we acquire;
	•	the assumption of unknown liabilities;
	•	limitations on rights to indemnity from the seller;
	•	mistaken assumptions about the overall costs of equity or debt;
	•	the diversion of management’s and employees’ attention from other business concerns;
	•	unforeseen difficulties operating in new product areas or new geographic areas; and
	•	customer or key employee losses at the acquired businesses.

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	•	damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
	•	inadvertent damage from construction, farm and utility equipment;
	•	leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;
	•	fires and explosions; and
	•	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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	•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
	•	we will need a portion of our cash flow to make interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders;
	•	our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
	•	our debt level may limit our flexibility in responding to changing business and economic conditions.

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	•	neither our partnership agreement nor any other agreement requires Duke Energy Field Services to pursue a business strategy that favors us. Duke Energy Field Services’ directors and officers have a fiduciary duty to make these decisions in the best interests of the owners of Duke Energy Field Services, which may be contrary to our interests;
	•	our general partner is allowed to take into account the interests of parties other than us, such as Duke Energy Field Services and its affiliates, in resolving conflicts of interest;
	•	Duke Energy Field Services and its affiliates, including Duke Energy Corporation, which we refer to as Duke Energy, and ConocoPhillips, are not limited in their ability to compete with us. Please read “— Duke Energy Field Services and its affiliates are not limited in their ability to compete with us” beginning on page 31;
	•	Our general partner may make a determination to receive a quantity of our Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions” beginning on page 57.
	•	some officers of Duke Energy Field Services who provide services to us also will devote significant time to the business of Duke Energy Field Services, and will be compensated by Duke Energy Field Services for the services rendered to it;
	•	our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
	•	our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;
	•	our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;
	•	our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

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	•	our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
	•	our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;
	•	our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;
	•	our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and
	•	our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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	•	the exercise of its right to reset the target distribution levels of its incentive distribution rights at higher levels and receive, in connection with this reset, a number of Class B units that are convertible at any time following the first anniversary of the issuance of these Class B units into common units;
	•	its limited call right;
	•	its voting rights with respect to the units it owns;
	•	its registration rights; and
	•	and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

	•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;
	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
	•	provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

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	Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

	Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

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	Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

	Control of our general partner may be transferred to a third party without unitholder consent.

	You will experience immediate and substantial dilution of $14.32 in tangible net book value per common unit.

	We may issue additional units without your approval, which would dilute your existing ownership interests.

	•	our unitholders’ proportionate ownership interest in us will decrease;
	•	the amount of cash available for distribution on each unit may decrease;
	•	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
	•	the ratio of taxable income to distributions may increase;
	•	the relative voting strength of each previously outstanding unit may be diminished; and
	•	the market price of the common units may decline.

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	Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

	Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

	•	a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
	•	your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

	Unitholders may have liability to repay distributions that were wrongfully distributed to them.

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	We will incur increased costs as a result of being a publicly-traded company.

	Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the Internal Revenue Service treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to our unitholders.

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	An IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

	You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

	Tax gain or loss on disposition of common units could be more or less than expected.

	Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

	We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

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	Unitholders may be subject to state and local taxes and return filing requirements.

	The sale or exchange of 50% or more of our capital and profits interests will result in the termination of our partnership for federal income tax purposes.

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	•	purchase $61.0 million of United States Treasury and other qualifying securities, which will be assigned as collateral to secure the term loan portion of our credit facility;
	•	pay approximately $4.7 million of expenses associated with the offering and related formation transactions;
	•	use approximately $53.9 million to fund payables;
	•	distribute approximately $8.0 million in cash to affiliates of Duke Energy Field Services as reimbursement for capital expenditures incurred by affiliates of Duke Energy Field Services related to the assets to be contributed to us upon the closing of this offering; and
	•	use the remaining proceeds of approximately $40.7 million to fund future capital expenditures (including potential acquisitions), working capital and other general partnership purposes.

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	•	the cash and long-term investments and the capitalization of DCP Midstream Partners Predecessor as of September 30, 2005; and
	•	our pro forma cash and long-term investments and capitalization as of September 30, 2005, as adjusted to reflect this offering, the other transactions described under “Summary — Formation Transactions and Partnership Structure — General” and the application of the net proceeds from this offering as described under “Use of Proceeds.”

					As of September 30, 2005
					Historical				Pro Forma
					($ in millions)
Cash					$	—			$	94.6
Long-term investments						—				61.0
		Total cash and long-term investments			$	—			$	155.6
Long-term debt:
	Revolving credit facility				$	—			$	110.0
	Term loan facility					—				61.0
		Total long-term debt			$	—			$	171.0
Total partners’ capital/net parent equity:
	Net parent equity				$	214.2			$	—
	Common units — public					—				164.0
	Common units — sponsor					—				(9.3	)
	Subordinated units — sponsor					—				(48.7	)
	General partner interest					—				(2.4	)
		Total partners’ capital/net parent investment				214.2				103.6
			Total capitalization		$	214.2			$	274.6

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Assumed initial public offering price per common unit							$	20.00
	Net tangible book value per common unit before the offering(a)		$	23.94
	Decrease in net tangible book value per common unit attributable to purchasers in the offering			(18.26	)
Less: Pro forma net tangible book value per common unit after the offering(b)								5.68
Immediate dilution in tangible net book value per common unit to new investors							$	14.32

	(a)	Determined by dividing the number of units and general partner units (1,357,143 common units, 7,142,857 subordinated units and 357,143 general partner units) to be issued to a subsidiary of Duke Energy Field Services for its contribution of assets and liabilities to DCP Midstream Partners, LP into the net tangible book value of the contributed assets and liabilities.

	(b)	Determined by dividing the total number of units and general partner units to be outstanding after the offering (10,357,143 common units, 7,142,857 subordinated units and 357,143 general partner units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.

			Units Acquired								Total Consideration
			Number				Percent				Amount				Percent
			($ in millions)
General partner and affiliates (a)(b)				8,857,143				49.6	%		$	(60.4	)			(50.50	)%
New investors				9,000,000				50.4	%			180.0				150.50	%
	Total			17,857,143				100.0	%		$	119.6				100.00	%

	(a)	The common and subordinated units and general partner units acquired by our general partner and its affiliates consist of 1,357,143 common units and 7,142,857 subordinated units and 357,143 general partner units.

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	(b)	The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of September 30, 2005, after giving effect to the application of the net proceeds of this offering and the retention of accounts receivable and a 5% interest in the Black Lake Pipe Line Company by affiliates of our general partner, is as follows:

			($ in millions)
Net parent investment			$	213.8
Less: Payment to affiliates of our general partner from the net proceeds of the offering and borrowings under the credit facility				(179.0	)
Less: The retention by affiliates of our general partner of accounts receivable and a 5% interest in the Black Lake Pipe Line Company				(95.2	)
	Total consideration		$	(60.4	)

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	•	Our distribution policy is subject to restrictions on distributions under our new credit facility. Specifically, the agreement related to our credit facility contains material financial tests and covenants that we must satisfy. These financial tests and covenants are described in this prospectus under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements — Description of Credit Agreement.” Should we be unable to satisfy these restrictions under our credit facility or if we are otherwise in default under our credit facility, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.
	•	Our board of directors will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy.
	•	While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of the public common unitholders, our partnership agreement can be amended with the approval of a majority of the outstanding common units and any Class B units issued upon the reset of incentive distribution rights, if any, voting as a class (including common units held by affiliates of Duke Energy Field Services) after the subordination period has ended. At the closing of this offering, a subsidiary of Duke Energy Field Services will own our general partner and approximately 48.6% of our outstanding common units and subordinated units.
	•	Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by of our general partner, taking into consideration the terms of our partnership agreement.

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	•	Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.
	•	We may lack sufficient cash to pay distributions to our unitholders due to increases in our general and administrative expense, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.
	•	We own a 45% interest in the Black Lake Pipe Line Company, Duke Energy Field Services owns a 5% interest and BP owns the other 50% interest. Black Lake Pipe Line Company is required by the terms of its partnership agreement to make monthly cash distributions equal to 100% of its available cash, which is defined as receipts less disbursements plus any reduction in cash reserves or minus any increase in cash reserves. BP, as the operator of this company, makes all of these determinations. As a result, we generally do not have any control over the amount or timing of cash distributions made by Black Lake Pipe Line Company. The partnership agreement of Black Lake Pipe Line Company may not be amended without the approval of us and BP. In anticipation of a pipeline integrity project, Black Lake Pipe Line Company suspended making monthly cash distributions in December 2004 in order to reserve cash to pay the expenses of this project. We expect that this project will be completed in 2006 and the monthly cash distributions will resume following the completion of this project.

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							Distributions
			Number of
			Units				One Quarter				Four Quarters
Publicly held common units				9,000,000			$	3,150,000			$	12,600,000
Common units held by Duke Energy Field Services				1,357,143				475,000				1,900,000
Subordinated units held by Duke Energy Field Services				7,142,857				2,500,000				10,000,000
General partner units held by Duke Energy Field Services				357,143				125,000				500,000
	Total			17,857,143			$	6,250,000			$	25,000,000

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	•	“Unaudited Pro Forma Available Cash,” in which we present the amount of cash we would have had available for distribution for our fiscal year ended December 31, 2004 and the twelve months ended September 30, 2005, derived from our unaudited pro forma financial statements that are included in this prospectus beginning on page F-2, which unaudited pro forma financial statements are based on the audited historical financial statements of DCP Midstream Partners Predecessor for the year ended December 31, 2004 and for the nine months ended September 30, 2005, as adjusted to give pro forma effect to:

	-	the transactions to be completed as of the closing of this offering, including the incurrences of approximately $171.0 million of indebtedness under our new credit facility; and
	-	this offering and the application of the net proceeds as described under “Use of Proceeds.”

	•	“Statement of Forecasted Results of Operations for the Twelve Months Ending December 31, 2006,” in which we present our financial forecast of our results of operations and the minimum estimated EBITDA necessary for us to pay distributions at the initial distribution rate on all units for the twelve months ending December 31, 2006, and the significant assumptions upon which the forecast is based; and
	•	“Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2006,” in which we present our estimate of the minimum amount of EBITDA necessary for us to pay distributions at the initial distribution rate on all units for the twelve months ending December 31, 2006.

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			Year Ended				Twelve Months
			December 31,				Ended
			2004				September 30, 2005
			($ in millions, except per unit data)
Net Cash Provided by Operating Activities (a)			$	25.6			$	7.0
	Net changes in working capital accounts, including net changes in price risk management assets and liabilities (b)			11.2				29.5
	Non-cash impairment of equity method investment (f)			(4.4	)			—
	Other, including changes in noncurrent assets and liabilities			0.6				0.4
EBITDA (c)			$	33.0			$	36.9
	Incremental general and administrative expense of being a public company (d)			(7.7	)			(7.7	)
	Expenses incurred relating to the offering (e)			—				2.7
	Non-cash impairment of equity method investment (f)			4.4				—

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				Year Ended				Twelve Months
				December 31,				Ended
				2004				September 30, 2005
				($ in millions, except per unit data)
	Pro forma net cash interest expense (g)				(3.0	)			(4.3	)
	Maintenance capital expenditures (h)				(1.9	)			(3.1	)
	Earnings in excess of distributions received from equity investments				(0.6	)			(0.6	)
Pro Forma Available Cash				$	24.2			$	23.9
Pro Forma Cash Distributions:
	Distributions per unit (i)			$	1.40			$	1.40
	Distributions to public common unitholders (i)			$	12.6			$	12.6
	Distributions to Duke Energy Field Services (i)				12.4				12.4
		Total distributions (i)		$	25.0			$	25.0
Excess (shortfall) (j)				$	(0.8	)		$	(1.1	)
Interest coverage ratio (k)					11.0	x			8.6	x
Leverage ratio (k)					3.3	x			3.0	x

(a)	Reflects net cash provided by operating activities of DCP Midstream Partners Predecessor derived from its historical combined financial statements for the periods indicated without giving pro forma effect to the offering and the related transactions.
(b)	At the closing of this offering, we will have a revolving credit facility that provides for an aggregate of up to $250 million in borrowing availability. As we will utilize this facility to satisfy our working capital needs, thereby allowing us to avoid using cash flow from operations to satisfy our working capital needs, we do not reflect any pro forma adjustments to cash available for distributions as a result of these requirements.
(c)	EBITDA is defined as net income plus net interest expense and depreciation and amortization expense. Net changes in working capital accounts and other, including changes in noncurrent assets and liabilities, are not included in EBITDA, and thus are reconciling items in the reconciliation of Net Cash Provided by Operating Activities and EBITDA. Please read “Summary — Non-GAAP Financial Measures.”
(d)	Reflects an adjustment to our EBITDA for an estimated incremental cash expense associated with being a publicly traded limited partnership, including compensation and benefit expenses of our executive management personnel, costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.
(e)	Represents an adjustment to our EBITDA for the portion of costs associated with this offering, that were incurred during the third quarter of 2005.

(f)	Represents an impairment to our equity method investment in Black Lake Pipe Line Company. Our investment in the Black Lake Pipe Line Company was analyzed during the third quarter of 2004 and determined to be impaired. As a result, this investment was written down to fair value which was determined based on management’s best estimates of discounted future cash flows.

(g)	Reflects on a net basis the interest expense related to borrowings under our credit facility made in connection with this offering and the interest income related to the short-term investments we intend to purchase with a portion of the proceeds from this offering.

(h)	Includes actual maintenance capital expenditures of $1.9 million and $3.1 million for the year ended December 31, 2004 and the twelve months ended September 30, 2005, respectively. Maintenance capital

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	expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows.

In addition, we made expansion capital expenditures of $1.2 million and $4.5 million for the year ended December 31, 2004 and the twelve months ended September 30, 2005, respectively. Expansion capital expenditures are made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire similar systems or facilities. These expenditures were funded by cash contributions from our parent, Duke Energy Field Services, and are not included in our Pro Forma Available Cash calculation.

(i)

The table below sets forth the assumed number of outstanding common units, subordinated units and general partner units upon the closing of this offering and the estimated per unit and aggregate distribution amounts payable on our common units, subordinated units and general partner units for four quarters at our initial distribution rate of $0.35 per common unit per quarter ($1.40 per common unit on an annualized basis).

							Distributions for
							Four Quarters
			Number of
			Units				Per Unit				Aggregate
Pro forma distributions on publicly held common units				9,000,000			$	1.40			$	12,600,000
Pro forma distributions on common units held by Duke Energy Field Services				1,357,143			$	1.40				1,900,000
Pro forma distribution on subordinated units held by Duke Energy Field Services				7,142,857			$	1.40				10,000,000
Pro forma distribution on general partner units				357,143			$	1.40				500,000
	Total			17,857,143							$	25,000,000

(j)	Pro forma cash distributions are based on an assumed distribution of $0.35 per common unit per quarter and, due to our general partner’s right to receive incentive distributions when distributions exceed $0.4025 per common unit, not all cash available for distribution in excess of the $0.4025 per common unit per quarter would be distributed to holders of common units and subordinated units.

(k)	In connection with the closing of this offering, our operating partnership will enter into a credit agreement in an aggregate principal amount of up to $400.0 million. There will be two facilities under our credit agreement, including a term loan facility of up to $175.0 million and a revolving credit facility of up to $250.0 million.

	The credit agreement will contain financial covenants requiring us to maintain:

	•	an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, in each case as defined in the credit agreement) of not less than 3.0 to 1.0, determined as of the last day of each quarter for the four-quarter period ending on the date of determination; and
	•	a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as defined in the credit agreement) of not more than 4.75 to 1.0 (or, on a temporary basis for not more than three consecutive quarters following the consummation of certain acquisitions and/or qualified capital expenditures, not more than 5.25 to 1.0).

	On a pro forma basis for the year ended December 31, 2004 and the twelve months ended September 30, 2005, we would have been in compliance with these covenants.

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				Twelve Months
				Ending
				December 31,
				2006
				($ in millions)
Total operating revenues				$	468.9
Costs and expenses:
	Purchases of natural gas and NGLs				403.5
	Operating and maintenance expense				15.5
	Depreciation and amortization expense				12.2
	General and administrative expense				14.0
		Total costs and expenses			445.2
Operating income					23.7
	Loss from equity method investment				—
	Cash interest expense, net				(6.4	)
		Net income			17.3
Adjustments to reconcile net income to cash available for distributions:
	Depreciation and amortization expense				12.2
	Cash interest expense, net				6.4
		Forecasted EBITDA			35.9
	Cash interest expense, net				(6.4	)
	Maintenance capital expenditures				(2.2	)
	Expansion capital expenditures				(1.0	)
	Proceeds from liquidation of United States Treasury and other qualified securities				1.0
	Distributions received in excess of earnings from equity investment				0.3
	Non-cash general and administrative expense				0.7
		Cash available for distribution			28.3
Total distributions to our unitholders and general partner at the initial distribution rate					25.0
	Excess of cash available for distributions over distributions at the initial distribution rate			$	3.3
Calculation of minimum estimated EBITDA necessary to pay cash distributions at the initial distribution rate:
	Forecasted EBITDA			$	35.9
	Excess of cash available for distributions over distributions at the initial distribution rate				(3.3	)
		Minimum estimated EBITDA necessary to pay cash distributions at the initial distribution rate		$	32.6
Interest coverage ratio (a)					5.6	x
Leverage ratio (a)					3.1	x

(a)	In connection with the closing of this offering, our operating partnership will enter into a credit agreement in an aggregate principal amount of up to $400.0 million. There will be two facilities under our credit agreement, including a term loan facility of up to $175.0 million and a revolving credit facility of up to $250.0 million.

