Exhibit 99.1

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2010 (UNAUDITED) AND DECEMBER 31, 2009 AND 2008

AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2010 (AS RESTATED) (UNAUDITED) AND

2009 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007

Deloitte & Touche LLP

Suite 3600

555 Seventeenth Street

Denver, CO 80202-3942

USA

Tel: +1 303 292 5400

Fax: +1 303 312 4000

www.deloitte.com

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Members of

DCP Midstream, LLC

Denver, CO

We have audited the accompanying combined balance sheets of the Southeast Texas Midstream Business (the “Business”), which consists of assets which are under common ownership and common management, as of December 31, 2009 and 2008, and the related combined statements of operations, comprehensive income, changes in net parent equity, and cash flows for each of the three years in the period ended December 31, 2009. These combined financial statements are the responsibility of the Business’ management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

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

In our opinion, such combined financial statements present fairly, in all material respects, the combined financial position of the Business at December 31, 2009 and 2008, and the combined results of its operations and its combined cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

The accompanying combined financial statements have been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Business had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to, DCP Midstream, LLC as a whole.

/s/ Deloitte & Touche LLP

November 3, 2010

(November 8, 2010 as to note 13)

Member of

Deloitte Touche Tohmatsu

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED BALANCE SHEETS

	September 30, 2010			December 31, 2009			December 31, 2008
	(Unaudited)
	(Millions)
ASSETS
Current assets:
Accounts receivable:
Trade	$	29.9		$	37.3		$	30.5
Affiliates		5.5			1.5			10.8
Inventories		24.9			19.5			5.7
Unrealized gains on derivative instruments		35.0			35.4			53.1
Total current assets		95.3			93.7			100.1
Property, plant and equipment, net		261.6			225.2			223.4
Goodwill, net		11.8			—			—
Intangibles, net		34.3			—			—
Unrealized gains on derivative instruments		1.0			4.7			1.4
Other long-term assets		0.5			0.5			0.5
Total assets	$	404.5		$	324.1		$	325.4
LIABILITIES AND NET PARENT EQUITY
Current liabilities:
Accounts payable:
Trade	$	58.5		$	66.7		$	45.9
Affiliates		—			—			1.0
Unrealized losses on derivative instruments		29.4			31.9			47.5
Other		8.0			4.3			7.5
Total current liabilities		95.9			102.9			101.9
Unrealized losses on derivative instruments		1.4			4.5			1.2
Other long-term liabilities		4.0			4.4			4.7
Total liabilities		101.3			111.8			107.8
Commitments and contingent liabilities
Equity:
Parent equity		305.9			215.0			218.3
Accumulated other comprehensive loss		(2.7	)		(2.7	)		(0.7	)
Total net parent equity		303.2			212.3			217.6
Total liabilities and net parent equity	$	404.5		$	324.1		$	325.4

See accompanying notes to combined financial statements.

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF OPERATIONS

	Nine Months  Ended September 30,						Year Ended December 31,
	2010 (As Restated – Note 15)			2009			2009			2008			2007
	(Unaudited)
	(Millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	311.0		$	192.7		$	274.4		$	707.9		$	533.4
Sales of natural gas, NGLs and condensate to affiliates		277.8			152.5			241.9			410.5			364.6
Transportation, processing and other		10.0			6.7			9.7			10.8			10.0
Transportation, processing and other to affiliates		1.4			—			—			—			1.4
Gains from commodity derivative activity, net		9.4			6.4			8.9			12.8			3.9
(Losses) gains from commodity derivative activity, net — affiliates		(0.7	)		0.4			0.6			0.1			4.0
Total operating revenues		608.9			358.7			535.5			1,142.1			917.3
Operating costs and expenses:
Purchases of natural gas and NGLs		545.6			316.1			471.5			1,049.2			844.1
Purchases of natural gas and NGLs from affiliates		0.6			0.6			0.6			16.2			1.8
Operating and maintenance expense		13.3			12.4			14.5			17.6			14.2
Depreciation and amortization expense		10.2			9.0			12.0			11.8			11.0
General and administrative expense — affiliates		8.4			7.6			10.8			10.6			12.3
Other income		(1.0	)		—			—			—			—
Loss on sale of assets		—			0.5			0.5			1.8			—
Total operating costs and expenses		577.1			346.2			509.9			1,107.2			883.4
Operating income		31.8			12.5			25.6			34.9			33.9
Income tax expense		(0.5	)		(0.4	)		(0.4	)		(0.7	)		(0.7	)
Net income	$	31.3		$	12.1		$	25.2		$	34.2		$	33.2

See accompanying notes to combined financial statements.

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF COMPREHENSIVE INCOME

	Nine Months  Ended September 30,					Year Ended December 31,
	2010 (As Restated – Note 15)		2009			2009			2008			2007
	(Unaudited)
	(Millions)
Net income	$	31.3	$	12.1		$	25.2		$	34.2		$	33.2
Other comprehensive loss:
Net unrealized losses on cash flow hedges		—		(1.4	)		(2.0	)		(0.7	)		—
Total other comprehensive loss		—		(1.4	)		(2.0	)		(0.7	)		—
Total comprehensive income	$	31.3	$	10.7		$	23.2		$	33.5		$	33.2

See accompanying notes to combined financial statements.

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF CASH FLOWS

	Nine Months  Ended September 30,						Year Ended December 31,
	2010 (As Restated – Note 15)			2009			2009			2008			2007
	(Unaudited)
	(Millions)
OPERATING ACTIVITIES:
Net income	$	31.3		$	12.1		$	25.2		$	34.2		$	33.2
Adjustments to reconcile net income to net cash provided by operating activities:
Loss on sale of assets		—			0.5			0.5			1.8			—
Depreciation and amortization expense		10.2			9.0			12.0			11.8			11.0
Other, net		(1.0	)		—			0.1			(0.1	)		0.1
Change in operating assets and liabilities, which (used) provided cash:
Accounts receivable		7.0			22.1			2.1			23.5			(15.9	)
Inventories		(5.4	)		(1.0	)		(13.8	)		32.8			(7.6	)
Net unrealized (gains) losses on derivative instruments		(1.5	)		1.4			—			(1.4	)		8.4
Accounts payable		(11.3	)		(9.7	)		19.8			(45.8	)		30.5
Other current assets and liabilities		0.7			(0.3	)		(0.7	)		0.9			2.6
Other long-term assets and liabilities		(0.4	)		(0.3	)		(0.4	)		(0.2	)		(0.5	)
Net cash provided by operating activities		29.6			33.8			44.8			57.5			61.8
INVESTING ACTIVITIES:
Capital expenditures		(10.4	)		(11.3	)		(17.4	)		(14.1	)		(22.1	)
Purchase of Ceritas		(78.8	)		—			—			—			—
Proceeds from sale of assets		—			1.1			1.1			5.7			—
Net cash used in investing activities		(89.2	)		(10.2	)		(16.3	)		(8.4	)		(22.1	)
FINANCING ACTIVITIES:
Net change in parent advances		59.6			(23.6	)		(28.5	)		(49.1	)		(39.7	)
Net cash provided by (used in) financing activities		59.6			(23.6	)		(28.5	)		(49.1	)		(39.7	)
Net change in cash and cash equivalents		—			—			—			—			—
Cash and cash equivalents, beginning of period		—			—			—			—			—
Cash and cash equivalents, end of period	$	—		$	—		$	—		$	—		$	—

See accompanying notes to combined financial statements.

