SEC Filing | DCP Midstream, LP

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8-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): November 4, 2010

DCP MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)


Delaware	001-32678	03-0567133
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

370 17^th Street, Suite 2775 Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (303) 633-2900

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Explanatory Note

This amended Current Report on Form 8-K/A (this “Form 8-K/A”) is being filed to supplement the Current Report on Form 8-K filed by DCP Midstream Partners, LP (the “Partnership”) on November 8, 2010 (File No.: 001-32678 ), announcing the transaction entered into between the Partnership and DCP Midstream, LLC, whereby the Partnership will acquire a 33.33% interest in the Southeast Texas Midstream Business, for $150 million, which is expected to close in January 2011 (the “Transaction”). In connection with the Transaction, the Partnership is filing (i) as Exhibit 99.1 to this Form 8-K/A, audited combined financial statements of the Southeast Texas Midstream Business as of December 31, 2009 and 2008, and for the years ended December 31, 2009, 2008 and 2007, and unaudited combined financial statements of the Southeast Texas Midstream Business as of June 30, 2010, and for the six months ended June 30, 2010 and 2009; (ii) as Exhibit 99.2 to this Form 8-K/A, audited consolidated financial statements of Ceritas Holdings, LP as of December 31, 2009 and 2008, and for the years ended December 31, 2009, 2008 and 2007, and unaudited consolidated financial statements of Ceritas Holdings, LP as of March 31, 2010, and for the three months ended March 31, 2010 and 2009; and (iii) as Exhibit 99.3 to this Form 8-K/A, the unaudited pro forma condensed consolidated financial statements of the Partnership as of June 30, 2010, and for the six months ended June 30, 2010, and for the years ended December 31, 2009, 2008 and 2007.

Item 9.01

Financial Statements and Exhibits.

(a)

Financial statements of businesses acquired.

Audited combined financial statements of the Southeast Texas Midstream Business as of December 31, 2009 and 2008, and for the years ended December 31, 2009, 2008 and 2007, and unaudited combined financial statements of the Southeast Texas Midstream Business as of June 30, 2010, and for the six months ended June 30, 2010 and 2009, are attached hereto as Exhibit 99.1, and are incorporated herein by reference.

Audited consolidated financial statements of Ceritas Holdings, LP as of December 31, 2009 and 2008, and for the years ended December 31, 2009, 2008 and 2007, and unaudited consolidated financial statements of Ceritas Holdings, LP as of March 31, 2010, and for the three months ended March 31, 2010 and 2009, are attached hereto as Exhibit 99.2, and are incorporated herein by reference.

(b)

Pro forma financial information.

The unaudited pro forma condensed consolidated financial statements of the Partnership as of June 30, 2010, and for the six months ended June 30, 2010, and for the years ended December 31, 2009, 2008 and 2007, are attached hereto as Exhibit 99.3, and are incorporated herein by reference.

(c)

Not applicable.

(d)

Exhibits.


Exhibit Number		Description

Exhibit 23.1		Consent of Deloitte & Touche LLP on Southeast Texas Midstream Business Combined Financial Statements as of December 31, 2009 and 2008 and for the years ended December 31, 2009, 2008 and 2007.

Exhibit 23.2		Consent of Deloitte & Touche LLP on the Ceritas Holdings, LP Consolidated Financial Statements as of December 31, 2009 and 2008 and for the years ended December 31, 2009, 2008 and 2007.

Exhibit 99.1		Audited and unaudited historical combined financial statements of the Southeast Texas Midstream Business.

Exhibit 99.2		Audited and unaudited historical consolidated financial statements of Ceritas Holdings, LP.

Exhibit 99.3		Unaudited pro forma condensed consolidated financial statements of DCP Midstream Partners, LP.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


	DCP Midstream Partners, LP

	By:	DCP Midstream GP, LP
		its General Partner

	By:	DCP Midstream GP, LLC
		its General Partner

Date: November 9, 2010	/s/ Angela A. Minas
	Name: Angela A. Minas
	Title: Vice President and Chief Financial Officer

EXHIBIT INDEX


Exhibit Number		Description

Exhibit 23.1		Consent of Deloitte & Touche LLP on Southeast Texas Midstream Business Combined Financial Statements as of December 31, 2009 and 2008 and for the years ended December 31, 2009, 2008 and 2007.