	The credit agreement will contain financial covenants requiring us to maintain:

	•	an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, in each case as defined in the credit agreement) of not less than 3.0 to 1.0, determined as of the last day of each quarter for the four quarter period ending on the date of determination; and
	•	a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as defined in the credit agreement) of not more than 4.75 to 1.0 (or, on a temporary basis for not more than three consecutive quarters following the consummation of certain acquisitions, not more than 5.25 to 1.0).

	Based on our forecasted results of operations, we expect that we will be in compliance with these covenants for the 2006 forecast period.

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	•	Volumes, revenues and cost of sales are net of intercompany transactions.
	•	Our forecast includes the effect of our commodity price hedging program under which we have hedged approximately 80% of our expected natural gas, NGL and condensate commodity price risk related to our natural gas, NGL and condensate sales.
	•	Realized throughput volumes and commodity prices are the two primary factors that will influence whether the amount of cash available for distribution in 2006 is above or below our forecast. For example, if all other assumptions are held constant, a 6.0% decline in inlet volumes below forecasted levels would result in a $3.3 million decline in cash available for distribution. A decline in forecasted cash flows greater than $3.3 million would result in our generating less than the minimum cash available to pay distributions. For 2003 and 2004, a 5% decline in inlet volumes would have resulted in a $2.3 million and $2.4 million, respectively, decline in cash available for distribution.
	•	Similarly, a difference in realized versus forecasted commodity prices would effect our cash flows. For 2006, approximately $7.0 million of our forecasted gross margin is unhedged and therefore has commodity price sensitivity. If all other assumptions are held constant, a combined 45.0% decrease in realized natural gas, crude oil and NGL prices versus our forecasted prices for the unhedged portions of our forecasted volumes of natural gas, condensate and NGLs would result in a $3.3 million decline in cash available for distribution. For 2006, our forecast market prices for the unhedged portions of our forecasted volumes of natural gas, condensate and NGLs are $7.51/MMBtu, $51.02/Bbl and $32.70/Bbl, respectively. These forecast prices for the unhedged portions of our forecasted volumes were based on 87% of the average price for natural gas, crude oil and NGLs pursuant to futures contracts for product delivery during a five-year period. For 2003 and 2004, a 5% decline in market prices for natural gas, crude oil and NGLs would have resulted in a $1.3 million and $1.8 million, respectively, decline in cash available for distribution. The significant difference between historical and forecasted price sensitivity is attributable to the hedge transactions and their forecasted effectiveness.
	•	As described below, our 2006 average price forecast for each commodity reflects the volume-weighted average of (i) our five-year flat hedge price and (ii) five-year average market futures prices, reduced by approximately 13% for conservatism.

	•	We will sell an average of 124 BBtu/d of residue gas for the twelve months ending December 31, 2006 at an average price of $8.03/MMBtu, as compared to 128 BBtu/d at an average price of $5.90/MMBtu for the calendar year ended December 31, 2004, and 139 BBtu/d at an average price of $5.54/MMBtu for the calendar year ended December 31, 2003. These assumptions take into account the effect of our natural gas hedge contract under which we have hedged approximately 80% of our expected natural gas commodity price exposure related to natural gas sales. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk — Hedging Strategies” for additional detail related to the terms of this natural gas hedge contract.
	•	We will gather and/or transport an average of 242 BBtu/d of natural gas for the twelve months ending December 31, 2006 under various tariff and fee arrangements at an average rate of $0.31/MMBtu, as compared to 185 BBtu/d at an average rate of $0.29/MMBtu for the calendar year ended December 31, 2004, and 214 Bbtu/d at an average rate of $0.24/MMBtu for the calendar year ended December 31, 2003.
	•	We will sell an average of 684 Bbls/d of condensate for the twelve months ending December 31, 2006 at an average price of $52.95/Bbl, as compared to 656 Bbls/d at an average price of $35.57/Bbl for the calendar year ended December 31, 2004, and 689 Bbls/d at an average price of $24.73/Bbl for the

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		calendar year ended December 31, 2003. These assumptions take into account the effect of crude oil hedge contract under which we have hedged approximately 80% of our expected condensate commodity price exposure related to condensate sales. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk — Hedging Strategies” for additional detail related to the terms of this crude oil hedge contract.
	•	We will sell an average of 4,620 Bbls/d of NGLs for the twelve months ending December 31, 2006 at an average price of $35.71/Bbl, as compared to 19,717 Bbls/d at an average price of $28.64/Bbl for the calendar year ended December 31, 2004, and 18,817 Bbls/d at an average price of $24.27/Bbl for the calendar year ended December 31, 2003. These assumptions take into account the effect of our crude oil hedge contract under which we have hedged approximately 80% of our expected NGLs commodity price exposure related to NGLs sales. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk — Hedging Strategies” for additional detail related to the terms of this crude oil hedge contract. Upon the closing of this offering, we will enter into a contractual arrangement with Duke Energy Field Services that will provide that Duke Energy Field Services will purchase the NGLs that were historically purchased by us with respect to our Seabreeze pipeline, and Duke Energy Field Services will pay us to transport the NGLs on the Seabreeze pipeline pursuant to a fee-based rate that will be applied to the volumes transported. Because of this contractual change, the forecasted NGL volumes sold are significantly different than the historical comparison.
	•	We will transport an average of 19,459 Bbls/d of NGLs for the twelve months ending December 31, 2006 under fee contracts at an average rate of $0.54/Bbl, as compared to 0 Bbls/d for the calendar years ended December 31, 2004 and December 31, 2003. Upon the closing of this offering, we will enter into a contractual arrangement with Duke Energy Field Services that will provide that Duke Energy Field Services will purchase the NGLs that were historically purchased by us with respect to our Seabreeze pipeline, and Duke Energy Field Services will pay us to transport the NGLs on the Seabreeze pipeline pursuant to a fee-based rate that will be applied to the volumes transported. Because of this contractual change, the forecasted NGL volumes transported are significantly different than the historical comparison.

	•	We will purchase an average of 124 BBtu/d of natural gas at an average price of $7.88/MMBtu, as compared to 129 BBtu/d at an average price of $5.69/MMBtu for the calendar year ended December 31, 2004, and 139 BBtu/d at an average price of $5.43/MMBtu for the calendar year ended December 31, 2003.
	•	We will purchase an average of 3,114 Bbls/d of NGLs at an average price of $39.95/Bbl, as compared to 17,681 Bbls/d at an average price of $28.48/Bbl for the calendar year ended December 31, 2004, and 17,621 Bbls/d at an average price of $24.11/Bbl for the calendar year ended December 31, 2003. The projected reduction in volumes is attributable to the contractual arrangement with Duke Energy Field Services described above under “— Total Operating Revenue.”
	•	Operating and maintenance expense will not be more than $15.5 million for the twelve months ending December 31, 2006, and includes certain scheduled asset integrity expenditures which do not occur annually, as compared to $13.6 million for the calendar year ended December 31, 2004, and $15.0 million for the calendar year ended December 31, 2003.
	•	Our general and administrative expense will not be more than $14.0 million, which will consist of $4.8 million of fixed general and administrative expense, pursuant to the omnibus agreement, and $9.2 million of additional general and administrative expense, of which $8.4 million relates to operating as a separate publicly held limited partnership. Our general and administrative expense of $14.0 million includes $0.7 million of non-cash expense related to awards to be granted under our

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		Long-Term Incentive Plan. General and administrative expense was $6.5 million and $7.1 million for the calendar years ended December 31, 2004 and 2003, respectively. Under the terms of the omnibus agreement with Duke Energy Field Services, our allocated general and administrative expense for 2006 will be capped at $4.8 million. Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement” on page 126.

	•	Our forecast takes into account our 45% interest in the Black Lake Pipe Line Company.
	•	Black Lake pipeline will transport an average of 9,998 Bbls/d of NGLs at an average rate of $0.89/Bbl for the twelve months ending December 31, 2006, as compared to 10,512 Bbls/d at an average rate of $0.81/Bbl for the calendar year ended December 31, 2004, and 11,094 Bbls/d at an average price of $0.81/Bbl for the calendar year ended December 31, 2003.
	•	Operating and maintenance expense for Black Lake pipeline will be no more than $2.5 million, as compared with $1.7 million and $2.2 million for the calendar years ended December 31, 2004 and 2003, respectively.
	•	Depreciation and amortization expense for Black Lake pipeline will be no more than $0.7 million.

	•	Our maintenance capital expenditures will not exceed $2.2 million for the twelve months ending December 31, 2006 as compared to $1.9 million and $1.3 million for the calendar years ended December 31, 2004 and 2003, respectively.
	•	Our expansion capital expenditures will be $1.0 million during the period.
	•	We will finance our $1.0 million in expansion capital expenditures by selling $1.0 million in United States Treasury and other qualified securities and subsequently will reduce our borrowings under our secured term loan facility by $1.0 million and increase our borrowing under our revolving credit facility by $1.0 million.

	•	Our debt levels will not exceed $171.0 million. Of this $171.0 million, $110.0 million will initially be drawn under our revolving credit facility and $61.0 million will initially be drawn under our secured term loan facility.
	•	We will finance our $1.0 million in expansion capital expenditures by selling $1.0 million in United States Treasury and other qualified securities and subsequently will reduce our borrowings under our secured term loan facility by $1.0 million and increase our borrowing under our revolving credit facility by $1.0 million.
	•	The borrowings under our revolver will bear an average interest rate of LIBOR + 0.75% through March 31, 2006. Subsequently, borrowings under the revolver will bear interest based on a leveraged based pricing grid. Borrowings under our term loan facility will bear an average interest rate of

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		approximately 0.20%, net of interest earned on the $61.0 million United States Treasury and other qualifying securities pledged to secure the term loan.
	•	We will remain in compliance with the restrictive financial covenants in our existing and future debt agreements.

	•	There will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business.
	•	There will not be any major adverse change in the portions of the energy industry or in general economic conditions.
	•	Market, insurance and overall economic conditions will not change substantially.

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				Twelve Months
				Ending
				December 31, 2006
				($ in
				millions, except
				per unit data)
Minimum estimated EBITDA necessary to pay cash distributions (a)				$	32.6
Less:
	Cash interest expense, net				6.4
	Maintenance capital expenditures				2.2
	Expansion capital expenditures				1.0
Add:
	Non-cash general and administrative expense				0.7
	Distributions in excess of earnings from equity method investment				0.3
	Borrowings and equity issuances				—
	Proceeds from liquidation of United States Treasury and other qualified securities				1.0
Minimum estimated cash available to pay distributions				$	25.0
Forecasted Cash Distributions (b):
	Forecasted distributions to our public common unitholders			$	12.6
	Forecasted distributions to common units held by Duke Energy Field Services				1.9
	Forecasted distributions to subordinated units held by Duke Energy Field Services				10.0
	Forecasted distributions to general partner units held by Duke Energy Field Services				0.5
		Total forecasted distributions to our unitholders and general partner		$	25.0
	Forecasted distribution per unit			$	1.40

(a)

This amount represents the minimum estimated amount of EBITDA that we will need to generate for the twelve months ending December 31, 2006 in order to pay cash distributions to our unitholders and our general partner at our initial distribution rate of $0.35 per unit per quarter. We expect that our EBITDA for this period will exceed this amount as reflected in our financial forecast found on page 49.

(b)

Represents the amount required to fund distributions to our unitholders and our general partner for four quarters based upon our initial distribution rate of $0.35 per unit per quarter. If cash distributions to our unitholders exceed $0.4025 per common unit in any quarter, our general partner will receive increasing percentages, up to 50%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions” beginning on page 57.

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	•	less the amount of cash reserves established by our 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 our unitholders and to our general partner for any one or more of the next four quarters;

	•	plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter.

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	•	an amount equal to four times the amount needed for any one quarter for us to pay a distribution on all of our units (including the general partner units) and the incentive distribution rights at the same per-unit amount as was distributed in the immediately preceding quarter; plus
	•	all of our cash receipts after the closing of this offering, excluding cash from borrowings, sales of equity and debt securities, sales or other dispositions of assets outside the ordinary course of business, the termination of interest rate swap agreements, capital contributions or corporate reorganizations or restructurings; less
	•	all of our operating expenditures after the closing of this offering, but excluding the repayment of borrowings, and including maintenance capital expenditures; less
	•	the amount of cash reserves established by our general partner to provide funds for future operating expenditures.

	•	borrowings;
	•	sales of our equity and debt securities; and
	•	sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

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	•	distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
	•	the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common and subordinated units and general partner units during those periods on a fully diluted basis during those periods; and
	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

	•	the subordination period will end and each subordinated unit will immediately convert into one common unit;
	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
	•	the general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests.

	•	distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $1.75 (125% of the annualized minimum quarterly distribution) for each of the two consecutive, non-overlapping four-quarter periods ending on or after December 31, 2008; and
	•	the adjusted operating surplus generated during each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of a distribution of $1.75 per common unit (125% of the annualized minimum quarterly distribution) on all of the

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		outstanding common and subordinated units and general partner units during those periods on a fully diluted basis; and
	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

	•	operating surplus generated with respect to that period; plus
	•	any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to that period; less
	•	any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus
	•	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

	•	first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute 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 the general partner, until we distribute 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 the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
	•	thereafter, in the manner described in “General Partner Interest and Incentive Distribution Rights” below.

	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
	•	thereafter, in the manner described in “General Partner Interest and Incentive Distribution Rights” below.

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	•	we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
	•	we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.4025 per unit for that quarter (the “first target distribution”);
	•	second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.4375 per unit for that quarter (the “second target distribution”);
	•	third, 75% to all unitholders, pro rata, and 25% to 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 the general partner.

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	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarter distribution for that quarter;
	•	second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for that quarter;
	•	third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives an amount per unit equal to 150% of the reset minimum quarterly distribution for that quarter; and
	•	thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

				Marginal Percentage
				Interest in Distributions
		Quarterly Distribution per Unit						General				Quarterly Distribution per Unit
		Prior to Reset		Unitholders				Partner				following Hypothetical Reset
Minimum Quarterly Distribution		$0.35			98	%			2	%		$0.60
First Target Distribution		up to $0.4025			98	%			2	%		up to $0.69 (1)
Second Target Distribution		above $0.4025 up to $0.4375			85	%			15	%		above $0.69 (1) up to $0.75 (2)
Third Target Distribution		above $0.4375 up to $0.525			75	%			25	%		above $0.75 (2) up to $0.90 (3)
Thereafter		above $0.525			50	%			50	%		above $0.90 (3)

(1)	This amount is 115% of the hypothetical reset minimum quarterly distribution.
(2)	This amount is 125% of the hypothetical reset minimum quarterly distribution.
(3)	This amount is 150% of the hypothetical reset minimum quarterly distribution.

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								General Partner Cash Distributions
								Prior to Reset
				Common
				Unitholders Cash								2% General
		Quarterly Distribution per Unit		Distributions				Class B				Partner												Total
		Prior to Reset		Prior to Reset				Units				Interest				IDRs				Total				Distributions
Minimum Quarterly Distribution		$0.35		$	15,750,000			$	—			$	321,429			$	—			$	321,429			$	16,071,429
First Target Distribution		up to $0.4025			2,362,500				—				48,214				—				48,214				2,410,714
Second Target Distribution		above $0.4025 up to $0.4375			1,575,000				—				37,059				240,882				277,941				1,852,941
Third Target Distribution		above $0.4375 up to $0.525			3,937,500				—				105,000				1,207,500				1,312,500				5,250,000
Thereafter		above $0.525			3,375,000				—				135,000				3,240,000				3,375,000				6,750,000
				$	27,000,000			$	—			$	646,702			$	4,688,382			$	5,335,084			$	32,335,084

								General Partner Cash Distributions
								After Reset
				Common
				Unitholders Cash								2% General
		Quarterly Distribution per		Distributions				Class B				Partner												Total
		Unit After Reset		After Reset				Units				Interest				IDRs				Total				Distributions
Minimum Quarterly Distribution		$0.60		$	27,000,000			$	4,688,382			$	646,702			$	—			$	5,335,084			$	32,335,084
First Target Distribution		up to $0.69			—				—				—				—				—				—
Second Target Distribution		above $0.69 up to $0.75			—				—				—				—				—				—
Third Target Distribution		above $0.75 up to $0.90			—				—				—				—				—				—
Thereafter		above $0.90			—				—				—				—				—				—
				$	27,000,000			$	4,688,382			$	646,702			$	—			$	5,335,084			$	32,335,084

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		Total Quarterly		Marginal Percentage
		Distribution		Interest in
		Per Unit		Distributions
								General
		Target Amount		Unitholders				Partner
Minimum Quarterly Distribution		$0.35			98	%			2	%
First Target Distribution		up to $0.4025			98	%			2	%
Second Target Distribution		above $0.4025 up to $0.4375			85	%			15	%
Third Target Distribution		above $0.4375 up to $0.525			75	%			25	%
Thereafter		above $0.525			50	%			50	%

	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;
	•	second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and
	•	thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

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	•	the minimum quarterly distribution;
	•	target distribution levels;
	•	the unrecovered initial unit price;
	•	the number of common units issuable during the subordination period without a unitholder vote; and
	•	the number of common units into which a subordinated unit is convertible.

	•	first, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

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	•	second, 98% to the common unitholders, pro rata, and 2% to the general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;
	•	third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;
	•	fourth, 98% to all unitholders, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to the general partner, for each quarter of our existence;
	•	fifth, 85% to all unitholders, pro rata, and 15% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to the general partner for each quarter of our existence;
	•	sixth, 75% to all unitholders, pro rata, and 25% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to the general partner for each quarter of our existence; and
	•	thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

	•	first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;
	•	second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and
	•	thereafter, 100% to the general partner.