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF CHANGES IN NET PARENT EQUITY

	Parent Equity			Accumulated Other Comprehensive Loss			Net Parent Equity
	(Millions)
Balance, January 1, 2007	$	239.7		$	—		$	239.7
Net change in parent advances		(39.7	)		—			(39.7	)
Comprehensive income:
Net income		33.2			—			33.2
Total comprehensive income		33.2			—			33.2
Balance, December 31, 2007		233.2			—			233.2
Net change in parent advances		(49.1	)		—			(49.1	)
Comprehensive income (loss):
Net income		34.2			—			34.2
Net unrealized losses on cash flow hedges		—			(0.7	)		(0.7	)
Total comprehensive income (loss)		34.2			(0.7	)		33.5
Balance, December 31, 2008		218.3			(0.7	)		217.6
Net change in parent advances		(28.5	)		—			(28.5	)
Comprehensive income (loss):
Net income		25.2			—			25.2
Net unrealized losses on cash flow hedges		—			(2.0	)		(2.0	)
Total comprehensive income (loss)		25.2			(2.0	)		23.2
Balance, December 31, 2009		215.0			(2.7	)		212.3
Net change in parent advances (As Restated – Note 15) (Unaudited)		59.6			—			59.6
Comprehensive income:
Net income (As Restated – Note 15) (Unaudited)		31.3			—			31.3
Total comprehensive income (Unaudited)		31.3			—			31.3
Balance, September 30, 2010 (Unaudited)	$	305.9		$	(2.7	)	$	303.2

See accompanying notes to combined financial statements.

5

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS

1. Description of Business and Basis of Presentation

The Southeast Texas Midstream Business, or the Business, we, our, or us, is engaged in the business of gathering, transporting, treating, compressing and processing natural gas and natural gas liquids, or NGL’s. The operations, located in Southeast, Texas, include 3 natural gas processing facilities with a total capacity of approximately 350 million cubic feet per day. The facilities are connected to our Liberty 36-mile gathering system and to our CIPCO system, which includes in excess of 600 miles of gathering and transmission lines, as well as our 3 salt dome natural gas storage caverns at Spindletop with a total working gas capacity of 9 billion cubic feet.

These combined financial statements and related notes present the financial position, results of operations, cash flows, and changes in net parent equity of the Business held by DCP Midstream, LLC and its subsidiaries, or Midstream. Midstream is owned 50% by Spectra Energy Corp, or Spectra Energy, and 50% by ConocoPhillips. As of January 1, 2011, Midstream owned an approximately 30% interest, including a 1% general partner interest, in DCP Midstream Partners, LP, or Partners. The Business was contributed to DCP Southeast Texas Holdings GP, and on January 1, 2011, Partners acquired from Midstream a 33.33% interest in DCP Southeast Texas Holdings, GP, or the transaction. As part of the closing of the transaction, the assets, liabilities and operations of the Business, with the exception of any financial derivative instruments and certain working capital and other liabilities now reside in DCP Southeast Texas Holdings, GP. Subsequent to the transaction, Midstream still directs our business operations. The Business does not currently and is not expected to have any employees. Midstream and its affiliates’ employees are responsible for conducting our business and operating our assets.

The combined financial statements include the accounts of the Business and have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The combined financial statements of the Business have been prepared from the separate records maintained by Midstream and may not necessarily be indicative of the conditions that would have existed, or the results of operations, if the Business had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various assets comprising the Business, Midstream’s net investment in the Business is shown as net parent equity, in lieu of owner’s equity, in the combined financial statements. All intercompany balances and transactions have been eliminated. Transactions between us and other Midstream operations have been identified in the combined financial statements as transactions between affiliates. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the combined financial statements.

The combined financial statements of operations and cash flows for the nine months ended September 30, 2010 and 2009, the combined statements of comprehensive income for the nine months ended September 30, 2010 and 2009, the combined statements of changes in net parent equity for the nine months ended September 30, 2010, and the combined balance sheet as of September 30, 2010, are unaudited. These unaudited interim combined financial statements have been prepared in accordance with GAAP. In the opinion of management, the unaudited interim combined financial statements have been prepared on the same basis as the audited combined financial statements, and reflect all normal recurring adjustments that are necessary to present fairly the financial position, and the results of operations and cash flows, for the respective interim periods.

Results of operations for the nine months ended September 30, 2010, are not necessarily indicative of the results that may be expected for the year ending December 31, 2010.

2. Summary of Significant Accounting Policies

Use of Estimates — Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the combined financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates.

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

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

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a risk free interest rate, and increases due to the passage of time based on the time value of money until the obligation is settled.

Intangible Assets and Goodwill — Intangible assets consist primarily of customer contracts. These intangible assets will be amortized on a straight-line basis over the term of the contract or anticipated relationship, of approximately 15 years. Intangible assets are removed from the gross carrying amount and the total of accumulated amortization in the period in which they become fully amortized.

Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We evaluate goodwill for impairment annually in the third quarter, and when we believe events or changes in circumstances indicate we may not be able to recover the carrying value of the reporting unit. Impairment testing of goodwill consists of a two-step process. The first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves comparing the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the fair value of that goodwill, the excess of the carrying value over the fair value is recognized as an impairment loss.

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

• significant adverse change in legal factors or business climate;

• a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;

• an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

• significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;

• a significant adverse 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.

If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.

Accounting for Risk Management Activities and Financial Instruments — We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge) or normal purchases or normal sales. The remaining non-trading derivatives, which are related to assets-based activities for which the normal purchases or normal sale exception are not elected, are recorded at fair value in the combined balance sheets as unrealized gains or unrealized losses in derivative instruments, with changes in the fair value recognized in the combined statements of operations. For each derivative, the accounting method and presentation of gains and losses or revenue and expense in the combined statements of operations are as follows:

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Non-Trading Derivative Activity	Mark-to-market method (a)	Net basis in gains and losses from commodity derivative activity
Cash Flow Hedge	Hedge method (b)	Gross basis in the same combined statements of operations category as the related hedged item

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

(b) Hedge method — An accounting method whereby the change in the fair value of the asset or liability is recorded in the combined balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges, there is no recognition in the combined statements of operations for the effective portion until the service is provided or the associated delivery period impacts earnings.

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

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

Valuation — When available, quoted market prices or prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily from historical relationships with quoted market prices and the expected relationship with quoted market prices.

Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

Revenue Recognition — We generate the majority of our revenues from gathering, processing, compressing and transporting natural gas and NGLs, and from trading and marketing of natural gas. We realize revenues either by selling the residue natural gas and NGLs, or by receiving fees from the producers.