Exhibit 23.2		Consent of Deloitte & Touche LLP on the Ceritas Holdings, LP Consolidated Financial Statements as of December 31, 2009 and 2008 and for the years ended December 31, 2009, 2008 and 2007.

Exhibit 99.1		Audited and unaudited historical combined financial statements of the Southeast Texas Midstream Business.

Exhibit 99.2		Audited and unaudited historical consolidated financial statements of Ceritas Holdings, LP.

Exhibit 99.3		Unaudited pro forma condensed consolidated financial statements of DCP Midstream Partners, LP.

Consent of Deloitte & Touche LLP on Southeast Texas Midstream

Exhibit 23.1

CONSENT OF INDEPENDENT AUDITORS

We consent to the incorporation by reference in Registration Statement No. 333-142271 on Form S-8 and Registration Statement No. 333-167108 on Form S-3 of our report dated November 3, 2010 (November 8, 2010, as to Note 13), relating to the combined financial statements of the Southeast Texas Midstream Business (which report expresses an unqualified opinion including an explanatory paragraph referring to the preparation of the combined financial statements from the separate records maintained by DCP Midstream, LLC), appearing in this Current Report on Form 8-K/A of DCP Midstream Partners, LP dated November 9, 2010.

/s/ Deloitte & Touche LLP

Denver, Colorado

November 8, 2010

Consent of Deloitte & Touche LLP on the Ceritas Holdings, LP

Exhibit 23.2

CONSENT OF INDEPENDENT AUDITORS

We consent to the incorporation by reference in Registration Statement No. 333-142271 on Form S-8 and Registration Statement No. 333-167108 on Form S-3 of our report dated April 30, 2010 (June 24, 2010, as to Note 8), relating to the consolidated financial statements of CERITAS Holdings LP and subsidiaries (the “Partnership”) (which report expresses an unqualified opinion including explanatory paragraphs regarding (i) a going concern uncertainty related to the Partnership’s negative working capital and the July 2010 termination of the Partnership’s line of credit and (ii) the retrospective adjustment for discontinued operations), appearing in this Current Report on Form 8-K/A of DCP Midstream Partners, LP dated November 9, 2010.

/s/ Deloitte & Touche LLP

Houston, Texas

November 8, 2010

Southeast Texas Midstream Business combined financial statements

Exhibit 99.1

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED FINANCIAL STATEMENTS

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

AND FOR THE SIX MONTHS ENDED JUNE 30, 2010 (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


	June 30, 2010			December 31, 2009			December 31, 2008
	(Unaudited)
	(Millions)
ASSETS
Current assets:
Accounts receivable:
Trade	$	44.1		$	37.3		$	30.5
Affiliates		3.0			1.5			10.8
Inventories		17.4			19.5			5.7
Unrealized gains on derivative instruments		19.2			35.4			53.1

Total current assets		83.7			93.7			100.1
Property, plant and equipment, net		260.6			225.2			223.4
Goodwill, net		11.8			—			—
Intangibles, net		34.9			—			—
Unrealized gains on derivative instruments		1.5			4.7			1.4
Other long-term assets		0.8			0.5			0.5

Total assets	$	393.3		$	324.1		$	325.4

LIABILITIES AND NET PARENT EQUITY
Current liabilities:
Accounts payable:
Trade	$	51.6		$	66.7		$	45.9
Affiliates		—			—			1.0
Unrealized losses on derivative instruments		20.5			31.9			47.5
Other		7.2			4.3			7.5

Total current liabilities		79.3			102.9			101.9
Unrealized losses on derivative instruments		2.7			4.5			1.2
Other long-term liabilities		4.0			4.4			4.7

Total liabilities		86.0			111.8			107.8


Commitments and contingent liabilities

Equity:
Parent equity		310.0			215.0			218.3
Accumulated other comprehensive loss		(2.7	)		(2.7	)		(0.7	)

Total net parent equity		307.3			212.3			217.6

Total liabilities and net parent equity	$	393.3		$	324.1		$	325.4

See accompanying notes to combined financial statements.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF OPERATIONS