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	•	the issuance by us of common units to the public;
	•	the payment of estimated underwriting commissions and other expenses;
	•	the proceeds received from borrowings under our new credit facility;
	•	the distribution to Duke Energy Field Services of a portion of the net proceeds from this offering and from borrowings under our new credit facility;
	•	the purchase of United States Treasury and other qualifying securities;
	•	the retention by Duke Energy Field Services of DCP Midstream Partners Predecessor’s accounts receivable and a 5% interest in the Black Lake Pipe Line Company; and
	•	the execution of a transportation agreement related to the Seabreeze pipeline between us and Duke Energy Field Services.

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																																	DCP Midstream Partners, LP
					DCP Midstream Partners Predecessor																												Pro Forma
					($ in millions except7per-unit data)
					Nine Months																																Nine Months
																									Ended								Year Ended				Ended
					Year Ended December 31,																				September 30,								December 31,				September 30,
					2000				2001				2002				2003				2004				2004				2005				2004				2005
Statement of Operations Data:
Total operating revenues					$	369.2			$	347.9			$	297.2			$	475.1			$	509.5			$	369.3			$	510.9			$	356.8			$	370.4
Operating Costs and Expenses:
	Purchases of natural gas and NGLs					324.1				304.1				256.8				430.6				452.6				327.5				464.4				299.7				323.9
	Operating and maintenance expense					15.7				13.3				14.0				15.0				13.6				9.7				11.5				13.6				11.5
	Depreciation and amortization expense					11.1				11.3				12.3				12.8				12.6				9.4				8.8				12.6				8.8
	General and administrative expense					6.7				5.6				6.1				7.1				6.5				4.8				8.2				6.5				8.2
		Total operating costs and
			expenses			357.6				334.3				289.2				465.5				485.3				351.4				492.9				332.4				352.4
Operating income						11.6				13.6				8.0				9.6				24.2				17.9				18.0				24.4				18.0
Earnings from equity method investment						2.0				1.4				0.5				0.4				0.6				0.4				0.4				0.5				0.4
Impairment of equity method investment						—				—				—				—				4.4				4.4				—				4.0				—
Interest expense, net						—				—				—				—				—				—				—				3.1				3.5
	Net income				$	13.6			$	15.0			$	8.5			$	10.0			$	20.4			$	13.9			$	18.4			$	17.8			$	14.9
Pro forma net income per limited partner unit																																	$	0.99			$	0.83
Balance Sheet Data (at period end):
Property, plant and equipment, net					$	181.4			$	187.2			$	193.5			$	181.9			$	172.0							$	168.8							$	168.8
Total assets					$	268.0			$	232.2			$	249.3			$	239.5			$	241.1							$	278.4							$	339.2
Accounts payable					$	46.0			$	15.7			$	26.0			$	35.5			$	39.8							$	53.9							$	53.9
Long-term debt					$	—			$	—			$	—			$	—			$	—							$	—							$	171.0
Partners’ capital/Net parent equity					$	219.8			$	211.1			$	220.7			$	201.1			$	198.4							$	214.2							$	104.0

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	•	our Natural Gas Services segment, which consists of our North Louisiana natural gas gathering, processing and transportation system; and
	•	our NGL Logistics segment, which consists of our interests in two NGL pipelines.

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	•	the indebtedness we incur at the closing of this offering will increase our interest expense from the interest expense reflected in our historical financial statements;
	•	we have entered into long-term hedging arrangement for approximately 80% of our expected natural gas, NGL and condensate commodity price risk relating to our gathering and processing arrangements through 2010; and
	•	we anticipate initially incurring approximately $8.4 million, some of which will be allocated to us by Duke Energy Field Services, of additional general and administrative expenses relating to operating as a separate publicly held limited partnership, including compensation and benefit expenses of our executive management personnel, costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and director compensation.

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	Natural Gas Services Segment

	•	Fee-based arrangements. Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing or transporting natural gas. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead or other receipt points at an index related price at the delivery point less a specified amount, which specified amount is generally the same as the transportation fees we would otherwise charge for transportation of natural gas from the wellhead location to the delivery point. Revenues associated with these arrangements may be included as sales of natural gas, NGLs and condensate or transportation and processing services. The revenue we earn is directly related to the

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		volume of natural gas that flows through our systems and is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these arrangements would be reduced. For the nine months ended September 30, 2005, our fee-based activities accounted for approximately 46% of our gross margin and 74% of our volume for this segment.
	•	Percentage-of-proceeds arrangements. Under percentage-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, transport the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and NGLs at index prices based on published index market prices. We remit to the producers either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. Under these types of arrangements, our revenues correlate directly with the price of natural gas and NGLs. For the nine months ended September 30, 2005, our percentage-of-proceeds activities accounted for approximately 48% of our gross margin and 20% of our volumes for this segment.

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	NGL Logistics Segment

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	•	financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
	•	our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing methods or capital structure; and
	•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

	•	sales of natural gas, NGLs and condensate;
	•	natural gas gathering, processing and transportation, from which we generate revenues primarily through the compression, gathering, treating, processing and transportation of natural gas; and
	•	NGL transportation from which we generate revenues from transportation fees.

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

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Classification of Contract		Accounting Method				Presentation of Gains & Losses or Revenue & Expense
Non-Trading Derivative Activity			Mark-to-market  (a)			Net basis in Gains and losses from non-trading derivative activity
Cash Flow Hedge			Hedge method (b)			Gross basis in the same income statement category as the related hedged item
Fair Value Hedge			Hedge method (b)			Gross basis in the same income statement category as the related hedged item
Normal Purchases or Normal Sales			Accrual method  (c)			Gross basis upon settlement in the corresponding income statement category based on purchase or sale

(a)	Mark-to-market — An accounting method whereby the change in the fair value of the asset or liability is recognized in the results of operations in Gains and losses from non-trading derivative activity during the current period.

(b)	Hedge method — An accounting method whereby the effective portion of the change in the fair value of the asset or liability is recorded as a balance sheet adjustment and there is no recognition in the results of operations for the effective portion until the service is provided or the associated delivery period occurs.

(c)	Accrual method — An accounting method whereby there is no recognition in the results of operations for changes in fair value of a contract until the service is provided or the associated delivery period occurs.

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	Combined Overview

																Nine Months Ended
				Year Ended December 31,												September 30,
				2002				2003				2004				2004				2005
				($ in millions except operating data)
Operating revenues:
	Sales of natural gas, NGLs and condensate			$	283.2			$	454.0			$	489.7			$	354.4			$	494.2
	Transportation and processing services				14.3				18.6				19.9				15.0				16.7
	Gains and (losses) from non-trading derivative activity				(0.3	)			2.5				(0.1	)			(0.1	)			—
		Total operating revenues			297.2				475.1				509.5				369.3				510.9
	Purchases of natural gas and NGLs				256.8				430.6				452.6				327.5				464.4
Gross margin (a)					40.4				44.5				56.9				41.8				46.5
	Operating and maintenance expense				14.0				15.0				13.6				9.7				11.5
	General and administrative expense				6.1				7.1				6.5				4.8				8.2
	Earnings from equity method investment				0.5				0.4				0.6				0.4				0.4
	Impairment of equity method investment				—				—				4.4				4.4				—
EBITDA (b)					20.8				22.8				33.0				23.3				27.2
	Depreciation and amortization expense				12.3				12.8				12.6				9.4				8.8
Net income				$	8.5			$	10.0			$	20.4			$	13.9			$	18.4
Segment financial and operating data:
Natural Gas Services Segment
	Financial data:
		Gross margin (a)		$	39.1			$	42.2			$	53.6			$	39.3			$	43.8
	Operating data:
		Natural gas throughput (MMcf/d)			363				348				328				332				339
		NGL gross production (Bbls/d)			4,186				4,381				4,690				4,652				4,795
NGL Logistics Segment
	Financial data:
		Gross margin (a)		$	1.3			$	2.3			$	3.3			$	2.5			$	2.7
	Operating data:
		Seabreeze throughput (Bbls/d)			7,206				14,685				14,966				14,903				15,334
		Black Lake throughput (Bbls/d) (c)			5,099				5,547				5,256				5,237				4,972

(a)		Gross margin consists of total operating revenues less purchases of natural gas and NGLs and segment gross margin for each segment consists of total operating revenues for that segment less purchases of natural gas and NGLs for that segment. Our gross margin equals the sum of our segment gross margins. Please read “Summary — Non-GAAP Financial Matters” on page 16.
(b)		EBITDA consists of net income plus depreciation and amortization expense. Please read “Summary — Non-GAAP Financial Measures” on page 16.
(c)		Represents 50% of the throughput volumes of the Black Lake pipeline. Following this offering, we will own a 45% interest in the Black Lake Pipe Line Company.

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	Nine Months Ended September 30, 2005 vs. Nine Months Ended September 30, 2004

	•	$108.8 million increase attributable primarily to higher commodity prices for our Natural Gas Services segment; and
	•	$32.8 million increase attributable to higher NGL prices for our Seabreeze pipeline.

	•	$104.3 million increase attributable to higher costs of raw natural gas supply driven primarily by higher commodity prices for our Natural Gas Services segment; and
	•	$32.6 million increase attributable to higher NGL prices for our Seabreeze pipeline.

	•	$4.5 million increase attributable primarily to higher commodity prices for our Natural Gas Services segment; and
	•	$0.2 million increase due to increased per unit margin for our Seabreeze pipeline.

	Year Ended December 31, 2004 vs. Year Ended December 31, 2003

	•	$24.8 million increase attributable primarily to higher commodity prices for our Seabreeze pipeline; and
	•	$9.6 million increase attributable primarily to higher commodity prices, partially offset by lower sales volumes for our Natural Gas Services segment.

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	•	$23.8 million increase attributable to higher commodity prices in our Seabreeze pipeline; and
	•	$1.8 million decrease attributable to lower natural gas throughput in our Natural Gas Services segment, offset by higher raw natural gas supply prices.

	•	$11.4 million increase attributable to percentage-of-proceeds processing arrangements, mainly due to higher commodity prices and improved per unit margin from our PELICO system; and
	•	$1.0 million increase attributable to higher per unit margins for our Seabreeze pipeline.

	Year Ended December 31, 2003 vs. Year Ended December 31, 2002

	•	$93.6 million increase attributable to a full year of operation and higher commodity prices for our Seabreeze pipeline in 2003; and
	•	$84.3 million increase attributable primarily to higher commodity prices for our Natural Gas Services segment.

	•	$92.6 million increase attributable to a full year of operation and higher commodity prices for our Seabreeze pipeline; and
	•	$81.2 million increase attributable to higher costs of raw natural gas supply driven by higher commodity prices, partially offset by lower volumes for our Natural Gas Services segment.

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	•	$1.0 million increase attributable to a full year of operation of our Seabreeze pipeline; and
	•	$3.1 million increase attributable to higher commodity prices.

	Results of Operations — Natural Gas Services Segment

																Nine Months
																Ended
				Year Ended December 31,												September 30,
				2002				2003				2004				2004				2005
				($ in millions except operating data)
Operating revenues:
	Sales of natural gas, NGLs and condensate			$	245.4			$	322.6			$	333.5			$	244.0			$	351.0
	Transportation and processing services				14.3				18.6				19.9				15.0				16.7
	Gains and (losses) from non-trading derivative activity				(0.3	)			2.5				(0.1	)			(0.1	)			—
		Total operating revenues			259.4				343.7				353.3				258.9				367.7
Purchases of natural gas and NGLs					220.3				301.5				299.7				219.6				323.9
Gross margin (a)					39.1				42.2				53.6				39.3				43.8
	Operating and maintenance expense				13.7				14.7				13.4				9.5				11.3
	Depreciation and amortization expense				11.8				11.9				11.7				8.7				8.3
Natural Gas Services segment net income				$	13.6			$	15.6			$	28.5			$	21.1			$	24.2
Operating data:
	Natural gas throughput (MMcf/d)				363				348				328				332				339
	NGL gross production (Bbls/d)				4,186				4,381				4,690				4,652				4,795

(a)	Segment gross margin for each segment consists of total operating revenues for that segment less purchases of natural gas and NGLs for that segment. Our gross margin equals the sum of our segment gross margins. Please read “Summary — Non-GAAP Financial Measures” on page 16.

	Nine Months Ended September 30, 2005 vs. Nine Months Ended September 30, 2004

	•	$67.2 million increase attributable to an increase in natural gas prices;
	•	$10.5 million increase attributable to an increase in NGL and condensate prices;

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	•	$29.3 million increase attributable to higher natural gas and NGL sales volumes driven primarily by incremental natural gas demand at our Minden and Ada processing plants related to our merchant arrangements and higher gas supply volumes for our Ada processing plant and gathering system; and
	•	$1.7 million increase attributable to higher processing fees primarily driven by incremental fee based services of our Ada gathering system and higher transportation fees on our PELICO system.

	•	$5.7 million increase attributable to higher commodity prices;
	•	$1.4 million increase attributable to higher fees and volumes for our Ada processing plant and gathering system as described above; and
	•	$2.4 million decrease attributable to lower per unit margin for our PELICO system driven primarily by lower contractual premiums charged to customers related to pipeline imbalances.

	Year Ended December 31, 2004 vs. Year Ended December 31, 2003

	•	$17.0 million increase attributable to higher natural gas prices;
	•	$12.5 million increase attributable to higher NGL and condensate prices;
	•	$4.5 million increase attributable to higher NGL sales volume due to favorable market economics for processing NGLs;
	•	$1.2 million increase attributable to higher transportation and processing fees due primarily to the incremental fee based services of our Ada gathering system offset by gas supply declines;
	•	$23.1 million decrease attributable to lower natural gas sales volume driven by wellhead gas supply decline and higher NGL recoveries; and
	•	$2.6 million decrease attributable to lower non-trading derivative activity primarily due to natural gas asset based marketing.

	•	$23.3 million decrease attributable to lower raw natural gas supply volume due to declining wellhead production; and

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	•	$21.5 million increase attributable to higher costs of raw natural gas supply which is primarily due to higher commodity prices.

	•	$8.0 million increase attributable to percentage-of-proceeds processing arrangements, mainly due to higher commodity prices;
	•	$2.3 million increase attributable to higher per unit margins for our PELICO system primarily due to higher contractual premiums charged to customers related to pipeline imbalances; and
	•	$1.2 million increase attributable to higher transportation and processing fees as described above.

	Year Ended December 31, 2003 vs. Year Ended December 31, 2002

	•	$114.5 million increase attributable to higher natural gas prices;
	•	$8.6 million increase attributable to higher NGL and condensate prices;
	•	$4.3 million increase attributable to higher fees as a result of replacing purchase and sales contracts with fee-based throughput contracts for our PELICO system;
	•	$2.8 million increase attributable to net margin from non-trading derivative activity primarily due to natural gas asset-based marketing;
	•	$42.9 million decrease attributable to lower natural gas sales volumes primarily as a result of replacing purchase and sales contracts with fee-based throughput contracts for our PELICO system; and
	•	$2.9 million decrease attributable to lower NGL and sales volumes driven primarily by certain customers directly marketing their share of the product.

	•	$117.0 million increase attributable to higher costs of raw natural gas supply which is primarily due to higher commodity prices; and
	•	$35.8 million decrease attributable to lower purchased raw natural gas supply volumes due primarily to replacing purchase and sales contracts with fee based throughput contracts for our PELICO system.

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	•	$6.0 million increase attributable to percentage-of-proceeds processing arrangements, mainly due to higher NGL and condensate prices;
	•	$1.9 million decrease attributable to lower fractionation activity, which was due to the shut down of the fractionator at the Minden processing plant in late 2002; and
	•	$1.0 million decrease attributable to lower throughput volume as discussed above.

	Results of Operations — NGL Logistics Segment

															Nine Months
															Ended
			Year Ended December 31,												September 30,
			2002				2003				2004				2004				2005
			($ in millions except operating data)
Operating revenues:
	Sales of NGLs		$	37.8			$	131.4			$	156.2			$	110.4			$	143.2
	Total operating revenues			37.8				131.4				156.2				110.4				143.2
Purchases of NGLs				36.5				129.1				152.9				107.9				140.5
Gross margin (a)				1.3				2.3				3.3				2.5				2.7
	Operating and maintenance expense			0.3				0.3				0.2				0.2				0.2
	Earnings from equity method investment			0.5				0.4				0.6				0.4				0.4
	Impairment of equity method investment			—				—				4.4				4.4				—
	Depreciation and amortization expense			0.5				0.9				0.9				0.7				0.5
NGL Logistics segment net income			$	1.0			$	1.5			$	(1.6	)		$	(2.4	)		$	2.4
Operating data:
	Seabreeze throughput (Bbls/d)			7,206				14,685				14,966				14,903				15,334
	Black Lake throughput (Bbls/d) (b)			5,099				5,547				5,256				5,237				4,972

(a)	Segment gross margin for each segment consists of total operating revenues for that segment less purchases of natural gas and NGLs for that segment. Our gross margin equals the sum of our segment gross margins. Please read “Summary — Non-GAAP Financial Measures” on page 16.

(b)	Represents 50% of the throughput volumes of the Black Lake pipeline. Following this offering, we will own a 45% interest in the Black Lake Pipe Line Company.

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	Nine Months Ended September 30, 2005 vs. Nine Months Ended September 30, 2004

	•	$29.6 million increase attributable to higher NGL prices for our Seabreeze pipeline; and
	•	$3.2 million increase attributable to higher throughput volume for our Seabreeze pipeline due to a temporary supply disruption in the first, second and third quarters of 2004 which was restored during June of 2005.

	•	$29.5 million increase attributable to higher NGL prices for our Seabreeze pipeline; and
	•	$3.1 million increase attributable to higher throughput volumes for our Seabreeze pipeline due to a temporary supply disruption in the first and second quarters of 2004 which was restored during June of 2005.