We obtain access to commodities and provide our midstream services principally under contracts that contain a combination of one or more of the following arrangements:

• Fee-based arrangements — Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, compressing, treating, processing or transporting natural gas; and transporting NGLs. Our fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead or other receipt points, at an index related price at the delivery point less a specified amount, generally the same as the transportation fees we would otherwise charge for transportation of natural gas from the wellhead

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

location to the delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced.

• Percent-of-proceeds arrangements — Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat and process the natural gas, and then sell the resulting residue natural gas and NGLs based on index prices from published index market prices. We remit to the producers either an agreed-upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas and the NGLs, regardless of the actual amount of the sales proceeds we receive. Certain of these arrangements may also result in our returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. Our revenues under percent-of-proceeds arrangements relate directly with the price of natural gas and/or NGLs.

Our marketing of natural gas consists of physical purchases and sales, as well as positions in derivative instruments.

We recognize revenues for sales and services under the four revenue recognition criteria, as follows:

• Persuasive evidence of an arrangement exists — Our customary practice is to enter into a written contract.

• Delivery — Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.

• The fee is fixed or determinable — We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.

• Collectability is reasonably assured — Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit metrics, liquidity and credit rating) and their ability to pay. If collectability is not considered reasonably assured at the outset of an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected.

We generally report revenues gross in the combined statements of operations, as we typically act as the principal in these transactions, take custody to the product, and incur the risks and rewards of ownership. New or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for non-trading commodity derivative activity net in the combined statements of operations as gains and losses from commodity derivative activity. These activities include mark-to-market gains and losses on energy trading contracts and the settlement of financial or physical energy trading contracts.

Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as accounts receivable or accounts payable using current market prices or the weighted-average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash. Included in the combined balance sheets as accounts receivable—trade and accounts receivable—affiliates as of September 30, 2010, December 31, 2009 and December 31, 2008, were imbalances of $0 (unaudited), $0.1 million and $0.1 million, respectively. Included in the combined balance sheets as accounts payable—trade as of September 30, 2010, December 31, 2009 and December 31, 2008, were imbalances of $0.1 million (unaudited), $0.2 million and less than $0.1 million, respectively.

Environmental Expenditures — Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. As of September 30, 2010 (unaudited), December 31, 2009 and December 31, 2008, we had no environmental liabilities in our combined balance sheets.

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Allowance for Doubtful Accounts — Management estimates the amount of required allowances for the potential non-collectability of accounts receivable generally based upon the number of days past due, past collection experience and consideration of other relevant factors. However, past experience may not be indicative of future collections and therefore additional charges could be incurred in the future to reflect differences between estimated and actual collections.

Income Taxes — We are treated as a pass-through entity for federal income tax purposes, as such we do not directly pay federal income taxes. We are subject to the Texas margin tax, which is treated as an income tax. We follow the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. The Business is a member of a group. We have calculated current and deferred income taxes as if we were a separate tax payer.

3. Recent Accounting Pronouncements

On July 1, 2009, the Financial Accounting Standards Board, or FASB, Accounting Standards Codification, or ASC, became the source for authoritative GAAP. During the second half of 2009, the FASB issued several ASUs. The following outlines the ASUs that are applicable to us and may have an impact on our combined financial statements and related disclosures:

FASB ASU 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements,” or ASU 2010-06 — In January 2010, the FASB issued Accounting Standards Update, or ASU, 2010-06 which amended ASC Topic 820-10 “Fair Value Measurement and Disclosures—Overall.” ASU 2010-06 requires new disclosures regarding transfers in and out of assets and liabilities measured at fair value classified within the valuation hierarchy as either Level 1 or Level 2 and information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3. ASU 2010-06 clarifies existing disclosures on the level of disaggregation required and inputs and valuation techniques. The provisions of ASU 2010-06 became effective for us on January 1, 2010, except for disclosure of information about sales, issuances and settlements on a gross basis for assets and liabilities classified as Level 3, which is effective for us on January 1, 2011. The provisions of ASU 2010-06 impact only disclosures and we have disclosed information in accordance with the revised provisions of ASU 2010-06 within our combined financial statements.

ASU 2009-17 “Consolidation (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” or ASU 2009-17 — In December 2009, the FASB issued ASU 2009-17 which amended ASC Topic 810 “Consolidation.” ASU 2009-17 requires entities to perform additional analysis of their variable interest entities and consolidation methods. This ASU became effective for us on January 1, 2010 and upon adoption we did not change our conclusions on which entities we consolidate in our combined financial statements.

ASU 2009-13 “Revenue Recognition (Topic 605): Multiple-Deliverable Revenue Arrangements,” or ASU 2009-13 — In October 2009, the FASB issued ASU 2009-13 which amended ASC Topic 605 “Revenue Recognition.” The ASU addresses the accounting for multiple-deliverable arrangements, to enable vendors to account for products or services separately rather than as a combined unit. ASU 2009-13 is effective for us on January 1, 2011 and we are in the process of assessing the impact of ASU 2009-13 on our combined results of operations, cash flows and financial position as a result of adoption.

ASU 2009-05 “Fair Value Measurements and Disclosures (Topic 820): Measuring Liabilities at Fair Value,” or ASU 2009-05 — In August 2009, the FASB issued ASU 2009-05 which amended ASC Topic 820-10 “Fair Value Measurements and Disclosures—Overall” for the fair value measurement of liabilities. The amended provisions in this update are designed to reduce potential ambiguity in financial reporting when measuring the fair value of liabilities, helping to improve the consistency in the application of Topic 820 “Fair Value Measurements and Disclosures.” ASU 2009-05 became effective on October 1, 2009 and there was no impact on our combined results of operations, cash flows or financial position as a result of adoption.

ASC 350 “Intangibles—Goodwill and Other,” or ASC 350, ASC 275 “Risks and Uncertainties,” or ASC 275 — In April 2008, the FASB amended guidance relating to intangible assets and risks and uncertainties, for factors that should be considered in developing renewal or extension assumptions used to determine the useful life of an intangible asset. We adopted these amended provisions on January 1, 2009. As a result of acquisitions, we have intangible assets for customer contracts and related relationships in our combined balance sheets. Generally, costs to renew or extend such contracts are not significant, and are expensed to the combined statements of operations as incurred. During the nine months ended September 30, 2010 and for the year ended December 31, 2009, there were no contracts that were recognized as intangible assets that were renewed or extended.

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ASC 805 “Business Combinations,” or ASC 805 — In April 2009, the FASB amended guidance relating to business combinations, providing additional guidance on the valuation of assets and liabilities assumed in a business combination that arise from contingencies, which would otherwise be subject to the provisions of other applicable GAAP. This amendment emphasizes that assets and liabilities assumed in a business combination that have an estimated fair value should be recorded at the time of acquisition. Assets and liabilities where the fair value may not be determinable during the measurement period will continue to be recognized pursuant to other applicable GAAP. This amendment was effective for us for business combinations with closing dates subsequent to January 1, 2009. We have accounted for business combinations with closing dates subsequent to the effective date in accordance with this new guidance.