	Six Months Ended June 30,						Year Ended December 31,
	2010			2009			2009			2008			2007
	(Unaudited)
							(Millions)
Operating revenues:
Sales of natural gas, NGLs and condensate	$	214.0		$	130.4		$	274.4		$	707.9		$	533.4
Sales of natural gas, NGLs and condensate to affiliates		181.6			95.5			241.9			410.5			364.6
Transportation, processing and other		5.6			4.3			9.7			10.8			10.0
Transportation, processing and other to affiliates		—			—			—			—			1.4
Gains from commodity derivative activity, net		1.3			4.6			8.9			12.8			3.9
(Losses) gains from commodity derivative activity, net — affiliates		(0.8	)		0.1			0.6			0.1			4.0

Total operating revenues		401.7			234.9			535.5			1,142.1			917.3

Operating costs and expenses:
Purchases of natural gas and NGLs		367.4			203.8			471.5			1,049.2			844.1
Purchases of natural gas and NGLs from affiliates		0.3			0.6			0.6			16.2			1.8
Operating and maintenance expense		8.0			8.3			14.5			17.6			14.2
Depreciation expense		6.2			5.9			12.0			11.8			11.0
General and administrative expense — affiliates		4.9			5.1			10.8			10.6			12.3
Loss on sale of assets		—			0.5			0.5			1.8			—

Total operating costs and expenses		386.8			224.2			509.9			1,107.2			883.4

Operating income		14.9			10.7			25.6			34.9			33.9
Income tax expense		(0.3	)		(0.3	)		(0.4	)		(0.7	)		(0.7	)

Net income	$	14.6		$	10.4		$	25.2		$	34.2		$	33.2

See accompanying notes to combined financial statements.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF COMPREHENSIVE INCOME


	Six Months Ended June 30,					Year Ended December 31,
	2010		2009			2009			2008			2007
	(Unaudited)
	(Millions)
Net income	$	14.6	$	10.4		$	25.2		$	34.2		$	33.2

Other comprehensive loss:
Net unrealized losses on cash flow hedges		—		(1.9	)		(2.0	)		(0.7	)		—

Total other comprehensive loss		—		(1.9	)		(2.0	)		(0.7	)		—

Total comprehensive income	$	14.6	$	8.5		$	23.2		$	33.5		$	33.2

See accompanying notes to combined financial statements.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

COMBINED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,						Year Ended December 31,
	2010			2009			2009			2008			2007
	(Unaudited)
	(Millions)
OPERATING ACTIVITIES:
Net income	$	14.6		$	10.4		$	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 expense		6.2			5.9			12.0			11.8			11.0
Other, net		—			—			0.1			(0.1	)		0.1
Change in operating assets and liabilities, which (used) provided cash:
Accounts receivable		(4.6	)		20.0			2.1			23.5			(15.9	)
Inventories		2.2			(2.9	)		(13.8	)		32.8			(7.6	)
Net unrealized losses (gains) on derivative instruments		6.3			6.3			—			(1.4	)		8.4
Accounts payable		(18.2	)		(13.7	)		19.8			(45.8	)		30.5
Other current assets and liabilities		(0.8	)		(1.2	)		(0.7	)		0.9			2.6
Other long-term assets and liabilities		(0.7	)		(0.3	)		(0.4	)		(0.2	)		(0.5	)

Net cash provided by operating activities		5.0			25.0			44.8			57.5			61.8

INVESTING ACTIVITIES:
Capital expenditures		(6.6	)		(10.9	)		(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		(85.4	)		(9.8	)		(16.3	)		(8.4	)		(22.1	)

FINANCING ACTIVITIES:
Net change in parent advances		80.4			(15.2	)		(28.5	)		(49.1	)		(39.7	)

Net cash provided by (used in) financing activities		80.4			(15.2	)		(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.

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 (Unaudited)		80.4			—			80.4
Comprehensive income:
Net income (Unaudited)		14.6			—			14.6

Total comprehensive income (Unaudited)		14.6			—			14.6

Balance, June 30, 2010 (Unaudited)	$	310.0		$	(2.7	)	$	307.3

See accompanying notes to combined financial statements.

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 June 30, 2010, Midstream owned an approximately 32% interest, including 1% general partner interest, in DCP Midstream Partners, LP, or Partners. 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 six months ended June 30, 2010 and 2009, the combined statements of comprehensive income for the six months ended June 30, 2010 and 2009, the combined statements of changes in net parent equity for the six months ended June 30, 2010, and the combined balance sheet as of June 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 six months ended June 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.