	Year Ended December 31, 2004 vs. Year Ended December 31, 2003

	•	$22.3 million increase attributable to higher commodity prices for our Seabreeze pipeline; and
	•	$2.5 million increase attributable to higher throughput volumes for our Seabreeze pipeline due to additional supply sources.

	•	$21.3 million increase attributable to higher NGL prices for our Seabreeze pipeline; and
	•	$2.5 million increase attributable to higher throughput volumes for our Seabreeze pipeline as described above.

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	Year Ended December 31, 2003 vs. Year Ended December 31, 2002

	•	$64.5 million increase attributable to a full year of operations of our Seabreeze pipeline in 2003; and
	•	$29.1 million increase attributable to higher NGL prices for our Seabreeze pipeline.

	•	$63.8 million increase attributable to a full year of operations of our Seabreeze pipeline; and
	•	$28.8 million increase attributable to higher NGL prices for our Seabreeze pipeline.

	•	the retention of a portion of the proceeds from our initial public offering as described below;
	•	cash generated from operations;
	•	cash distributions from the Black Lake Pipe Line Company;
	•	borrowings under our credit facility;
	•	cash realized from the liquidation of United States Treasury and other securities that will be pledged under our credit facility;
	•	issuance of additional partnership units; and
	•	debt offerings.

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														Nine Months
		Year Ended												Ended
		December 31,												September 30,
		2002				2003				2004				2004				2005
		($ in millions)
Net cash provided by operating activities		$	21.3			$	30.8			$	25.6			$	26.3			$	7.7
Net cash used in investing activities		$	(22.4	)		$	(1.2	)		$	(2.5	)		$	(0.3	)		$	(4.7	)
Net cash provided by (used in) financing activities		$	1.1			$	(29.6	)		$	(23.1	)		$	(26.0	)		$	( 3.0	)

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	•	maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and
	•	expansion capital expenditures such as those to acquire additional assets to grow our business, to expand and upgrade gathering systems and processing plants and to construct or acquire similar systems or facilities.

	•	up to a $250 million revolving credit facility; and
	•	up to a $175 million term loan facility.

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	•	grant liens;
	•	incur additional indebtedness;
	•	engage in a merger, consolidation or dissolution;
	•	enter into transactions with affiliates;
	•	sell or otherwise dispose of our assets, businesses and operations;
	•	materially alter the character of our business as conducted at the closing of this offering; and
	•	make acquisitions, investments and capital expenditures.

	•	failure to pay any principal when due or any interest or fees within five business days of the due date;
	•	failure to perform or otherwise comply with the covenants in the credit agreement;
	•	failure of any representation or warranty to be true and correct in any material respect;

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	•	failure to pay any other material debt, to be defined as the greater of (1) $10.0 million or (2) the lesser of (A) 3.0% of our net tangible consolidated assets and (B) $100.0 million, when due or within applicable grace period;
	•	a change of control; and
	•	other customary defaults, including specified bankruptcy or insolvency events, the Employee Retirement Income Security Act of 1974, or ERISA, violations, and judgment defaults.

			Payments Due By Period
			(Millions)
							Less
							than 1				More than
			Total				Year				5 Years
Purchase commitments (a)			$	2.9			$	2.9				—
Other long-term liabilities (b)				0.3				—				0.3
	Total		$	3.2			$	2.9			$	0.3

(a)		Purchase commitments total $2.9 million of various non-cancelable commitments for capital projects expected to be completed in 2006. Purchase commitments exclude $53.9 million of accounts payable and $3.9 million of other current liabilities recognized on the September 30, 2005 combined balance sheet. Purchase commitments also exclude $3.6 million of current and $2.5 million of long-term unrealized losses on non-trading derivative and hedging transactions included in the September 30, 2005 combined balance sheet. These amounts represent the current fair value of various derivative contracts and do not represent future cash purchase commitments. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities. In addition, many of our gas purchase contracts include short- and long-term commitments to purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from the table.
(b)		Other long-term liabilities includes $0.2 million of asset retirement obligations and $0.1 million of environmental reserves recognized on the September 30, 2005 combined balance sheet.

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	Risk and Accounting Policies

	Credit Risk

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	Interest Rate Risk

	Commodity Price Risk

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Period

Commodity

Notional Volume

Reference Price

Swap Price

January 2006 — December 2006

Natural Gas

4,200 MMBtu/d

Texas Gas Transmission Price(1)

$9.20/MMBtu

January 2007 — December 2007

Natural Gas

4,100 MMBtu/d

Texas Gas Transmission Price(1)

$9.20/MMBtu

January 2008 — December 2008

Natural Gas

4,000 MMBtu/d

Texas Gas Transmission Price(1)

$9.20/MMBtu

January 2009 — December 2009

Natural Gas

4,000 MMBtu/d

Texas Gas Transmission Price(1)

$9.20/MMBtu

January 2010 — December 2010

Natural Gas

3,900 MMBtu/d

Texas Gas Transmission Price(1)

$9.20/MMBtu

January 2006 — December 2006

Crude Oil

670 Bbls/d

NYMEX Index Price(2)

$63.27/Bbl

January 2007 — December 2007

Crude Oil

660 Bbls/d

NYMEX Index Price(2)

$63.27/Bbl

January 2008 — December 2008

Crude Oil

650 Bbls/d

NYMEX Index Price(2)

$63.27/Bbl

January 2009 — December 2009

Crude Oil

650 Bbls/d

NYMEX Index Price(2)

$63.27/Bbl

January 2010 — December 2010

Crude Oil

640 Bbls/d

NYMEX Index Price(2)

$63.27/Bbl

(1)	NYMEX index price for natural gas delivered into the Texas Gas Transmission pipeline in the North Louisiana area.
(2)	NYMEX index price for light, sweet crude oil delivered at Cushing, Oklahoma.

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			Fair Value of Contracts as of September 30, 2005
															Maturity in
			Maturity in				Maturity in				Maturity in				2009 and				Total Fair
Sources of Fair Value			2006				2007				2008				Thereafter				Value
			(millions)
Prices supported by quoted market prices and other external sources			$	(4.0	)		$	(0.3	)		$	—			$	—			$	(4.3	)
Prices based on models or other valuation techniques				(0.5	)			(0.8	)			0.9				5.1				4.7
	Total		$	(4.5	)		$	(1.1	)		$	0.9			$	5.1			$	0.4

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	•	the Minden processing plant and gathering system, which includes a cryogenic natural gas processing plant supplied by approximately 700 miles of natural gas gathering pipelines, connected to approximately 460 receipt points, with throughput capacity of approximately 115 MMcf/d;
	•	the Ada processing plant and gathering system, which includes a refrigeration natural gas processing plant supplied by approximately 130 miles of natural gas gathering pipelines, connected to approximately 210 receipt points, with throughput capacity of approximately 80 MMcf/d; and
	•	the PELICO system, an approximately 600-mile intrastate natural gas gathering and transportation pipeline with throughput capacity of approximately 250 MMcf/d and connections to the Minden and Ada processing plants and approximately 450 other receipt points. The PELICO system delivers natural gas to multiple interstate and intrastate pipelines, as well as directly to industrial and utility end-use markets.

	•	our Seabreeze pipeline, an approximately 68-mile intrastate NGL pipeline in Texas with throughput capacity of 33 MBbls/d; and
	•	our 45% interest in the Black Lake Pipe Line Company, the owner of an approximately 317-mile interstate NGL pipeline in Louisiana and Texas with throughput capacity of 40 MBbls/d.

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	Natural Gas Demand and Production

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	Midstream Natural Gas Industry

	Natural Gas Gathering

	Natural Gas Compression

	Natural Gas Processing and Transportation

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	General

	•	gathering;
	•	compression;
	•	treating;
	•	processing;
	•	transportation; and
	•	sales of natural gas, NGLs and condensate.

	•	our Minden processing plant, which has a processing capacity of approximately 115 MMcf/d, and gathering system, which is an approximately 700-mile natural gas gathering system with throughput capacity of approximately 115 MMcf/d;
	•	our Ada processing plant, which has a processing capacity of approximately 45 MMcf/d, and gathering system, which is an approximately 130-mile natural gas gathering system with throughput capacity of approximately 80 MMcf/d; and
	•	our PELICO system, an approximately 600-mile intrastate natural gas pipeline with throughput capacity of approximately 250 MMcf/d.

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	Natural Gas Supply

Year		Wells Drilled (a)
2000			162
2001			190
2002			131
2003			164
2004			237
Eight months ended August 31, 2005			163

(a)	Represents the number of wells during a particular period for which drilling commenced, but does not represent the actual number of wells that were completed or that produced commercial quality natural gas.

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	Gathering Systems

	Processing Plants

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	Transportation System

	Natural Gas Markets

	Customers and Contracts

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	Competition

	NGL Pipelines

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	Intrastate Natural Gas Pipeline Regulation

	Gathering Pipeline Regulation

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	Sales of Natural Gas

	Interstate NGL Pipeline Regulation

	General

	•	restricting the way we can handle or dispose of our wastes;
	•	limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions or areas inhabited by endangered species;
	•	requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operations; and

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	•	enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

	Air Emissions

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	Hazardous Substances and Waste

	Water

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	•	sell all or substantially all of our assets,
	•	merge or consolidate,
	•	dissolve or liquidate,
	•	make or consent to a general assignment for the benefit of creditors,
	•	file or consent to the filing of any bankruptcy, insolvency or reorganization petition for relief under the United States Bankruptcy Code or otherwise such relief from debtor or protection from creditors, or
	•	take various actions similar to the foregoing.

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Name		Age				Position with DCP Midstream GP, LLC
Jim W. Mogg			56				Chairman of the Board
Michael J. Bradley			51			President, Chief Executive Officer and Director Nominee
Thomas E. Long			48			Vice President and Chief Financial Officer
Michael S. Richards			45			Vice President, General Counsel and Secretary
Greg K. Smith			39				Vice President, Business Development
William H. Easter III			55				Director Nominee
Paul F. Ferguson, Jr.			56				Director Nominee
John E. Lowe			46				Director Nominee

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	•	each person who then will beneficially own 5% or more of the then outstanding units;
	•	all of the directors and director nominees of DCP Midstream GP, LLC;
	•	each named executive officer of DCP Midstream GP, LLC; and
	•	all directors, director nominees and officers of DCP Midstream GP, LLC as a group.

																		Percentage of
																		Total Common
														Percentage of				and
		Common Units				Percentage of				Subordinated				Subordinated				Subordinated
		to be				Common Units to				Units to be				Units to be				Units to be
		Beneficially				be Beneficially				Beneficially				Beneficially				Beneficially
Name of Beneficial Owner(1)		Owned				Owned				Owned				Owned				Owned
DCP LP Holdings, LP			1,357,143				13.1	%			7,142,857				100	%			48.6	%
Jim W. Mogg			—				—	%			—				—	%			—	%
Michael J. Bradley			—				—	%			—				—	%			—	%
Thomas E. Long			—				—	%			—				—	%			—	%
Michael S. Richards			—				—	%			—				—	%			—	%
Greg K. Smith			—				—	%			—				—	%			—	%
William H. Easter III			—				—	%			—				—	%			—	%
Paul F. Ferguson, Jr.			—				—	%			—				—	%			—	%
John E. Lowe			—				—	%			—				—	%			—	%
All directors, director nominees and executive officers as a group (8 persons)			—				—	%			—				—	%			—	%

(1)	The address for all beneficial owners in this table is 370 17th Street, Suite 2775, Denver, Colorado 80202.

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The consideration received by our general partner and its affiliates for the contribution of the assets and liabilities to us		• 1,357,143 common units;
		• 7,142,857 subordinated units;
		• 357,143 general partner units;
		• the incentive distribution rights; and
		• $179.0 million cash payment from the proceeds of the offering and borrowings under our credit facility.

Distributions of available cash to our general partner and its affiliates		We will generally make cash distributions 98% to our unitholders pro rata, including our general partner and its affiliates, as the holders of an aggregate 1,357,143 common units and 7,142,857 subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.
		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $0.5 million on their general partner units and $11.9 million on their common and subordinated units.
Payments to our general partner and its affiliates		We will reimburse Duke Energy Field Services and its affiliates for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit. For further information regarding the administrative fee, please read “Certain Relationship and Related Party Transactions — Omnibus Agreement — Reimbursement of Operating and General and Administrative Expense” beginning on page 127.

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Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement — Withdrawal or Removal of the General Partner” beginning on page 146.

Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

	•	our obligation to reimburse Duke Energy Field Services 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 pay Duke Energy Field Services an annual administrative fee for providing us general and administrative services with respect to our business and operations, which is fixed at $4.8 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 conflicts committee;
	•	our obligation to reimburse Duke Energy Field Services for insurance coverage expenses it incurs with respect to our business and operations and with respect to director and officer liability coverage;
	•	Duke Energy Field Services’ obligation to indemnify us for certain liabilities and our obligation to indemnify Duke Energy Field Services for certain liabilities;
	•	Duke Energy Field Services’ 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 are in effect as of the closing of this offering until the earlier to occur of the fifth anniversary of the closing of this 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
	•	Duke Energy Field Services’ obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to commercial contracts with

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		respect to our business or operations that are in effect at the closing of this offering until the expiration of such contracts.

			Estimates for the
			Twelve Months
			Ending
			December 31, 2006
			(In millions)
Reimbursement of operating expenses			$	15.5
Reimbursement of general and administrative expenses				5.6
Reimbursement of public company expenses				1.6
Reimbursement of compensation and benefits for executive management of our general partner				2.4
	Total		$	25.1

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	Hedging Arrangements

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	•	approved by the conflicts committee, although our general partner is not obligated to seek such approval;
	•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
	•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
	•	fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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	•	provides that the general partner shall not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed that the decision was in the best interests of our partnership;
	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by the general partner in good faith, and that, in determining whether a transaction or resolution is “fair and

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		reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
	•	provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

	•	the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;
	•	the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;
	•	the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;
	•	the negotiation, execution and performance of any contracts, conveyances or other instruments;
	•	the distribution of our cash;
	•	the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;
	•	the maintenance of insurance for our benefit and the benefit of our partners;
	•	the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships;
	•	the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;
	•	the indemnification of any person against liabilities and contingencies to the extent permitted by law;
	•	the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and
	•	the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

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	Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

	•	amount and timing of asset purchases and sales;
	•	cash expenditures;
	•	borrowings;
	•	the issuance of additional units; and
	•	the creation, reduction or increase of reserves in any quarter.

	•	enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or
	•	hastening the expiration of the subordination period.

	Our general partner determines which costs incurred by Duke Energy Field Services are reimbursable by us.

	Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

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	Our general partner intends to limit its liability regarding our obligations.

	Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

	Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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State-law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

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		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.
Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.
		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.
		Special provisions regarding affiliated transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:
		• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
		• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).
		If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such

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		presumption. These standards reduce the obligations to which our general partner would otherwise be held.

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	•	surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
	•	special charges for services requested by a common unitholder; and
	•	other similar fees or charges.

	•	represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;
	•	automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and
	•	gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

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	•	with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions” beginning on page 57;
	•	with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties” beginning on page 130;
	•	with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units” beginning on page 138; and
	•	with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences” beginning on page 153.

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	•	during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and
	•	after the subordination period, the approval of a majority of the common units and Class B units, if any, voting as a class.

Issuance of additional units		No approval right.
Amendment of the partnership agreement		Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement” beginning on page 142.
Merger of our partnership or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets” beginning on page 144.
Dissolution of our partnership		Unit majority. Please read “— Termination and Dissolution” beginning on page 145.
Continuation of our business upon dissolution		Unit majority. Please read “— Termination and Dissolution” beginning on page 145.
Withdrawal of the general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to December 31, 2015 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of the General Partner” beginning on page 146.
Removal of the general partner		Not less than 662/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of the General Partner” beginning on page 146.
Transfer of the general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to

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		an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets, to such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2015. See “— Transfer of General Partner Units” beginning on page 147.
Transfer of incentive distribution rights		Except for transfers to an affiliate or another person as part of our general partner’s merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder, the approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to December 31, 2015. Please read “— Transfer of Incentive Distribution Rights” beginning on page 147.
Transfer of ownership interests in our general partner		No approval required at any time. Please read “— Transfer of Ownership Interests in the General Partner” beginning on page 147.

	•	to remove or replace the general partner;
	•	to approve some amendments to the partnership agreement; or
	•	to take other action under the partnership agreement;

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	•	enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or
	•	enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

	•	a change in our name, the location of our principal place of our business, our registered agent or our registered office;
	•	the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
	•	a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating partnership nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
	•	an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;
	•	an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with:

	•	the adjustments of the minimum quarterly distribution, first target distribution, second target distribution and third target distribution in connection with the reset of our general partner’s incentive distribution rights as described under “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels;” or
	•	the implementation of the provisions relating to our general partner’s right to reset its incentive distribution rights in exchange for Class B units; and
	•	any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the conflicts committee of our general partner;

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	•	any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
	•	an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;
	•	any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;
	•	a change in our fiscal year or taxable year and related changes;
	•	conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or
	•	any other amendments substantially similar to any of the matters described in the clauses above.

	•	do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;
	•	are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
	•	are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;
	•	are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or
	•	are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

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	•	the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
	•	there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;
	•	the entry of a decree of judicial dissolution of our partnership; or
	•	the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

	•	the action would not result in the loss of limited liability of any limited partner; and
	•	neither our partnership, our operating partnership nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

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	•	the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
	•	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

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	•	an affiliate of our general partner (other than an individual); or
	•	another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

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	•	the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
	•	our general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

	•	the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and
	•	the current market price as of the date three days before the date the notice is mailed.