In December 2007, the FASB amended guidance relating to business combinations, which requires the acquiring entity in a business combination subsequent to January 1, 2009 to recognize all (and only) the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. We adopted these amended provisions effective January 1, 2009, and have accounted for all transactions with closing dates subsequent to adoption in accordance with the revised provisions of this standard.

ASC 815 “Derivatives and Hedging,” or ASC 815 — In March 2008, the FASB amended guidance relating to derivatives and hedging to require disclosures of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. We adopted these amended provisions effective January 1, 2009, and have included all required disclosures in these financial statements. The amended provisions impact only disclosures, so there was no effect on our combined results of operations, cash flows or financial position as a result of adoption.

ASC 820 “Fair Value Measurements and Disclosures,” or ASC 820 — In April 2009, the FASB amended guidance relating to fair value measurements and disclosures, which provides additional guidance on the valuation of assets or liabilities that are held in markets that have seen a significant decline in activity. While this amendment does not change the overall objective of determining fair value, it emphasizes that in markets with significantly decreased activity and the appearance of non-orderly transactions, an entity may employ multiple valuation techniques, to which significant adjustments may be required, to determine the most appropriate fair value. During 2009, certain of the markets in which we transact saw a decrease in overall volume; however, we believe that these markets continue to provide sufficient liquidity such that transactions are executed in an orderly manner at fair value. We adopted these amended provisions effective June 30, 2009 and there was no impact on our combined results of operations, cash flows or financial position.

On January 1, 2008 we adopted the fair value measurement and disclosure requirements of ASC 820 for all financial assets and liabilities. Effective January 1, 2009, we adopted the fair value measurement and disclosure requirements for all nonfinancial assets and liabilities. There was no effect on our combined results of operations, cash flows, or financial position, and we have included all required disclosures as a result of the adoption of these requirements relative to nonfinancial assets and liabilities.

ASC 855 “Subsequent Events,” or ASC 855 — In May 2009, the FASB amended guidance relating to subsequent events, which sets forth the recognition and disclosure requirements for events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. We adopted these amended provisions effective June 30, 2009, and there was no effect on our combined results of operations, cash flows or financial position as a result of adoption. All appropriate disclosure of subsequent events is made within the footnotes.

4. Acquisitions

On June 29, 2010, we acquired the Raywood processing plant and Liberty gathering system, which are located in Liberty County, Texas, from Ceritas Holdings, LP, or Ceritas, for $78.8 million (unaudited), subject to customary purchase price adjustments. We may pay up to an additional $6.0 million (unaudited) to Ceritas based upon recovery of certain currently non-producing wells over a period of approximately one year. We initially recorded a liability of $3.1 million (unaudited), which represented the initial fair value of the contingent consideration. As of September 30, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to $2.1 million. This liability is recorded in other current liabilities within the combined balance sheet as of September 30, 2010. Accordingly, we have recognized a gain of $1.0 million for the nine months ended September 30, 2010, within other operating income in the combined results of operations. The acquired system will connect with our existing southeast Texas assets.

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The purchase price allocation is preliminary and is based on initial estimates of fair values at the date of the acquisition. We will continue to evaluate the initial purchase price allocation, which may be adjusted as additional information relative to the fair value of working capital becomes available. The preliminary purchase price allocation is as follows:

	(Unaudited) (Millions)
Aggregate consideration	$	78.8
The preliminary purchase price was allocated as follows:
Property, plant and equipment	$	34.6
Intangible assets		34.9
Goodwill		11.8
Other assets		3.5
Other liabilities		(2.9	)
Contingent consideration		(3.1	)
Total preliminary purchase price allocation	$	78.8

Combined Financial Information

The following table presents unaudited pro forma information for the combined statements of operations for the nine months ended September 30, 2010 and 2009, as if the acquisition of the Raywood processing plant and Liberty gathering system had occurred at the beginning of each period presented. For the nine months ended September 30, 2010, revenues of $15.0 (unaudited) and net income of $1.9 (unaudited) associated with the acquired assets, from the date of acquisition through September 30, 2010 have been included in the combined statements of operations.

	Nine Months Ended September 30, 2010						Nine Months Ended September 30, 2009
	The South East Texas Midstream Business		Acquisition of the Raywood Processing Plant and the Liberty Gathering System		The South East Texas Midstream Business Pro Forma		The South East Texas Midstream Business		Acquisition of the Raywood Processing Plant and  the Liberty Gathering System		The South East Texas Midstream Business Pro Forma
	(Unaudited)
	(Millions)
Total operating revenues	$	604.3	$	22.6	$	626.9	$	358.7	$	30.3	$	389.0
Net income	$	26.7	$	2.0	$	28.7	$	12.1	$	2.1	$	14.2

5. Agreements and Transactions with Affiliates

DCP Midstream, LLC

The employees supporting our operations are employees of Midstream. Costs incurred by Midstream on our behalf for salaries and benefits of operating personnel, as well as capital expenditures, maintenance and repair costs, and taxes have been directly allocated to us. Midstream also provides centralized corporate functions on our behalf, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. Midstream records the accrued liabilities and prepaid expenses for general and administrative expenses in its financial statements, including liabilities related to payroll, short and long-term incentive plans, employee retirement and medical plans, paid time off, audit, tax, insurance and other service fees. Our share of those costs has been allocated based on Midstream’s proportionate investment (consisting of property, plant and equipment, intangibles, and investments in unconsolidated affiliates) compared to our investment. In management’s estimation, the allocation methodologies used are reasonable and result in an allocation to us of our costs of doing business borne by Midstream.

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Midstream has issued parental guarantees in favor of certain counterparties. A portion of these parental guarantees relate to assets included in these combined financial statements.

We participate in Midstream’s cash management program. As a result, we have no cash balances on the combined balance sheets and all of our cash management activity was performed by Midstream on our behalf, including collection of receivables, payment of payables, and the settlement of sales and purchases transactions with Midstream, which were recorded as parent advances and are included in net parent equity on the accompanying combined balance sheets.

We currently, and anticipate to continue to, purchase and sell to Midstream in the ordinary course of business. Midstream was a significant customer during the nine months ended September 30, 2010 and 2009 (unaudited), and for the years ended December 31, 2009, 2008 and 2007.

ConocoPhillips

We currently, and anticipate to continue to, sell to ConocoPhillips in the ordinary course of business. ConocoPhillips was a significant customer during the nine months ended September 30, 2010 and 2009 (unaudited), and for the years ended December 31, 2009, 2008 and 2007.