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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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:


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 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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

•

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 June 30, 2010, December 31, 2009 and December 31, 2008, were imbalances of $0.2 million (unaudited), $0.1 million and $0.1 million, respectively. Included in the combined balance sheets as accounts payable—trade as of June 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 June 30, 2010 (unaudited), December 31, 2009 and December 31, 2008, we had no environmental liabilities in our combined balance sheets.

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 six months ended June 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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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 have recorded a liability of $3.1 million (unaudited), which represents the initial fair value of the contingent consideration and is recorded in other current liabilities within the combined balance sheets as of June 30, 2010. The acquired system will connect with our existing southeast Texas assets.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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 assets and liabilities 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 six months ended June 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 six months ended June 30, 2010, revenues of $0 (unaudited) and net income of $0 (unaudited) associated with the acquired assets, from the date of acquisition through June 30, 2010 have been included in the combined statements of operations.


	Six Months Ended June 30, 2010						Six Months Ended June 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	$	401.7	$	22.6	$	424.3	$	234.9	$	21.4	$	256.3
Net income	$	14.6	$	2.0	$	16.6	$	10.4	$	1.3	$	11.7

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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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 six months ended June 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 six months ended June 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:


	Six Months Ended June 30,						Year Ended December 31,
	2010			2009			2009			2008			2007
	(Unaudited)
	(Millions)
DCP Midstream, LLC:
Sales of natural gas, NGLs and condensate	$	170.2		$	71.5		$	216.5		$	313.6		$	305.7
Purchases of natural gas and NGLs	$	0.3		$	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	$	4.9		$	5.1		$	10.8		$	10.6		$	12.3
ConocoPhillips:
Sales of natural gas, NGLs and condensate	$	11.4		$	23.7		$	25.1		$	96.9		$	58.9
Purchases of natural gas and NGLs	$	—		$	0.1		$	0.1		$	5.8		$	1.2
Gains on derivative activity, net	$	—		$	0.2		$	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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

We had balances with affiliates as follows:


	June 30, 2010			December 31, 2009		December 31, 2008
	(Unaudited)
	(Millions)
DCP Midstream, LLC:
Unrealized losses on derivative instruments — current	$	(0.2	)	$	—	$	—
ConocoPhillips:
Accounts receivable	$	3.0		$	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		June 30, 2010			December 31, 2009			December 31, 2008
			(Unaudited)
			(Millions)
Gathering systems		15 — 30 Years	$	72.9		$	59.6		$	56.7
Underground storage		0 — 50 Years		121.7			98.5			99.8
Processing plants		25 — 30 Years		90.0			70.1			68.5
Transportation		25 — 30 Years		105.3			103.2			103.1
General plant		3 — 5 Years		2.6			1.6			1.5
Land		Non-Depreciable		1.3			1.2			0.5
Construction work in progress				2.0			20.0			10.3

Property, plant and equipment				395.8			354.2			340.4
Accumulated depreciation				(135.2	)		(129.0	)		(117.0	)

Property, plant and equipment, net			$	260.6		$	225.2		$	223.4

The above amounts include accrued capital expenditures of $0.7 million (unaudited) for the six months ended June 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 six months ended June 30, 2010 and 2009 or for the years ended December 31, 2009, 2008 and 2007.

Depreciation expense was $6.2 million (unaudited) and $5.9 million (unaudited) for the six months ended June 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 $0.8 million (unaudited) at June 30, 2010, $0.8 million at December 31, 2009 and $0.7 million at December 31, 2008. Accretion expense for the six months ended June 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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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 June 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.

As of June 30, 2010, we held intangible assets of $34.9 million (unaudited) as a result of our acquisition of the Raywood processing plant and Liberty gathering system from Ceritas. These intangible assets consist primarily of customer contracts. Estimated amortization for these contracts for the next five years and thereafter is as follows as of June 30, 2010:

Estimated Amortization

(Unaudited)

(Millions)


2010 (remainder)	$	1.2
2011		2.3
2012		2.3
2013		2.3
2014		2.3
Thereafter		24.5

Total	$	34.9

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 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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

•

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.