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	•	our general partner;
	•	any departing general partner;
	•	any person who is or was an affiliate of a general partner or any departing general partner;

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	•	any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;
	•	any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and
	•	any person designated by our general partner.

	•	a current list of the name and last known address of each partner;
	•	a copy of our tax returns;
	•	information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;
	•	copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

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	•	information regarding the status of our business and financial condition; and
	•	any other information regarding our affairs as is just and reasonable.

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	•	1% of the total number of the securities outstanding; or
	•	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

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	(a)	Neither we nor the operating company will elect to be treated as a corporation; and

	(b)	For each taxable year, more than 90% of our gross income will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

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	•	interest on indebtedness properly allocable to property held for investment;
	•	our interest expense attributed to portfolio income; and
	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

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	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
	•	any cash distributions received by the unitholder as to those units would be fully taxable; and
	•	all of these distributions would appear to be ordinary income.

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	•	a short sale;
	•	an offsetting notional principal contract; or
	•	a futures or forward contract with respect to the partnership interest or substantially identical property.

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	(a)	the name, address and taxpayer identification number of the beneficial owner and the nominee;

	(b)	whether the beneficial owner is:

	1.	a person that is not a United States person;
	2.	a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or
	3.	a tax-exempt entity;

	(c)	the amount and description of units held, acquired or transferred for the beneficial owner; and

	(d)	specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

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	(1)	for which there is, or was, “substantial authority”; or
	(2)	as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

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	•	the underwriters’ option to purchase additional units is not exercised; and
	•	the underwriters exercise their option to purchase additional units in full.

Units Owned Immediately

After Exercise of

Units Owned

Underwriters’ Option and

Immediately After

Related Unit Redemption

This Offering

Assuming

Assuming

Underwriters’

Underwriters’

Option is

Option is

Exercised

Name of Selling Unitholder

Not Exercised

Percent(1)

in Full

Percent(1)

DCP LP Holdings, LP

Common units

1,357,143

7.6%

7,143

*

Subordinated units

7,142,857

40.0%

7,142,857

40.0

%

*	Less than 1%.
(1)	Percentage of total units outstanding, including common units, subordinated units and general partner units.

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	•	whether the investment is prudent under Section 404(a)(1)(B) of ERISA;
	•	whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and
	•	whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors” beginning on page 163.

	(a)	the equity interests acquired by employee benefit plans are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

	(b)	the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

	(c)	there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

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			Number of
Underwriters			Common Units
Lehman Brothers Inc.
Citigroup Global Markets Inc.
UBS Securities LLC
Wachovia Capital Markets, LLC
A.G. Edwards & Sons, Inc.
KeyBanc Capital Markets, a division of McDonald Investments Inc.
	Total			9,000,000

	•	the obligation to purchase all of the common units offered hereby if any of the common units are purchased;
	•	the representations and warranties made by us to the underwriters are true;
	•	there has been no material change in the condition of us or in the financial markets; and
	•	we deliver customary closing documents to the underwriters.

			No Exercise				Full Exercise
Per unit			$				$
	Total		$				$

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	•	during the last 17 days of the 180-day restricted period we issue an earnings release or announce material news or a material event; or
	•	prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period,

	•	the history and prospects for the industry in which we compete;
	•	our financial information;
	•	the ability of our management and our business potential and earning prospects;
	•	the prevailing securities markets at the time of this offering; and
	•	the recent market prices of, and the demand for, publicly traded common units of generally comparable master limited partnerships.

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	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
	•	A short position involves a sale by the underwriters of the common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.
	•	Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.
	•	Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

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DCP MIDSTREAM PARTNERS, LP UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS:
	Introduction			F-2
	Unaudited Pro Forma Combined Balance Sheet as of September 30, 2005			F-3
	Unaudited Pro Forma Combined Statement of Operations for the year ended December 31, 2004			F-4
	Unaudited Pro Forma Combined Statement of Operations for the nine months ended September 30, 2005			F-5
	Notes to Unaudited Pro Forma Combined Financial Statements			F-6
DCP MIDSTREAM PARTNERS PREDECESSOR COMBINED FINANCIAL STATEMENTS:
	Report of Independent Registered Public Accounting Firm			F-9
	Combined Balance Sheets as of December 31, 2003 and 2004 and as of September 30, 2005			F-10
	Combined Statements of Operations for the years ended December 31, 2002, 2003 and 2004 and for the nine months ended September 30, 2004 (unaudited) and 2005			F-11
	Combined Statements of Changes in Net Parent Equity for the years ended December 31, 2002, 2003, and 2004 and for the nine months ended September 30, 2005			F-13
	Combined Statements of Cash Flows for the years ended December 31, 2002, 2003 and 2004 and for the nine months ended September 30, 2004 (unaudited) and 2005			F-14
	Notes to Combined Financial Statements			F-15
DCP MIDSTREAM PARTNERS, LP FINANCIAL STATEMENTS:
	Report of Independent Registered Public Accounting Firm			F-31
	Balance Sheet as of September 9, 2005			F-32
	Note to Balance Sheet			F-33
DCP MIDSTREAM GP, LP FINANCIAL STATEMENTS:
	Report of Independent Registered Public Accounting Firm			F-34
	Balance Sheet as of September 9, 2005			F-35
	Note to Balance Sheet			F-36

F-1

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F-2

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					DCP Midstream
					Partners
					Predecessor								Partnership
					Historical				Adjustments				Pro Forma
ASSETS
Current assets:
	Cash				$	—			$	180.0	(a)		$	94.6
										(11.7	)(b)
										(4.3	)(c)
										110.0	(d)
										61.0	(e)
										(61.0	)(f)
										(0.4	)(g)
										(179.0	)(h)
	Accounts receivable:
		Trade, net of allowance for doubtful accounts of $0.2 million				93.5				(93.5	)(i)
		Affiliates				1.1				(1.1	)(i)
		Imbalances				—				—
	Unrealized gains on non-trading derivative and hedging transactions — affiliate					—				—
	Other					—				—
			Total current assets			94.6				—				94.6
Long-term investments						—				61.0	(f)			61.0
Property, plant and equipment, net						168.8				—				168.8
Intangible assets, net and deferred charges						2.2				0.4	(g)			2.6
Equity method investment						6.3				(0.6	) (i)			5.7
Unrealized gains on non-trading derivative and hedging transactions — affiliate						6.5				—				6.5
			Total assets		$	278.4			$	60.8			$	339.2
LIABILITIES AND PARTNERS’ CAPITAL/NET PARENT EQUITY
Current liabilities:
	Accounts payable:
		Trade			$	49.8			$	—			$	49.8
		Affiliates				2.0				—				2.0
		Imbalances				2.1				—				2.1
	Unrealized losses on non-trading derivative and hedging transactions — affiliate					3.6				—				3.6
	Other					3.9				—				3.9
			Total current liabilities			61.4				—				61.4
Long-term debt						—				110.0	(d)			171.0
										61.0	(e)
Unrealized losses on non-trading derivative and hedging transactions — affiliate						2.5				—				2.5
Other long-term liabilities						0.3				—				0.3
Commitments and contingent liabilities
Accumulated other comprehensive income						0.4				—				0.4
Net parent investment						213.8				(95.2	)(i)
										(179.0	)(h)
										60.4	(j)
Common unitholders — public										180.0	(a)			164.0
										(11.7	)(b)
										(4.3	)(c)
Common unitholders — sponsor										(9.3	)(j)			(9.3	)
Subordinated unitholders — sponsor										(48.7	)(j)			(48.7	)
General partner interest										(2.4	)(j)			(2.4	)
			Total liabilities and partners’ capital/net parent equity		$	278.4			$	60.8			$	339.2

F-3

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				DCP Midstream
				Partners
				Predecessor								Partnership
				Historical				Adjustments				Pro Forma
Operating revenues:
	Sales of natural gas, NGLs and condensate			$	412.7			$	(156.2	)(k)		$	256.5
	Sales of natural gas, NGLs and condensate to affiliates				77.0				—				77.0
	Transportation and processing services				9.5								9.5
	Transportation and processing services to affiliates				10.4				3.5	(k)			13.9
	Losses from non-trading derivative activity — affiliate				(0.1	)			—				(0.1	)
		Total operating revenues			509.5				(152.7	)			356.8
Costs and expenses:
	Purchases of natural gas and NGLs				404.1				(152.9	)(k)			251.2
	Purchases of natural gas and NGLs from affiliates				48.5				—				48.5
	Operating and maintenance expense				13.6				—				13.6
	Depreciation and amortization expense				12.6				—				12.6
	General and administrative expense — affiliate				6.5				—				6.5
		Total costs and expenses			485.3				(152.9	)			332.4
Operating income					24.2				0.2				24.4
Earnings from equity method investment					0.6				(0.1	)(m)			0.5
Impairment of equity method investment					(4.4	)			0.4	(m)			(4.0	)
Interest expense, net					—				(3.1	)(l)			(3.1	)
Net income				$	20.4			$	(2.6	)		$	17.8
General partner’s interest in net income												$	0.4
Limited partners’ interest in net income												$	17.4
Net income per limited partners’ unit												$	0.99
Weighted average number of limited partners’ units outstanding													17,500,000

F-4

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				DCP Midstream
				Partners
				Predecessor								Partnership
				Historical				Adjustments				Pro Forma
Operating revenues:
	Sales of natural gas, NGLs and condensate			$	441.1			$	(143.2	)(k)		$	297.9
	Sales of natural gas, NGLs and condensate to affiliates				53.1				—				53.1
	Transportation and processing services				8.4								8.4
	Transportation and processing services to affiliates				8.3				2.7	(k)			11.0
		Total operating revenues			510.9				(140.5	)			370.4
Costs and expenses:
	Purchases of natural gas and NGLs				410.6				(140.5	)(k)			270.1
	Purchases of natural gas and NGLs from affiliates				53.8				—				53.8
	Operating and maintenance expense				11.5				—				11.5
	Depreciation and amortization expense				8.8				—				8.8
	General and administrative expense — affiliate				8.2				—				8.2
		Total costs and expenses			492.9				(140.5	)			352.4
Operating income					18.0				—				18.0
Earnings from equity method investment					0.4				—	(m)			0.4
Interest expense, net					—				(3.5	)(l)			(3.5	)
Net income				$	18.4			$	(3.5	)		$	14.9
General partner’s interest in net income												$	0.3
Limited partners’ interest in net income												$	14.6
Net income per limited partners’ unit												$	0.83
Weighted average number of limited partners’ units outstanding													17,500,000

F-5

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	•	the issuance by DCP Midstream Partners, LP of common units to the public;
	•	the payment of estimated underwriting commissions and other offering expenses;
	•	the net proceeds received from borrowings under up to a new $400 million credit facility consisting of up to a $175 million term loan facility and up to a $250 million revolving credit facility;
	•	the distribution to Duke Energy Field Services of a portion of the net proceeds from this offering and from borrowings under the new credit facility;
	•	the retention by Duke Energy Field Services of DCP Midstream Partners Predecessor’s accounts receivable and a 5% interest in the Black Lake Pipe Line Company; and
	•	the execution of a transportation agreement related to the Seabreeze pipeline between DCP Midstream Partners, LP and Duke Energy Field Services.

	(a)	Reflects the proceeds to DCP Midstream Partners, LP of $180.0 million from the issuance and sale of 9.0 million common units at an initial public offering price of $20.00 per unit.

	(b)	Reflects the payment of estimated underwriting commissions of $11.7 million, which will be allocated to the public common units.

	(c)	Reflects the payment of $4.3 million for the estimated costs associated with the offering, which will be allocated to the public common units.

	(d)	Reflects $110.0 million of borrowings under the new revolving credit facility.

	(e)	Reflects $61.0 million of borrowings under the new term loan facility.

	(f)	Reflects the purchase of United States Treasury and other qualifying securities using a portion of the proceeds from the offering. These are pledged as collateral for the borrowings under the term loan portion of our credit facility.

	(g)	Reflects estimated deferred issuance costs associated with the new $400 million credit facility.
	(h)	Reflects the distribution to Duke Energy Field Services of a portion of the net proceeds from the offering and borrowings under the new $400 million credit facility.

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	(i)	Reflects the retention by Duke Energy Field Services of DCP Midstream Partners Predecessor’s accounts receivable in the amount of $94.6 million and a 5% interest in the Black Lake Pipe Line Company with a carrying amount of $0.6 million.

	(j)	Reflects the conversion of the adjusted net parent investment of DCP Midstream Partners Predecessor of $(60.4) million from net parent investment to common and subordinated limited partner equity of DCP Midstream Partners, LP and the general partner’s interest in DCP Midstream Partners, LP. The conversion is allocated as follows:

	•     $(9.3) million for 1,357,143 common units
	•     $(48.7) million for 7,142,857 subordinated units
	•     $(2.4) million for 357,143 general partner units

		After the conversion, the equity amounts of the common and subordinated unitholders are 58% and 40%, respectively, of total equity, with the remaining 2% equity representing the general partner interest.
	(k)	Reflects the terms of a new agreement between Duke Energy Field Services and DCP Midstream Partners, LP in which Duke Energy Field Services will purchase the NGLs that were historically purchased by DCP Midstream Partners Predecessor and transported on the Seabreeze pipeline, and Duke Energy Field Services will pay DCP Midstream Partners, LP to transport the NGLs on the Seabreeze pipeline pursuant to a fee-based rate that will be applied to the volumes transported. This fee-based contractual arrangement will result in approximately the same operating income that would be realized when DCP Midstream Partners Predecessor was the purchaser and seller of the NGLs.
	(l)	Reflects on a net basis the interest expense related to the borrowings described in (d) and (e) above and the interest income related to the long-term investments described in (f) above. The interest expense is based on an average interest rate of 2.4% and 3.8% for the year ended December 31, 2004 and the nine months ended September 2005 which reflects the LIBOR interest rates during those periods. An increase in interest rates of 1% would have increased net interest expense by $1.1 million for 2004 and $0.8 million for the nine months ended September 2005.
	(m)	Reflects the retention by Duke Energy Field Services of a 5% interest in the Black Lake Pipe Line Company.

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					December 31,
													September 30,
					2003				2004				2005
ASSETS
Current assets:
	Accounts receivable:
		Trade, net of allowance for doubtful accounts of $0.2 million, $0.1 million and $0.2 million, respectively			$	39.4			$	59.0			$	93.5
		Affiliates				5.8				1.9				1.1
		Imbalances				—				0.1				—
	Unrealized gains on non-trading derivative and hedging transactions — affiliate					0.5				—				—
	Other					—				0.1				—
			Total current assets			45.7				61.1				94.6
Property, plant and equipment, net						181.9				172.0				168.8
Intangible asset, net						2.3				2.2				2.2
Equity method investment						9.6				5.8				6.3
Unrealized gains on non-trading derivative and hedging transactions — affiliate						—				—				6.5
			Total assets		$	239.5			$	241.1			$	278.4
LIABILITIES AND NET PARENT EQUITY
Current liabilities:
	Accounts payable:
		Trade			$	34.2			$	35.2			$	49.8
		Affiliates				0.4				3.2				2.0
		Imbalances				0.9				1.4				2.1
	Unrealized losses on non-trading derivative and hedging transactions — affiliate					—				0.1				3.6
	Other					2.8				2.7				3.9
			Total current liabilities			38.3				42.6				61.4
Unrealized losses on non-trading derivative and hedging transactions — affiliate						—				—				2.5
Other long-term liabilities						0.1				0.1				0.3
Commitments and contingent liabilities
Net parent equity						201.1				198.4				214.2
			Total liabilities and net parent equity		$	239.5			$	241.1			$	278.4

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																Nine Months
																Ended
				Year Ended December 31,												September 30,
				2002				2003				2004				2004				2005
												(unaudited)
Operating revenues:
	Sales of natural gas, NGLs and condensate			$	122.9			$	319.3			$	412.7			$	294.4			$	441.1
	Sales of natural gas, NGLs and condensate to affiliates				160.3				134.7				77.0				60.0				53.1
	Transportation and processing services				7.3				9.5				9.5				6.8				8.4
	Transportation and processing services to affiliates				7.0				9.1				10.4				8.2				8.3
	(Losses) and gains from non-trading derivative activity — affiliate				(0.3	)			2.5				(0.1	)			(0.1	)			—
		Total operating revenues			297.2				475.1				509.5				369.3				510.9
Costs and expenses:
	Purchases of natural gas and NGLs				169.8				309.3				404.1				287.6				410.6
	Purchases of natural gas and NGLs from affiliates				87.0				121.3				48.5				39.9				53.8
	Operating and maintenance expense				14.0				15.0				13.6				9.7				11.5
	Depreciation and amortization expense				12.3				12.8				12.6				9.4				8.8
	General and administrative expense — affiliate				6.1				7.1				6.5				4.8				8.2
		Total costs and expenses			289.2				465.5				485.3				351.4				492.9
Operating income					8.0				9.6				24.2				17.9				18.0
Earnings from equity method investment					0.5				0.4				0.6				0.4				0.4
Impairment of equity method investment					—				—				(4.4	)			(4.4	)			—
Net income				$	8.5			$	10.0			$	20.4			$	13.9			$	18.4

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																Nine Months
																Ended
				Years Ended December 31,												September 30,
				2002				2003				2004				2004				2005
												(unaudited)
Net income				$	8.5			$	10.0			$	20.4			$	13.9			$	18.4
Other comprehensive income:
	Net unrealized gains on cash flow hedges				—				—				—				—				0.4
		Total other comprehensive income			—				—				—				—				0.4
Total comprehensive income				$	8.5			$	10.0			$	20.4			$	13.9			$	18.8