Summary of Transactions with Affiliates

The following table summarizes transactions with affiliates:

	Nine Months  Ended September 30,						Year Ended December 31,
	2010 (As Restated  – Note 15)			2009			2009			2008			2007
	(Unaudited)
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, NGLs and condensate	$	254.1		$	127.9		$	216.5		$	313.6		$	305.7
Purchases of natural gas and NGLs	$	0.6		$	0.4		$	0.4		$	9.7		$	0.2
Losses from commodity derivative activity, net	$	(0.8	)	$	(0.1	)	$	(0.1	)	$	(0.2	)	$	—
General and administrative expense	$	8.4		$	7.6		$	10.8		$	10.6		$	12.3
ConocoPhillips:
Sales of natural gas, NGLs and condensate	$	23.7		$	24.3		$	25.1		$	96.9		$	58.9
Transportation, processing and other	$	1.4		$	—		$	—		$	—		$	—
Purchases of natural gas and NGLs	$	—		$	0.1		$	0.1		$	5.8		$	1.2
Gains on derivative activity, net	$	0.1		$	0.5		$	0.7		$	0.3		$	4.0
Spectra Energy:
Sales of natural gas, NGLs and condensate	$	—		$	0.3		$	0.3		$	—		$	—
Transportation, processing and other	$	—		$	—		$	—		$	—		$	1.4
Purchases of natural gas and NGLs	$	—		$	0.1		$	0.1		$	0.4		$	0.4
Operating and maintenance expense	$	—		$	—		$	0.2		$	—		$	—
Other:
Purchases of natural gas and NGLs	$	—		$	—		$	—		$	0.3		$	—
Operating and maintenance expense (a)	$	—		$	—		$	(0.2	)	$	—		$	—

(a) Balance for the year ended December 31, 2009 includes hurricane insurance recovery receivables, which were treated as a reduction to operating expense in the accompanying combined statements of operations.

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We had balances with affiliates as follows:

	September 30, 2010		December 31, 2009		December 31, 2008
	(Unaudited)
	(Millions)
DCP Midstream, LLC:
Unrealized losses on derivative instruments — current	$	—	$	—	$	—
ConocoPhillips:
Accounts receivable	$	5.5	$	1.5	$	10.6
Accounts payable	$	—	$	—	$	(0.1	)
Unrealized gains on derivative instruments — current	$	—	$	0.4	$	—
Unrealized gains on derivative instruments — long-term	$	—	$	—	$	0.1
Spectra Energy:
Accounts receivable	$	—	$	—	$	0.2
Accounts payable	$	—	$	—	$	(0.9	)

6. Property, Plant and Equipment

A summary of property, plant and equipment by classification is as follows:

	Depreciable Life		September 30, 2010			December 31, 2009			December 31, 2008
			(Unaudited)
			(Millions)
Gathering systems		15 — 30 Years	$	73.0		$	59.6		$	56.7
Underground storage		0 — 50 Years		122.1			98.5			99.8
Processing plants		25 — 30 Years		90.5			70.1			68.5
Transportation		25 — 30 Years		106.6			103.2			103.1
General plant		3 — 5 Years		1.7			1.6			1.5
Land		Non-Depreciable		1.3			1.2			0.5
Construction work in progress				5.0			20.0			10.3
Property, plant and equipment				400.2			354.2			340.4
Accumulated depreciation				(138.6	)		(129.0	)		(117.0	)
Property, plant and equipment, net			$	261.6		$	225.2		$	223.4

The above amounts include accrued capital expenditures of $1.1 million (unaudited) for the nine months ended September 30, 2010, and $0.3 million and $2.8 million for the years ended December 31, 2009 and 2008, respectively. There was no interest capitalized on construction projects for the nine months ended September 30, 2010 and 2009 or for the years ended December 31, 2009, 2008 and 2007.

Depreciation expense was $9.6 million (unaudited) and $9.0 million (unaudited) for the nine months ended September 30, 2010 and 2009, respectively, and $12.0 million, $11.8 million and $11.0 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Asset Retirement Obligations — Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We adjust our asset retirement obligation for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The asset retirement obligations, included in other long-term liabilities in the combined balance sheets, are $0.9 million (unaudited) at September 30, 2010, $0.8 million at December 31, 2009 and $0.7 million at December 31, 2008. Accretion expense for the nine months ended September 30, 2010 and 2009 was less than $0.1 million (unaudited), for both periods. Accretion expense for the years ended December 31, 2009 and 2007 was $0.1 million for both periods. During the year ended December 31, 2008, we purchased a parcel of land which was previously leased. This transaction resulted in relieving the associated ARO and recognizing a $0.1 million benefit to accretion expense.

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We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.

7. Goodwill and Intangible Assets

At September 30, 2010, we had goodwill of $11.8 million (unaudited) as a result of the amount that we recognized in connection with our acquisition of the Raywood processing plant and Liberty gathering system from Ceritas on June 29, 2010.

Intangible assets consist primarily of customer contracts, and are as a result of our acquisition of the Raywood processing plant and Liberty gathering system from Ceritas on June 29, 2010. The gross carrying amount and accumulated amortization of these intangible assets are included in the accompanying consolidated balance sheets as intangible assets, net, and are as follows:

	September 30, 2010
	(Millions)
Gross carrying amount	$	34.9
Amortization charge		(0.6	)
Intangible assets, net	$	34.3

Estimated amortization for these intangibles is as follows as of September 30, 2010:

Estimated Amortization
(Unaudited)
(Millions)
2010 (remainder)	$	0.6
2011		2.3
2012		2.3
2013		2.3
2014		2.3
Thereafter		24.5
Total	$	34.3

As of September 30, 2010, the remaining amortization period was 14.75 years.

8. Fair Value Measurement

Determination of Fair Value

Below is a general description of our valuation methodologies for derivative financial assets and liabilities, which are measured at fair value. Fair values are generally based upon quoted market prices, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.

• Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties

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NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided.

• Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability position with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.

• Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.

We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 9 Risk Management and Hedging Activities.

Valuation Hierarchy

Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.

• Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.

• Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

• Level 3 — inputs are unobservable and considered significant to the fair value measurement.

A financial instrument’s categorization within the hierarchy is based upon the input that requires the highest degree of judgment in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.

Commodity Derivative Assets and Liabilities

We enter into a variety of derivative financial instruments, which may include over the counter, or OTC, instruments, such as natural gas contracts.

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We typically use OTC derivative contracts in order to mitigate a portion of our exposure to natural gas price changes. We also may enter into natural gas derivatives to lock in margin around our storage and transportation assets. These instruments are generally classified as Level 2. Depending upon market conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.

Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.

Nonfinancial Assets and Liabilities

We utilize fair value on a non-recurring basis to perform impairment tests as required on our property, plant and equipment. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3, in the event that we were required to measure and record such assets at fair value within our combined financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified within Level 3.

We utilize fair value on a recurring basis to measure our contingent consideration that is a result of certain acquisitions. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and are classified within Level 3.