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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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 June 30, 2010 (unaudited), December 31, 2009 and 2008, by combined balance sheet caption and by valuation hierarchy as described above:


	June 30, 2010
	Level 1		Level 2			Level 3			Total Carrying Value
	(Unaudited)
	(Millions)
Current assets:
Commodity derivatives (a)	$	—	$	18.5		$	0.7		$	19.2

Long-term assets:
Commodity derivatives (b)	$	—	$	0.9		$	0.6		$	1.5

Current liabilities :
Commodity derivatives (c)	$	—	$	(20.1	)	$	(0.4	)	$	(20.5	)
Acquisition related contingent consideration (d)	$	—	$	—		$	(3.1	)	$	(3.1	)

Long-term liabilities (e):
Commodity derivatives	$	—	$	(2.0	)	$	(0.7	)	$	(2.7	)

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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)
Six months ended June 30, 2010:
Beginning balance	$	0.8		$	0.5	$	(0.8	)	$	(0.3	)
Net realized and unrealized gains (losses) included in earnings		—			0.1		0.2			(0.4	)
Transfers into Level 3 (a)		—			—		—			—
Transfers out of Level 3 (a)		(0.1	)		—		0.2			—
Purchases, issuances and settlements, net		—			—		—			—

Ending balance	$	0.7		$	0.6	$	(0.4	)	$	(0.7	)

Net unrealized gains (losses) still held included in earnings (b)	$	0.3		$	0.1	$	(0.2	)	$	(0.4	)


Six months ended June 30, 2009:
Beginning balance	$	0.2		$	—	$	—		$	—
Net realized and unrealized gains (losses) included in earnings		0.2			0.4		(0.2	)		(0.1	)
Net transfers (out) of/into Level 3 (c)		(0.3	)		—		0.1			—
Purchases, issuances and settlements, net		—			—		—			—

Ending balance	$	0.1		$	0.4	$	(0.1	)	$	(0.1	)

Net unrealized gains (losses) still held included in earnings (b)	$	0.1		$	0.4	$	(0.1	)	$	(0.1	)

(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 June 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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)


	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.

During the six months ended June 30, 2010 (unaudited), we had no significant 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.

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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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 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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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 June 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 June 30, 2010 and December 31, 2009 we had $2.0 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 June 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 June 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 $1.9 million (unaudited) and $4.9 million, as of June 30, 2010 and December 31, 2009, respectively.

Summarized Derivative Information

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


	June 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	June 30, 2010		December 31, 2009		December 31, 2008		Balance Sheet Line Item	June 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	$	19.2	$	34.8	$	53.1	Unrealized losses on derivative instruments – current	$	(20.5	)	$	(28.8	)	$	(47.5	)
Unrealized gains on derivative instruments – long-term		1.5		4.7		1.4	Unrealized losses on derivative instruments – long-term		(2.7	)		(4.5	)		(0.5	)

	$	20.7	$	39.5	$	54.5		$	(23.2	)	$	(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 June 30, 2011
	Six Months Ended June 30,
	2010		2009			2010		2009
						(Unaudited)
	(Millions)					(Millions)					(Millions)
Commodity derivatives	$	—	$	(1.9	)	$	—	$	—	(a)	$	—

(a)	For the six months ended June 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.

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)	$	—	$	—	(b)	$	—

(a)	Included in sales of natural gas, NGLs and condensate in our combined statements of operations.

(b)	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	Six Months Ended June 30,						Year Ended December 31,
	2010			2009			2009			2008			2007
	(Unaudited)
Third party:	(Millions)
Realized	$	9.3		$	11.1		$	9.5		$	11.8		$	16.9
Unrealized		(8.0	)		(6.5	)		(0.6	)		1.0			(13.0	)

Gains from commodity derivative activity, net	$	1.3		$	4.6		$	8.9		$	12.8		$	3.9

Affiliates:
Realized	$	(0.1	)	$	(0.1	)	$	0.2		$	(0.3	)	$	(0.6	)
Unrealized		(0.7	)		0.2			0.4			0.4			4.6

(Losses) gains from commodity derivative activity, net — affiliates	$	(0.8	)	$	0.1		$	0.6		$	0.1		$	4.0

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

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.