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		Accumulated
		Other
		Comprehensive				Net Parent				Net Parent
		Income				Investment				Equity
Balance, January 1, 2002		$	—			$	211.1			$	211.1
Net change in parent advances			—				1.1				1.1
Net income			—				8.5				8.5
Balance, December 31, 2002			—				220.7				220.7
Net change in parent advances			—				(29.6	)			(29.6	)
Net income			—				10.0				10.0
Balance, December 31, 2003			—				201.1				201.1
Net change in parent advances			—				(23.1	)			(23.1	)
Net income			—				20.4				20.4
Balance, December 31, 2004			—				198.4				198.4
Net change in parent advances			—				(3.0	)			(3.0	)
Other comprehensive income			0.4				—				0.4
Net income			—				18.4				18.4
Balance, September 30, 2005		$	0.4			$	213.8			$	214.2

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																Nine Months
																Ended
				Year Ended December 31,												September 30,
				2002				2003				2004				2004				2005
												(unaudited)
OPERATING ACTIVITIES:
Net income				$	8.5			$	10.0			$	20.4			$	13.9			$	18.4
Adjustments to reconcile net income to net cash provided by operating activities:
	Depreciation and amortization expense and impairment charge				12.3				12.8				17.0				13.8				8.8
	Other, net				—				0.2				(0.6	)			(0.4	)			(0.5	)
Change in operating assets and liabilities which provided (used) cash:
	Accounts receivable				(10.9	)			(2.1	)			(15.7	)			2.6				(33.7	)
	Net unrealized (gains) losses on non-trading derivative and hedging transactions				—				(0.5	)			0.6				0.3				(0.1	)
	Accounts payable				10.8				9.2				3.8				(4.8	)			14.1
	Other				0.6				1.2				0.1				0.9				0.7
		Net cash provided by operating activities			21.3				30.8				25.6				26.3				7.7
INVESTING ACTIVITIES:
	Capital expenditures				(22.7	)			(2.7	)			(3.1	)			(0.7	)			(5.3	)
	Proceeds from sales of assets				0.3				1.5				0.6				0.4				0.6
		Net cash used in investing activities			(22.4	)			(1.2	)			(2.5	)			(0.3	)			(4.7	)
FINANCING ACTIVITIES:
	Net change in parent advances				1.1				(29.6	)			(23.1	)			(26.0	)			(3.0	)
		Net cash provided by (used in) financing activities			1.1				(29.6	)			(23.1	)			(26.0	)			(3.0	)
Net change in cash					—				—				—				—				—
Cash, beginning of period					—				—				—				—				—
	Cash, end of period			$	—			$	—			$	—			$	—			$	—

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Classification of Contract		Accounting Method				Presentation of Gains & Losses or Revenue & Expense
Non-Trading Derivative Activity			Mark-to-market  (a)			Net basis in Gains and losses from non-trading derivative activity
Cash Flow Hedge			Hedge method (b)			Gross basis in the same income statement category as the related hedged item
Fair Value Hedge			Hedge method (b)			Gross basis in the same income statement category as the related hedged item
Normal Purchases or Normal Sales			Accrual method  (c)			Gross basis upon settlement in the corresponding income statement category based on purchase or sale

(a)	Mark-to-market — An accounting method whereby the change in the fair value of the asset or liability is recognized in the results of operations in Gains and losses from non-trading derivative activity during the current period.

(b)	Hedge method — An accounting method whereby the effective portion of the change in the fair value of the asset or liability is recorded as a balance sheet adjustment and there is no recognition in the results of operations for the effective portion until the service is provided or the associated delivery period occurs.

(c)	Accrual method — An accounting method whereby there is no recognition in the results of operations for changes in fair value of a contract until the service is provided or the associated delivery period occurs.

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	•	significant adverse change in legal factors or in the business climate;
	•	a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;
	•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
	•	significant adverse changes in the extent or manner in which an asset is used or in its physical condition;
	•	a significant change in the market value of an asset; or
	•	a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

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	•	sales of natural gas, NGLs and condensate;
	•	natural gas gathering, processing and transportation, from which DCP Midstream Partners Predecessor generates revenues primarily through the compression, gathering, treating, processing and transportation of natural gas; and
	•	NGL transportation from which we generate revenues from transportation fees.

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			For the Years Ended												For the Nine Months
			December 31,												Ended September 30,
			2002				2003				2004				2004				2005
															(unaudited)
Duke Energy Field Services:
	Sales of natural gas, NGLs and condensate		$	16.8			$	50.0			$	63.0			$	45.9			$	46.4
	Purchases of natural gas and NGLs		$	27.8			$	87.8			$	26.7			$	26.7			$	30.8
	General and administrative expense		$	6.1			$	7.1			$	6.5			$	4.8			$	8.2
Duke Energy:
	Sales of natural gas, NGLs and condensate		$	143.5			$	81.1			$	10.3			$	10.3			$	—
	Transportation and processing services		$	1.1			$	0.7			$	0.5			$	0.5			$	0.4
	Purchases of natural gas and NGLs		$	—			$	1.6			$	3.4			$	3.4			$	10.1
ConocoPhillips:
	Sales of natural gas, NGLs and condensate		$	—			$	3.6			$	3.7			$	3.8			$	6.7
	Transportation and processing services		$	5.9			$	8.4			$	9.9			$	7.7			$	7.9
	Purchases of natural gas and NGLs		$	59.2			$	31.9			$	18.4			$	9.8			$	12.9

			December 31,
											September 30,
			2003				2004				2005
Duke Energy Field Services:
	Accounts receivable		$	0.6			$	0.7			$	—
Duke Energy:
	Accounts receivable		$	3.8			$	—			$	—
	Accounts payable		$	0.4			$	—			$	—
ConocoPhillips:
	Accounts receivable		$	1.4			$	1.2			$	1.1
	Accounts payable		$	—			$	3.2			$	2.0

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5.	Property, Plant and Equipment

							December 31,
			Depreciable												September 30,
			Life				2003				2004				2005
Gathering systems				15 – 30  years			$	91.2			$	92.9			$	95.9
Processing plants				25 – 30  years				53.9				53.7				53.4
Transportation				25 – 30  years				126.9				127.2				127.2
General plant				3 – 5  years				2.7				2.7				2.5
Construction work in progress								2.4				3.1				6.0
	Property, plant and equipment							277.1				279.6				285.0
Accumulated depreciation								(95.2	)			(107.6	)			(116.2	)
	Property, plant and equipment, net						$	181.9			$	172.0			$	168.8

6.	Intangible Asset

			December 31,
											September 30,
			2003				2004				2005
Intangible asset			$	2.5			$	2.5			$	2.5
Accumulated amortization				(0.2	)			(0.3	)			(0.3	)
	Intangible asset, net		$	2.3			$	2.2			$	2.2

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			December 31,				September 30,
			2004				2005
2005			$	0.1			$	0.1
2006				0.1				0.1
2007				0.1				0.1
2008				0.1				0.1
2009				0.1				0.1
Thereafter				1.7				1.7
	Total		$	2.2			$	2.2

7.	Equity Method Investment

						December 31,
														September 30,
		Ownership				2003				2004				2005
Black Lake Pipe Line Company			50.0	%		$	9.6			$	5.8			$	6.3

		December 31,												September 30,
		2002				2003				2004				2004				2005
														(unaudited)
Black Lake Pipe Line Company		$	0.5			$	0.4			$	0.6			$	0.4			$	0.4

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				December 31,												September 30,
				2002				2003				2004				2004				2005
																(unaudited)
Income statement:
	Operating revenues			$	3.5			$	3.2			$	3.2			$	2.4			$	2.5
	Operating expenses			$	2.9			$	2.9			$	2.4			$	1.8			$	2.2
	Net income			$	0.6			$	0.3			$	0.8			$	0.6			$	0.3
Balance sheet:
	Current assets							$	3.1			$	4.3							$	5.2
	Noncurrent assets								18.6				18.0								17.5
	Current liabilities								0.4				0.2								0.3
		Net assets						$	21.3			$	22.1							$	22.4

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

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9.	Estimated Fair Value of Financial Instruments

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10.	Commitments and Contingent Liabilities

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11.	Business Segments

		Natural Gas				NGL
		Services				Logistics				Other(b)				Total
Total operating revenues		$	259.4			$	37.8			$	—			$	297.2
Gross margin (a)		$	39.1			$	1.3			$	—			$	40.4
Operating and maintenance expense			13.7				0.3				—				14.0
Depreciation and amortization expense			11.8				0.5				—				12.3
General and administrative expense — affiliate			—				—				6.1				6.1
Earnings from equity method investment			—				0.5				—				0.5
Net income		$	13.6			$	1.0			$	(6.1	)		$	8.5
Capital expenditures		$	12.7			$	10.0			$	—			$	22.7

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		Natural Gas				NGL
		Services				Logistics				Other(b)				Total
Total operating revenues		$	343.7			$	131.4			$	—			$	475.1
Gross margin (a)		$	42.2			$	2.3			$	—			$	44.5
Operating and maintenance expense			14.7				0.3				—				15.0
Depreciation and amortization expense			11.9				0.9				—				12.8
General and administrative expense — affiliate			—				—				7.1				7.1
Earnings from equity method investment			—				0.4				—				0.4
Net income		$	15.6			$	1.5			$	(7.1	)		$	10.0
Capital expenditures		$	2.4			$	0.3			$	—			$	2.7

		Natural Gas				NGL
		Services				Logistics				Other(b)				Total
Total operating revenues		$	353.3			$	156.2			$	—			$	509.5
Gross margin (a)		$	53.6			$	3.3			$	—			$	56.9
Operating and maintenance expense			13.4				0.2				—				13.6
Depreciation and amortization expense			11.7				0.9				—				12.6
General and administrative expense — affiliate			—				—				6.5				6.5
Earnings from equity method investment, net of impairment			—				(3.8	)			—				(3.8	)
Net income (loss)		$	28.5			$	(1.6	)		$	(6.5	)		$	20.4
Capital expenditures		$	2.8			$	0.3			$	—			$	3.1

		Natural Gas				NGL
		Services				Logistics				Other(b)				Total
		(unaudited)
Total operating revenues		$	258.9			$	110.4			$	—			$	369.3
Gross margin (a)		$	39.3			$	2.5			$	—			$	41.8
Operating and maintenance expense			9.5				0.2				—				9.7
Depreciation and amortization expense			8.7				0.7				—				9.4
General and administrative expense — affiliate			—				—				4.8				4.8
Earnings from equity method investment, net of impairment			—				(4.0	)			—				(4.0	)
Net income		$	21.1			$	(2.4	)		$	(4.8	)		$	13.9
Capital expenditures		$	0.8			$	—			$	—			$	0.8

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		Natural Gas				NGL
		Services				Logistics				Other(b)				Total
Total operating revenues		$	367.7			$	143.2			$	—			$	510.9
Gross margin (a)		$	43.8			$	2.7			$	—			$	46.5
Operating and maintenance expense			11.3				0.2				—				11.5
Depreciation and amortization expense			8.3				0.5				—				8.8
General and administrative expense — affiliate			—				—				8.2				8.2
Earnings from equity method investment			—				0.4				—				0.4
Net income		$	24.2			$	2.4			$	(8.2	)		$	18.4
Capital expenditures		$	5.3			$	—			$	—			$	5.3

				December 31,
												September 30,
				2003				2004				2005
Segment Long-term assets:
	Natural Gas Services			$	164.3			$	154.9			$	158.9
	NGL Logistics				29.5				25.1				24.9
		Total Long-Term assets			193.8				180.0				183.8
Current assets					45.7				61.1				94.6
Total assets				$	239.5			$	241.1			$	278.4

(a)		Gross margin consists of Total operating revenues less Purchases of natural gas and NGLs. Gross margin is viewed as a non-Generally Accepted Accounting Principles (“GAAP”) measure under the rules of the Securities and Exchange Commission (“SEC”), but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of DCP Midstream Partners Predecessor’s operating performance, Gross margin should not be considered an alternative to, or more meaningful than, Net income or cash flow as determined in accordance with GAAP. DCP Midstream Partners Predecessor’s Gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.
(b)		Other consists of General and administrative expense allocations from Duke Energy Field Services.

12.	New Accounting Standards

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ASSETS
Current assets:
	Cash			$	2,000
		Total assets		$	2,000
PARTNERS’ EQUITY
	Limited partners’ equity				1,960
	General partner’s equity				40
		Total partners’ equity		$	2,000

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1.	Nature of Operations

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ASSETS
Current assets:
	Cash			$	960
	Investment in DCP Midstream Partners, LP				40
		Total assets		$	1,000
OWNER’S EQUITY
	Owner’s equity				1,000
		Total owner’s equity		$	1,000

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1.	Nature of Operations

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				Page
Section 1.1		Definitions			A-1
Section 1.2		Construction			A-15
ARTICLE II Organization
Section 2.1		Formation			A-15
Section 2.2		Name			A-15
Section 2.3		Registered Office; Registered Agent; Principal Office; Other Offices			A-16
Section 2.4		Purpose and Business			A-16
Section 2.5		Powers			A-16
Section 2.6		Power of Attorney			A-16
Section 2.7		Term			A-17
Section 2.8		Title to Partnership Assets			A-17
ARTICLE III Rights of Limited Partners
Section 3.1		Limitation of Liability			A-18
Section 3.2		Management of Business			A-18
Section 3.3		Outside Activities of the Limited Partners			A-18
Section 3.4		Rights of Limited Partners			A-18
ARTICLE IV Certificates; Record Holders; Transfer of Partnership Interests; Redemption of Partnership Interests
Section 4.1		Certificates			A-19
Section 4.2		Mutilated, Destroyed, Lost or Stolen Certificates			A-19
Section 4.3		Record Holders			A-20
Section 4.4		Transfer Generally			A-20
Section 4.5		Registration and Transfer of Limited Partner Interests			A-21
Section 4.6		Transfer of the General Partner’s General Partner Interest			A-21
Section 4.7		Transfer of Incentive Distribution Rights			A-22
Section 4.8		Restrictions on Transfers			A-22
Section 4.9		Citizenship Certificates; Non-citizen Assignees			A-23
Section 4.10		Redemption of Partnership Interests of Non-citizen Assignees			A-24
ARTICLE V Capital Contributions and Issuance of Partnership Interests
Section 5.1		Organizational Contributions			A-25
Section 5.2		Contributions by the General Partner and its Affiliates			A-25
Section 5.3		Contributions by Initial Limited Partners			A-25
Section 5.4		Interest and Withdrawal			A-26
Section 5.5		Capital Accounts			A-26
Section 5.6		Issuances of Additional Partnership Securities			A-28
Section 5.7		Conversion of Subordinated Units			A-29

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Section 5.8		Limited Preemptive Right			A-30
Section 5.9		Splits and Combinations			A-30
Section 5.10		Fully Paid and Non-Assessable Nature of Limited Partner Interests			A-31
Section 5.11		Issuance of Class B Units in Connection with Reset of Incentive Distribution Rights			A-31
ARTICLE VI Allocations and Distributions
Section 6.1		Allocations for Capital Account Purposes			A-32
Section 6.2		Allocations for Tax Purposes			A-38
Section 6.3		Requirement and Characterization of Distributions; Distributions to Record Holders			A-40
Section 6.4		Distributions of Available Cash from Operating Surplus			A-40
Section 6.5		Distributions of Available Cash from Capital Surplus			A-42
Section 6.6		Adjustment of Minimum Quarterly Distribution and Target Distribution Levels			A-42
Section 6.7		Special Provisions Relating to the Holders of Subordinated Units and Class B Units			A-42
Section 6.8		Special Provisions Relating to the Holders of Incentive Distribution Rights			A-43
Section 6.9		Entity-Level Taxation			A-44
ARTICLE VII Management and Operation of Business
Section 7.1		Management			A-44
Section 7.2		Certificate of Limited Partnership			A-46
Section 7.3		Restrictions on the General Partner’s Authority			A-46
Section 7.4		Reimbursement of the General Partner			A-46
Section 7.5		Outside Activities			A-47
Section 7.6		Loans from the General Partner; Loans or Contributions from the Partnership or Group Members			A-48
Section 7.7		Indemnification			A-48
Section 7.8		Liability of Indemnitees			A-49
Section 7.9		Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties			A-50
Section 7.10		Other Matters Concerning the General Partner			A-51
Section 7.11		Purchase or Sale of Partnership Securities			A-52
Section 7.12		Registration Rights of the General Partner and its Affiliates			A-52
Section 7.13		Reliance by Third Parties			A-54
ARTICLE VIII Books, Records, Accounting and Reports
Section 8.1		Records and Accounting			A-55
Section 8.2		Fiscal Year			A-55
Section 8.3		Reports			A-55
ARTICLE IX Tax Matters
Section 9.1		Tax Returns and Information			A-56
Section 9.2		Tax Elections			A-56
Section 9.3		Tax Controversies			A-56
Section 9.4		Withholding			A-56