The following tables present the financial instruments carried at fair value as of September 30, 2010 (unaudited), December 31, 2009 and 2008, by combined balance sheet caption and by valuation hierarchy as described above:

	September 30, 2010
	Level 1		Level 2			Level 3			Total Carrying Value
	(Unaudited)
	(Millions)
Current assets:
Commodity derivatives (a)	$	—	$	35.0		$	—		$	35.0
Long-term assets:
Commodity derivatives (b)	$	—	$	1.0		$	—		$	1.0
Current liabilities :
Commodity derivatives (c)	$	—	$	(29.4	)	$	—		$	(29.4	)
Acquisition related contingent consideration (d)	$	—	$	—		$	(2.1	)	$	(2.1	)
Long-term liabilities (e):
Commodity derivatives	$	—	$	(1.4	)	$	—		$	(1.4	)

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NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

	December 31, 2009											December 31, 2008
	Level 1		Level 2			Level 3			Total Carrying Value			Level 1		Level 2			Level 3		Total Carrying Value
	(Millions)
Current assets:
Commodity derivatives (a)	$	—	$	34.6		$	0.8		$	35.4		$	—	$	52.9		$	0.2	$	53.1
Long-term assets:
Commodity derivatives (b)	$	—	$	4.2		$	0.5		$	4.7		$	—	$	1.4		$	—	$	1.4
Current liabilities :
Commodity derivatives (c)	$	—	$	(31.1	)	$	(0.8	)	$	(31.9	)	$	—	$	(47.5	)	$	—	$	(47.5	)
Long-term liabilities (e):
Commodity derivatives	$	—	$	(4.2	)	$	(0.3	)	$	(4.5	)	$	—	$	(1.2	)	$	—	$	(1.2	)

(a) Included in current unrealized gains on derivative instruments in our combined balance sheets.

(b) Included in long-term unrealized gains on derivative instruments in our combined balance sheets.

(c) Included in current unrealized losses on derivative instruments in our combined balance sheets.

(d) Included in other current liabilities in our combined balance sheets.

(e) Included in long-term unrealized losses on derivative instruments in our combined balance sheets.

Changes in Level 3 Fair Value Measurements

The tables below illustrate a rollforward of the amounts included in our combined balance sheets for derivative financial instruments that we have classified within Level 3. The determination to classify a financial instrument within Level 3 is based upon the significance of the unobservable factors used in determining the overall fair value of the instrument. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. In the event that there were movements to/from the classification of an instrument as Level 3, we would reflect such items in the table below within the “Transfers into Level 3” and “Transfers out of Level 3” captions.

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We manage our overall risk at the portfolio level, and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforward below, the gains or losses in the table do not reflect the effect of our total risk management activities.

	Commodity Derivative Instruments
	Current Assets			Long-Term Assets			Current Liabilities			Long-Term Liabilities
	(Unaudited)
	(Millions)
Nine months ended September 30, 2010:
Beginning balance	$	0.8		$	0.5		$	(0.8	)	$	(0.3	)
Net realized and unrealized gains (losses) included in earnings		0.2			(0.5	)		0.2			0.3
Transfers into Level 3 (a)		—			—			—			—
Transfers out of Level 3 (a)		(1.0	)		—			0.6			—
Purchases, issuances and settlements, net		—			—			—			—
Ending balance	$	—		$	—		$	—		$	—
Net unrealized gains (losses) still held included in earnings (b)	$	—		$	—		$	—		$	—
Nine months ended September 30, 2009:
Beginning balance	$	0.2		$	—		$	—		$	—
Net realized and unrealized gains (losses) included in earnings		0.2			0.7			(0.4	)		(0.4	)
Net transfers (out) of/into Level 3 (c)		(0.1	)		—			0.1			—
Purchases, issuances and settlements, net		—			—			—			—
Ending balance	$	0.3		$	0.7		$	(0.3	)	$	(0.4	)
Net unrealized gains (losses) still held included in earnings (b)	$	0.3		$	0.7		$	(0.3	)	$	(0.4	)

(a) Amounts transferred in and amounts transferred out are reflected at fair value as of the end of the period.

(b) Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to change in unrealized gains or losses relating to assets and liabilities classified as Level 3 that are still held as of September 30, 2010 and 2009.

(c) Amounts transferred in are reflected at the fair value as of the beginning of the period and amounts transferred out are reflected at fair value at the end of the period.

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	Commodity Derivative Instruments
	Current Assets			Long-Term Assets		Current Liabilities			Long-Term Liabilities
	(Millions)
Year ended December 31, 2009:
Beginning balance	$	0.2		$	—	$	—		$	—
Net realized and unrealized gains (losses) included in earnings		1.0			0.5		(0.8	)		(0.3	)
Net transfers in (out) of Level 3 (a)		—			—		—			—
Purchases, issuances and settlements, net		(0.4	)		—		—			—
Ending balance	$	0.8		$	0.5	$	(0.8	)	$	(0.3	)
Net unrealized gains (losses) still held included in earnings (b)	$	0.9		$	0.5	$	(0.8	)	$	(0.3	)
Year ended December 31, 2008:
Beginning balance	$	—		$	—	$	—		$	—
Net realized and unrealized gains included in earnings		0.2			—		—			—
Net transfers in (out) of Level 3 (a)		—			—		—			—
Purchases, issuances and settlements, net		—			—		—			—
Ending balance	$	0.2		$	—	$	—		$	—
Net unrealized gains still held included in earnings (b)	$	0.2		$	—	$	—		$	—

(a) Amounts transferred in are reflected at the fair value as of the beginning of the period and amounts transferred out are reflected at fair value at the end of the period.

(b) Represents the amount of total gains or losses for the period, included in gains or losses from commodity derivative activity, net, attributable to change in unrealized gains or losses relating to assets and liabilities classified as Level 3 that are still held as of December 31, 2009 and 2008.

As of June 30, 2010, we recognized the fair value of our contingent consideration, which is classified as Level 3, in relation to our acquisition of the Raywood processing plant and Liberty gathering system, of approximately $3.1 million (unaudited), which we recorded to other current liabilities in our combined balance sheets. As of September 30, 2010, we reassessed the fair value of the contingent consideration and adjusted the fair value of the liability to $2.1 million. Accordingly we recognized $1.0 million (unaudited) in other income in our combined statements of operations for the nine months ended September 30, 2010.

During the nine months ended September 30, 2010 (unaudited), we had the following transfers into and out of Levels 1, 2 and 3. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period.

	Nine Months Ended September 30, 2010
	Transfers from Level  1 to Level 2		Transfers from Level  2 to Level 1		Transfers from Level  2 to Level 3		Transfers from Level  3 to Level 2 (a)
	(Unaudited)
	(Millions)
Current assets	$	—	$	—	$	—	$	1.0
Current liabilities	$	—	$	—	$	—	$	(0.6	)

(a) Financial instruments have moved into a lower level due to the passage of time. The inputs now include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly.

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NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Estimated Fair Value of Financial Instruments

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

The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short term nature of these instruments. Unrealized gains and unrealized losses on derivative instruments are carried at fair value.

9. Risk Management and Hedging Activities

Our day to day operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell and the creditworthiness of each of our counterparties. We manage certain of these exposures with both physical and financial transactions. All of our derivative activities are conducted under the governance of Midstream’s internal Risk Management Committee that establishes policies, limiting exposure to market risk and requiring daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate daily value at risk. The following briefly describes each of the risks that we manage.

Commodity Price Risk

Our natural gas asset based trading and marketing activities engage in the business of trading energy related products and services, including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and we may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. We manage commodity price risk related to owned natural gas storage and pipeline assets by engaging in natural gas asset based trading and marketing. The commercial activities related to our natural gas asset based trading and marketing primarily consist of time spreads and basis spreads.