	June 30, 2010
	Natural Gas			Natural Gas Basis Swaps
Year of Expiration	Net Long (Short) Position (MMBtu)			Net Long (Short) Position (MMBtu)
	(Unaudited)
2010		(7,952,500	)		11,142,500
2011		(3,650,000	)		21,040,000
2012		—			9,585,000

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)


	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:


	Six Months Ended June 30,						Year Ended December 31,
	2010			2009			2009			2008			2007
	(Unaudited)
	(millions)
Current:
State	$	(0.3	)	$	(0.3	)	$	(0.5	)	$	(0.6	)	$	(0.6	)
Deferred:
State		—			—			0.1			(0.1	)		(0.1	)

Total income tax expense	$	(0.3	)	$	(0.3	)	$	(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 June 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.

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.

THE SOUTHEAST TEXAS MIDSTREAM BUSINESS

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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


	Six Months Ended June 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	$	0.7	$	0.7	$	0.3	$	2.8	$	0.3

13.

Subsequent Events

We have evaluated subsequent events occurring through November 8, 2010, the date the combined financial statements were issued.

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.

Ceritas Holdings, LP consolidated financial statements

Exhibit 99.2

CERITAS Holdings, LP

Consolidated Financial Statements as of March 31,

2010 (Unaudited) and December 31, 2009 and

2008, and for the Years Ended December 31, 2009,

2008 and 2007, and for the Three Month Periods

Ended March 31, 2010 and 2009 (Unaudited) and

Independent Auditors’ Report


				Deloitte & Touche LLP
				Suite 4500
				1111 Bagby Street
				Houston, TX 77002-4196
				USA
				Tel: +1 713 982 2000
				Fax: +1 713 982 2001
				www.deloitte.com

INDEPENDENT AUDITORS’ REPORT

The Board of Directors of

CERITAS Holdings, LP:

We have audited the accompanying consolidated balance sheets of CERITAS Holdings, LP and subsidiaries (the “Partnership”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2009. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated 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 Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the 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 consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2009 and 2008, and the results of its operations and its 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 consolidated financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Partnership’s negative working capital, which is attributable to the July 2010 termination of the Partnership’s line of credit, raises substantial doubt about its ability to continue as a going concern. Management’s plans concerning this matter is also discussed in Note 1 to the consolidated financial statements. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 8 to the consolidated financial statements, the accompanying consolidated financial statements have been retrospectively adjusted for discontinued operations.

/s/ Deloitte & Touche LLP

April 30, 2010, except for the retrospective adjustment for discontinued operations discussed in Note 8, as to which the date is June 24, 2010.


				Member of
				Deloitte Touche Tohmatsu

CERITAS HOLDINGS, LP

CONSOLIDATED BALANCE SHEETS

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


	March 31,			December 31,			December 31,
	2010			2009			2008
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	444,787		$	508,000		$	546,550
Accounts receivable		814,830			434,279			1,263,867
Prepayments and other current assets		120,723			122,593			146,613
Current assets held for sale		5,825,585			6,376,215			7,809,481


Total current assets		7,205,925			7,441,087			9,766,511


PROPERTY, PLANT, AND EQUIPMENT:
Oil and gas properties — at cost (successful efforts method):
Proved properties		3,269,254			3,216,435			3,159,779
Accumulated depletion		(2,719,117	)		(2,664,135	)		(2,046,181	)


Total oil and gas properties — net		550,137			552,300			1,113,598


Office furniture and equipment		308,815			308,815			289,434
Accumulated depreciation		(187,313	)		(171,877	)		(110,883	)


Total office furniture and equipment — net		121,502			136,938			178,551

DEFERRED CHARGES — Net		263,799			467,822			693,485

OTHER ASSETS		129,393			129,393			206,097

OTHER ASSETS HELD FOR SALE		112,396,372			113,721,827			123,264,212


TOTAL	$	120,667,128		$	122,449,367		$	135,222,454


LIABILITIES AND PARTNERS’ EQUITY

CURRENT LIABILITIES:
Current portion of debt	$	78,098,594		$	78,196,827		$	—
Accounts payable		464,050			462,128			2,936,997
Accrued liabilities		178,418			776,693			2,801
Other liabilities		99,000			99,000			99,000
Current liabilities held for sale		3,978,208			4,639,932			19,751,068

Total current liabilities		82,818,270			84,174,580			22,789,866

LONG-TERM DEBT								67,100,000

ASSET RETIREMENT OBLIGATION		49,680			48,827			45,393

ASSET RETIREMENT OBLIGATION HELD FOR SALE		1,330,334			1,307,488			1,215,537

PARTNERS’ EQUITY		36,468,844			36,918,472			44,071,658


TOTAL	$	120,667,128		$	122,449,367		$	135,222,454

See notes to consolidated financial statements.