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ARTICLE X Admission of Partners
Section 10.1		Admission of Limited Partners			A-56
Section 10.2		Admission of Successor General Partner			A-57
Section 10.3		Amendment of Agreement and Certificate of Limited Partnership			A-57
ARTICLE XI Withdrawal or Removal of Partners
Section 11.1		Withdrawal of the General Partner			A-58
Section 11.2		Removal of the General Partner			A-59
Section 11.3		Interest of Departing General Partner and Successor General Partner			A-59
Section 11.4		Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages			A-60
Section 11.5		Withdrawal of Limited Partners			A-61
ARTICLE XII Dissolution and Liquidation
Section 12.1		Dissolution			A-61
Section 12.2		Continuation of the Business of the Partnership After Dissolution			A-61
Section 12.3		Liquidator			A-62
Section 12.4		Liquidation			A-62
Section 12.5		Cancellation of Certificate of Limited Partnership			A-63
Section 12.6		Return of Contributions			A-63
Section 12.7		Waiver of Partition			A-63
Section 12.8		Capital Account Restoration			A-63
ARTICLE XIII Amendment of Partnership Agreement; Meetings; Record Date
Section 13.1		Amendments to be Adopted Solely by the General Partner			A-63
Section 13.2		Amendment Procedures			A-64
Section 13.3		Amendment Requirements			A-65
Section 13.4		Special Meetings			A-65
Section 13.5		Notice of a Meeting			A-65
Section 13.6		Record Date			A-66
Section 13.7		Adjournment			A-66
Section 13.8		Waiver of Notice; Approval of Meeting; Approval of Minutes			A-66
Section 13.9		Quorum and Voting			A-66
Section 13.10		Conduct of a Meeting			A-67
Section 13.11		Action Without a Meeting			A-67
Section 13.12		Right to Vote and Related Matters			A-67
ARTICLE XIV Merger, Consolidation or Conversion
Section 14.1		Authority			A-68
Section 14.2		Procedure for Merger, Consolidation or Conversion			A-68
Section 14.3		Approval by Limited Partners			A-69
Section 14.4		Certificate of Merger			A-70
Section 14.5		Effect of Merger, Consolidation or Conversion			A-70

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ARTICLE XV Right to Acquire Limited Partner Interests
Section 15.1		Right to Acquire Limited Partner Interests			A-71
ARTICLE XVI General Provisions
Section 16.1		Addresses and Notices			A-72
Section 16.2		Further Action			A-73
Section 16.3		Binding Effect			A-73
Section 16.4		Integration			A-73
Section 16.5		Creditors			A-73
Section 16.6		Waiver			A-73
Section 16.7		Third-Party Beneficiaries			A-73
Section 16.8		Counterparts			A-73
Section 16.9		Applicable Law			A-74
Section 16.10		Invalidity of Provisions			A-74
Section 16.11		Consent of Partners			A-74
Section 16.12		Facsimile Signatures			A-74

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	(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.
	(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided,that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

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	(a) the sum of (i) all cash and cash equivalents of the Partnership Group on hand at the end of such Quarter, and (ii) if the General Partner so determines, all or any portion of any additional cash and cash equivalents of the Partnership Group on hand on the date of determination of Available Cash with respect to such Quarter, less
	(b) the amount of any cash reserves established by the General Partner to (i) provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership Group) subsequent to such Quarter, (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject or (iii) provide funds for distributions under Section 6.4 or 6.5 in respect of any one or more of the next four Quarters; provided, however, that the General Partner may not establish cash reserves pursuant to (iii) above if the effect of such reserves would be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units, plus any Cumulative Common Unit Arrearage on all Common Units, with respect to such Quarter; and, provided further, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

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	(a) payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness shall not constitute Operating Expenditures; and
	(b) Operating Expenditures shall not include (i) Expansion Capital Expenditures, (ii) payment of transaction expenses (including taxes) relating to Interim Capital Transactions or (iii) distributions to Partners. Where capital expenditures consist of both Maintenance Capital Expenditures and Expansion Capital Expenditures, the General Partner, with the concurrence of the Conflicts Committee, shall determine the allocation between the portion consisting of Maintenance Capital Expenditures and the portion consisting of Expansion Capital Expenditures and, with respect to the part of such capital expenditures consisting of Maintenance Capital Expenditures, the period over which the capital expenditures made for other purposes will be deducted as an Operating Expenditure in calculating Operating Surplus.

	(a) the sum of (i) an amount equal to four times the amount needed for any one Quarter for the Partnership to pay a distribution on all Units, the General Partner Units and the Incentive Distribution Rights at the same per Unit amount as was distributed immediately preceding the date of determination, and (ii) all cash receipts of the Partnership Group for the period beginning on the Closing Date and ending on the last day of such period, but excluding cash receipts from Interim Capital Transactions (except to the extent specified in Section 6.5) (or with respect to the period commencing on the Closing Date and ending on December 31, 2005, it means the product of (i) $1.40 multiplied by (ii) a fraction of which the numerator is the number of days in such period and the denominator is 92 multiplied by (iii) the number of Units and General Partner Units Outstanding on the Record Date with respect to such period), less
	(b) the sum of (i) Operating Expenditures for the period beginning on the Closing Date and ending on the last day of such period and (ii) the amount of cash reserves established by the General Partner to provide funds for future Operating Expenditures; provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.

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(a) the first day of any Quarter beginning after December 31, 2010 in respect of which (i) (A) distributions of Available Cash from Operating Surplus on each of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units and the General Partner Units with respect to each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units and the General Partner Units during such periods and (B) the Adjusted Operating Surplus for each of the three consecutive, non-overlapping four-Quarter periods immediately preceding

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	such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such periods on a Fully Diluted Basis, plus the related distribution on the General Partner Units, with respect to each such period and (ii) there are no Cumulative Common Unit Arrearages;
	(b) the first date on which there are no longer outstanding any Subordinated Units due to the conversion of Subordinated Units into Common Units pursuant to Section 5.7 or otherwise; and
	(c) the date on which the General Partner is removed as general partner of the Partnership upon the requisite vote by holders of Outstanding Units under circumstances where Cause does not exist and Units held by the General Partner and its Affiliates are not voted in favor of such removal.

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(i) execute, swear to, acknowledge, deliver, file and record in the appropriate public offices (A) all certificates, documents and other instruments (including this Agreement and the Certificate of Limited Partnership and all amendments or restatements hereof or thereof) that the General Partner or the Liquidator determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Partnership as a limited partnership (or a partnership in which the limited partners

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	have limited liability) in the State of Delaware and in all other jurisdictions in which the Partnership may conduct business or own property; (B) all certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement; (C) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the General Partner or the Liquidator determines to be necessary or appropriate to reflect the dissolution and liquidation of the Partnership pursuant to the terms of this Agreement; (D) all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Partner pursuant to, or other events described in, Article IV, Article X, Article XI or Article XII; (E) all certificates, documents and other instruments relating to the determination of the rights, preferences and privileges of any class or series of Partnership Securities issued pursuant to Section 5.6; and (F) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Partnership pursuant to Article XIV; and
	(ii) execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to (A) make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Partners hereunder or is consistent with the terms of this Agreement or (B) effectuate the terms or intent of this Agreement; provided, that when required by Section 13.3 or any other provision of this Agreement that establishes a percentage of the Limited Partners or of the Limited Partners of any class or series required to take any action, the General Partner and the Liquidator may exercise the power of attorney made in this Section 2.6(a)(ii) only after the necessary vote, consent or approval of the Limited Partners or of the Limited Partners of such class or series, as applicable.

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	(i) to obtain true and full information regarding the status of the business and financial condition of the Partnership;
	(ii) promptly after its becoming available, to obtain a copy of the Partnership’s federal, state and local income tax returns for each year;
	(iii) to obtain a current list of the name and last known business, residence or mailing address of each Partner;

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	(iv) to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed;
	(v) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Partner and that each Partner has agreed to contribute in the future, and the date on which each became a Partner; and
	(vi) to obtain such other information regarding the affairs of the Partnership as is just and reasonable.

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	(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;
	(ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;
	(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and
	(iv) satisfies any other reasonable requirements imposed by the General Partner.

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THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF DCP MIDSTREAM PARTNERS, LP THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF DCP MIDSTREAM PARTNERS, LP UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE DCP MIDSTREAM PARTNERS, LP TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). DCP MIDSTREAM GP LLC, THE GENERAL PARTNER OF DCP MIDSTREAM PARTNERS, LP, MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF DCP MIDSTREAM PARTNERS, LP BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

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	(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Limited Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.
	(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 5% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.
	(iii) Upon surrender by or on behalf of the Limited Partner, at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, the Limited Partner or his duly authorized representative shall be entitled to receive the payment therefor.
	(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

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(i) Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement or governing, organizational or similar documents) of all property owned by any other Group Member that is classified as a partnership for federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for federal income tax purposes of which a Group Member is, directly or indirectly, a partner.

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	(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.
	(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss and deduction shall be made without regard to any election under Section 754 of the Code which may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.
	(iv) Any income, gain or loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.
	(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery or amortization attributable to such property shall be determined (A) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment and (B) using a rate of depreciation, cost recovery or amortization derived from the same method and useful life (or, if applicable, the remaining useful life) as is applied for federal income tax purposes; provided, however, that, if the asset has a zero adjusted basis for federal income tax purposes, depreciation, cost recovery or amortization deductions shall be determined using any method that the General Partner may adopt.
	(vi) If the Partnership’s adjusted basis in a depreciable or cost recovery property is reduced for federal income tax purposes pursuant to Section 48(q)(1) or 48(q)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Partners pursuant to Section 6.1. Any restoration of such basis pursuant to Section 48(q)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Partners to whom such deemed deduction was allocated.

(ii) Subject to Section 6.7(c), immediately prior to the transfer of a Subordinated Unit or of a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this subparagraph 5.5(c)(ii) apply), the Capital Account maintained for such Person with respect to its Subordinated Units or converted Subordinated Units will (A) first, be allocated to the Subordinated Units or converted Subordinated Units to be transferred in an amount equal to the product of (x) the number of such Subordinated Units or converted Subordinated Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any Subordinated Units or converted Subordinated Units (“Retained Converted Subordinated Units”). Following any such allocation, the transferor’s Capital Account, if any, maintained with respect to the retained Subordinated Units or Retained Converted Subordinated Units, if any, will have a balance equal to the amount allocated under clause (B) hereinabove, and the transferee’s Capital Account established with respect to the transferred

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	Subordinated Units or converted Subordinated Units will have a balance equal to the amount allocated under clause (A) hereinabove.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1 in the same manner as any item of gain or loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

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	(i) distributions of Available Cash from Operating Surplus under Section 6.4(a) on each of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units and the General Partner Units with respect to each of the two consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units and the General Partner Units during such periods;
	(ii) the Adjusted Operating Surplus for each of the two consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such periods on a Fully Diluted Basis and the General Partner Units, with respect to such periods; and
	(iii) there are no Cumulative Common Unit Arrearages.

	(i) distributions of Available Cash from Operating Surplus under Section 6.4(a) on each of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units and the General Partner Units with respect to each of the two consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded 125% of the sum of the Minimum Quarterly Distribution on all of the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units and the General Partner Units during such periods;
	(ii) the Adjusted Operating Surplus for each of the two consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded 125% of the sum of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such periods on a Fully Diluted Basis and the General Partner Units, with respect to such periods; and

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	(iii) there are no Cumulative Common Unit Arrearages;

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	(i) First, 100% to the General Partner, in an amount equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(iii) for all previous taxable years until the aggregate Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(iii) for all previous taxable years;
	(ii) Second, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests, until the aggregate Net Income allocated to such Partners pursuant to this Section 6.1(a)(ii) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to such Partners pursuant to Section 6.1(b)(ii) for all previous taxable years; and
	(iii) Third, the balance, if any, 100% to the General Partner and to the Unitholders, in accordance with their respective Percentage Interests.

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	(i) First, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests, until the aggregate Net Losses allocated pursuant to this Section 6.1(b)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Income allocated to such Partners pursuant to Section 6.1(a)(iii) for all previous taxable years, provided that the Net Losses shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account);
	(ii) Second, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests; provided, that Net Losses shall not be allocated pursuant to this Section 6.1(b)(ii) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account); and
	(iii) Third, the balance, if any, 100% to the General Partner.

(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

	(A) First, to each Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;
	(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (B), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(i) or Section 6.4(b)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter defined as the “Unpaid MQD”) and (3) any then existing Cumulative Common Unit Arrearage;
	(C) Third, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Class B Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Class B Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (C), until the Capital Account in respect of each Class B Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, and (2) the Minimum Quarterly Distribution for the Quarter during which the

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	Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(b)(i) with respect to such Class B Unit for such Quarter;
	(D) Fourth, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (D), until the Capital Account in respect of each Subordinated Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, determined for the taxable year (or portion thereof) to which this allocation of gain relates, and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(iii) with respect to such Subordinated Unit for such Quarter;
	(E) Fifth, 100% to the General Partner and all Unitholders in accordance with their respective Percentage Interests, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Unpaid MQD, (3) any then existing Cumulative Common Unit Arrearage, and (4) the excess of (aa) the First Target Distribution less the Minimum Quarterly Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(iv) and Section 6.4(b)(ii) (the sum of (1), (2), (3) and (4) is hereinafter defined as the “First Liquidation Target Amount”);
	(F) Sixth, (x) to the General Partner in accordance with its Percentage Interest, (y) 13% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (x) and (y) of this clause (F), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the First Liquidation Target Amount, and (2) the excess of (aa) the Second Target Distribution less the First Target Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(v) and Section 6.4(b)(iii) (the sum of (1) and (2) is hereinafter defined as the “Second Liquidation Target Amount”);
	(G) Seventh, (x) to the General Partner in accordance with its Percentage Interest, (y) 23% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (x) and (y) of this clause (G), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the Second Liquidation Target Amount, and (2) the excess of (aa) the Third Target Distribution less the Second Target Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(vi) and Section 6.4(b)(iv) (the sum of (1) and (2) is hereinafter defined as the “Third Liquidation Target Amount”); and
	(H) Finally, (x) to the General Partner in accordance with its Percentage Interest, (y) 48% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (x) and (y) of this clause (H).

	(ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Loss shall be allocated among the Partners in the following manner:

(A) First, if such Net Termination Loss is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (A), until the Capital Account in respect of each Subordinated Unit then Outstanding has been reduced to zero;

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	(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Class B Unitholders, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (B) until the Capital Account in respect of each Class B Unit then Outstanding has been reduced to zero;
	(C) Third, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (B) until the Capital Account in respect of each Unit then Outstanding has been reduced to zero; and
	(D) Fourth, the balance, if any, 100% to the General Partner.

	(d) Special Allocations.     Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

	(i) Partnership Minimum Gain Chargeback.     Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.
	(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain.     Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.
	(iii) Priority Allocations.

(A) If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) to any Unitholder with respect to its Units for a taxable year is greater (on a per Unit basis) than the amount of cash or the Net Agreed Value of property distributed to the other Unitholders with respect to their Units (on a per Unit basis), then (1) there shall be allocated income and gain to each Unitholder receiving such greater cash or property distribution until the aggregate amount of such items allocated pursuant to this Section 6.1(d)(iii)(A) for the current taxable year and all previous taxable years is equal to the product of (aa) the amount by which the distribution (on a per Unit basis) to such Unitholder exceeds the distribution (on a per Unit basis) to the Unitholders receiving the smallest distribution and (bb) the number of Units owned by the Unitholder receiving the greater distribution; and (2) the General Partner shall be allocated income and gain in an aggregate amount equal to the product obtained by multiplying (aa) the quotient determined by

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	dividing (x) the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs by (y) the sum of 100 less the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs times (bb) the sum of the amounts allocated in clause (1) above.
	(B) After the application of Section 6.1(d)(iii)(A), all or any portion of the remaining items of Partnership income or gain for the taxable period, if any, shall be allocated (1) to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this Section 6.1(d)(iii)(B) for the current taxable year and all previous taxable years is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the Closing Date to a date 45 days after the end of the current taxable year; and (2) to the General Partner an amount equal to the product of (aa) an amount equal to the quotient determined by dividing (x) the General Partner’s Percentage Interest by (y) the sum of 100 less the General Partner’s Percentage Interest times (bb) the sum of the amounts allocated in clause (1) above.

	(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii).
	(v) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any Partnership taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership income and gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(v) were not in this Agreement.
	(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners in accordance with their respective Percentage Interests. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.
	(vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.
	(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners in accordance with their respective Percentage Interests.

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	(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.
	(x) Economic Uniformity.

	(A) At the election of the General Partner with respect to any taxable period ending upon, or after, the termination of the Subordination Period, all or a portion of the remaining items of Partnership income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii), shall be allocated 100% to each Partner holding Subordinated Units that are Outstanding as of the termination of the Subordination Period (“Final Subordinated Units”) in the proportion of the number of Final Subordinated Units held by such Partner to the total number of Final Subordinated Units then Outstanding, until each such Partner has been allocated an amount of income or gain that increases the Capital Account maintained with respect to such Final Subordinated Units to an amount equal to the product of (A) the number of Final Subordinated Units held by such Partner and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Final Subordinated Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Final Subordinated Units into Common Units. This allocation method for establishing such economic uniformity will be available to the General Partner only if the method for allocating the Capital Account maintained with respect to the Subordinated Units between the transferred and retained Subordinated Units pursuant to Section 5.5(c)(ii) does not otherwise provide such economic uniformity to the Final Subordinated Units.
	(B) At the election of the General Partner with respect to any taxable period ending upon, or after, the conversion of the Class B Units pursuant to Section 5.11(f), all or a portion of the remaining items of Partnership income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii) and Section 6.1(d)(x)(A), shall be allocated 100% to the holder or holders of the Common Units resulting from the conversion pursuant to Section 5.11(f) (“Converted Common Units”) in the proportion of the number of the Converted Common Units held by such holder or holders to the total number of Converted Common Units then Outstanding, until each such holder has been allocated an amount of income or gain that increases the Capital Account maintained with respect to such Converted Common Units to an amount equal to the product of (A) the number of Converted Common Units held by such holder and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Converted Common Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the receipt of Common Units pursuant to Section 5.11(f).

	(xi) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1.

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Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(d)(xi)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.