We may execute a time spread transaction when the difference between the current price of natural gas (cash or futures) and the futures market price for natural gas exceeds our cost of storing physical gas in our owned and/or leased storage facilities. The time spread transaction allows us to lock in a margin when this market condition exists. A time spread transaction is executed by establishing a long gas position at one point in time and establishing a corresponding short gas position at a future point in time. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period combined statement of operations. While gas held in our storage location is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facility is recorded at fair value and any changes in fair value are currently recorded in our combined statements of operations. Even though we may have economically hedged our exposure and locked in a future margin the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.

We may execute basis spread transactions when the market price differential between locations on a pipeline asset exceeds our cost of transporting physical gas through our owned and/or leased pipeline asset. When this market condition exists, we may execute derivative instruments around this differential at the market price. This basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period combined statements of operations. As discussed above, the accounting for physical gas purchases and sales and the accounting for the derivative instruments used to manage such purchases and sales differ, and may subject our earnings to market volatility, even though the transaction represents an economic hedge in which we have locked in a future margin.

Additionally, in order for our storage facility to remain operational, we maintain a minimum level of base gas in our storage cavern, which is capitalized on our combined balance sheets as a component of property, plant and equipment, net. In the fourth quarter of 2008 we commenced a capacity expansion project for our storage cavern, which required us to sell all of the base gas within the cavern. During 2009, the expansion project was completed and base gas was repurchased to restore our storage cavern to operation. To mitigate the risk associated with the forecasted re-purchase of base gas, we executed a series of derivative

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

financial instruments, which were designated as cash flow hedges. The cash paid upon settlement of these hedges economically offsets the cash paid to purchase the base gas. A deferred loss of $2.7 million was recognized and will remain in AOCI until such time that our cavern is emptied and the base gas is sold.

Contingent Credit Features

Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances.

We have International Swap Dealers Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below.

• In the event that Midstream was to be downgraded below investment grade by at least one of the major credit rating agencies, certain of our ISDA counterparties may have the right to reduce our collateral threshold to zero, potentially requiring us to fully collateralize any commodity contracts in a net liability position.

• Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under those agreements and the amount of the default is above certain predefined thresholds, which are significantly high. As of September 30, 2010, we are not a party to any agreements that would be subject to these provisions.

Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features.

Depending upon the movement of commodity prices, each of our individual contracts with counterparties to our commodity derivative instruments are in either a net asset or net liability position. As of September 30, 2010 and December 31, 2009 we had $2.1 million (unaudited) and $5.7 million, respectively, of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position, and have not posted any cash collateral relative to such positions. If a credit-risk related event were to occur and we were required to net settle our position with an individual counterparty, our ISDA contracts permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of September 30, 2010 and December 31, 2009, if a credit-risk related event were to occur we may be required to post additional collateral. Additionally, although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of September 30, 2010 and December 31, 2009, if a credit-risk related event were to occur, the net liability position would be partially offset by contracts in a net asset position reducing our net liability to $2.0 million (unaudited) and $4.9 million, as of September 30, 2010 and December 31, 2009, respectively.

Summarized Derivative Information

The following summarizes the balance within AOCI relative to our commodity cash flow hedges:

	September 30, 2010			December 31, 2009			December 31, 2008
	(Unaudited)
	(Millions)
Commodity cash flow hedges:
Net deferred losses in AOCI	$	(2.7	)	$	(2.7	)	$	(0.7	)
Total AOCI	$	(2.7	)	$	(2.7	)	$	(0.7	)

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NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

The fair value of our derivative instruments that are designated as hedging instruments, those that are marked-to-market each period, as well as the location of each within our combined balance sheets, by major category, is summarized as follows:

Balance Sheet Line Item	September 30, 2010		December 31, 2009		December 31, 2008		Balance Sheet Line Item	September 30, 2010			December 31, 2009			December 31, 2008
	(Unaudited)							(Unaudited)
	(Millions)							(Millions)
Derivative Assets Designated as Hedging Instruments:							Derivative Liabilities Designated as Hedging Instruments:
Commodity derivatives:							Commodity derivatives:
Unrealized gains on derivative instruments – current	$	—	$	0.6	$	—	Unrealized losses on derivative instruments – current	$	—		$	(3.1	)	$	—
Unrealized gains on derivative instruments – long-term		—		—		—	Unrealized losses on derivative instruments – long-term		—			—			(0.7	)
	$	—	$	0.6	$	—		$	—		$	(3.1	)	$	(0.7	)
Derivative Assets Not Designated as Hedging Instruments:							Derivative Liabilities Not Designated as Hedging Instruments:
Commodity derivatives:							Commodity derivatives:
Unrealized gains on derivative instruments – current	$	35.0	$	34.8	$	53.1	Unrealized losses on derivative instruments – current	$	(29.4	)	$	(28.8	)	$	(47.5	)
Unrealized gains on derivative instruments – long-term		1.0		4.7		1.4	Unrealized losses on derivative instruments – long-term		(1.4	)		(4.5	)		(0.5	)
	$	36.0	$	39.5	$	54.5		$	(30.8	)	$	(33.3	)	$	(48.0	)

The following tables summarize the impact on our combined balance sheet and combined statements of operations of our derivative instruments that are accounted for using the cash flow hedge method of accounting.

	Gain (Loss) Recognized in AOCI on Derivatives — Effective Portion					Gain (Loss) Recognized in Income on Derivatives — Ineffective Portion and Amount Excluded From Effectiveness Testing					Deferred Losses in AOCI Expected to be Reclassified into Earnings Over the 12 Months Ended September 30, 2011
	Nine Months Ended September 30,
	2010		2009			2010		2009
	(Unaudited)
	(Millions)					(Millions)					(Millions)
Commodity derivatives	$	—	$	(1.4	)	$	—	$	—	(a)	$	—

(a) For the nine months ended September 30, 2010 and 2009, no derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

	Loss Recognized in AOCI on Derivatives — Effective  Portion						Gain (Loss) Recognized in Income on Derivatives — Ineffective Portion and Amount Excluded From Effectiveness Testing					Deferred Losses in AOCI Expected to be Reclassified into Earnings Over the 12 Months Ended December 31, 2010
	Year Ended December 31,
	2009			2008			2009		2008
	(Millions)						(Millions)					(Millions)
Commodity derivatives	$	(2.0	)	$	(0.7	)	$	—	$	—	(a)	$	—

(a) For the years ended December 31, 2009 and 2008, no derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.