	(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

	(xii) Corrective Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

	(A) In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof), the General Partner shall allocate additional items of income and gain away from the holders of Incentive Distribution Rights to the Unitholders and the General Partner, or additional items of deduction and loss away from the Unitholders and the General Partner to the holders of Incentive Distribution Rights, to the extent that the Additional Book Basis Derivative Items allocated to the Unitholders or the General Partner exceed their Share of Additional Book Basis Derivative Items. For this purpose, the Unitholders and the General Partner shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders or the General Partner under the Partnership Agreement (e.g., Additional Book Basis Derivative Items taken into account in computing cost of goods sold would reduce the amount of book income otherwise available for allocation among the Partners). Any allocation made pursuant to this Section 6.1(d)(xii)(A) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.
	(B) In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the aggregate Capital Accounts of the Partners will equal the amount that would have been the Capital Account balance of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.
	(C) In making the allocations required under this Section 6.1(d)(xii), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xii).

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	(i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Partners in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.
	(ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Partners in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Partners in a manner consistent with Section 6.2(b)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.
	(iii) The General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities[, except with respect to goodwill contributed to the Partnership upon formation.]

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	(i) First, to the General Partner and the Unitholders holding Common Units, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;
	(ii) Second, to the General Partner and the Unitholders holding Common Units, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage existing with respect to such Quarter;
	(iii) Third, to the General Partner and the Unitholders holding Subordinated Units, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Subordinated Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;
	(iv) Fourth, to the General Partner and all Unitholders, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;
	(v) Fifth, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v) until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;
	(vi) Sixth, (A) to the General Partner in accordance with its Percentage Interest, (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this subclause (vi), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and
	(vii) Thereafter, (A) to the General Partner in accordance with its Percentage Interest; (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (vii);

	(i) First, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;
	(ii) Second, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;
	(iii) Third, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage

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	equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (iii), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;
	(iv) Fourth, (A) to the General Partner in accordance with its Percentage Interest; (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (A) and (B) of this clause (iv), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and
	(v) Thereafter, (A) to the General Partner in accordance with its Percentage Interest; (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v);

	Section 6.5	Distributions of Available Cash from Capital Surplus.

	Section 6.6	Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.

	Section 6.7	Special Provisions Relating to the Holders of Subordinated Units and Class B Units.

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	Section 6.8	Special Provisions Relating to the Holders of Incentive Distribution Rights.

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	(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into Partnership Securities, and the incurring of any other obligations;
	(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;
	(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article XIV);
	(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;
	(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the

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	General Partner or its assets other than its interest in the Partnership, even if same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);
	(vi) the distribution of Partnership cash;
	(vii) the selection and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;
	(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;
	(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;
	(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;
	(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;
	(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.8);
	(xiii) the purchase, sale or other acquisition or disposition of Partnership Securities, or the issuance of options, rights, warrants and appreciation rights relating to Partnership Securities;
	(xiv) the undertaking of any action in connection with the Partnership’s participation in any Group Member; and
	(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

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	Section 7.9	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

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	Section 7.10	Other Matters Concerning the General Partner.

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	Section 7.12	Registration Rights of the General Partner and its Affiliates.

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	(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;
	(ii) The General Partner transfers all of its rights as General Partner pursuant to Section 4.6;
	(iii) The General Partner is removed pursuant to Section 11.2;
	(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;
	(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or
	(vi) (A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

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	(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and an Opinion of Counsel is received as provided in Section 11.1(b) or 11.2 and such successor is admitted to the Partnership pursuant to Section 10.3;
	(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;
	(c) the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act; or
	(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

	(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;
	(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and
	(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement; provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received

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an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

	(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.
	(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.
	(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the

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	taxable year of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

	(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;
	(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;
	(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;
	(d) a change that the General Partner determines, (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or

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	comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.9 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;
	(e) a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;
	(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;
	(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.6, including any amendment that the General Partner determines is necessary or appropriate in connection with (i) the adjustments of the Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution pursuant to the provisions of Section 5.11, (ii) the implementation of the provisions of Section 5.11 or (iii) any modifications to the Incentive Distribution Rights made in connection with the issuance of Partnership Securities pursuant to Section 5.6, provided that, with respect to this clause (iii), the modifications to the Incentive Distribution Rights and the related issuance of Partnership Securities have received Special Approval;
	(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;
	(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;
	(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4;
	(k) a merger, conveyance or conversion pursuant to Section 14.3(d); or
	(l) any other amendments substantially similar to the foregoing.

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	(i) name and state of domicile of each of the business entities proposing to merge or consolidate;
	(ii) the name and state of domicile of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);
	(iii) the terms and conditions of the proposed merger or consolidation;
	(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;
	(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, operating agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

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	(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and
	(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

	(i) the name of the converting entity and the converted entity;
	(ii) a statement that the Partnership is continuing its existence in the organizational form of the converted entity;
	(iii) a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;
	(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the converted entity;
	(v) in an attachment or exhibit, the certificate of limited partnership of the Partnership; and
	(vi) in an attachment or exhibit, the certificate of limited partnership, articles of incorporation, or other organizational documents of the converted entity;
	(vii) the effective time of the conversion, which may be the date of the filing of the articles of conversion or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such articles of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such articles of conversion and stated therein); and
	(viii) such other provisions with respect to the proposed conversion that the General Partner determines to be necessary or appropriate.

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	(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;
	(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;
	(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and
	(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

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	(i) the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;
	(ii) all rights, title, and interests to all real estate and other property owned by the Partnership shall continue to be owned by the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;
	(iii) all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;
	(iv) all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and may be pursued by such creditors and obligees as if the conversion did not occur;
	(v) a proceeding pending by or against the Partnership or by or against any of Partners in their capacities as such may be continued by or against the converted entity in its new organizational form and by or against the prior partners without any need for substitution of parties; and
	(vi) the Partnership Units that are to be converted into partnership interests, shares, evidences of ownership, or other securities in the converted entity as provided in the plan of conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion.

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	Section 16.1	Addresses and Notices.

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	Section 16.2	Further Action.

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	GENERAL PARTNER:
	DCP MIDSTREAM GP, LP
	By: DCP MIDSTREAM GP, LLC

	By:

	Name:
	Title:
	ORGANIZATIONAL LIMITED PARTNER:
	DUKE ENERGY FIELD SERVICES, LLC

	By:

	Name:
	Title:
	LIMITED PARTNERS:
	All Limited Partners now and hereafter admitted as Limited Partners of the Partnership, pursuant to powers of attorney now and hereafter executed in favor of, and granted and delivered to the General Partner or without execution hereof pursuant to Section 10.2(a) hereof.
	DCP LP HOLDINGS, LP

	By:	DUKE ENERGY FIELD SERVICES, LLC

	Name:
	Title:

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No.	Common Units

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Dated:  Countersigned and Registered by: American Stock Transfer & Trust Company By:   as Transfer Agent and Registrar By:    Authorized Signature		DCP Midstream Partners, LP By: DCP Midstream GP, LP By: DCP Midstream GP, LLC, its General Partner By:    By: American Stock Transfer & Trust Company By:    Name:    By:    Secretary

TEN COM — as tenants in common TEN ENT — as tenants by the entireties JT TEN   — as joint tenants with right of survivorship and not as tenants in common		UNIF GIFT/TRANSFERS MIN ACT   Custodian           (Cust) (Minor)  under Uniform Gifts/Transfers to CD Minors Act (State)

(Please print or typewrite name and address of assignee)		(Please insert Social Security or other identifying number of assignee)

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Date:		NOTE: The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.
THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17d-15		(Signature)   (Signature)

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	(a)	increase operating surplus by any net decreases made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period;

	(b)	decrease operating surplus by any net reduction in cash reserves for operating expenditures during that period not relating to an operating expenditure made during that period; and

	(c)	increase operating surplus by any net increase in cash reserves for operating expenditures during that period required by any debt instrument for the repayment of principal, interest or premium.

	(1) all cash and cash equivalents of DCP Midstream Partners, LP and its subsidiaries on hand at the end of that quarter; and
	(2) if our general partner so determines all or a portion of any additional cash or cash equivalents of DCP Midstream Partners, LP and its subsidiaries on hand on the date of determination of available cash for that quarter;

	(b) less the amount of cash reserves established by our general partner to:

	(1) provide for the proper conduct of the business of DCP Midstream Partners, LP and its subsidiaries (including reserves for future capital expenditures and for future credit needs of DCP Midstream Partners, LP and its subsidiaries) after that quarter;
	(2) comply with applicable law or any debt instrument or other agreement or obligation to which DCP Midstream Partners, LP or any of its subsidiaries is a party or its assets are subject; and
	(3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;

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	(a)	borrowings, refinancings or refundings of indebtedness and sales of debt securities (other than for items purchased on open account in the ordinary course of business) by DCP Midstream Partners, LP or any of its subsidiaries;

	(b)	sales of equity interests by DCP Midstream Partners, LP or any of its subsidiaries;

	(c)	sales or other voluntary or involuntary dispositions of any assets of DCP Midstream Partners, LP or any of its subsidiaries (other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements);

	(d)	the termination of interest rate swap agreements;

	(e)	capital contributions; and

	(f)	corporate reorganizations or restructurings.

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	(a)	Payments (including prepayments) of principal of and premium on indebtedness will not constitute operating expenditures.

	(b)	Operating expenditures will not include:

	(1)	expansion capital expenditures;
	(2)	payment of transaction expenses relating to interim capital transactions; or
	(3)	distributions to unitholders.

	(a) the sum of:

	(1)	all cash receipts of DCP Midstream Partners, LP and our subsidiaries for the period beginning on the closing date of our initial public offering and ending with the last day of that period, other than cash receipts from interim capital transactions; and
	(2)	an amount equal to four times the amount needed for any one quarter for us to pay a distribution on all units (including general partner units) and incentive distribution rights at the same per-unit amount as was distributed in the immediately preceding quarter; less

	(b)	the sum of:

	(1)	operating expenditures for the period beginning on the closing date of our initial public offering and ending with the last day of that period; and
	(2)	the amount of cash reserves that is established by our general partner to provide funds for future operating expenditures; provided however, that disbursements made (including contributions to DCP Midstream Partners, LP or our subsidiaries or disbursements on behalf of DCP Midstream Partners, LP or our subsidiaries) or cash reserves established, increased or reduced after the end of that period but on or before the date of determination of available cash for that period shall be deemed to have been made, established, increased or reduced for purposes of determining operating surplus, within that period if our general partner so determines.

	(a)	the first day of any quarter beginning after December 31, 2010 for which:

	(1)	distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

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	(2)	the adjusted operating surplus generated during each of the three consecutive, non-overlapping four quarter periods, immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the common units and subordinated units that were outstanding during those periods on a fully diluted basis; and
	(3)	there are no outstanding cumulative common units arrearages.

	(b)	the date on which the general partner is removed as our general partner upon the requisite vote by the limited partners under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of the removal.

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Item 13.	Other Expenses of Issuance and Distribution.

SEC registration fee			$	25,583
NASD filing fee				22,235
New York Stock Exchange listing fee				150,000
Printing and engraving expenses				550,000
Fees and expenses of legal counsel				1,300,000
Accounting fees and expenses				2,300,000
Transfer agent and registrar fees				5,000
Miscellaneous				5,000
	Total		$	4,357,818

Item 14.	Indemnification of Officers and Members of Our Board of Directors.

Item 15.	Recent Sales of Unregistered Securities.

Item 16.	Exhibits and Financial Statement Schedules.

	(a) Exhibits.

Exhibit
Number						Description
	1	.1		—		Form of Underwriting Agreement
	3	.1*		—		Certificate of Limited Partnership of DCP Midstream Partners, LP
	3	.2		—		Form of Amended and Restated Limited Partnership Agreement of DCP Midstream Partners, LP (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)
	3	.3*		—		Certificate of Limited Partnership of DCP Midstream GP, LP
	3	.4		—		Form of First Amended and Restated Limited Partnership Agreement of DCP Midstream GP, LP
	3	.5		—		Certificate of Formation of DCP Midstream GP, LLC

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Exhibit
Number						Description
	3	.6		—		Form of Amended and Restated Limited Liability Agreement of DCP Midstream GP, LLC
	5	.1		—		Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
	8	.1		—		Opinion of Vinson & Elkins L.L.P. relating to tax matters
	10	.1		—		Form of Credit Agreement
	10	.2		—		Form of DCP Midstream Partners, LP Long-Term Incentive Plan
	10	.3		—		Form of Contribution, Conveyance and Assumption Agreement
	10	.4		—		Form of Omnibus Agreement
	10	.5†		—		Natural Gas Gathering Agreement dated June 1, 1987, as amended, between DEFS Asset Holding, LP, successor to the interest of Cornerstone Natural Gas Company and Conoco Phillips, successor to the interest of Phillips Petroleum Company
	21	.1		—		List of Subsidiaries of DCP Midstream Partners, LP
	23	.1		—		Consent of Deloitte & Touche LLP
	23	.2		—		Consent of Deloitte & Touche LLP
	23	.3		—		Consent of Deloitte & Touche LLP
	23	.4		—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
	23	.5		—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
	24	.1*		—		Powers of Attorney (contained on the signature page)
	99	.1		—		Consent of Nominee for Director
	99	.2		—		Consent of Nominee for Director
	99	.3		—		Consent of Nominee for Director
	99	.4		—		Consent of Nominee for Director

*	Previously filed.

†	Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

(b)	Financial Statement Schedules.

							Charged to								Credit to
			Balance at				Combined								Combined
			Beginning of				Statements of				Deductions/				Statements of				Balance at End
			Period				Operations				Other				Operations				of Period
			($ in millions)
September 30, 2005
	Allowance for doubtful accounts		$	0.2			$	0.1			$	(0.1	)		$	—			$	0.2
	Environmental			—				0.2				(0.1	)			—				0.1
	Other (a)			1.3				—				(1.0	)			—				0.3
			$	1.5			$	0.3			$	(1.2	)		$	—			$	0.6
December 31, 2004
	Allowance for doubtful accounts		$	0.2			$	—			$	—			$	—			$	0.2
	Environmental			—				—				—				—				—
	Other (a)			1.3				—				—				—				1.3
			$	1.5			$	—			$	—			$	—			$	1.5

II-2

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							Charged to								Credit to
			Balance at				Combined								Combined
			Beginning of				Statements of				Deductions/				Statements of				Balance at End
			Period				Operations				Other				Operations				of Period
			($ in millions)
December 31, 2003
	Allowance for doubtful accounts		$	0.2			$	—			$	—			$	—			$	0.2
	Environmental			—				0.1				(0.1	)			—				—
	Other (a)			—				1.3				—				—				1.3
			$	0.2			$	1.4			$	(0.1	)		$	—			$	1.5
December 31, 2002
	Allowance for doubtful accounts		$	0.6			$	—			$	(0.3	)		$	(0.1	)		$	0.2
	Environmental			0.1				—				(0.1	)			—				—
	Other			—				—				—				—				—
			$	0.7			$	—			$	(0.4	)		$	(0.1	)		$	0.2

(a)	Principally consists of other contingency liabilities which are included in Other current liabilities.

Item 17.	Undertakings.

	(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.
	(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-3

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Table of Contents

	DCP Midstream Partners, LP

	By:	DCP Midstream GP, LP

	its General Partner

	By:	DCP Midstream GP, LLC

	its General Partner

	By:	/s/ Michael J. Bradley

	Name: Michael J. Bradley
	Title:     President and Chief Executive Officer

Signature				Title		Date
/s/ Michael J. Bradley   Michael J. Bradley President and Chief Executive Officer				Chief Executive Officer (Principal Executive Officer)		November 17, 2005
*   Thomas E. Long Vice President and Chief Financial Officer				Chief Financial Officer (Principal Financial Officer)		November 17, 2005
*   Patrick J. Welch Vice President and Controller				Controller (Principal Accounting Officer)		November 17, 2005
*   Jim W. Mogg				Director		November 17, 2005
*By		/s/ Michael J. Bradley   Michael J. Bradley Attorney-in-Fact

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Exhibit
Number						Description
	1	.1		—		Form of Underwriting Agreement
	3	.1*		—		Certificate of Limited Partnership of DCP Midstream Partners, LP
	3	.2		—		Form of Amended and Restated Limited Partnership Agreement of DCP Midstream Partners, LP (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)
	3	.3*		—		Certificate of Limited Partnership of DCP Midstream GP, LP
	3	.4		—		Form of First Amended and Restated Limited Partnership Agreement of DCP Midstream GP, LP
	3	.5		—		Certificate of Formation of DCP Midstream GP, LLC
	3	.6		—		Form of Amended and Restated Limited Liability Agreement of DCP Midstream GP, LLC
	5	.1		—		Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
	8	.1		—		Opinion of Vinson & Elkins L.L.P. relating to tax matters
	10	.1		—		Form of Credit Agreement
	10	.2		—		Form of DCP Midstream Partners, LP Long-Term Incentive Plan
	10	.3		—		Form of Contribution, Conveyance and Assumption Agreement
	10	.4		—		Form of Omnibus Agreement
	10	.5†		—		Natural Gas Gathering Agreement dated June 1, 1987, as amended, between DEFS Asset Holding, LP, successor to the interest of Cornerstone Natural Gas Company and Conoco Phillips, successor to the interest of Phillips Petroleum Company
	21	.1		—		List of Subsidiaries of DCP Midstream Partners, LP
	23	.1		—		Consent of Deloitte & Touche LLP
	23	.2		—		Consent of Deloitte & Touche LLP
	23	.3		—		Consent of Deloitte & Touche LLP
	23	.4		—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
	23	.5		—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
	24	.1*		—		Powers of Attorney (contained on the signature page)
	99	.1		—		Consent of Nominee for Director
	99	.2		—		Consent of Nominee for Director
	99	.3		—		Consent of Nominee for Director
	99	.4		—		Consent of Nominee for Director

*	Previously filed.

†	Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

 

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