Changes in value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recorded in the combined statements of operations. The following summarizes these amounts and the location within the combined statements of operations that such amounts are reflected:

Commodity Derivatives: Statements of Operations Line Item	Nine Months  Ended September 30,						Year Ended December 31,
	2010			2009			2009			2008			2007
	(Unaudited)
	(Millions)
Third party:
Realized	$	9.9		$	8.3		$	9.5		$	11.8		$	16.9
Unrealized		(0.5	)		(1.9	)		(0.6	)		1.0			(13.0	)
Gains from commodity derivative activity, net	$	9.4		$	6.4		$	8.9		$	12.8		$	3.9
Affiliates:
Realized	$	(0.2	)	$	(0.1	)	$	0.2		$	(0.3	)	$	(0.6	)
Unrealized		(0.5	)		0.5			0.4			0.4			4.6
(Losses) gains from commodity derivative activity, net — affiliates	$	(0.7	)	$	0.4		$	0.6		$	0.1		$	4.0

We do not have any derivative financial instruments that qualify as a hedge of a net investment.

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

The following table represents, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the table below. This table also presents our net long or short natural gas basis swap positions separately from our net long or short natural gas positions.

	September 30, 2010
	Natural Gas			Natural Gas Basis Swaps
Year of Expiration	Net Long (Short) Position (MMBtu)			Net Long (Short) Position (MMBtu)
	(Unaudited)
2010		(13,932,500	)		5,092,500
2011		(3,650,000	)		16,245,000
2012		—			13,700,000
	December 31, 2009
	Natural Gas			Natural Gas Basis Swaps
Year of Expiration	Net Long (Short) Position (MMBtu)			Net Long (Short) Position (MMBtu)
2010		(16,552,500	)		(8,670,000	)
2011		(3,650,000	)		1,460,000

10. Income Taxes

The State of Texas imposes a margin tax that is assessed at 1% of taxable margin apportioned to Texas. Accordingly, we have recorded current tax expense for the Texas margin tax beginning in 2007.

Income tax expense consists of the following:

	Nine Months  Ended September 30,						Year Ended December 31,
	2010			2009			2009			2008			2007
	(Unaudited)
	(Millions)
Current:
State	$	(0.5	)	$	(0.4	)	$	(0.5	)	$	(0.6	)	$	(0.6	)
Deferred:
State		—			—			0.1			(0.1	)		(0.1	)
Total income tax expense	$	(0.5	)	$	(0.4	)	$	(0.4	)	$	(0.7	)	$	(0.7	)

We had net long-term deferred tax liabilities of $2.0 million (unaudited), $2.0 million, and $2.1 million as of September 30, 2010, December 31, 2009 and 2008, respectively. The net long-term deferred tax liabilities are included in other long-term liabilities on the combined balance sheets and are primarily associated with depreciation and amortization related to property.

Our effective tax rate differs from statutory rates primarily due to us being treated as a pass-through entity for United States income tax purposes, while being treated as a taxable entity in Texas.

25

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

11. Commitments and Contingent Liabilities

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

Insurance — Midstream’s insurance coverage is carried with an affiliate of ConocoPhillips, an affiliate of Spectra Energy and third-party insurers. Midstream’s insurance coverage includes: (1) general liability insurance covering third-party exposures; (2) statutory workers’ compensation insurance; (3) automobile liability insurance for all owned, non-owned and hired vehicles; (4) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (5) property insurance, which covers the replacement value of real and personal property and includes business interruption/extra expense; and (6) directors and officers insurance covering Midstream’s directors and officers for acts related to Midstream’s business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations.

A portion of the insurance costs described above are allocated by Midstream to us through the allocation methodology described in Note 5.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste storage, management, transportation and disposal, and other environmental matters including recently adopted EPA regulations related to reporting of greenhouse gas emissions which became effective in January 2010. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions or restrictions on operations. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our combined results of operations, financial position or cash flows.

12. Supplemental Cash Flow Information

	Nine Months Ended September 30,				Year Ended December 31,
	2010		2009		2009		2008		2007
	(Unaudited)
	(Millions)
Non-cash investing and financing activities:
Other non-cash additions of property, plant and equipment	$	1.3	$	1.1	$	0.3	$	2.8	$	0.3

13. Subsequent Events

We have evaluated subsequent events occurring through November 8, 2010.

On November 4, 2010, Midstream entered into agreements with DCP Midstream Partners, LP, or Partners, a master limited partnership of which Midstream acts as general partner, to sell a 33.33% interest in us for $150 million. The terms of our joint venture agreement provide that distributions to Partners from us for the first seven years related to the storage business and transportation margins will be pursuant to a fee-based arrangement, based on storage capacity and tailgate volumes. Distributions related to the gathering and processing business, along with reductions for all expenditures, will be pursuant to our owners’ respective interests in us. This transaction is expected to close in January 2011, resulting in our ownership as 66.67% by Midstream and 33.33% by Partners.

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THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

14. Subsequent Events (Unaudited)

We have evaluated subsequent events occurring through January 6, 2011, the date that the combined financial statements were issued, and also through March 2, 2011, the date that the combined financial statements were restated. See note 15 for discussion on restatement.

On January 1, 2011 Partners acquired a 33.33% interest in us from Midstream. As part of the closing of the contribution, the assets, liabilities and operations of the Business now reside in a new legal entity DCP Southeast Texas Holdings, GP, with the exception of any financial derivative instruments and certain working capital and other liabilities.

15. Restatement (Unaudited)

Subsequent to the issuance of our unaudited combined financial statements for the nine months ended September 30, 2010 in Partners current report on Form 8-K filed on January 6, 2011, the management of Partners concluded that the impact of Hurricane Ike business interruption insurance recoveries related to the Business for the nine months ended September 30, 2010, had not been identified from the separate records maintained by Midstream and had been improperly omitted from the unaudited combined financial statements of the Business. As a result, it was determined that revenues should be increased by $4.6 million for the nine months ended September 30, 2010. No other periods were impacted.

The effect of the restatement was as follows for the nine months ended September 30, 2010 (Unaudited):

	As  Previously Reported		Adjustments			As Restated
	(Millions)
Combined Statement of Operations:
Sales of natural gas, NGLs and condensate	$	310.1	$	0.9		$	311.0
Sales of natural gas, NGLs and condensate to affiliates	$	276.9	$	0.9		$	277.8
Transportation, processing and other	$	8.6	$	1.4		$	10.0
Transportation, processing and other to affiliates	$	—	$	1.4		$	1.4
Total operating revenues	$	604.3	$	4.6		$	608.9
Operating income	$	27.2	$	4.6		$	31.8
Net income	$	26.7	$	4.6		$	31.3
Combined Statement of Comprehensive Income:
Net income	$	26.7	$	4.6		$	31.3
Total comprehensive income	$	26.7	$	4.6		$	31.3
Combined Statement of Cash Flows:
OPERATING ACTIVITIES:
Net income	$	26.7	$	4.6		$	31.3
Net cash provided by operating activities	$	25.0	$	4.6		$	29.6
FINANCING ACTIVITIES:
Net change in parent advances	$	64.2	$	(4.6	)	$	59.6
Net cash provided by (used in) financing activities	$	64.2	$	(4.6	)	$	59.6
Combined Statement of Net Parent Equity:
Net change in parent advances	$	64.2	$	(4.6	)	$	59.6
Net income	$	26.7	$	4.6		$	31.3
Total comprehensive income	$	26.7	$	4.6		$	31.3

27