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CERITAS HOLDINGS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE THREE MONTH PERIODS ENDED MARCH 31, 2010 AND 2009 (UNAUDITED) AND

FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007


	For the			For the
	Three-Months			Three-Months
	Ended			Ended			For the Year Ended
	March 31,			March 31,			December 31,			December 31,		December 31,
	2010			2009			2009			2008		2007
	(Unaudited)
REVENUES:
Oil and gas production revenue	$	632,354		$	549,323		$	2,096,121		$	6,222,767	$	4,017,822


COST AND EXPENSES:
Lease operating expenses		154,028			151,877			708,266			1,315,429		805,469
Depreciation, depletion and amortization		70,418			117,993			678,944			1,038,172		750,262
General and administrative		427,419			534,436			2,020,824			3,765,057		4,003,397


Total cost and expenses		651,865			804,306			3,408,034			6,118,658		5,559,128


OPERATING (LOSS) INCOME		(19,511	)		(254,983	)		(1,311,913	)		104,109		(1,541,306	)

INTEREST AND OTHER INCOME		—			6,216			6,757			79,663		1,179


(LOSS) INCOME FROM CONTINUING OPERATIONS		(19,511	)		(248,767	)		(1,305,156	)		183,772		(1,540,127	)

(LOSS) INCOME FROM DISCONTINUED OPERATIONS — Net of income tax		(430,117	)		(1,086,173	)		(5,848,030	)		5,025,434		(1,962,220	)


NET (LOSS) INCOME	$	(449,628	)	$	(1,334,940	)	$	(7,153,186	)	$	5,209,206	$	(3,502,347	)

See notes to consolidated financial statements.

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CERITAS HOLDINGS, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

FOR THE THREE MONTH PERIOD ENDED MARCH 31, 2010 (UNAUDITED) AND

FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007


							Total
	General			Limited			Partners’
	Partner			Partners			Equity
BALANCE — January 1, 2007	$	42,365		$	42,322,434		$	42,364,799

Net loss		(3,502	)		(3,498,845	)		(3,502,347	)


BALANCE — December 31, 2007		38,863			38,823,589			38,862,452

Net income		5,209			5,203,997			5,209,206


BALANCE — December 31, 2008		44,072			44,027,586			44,071,658

Net income		(7,153	)		(7,146,033	)		(7,153,186	)


BALANCE — December 31, 2009		36,919			36,881,553			36,918,472

Net income (unaudited)		(450	)		(449,178	)		(449,628	)


BALANCE — March 31, 2010 (unaudited)	$	36,469		$	36,432,375		$	36,468,844

See notes to consolidated financial statements.

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CERITAS HOLDINGS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE THREE MONTH PERIODS ENDED MARCH 31, 2010 AND 2009 (UNAUDITED) AND

FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007


	For the			For the
	Three-Months			Three-Months
	Ended			Ended			For the Year Ended
	March 31,			March 31,			December 31			December 31			December 31
	2010			2009			2009			2008			2007
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(449,628	)	$	(1,334,940	)	$	(7,153,186	)	$	5,209,206		$	(3,502,347	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization		1,749,921			3,527,453			13,995,944			14,020,608			12,572,352
Debt issuance amortization		204,044			109,498			653,163			386,835			1,233,247
Deferred income tax		7,087			24,000			162,841			(14,833,289	)		(1,233,600	)
Accretion expense		23,699			23,700			95,388			94,798			87,238
Loss on sale of assets		—			449			3,168						41,199
Loss on abandonment		—			—			—			23,623			—
Effect of changes in current assets and liabilities:
(Increase) decrease in accounts receivable and accrued oil and gas sales		152,081			2,672,091			2,200,782			(299,700	)		(936,880	)
(Increase) decrease in inventory and other current assets		19,868			10,695			86,092			(53,828	)		19,501
Increase (decrease) in accounts payable and accrued expenses, and other		(1,250,294	)		(15,067,119	)		(16,773,142	)		13,118,766			(5,788,840	)


Net cash provided by (used in) operating activities		456,778			(10,034,173	)		(6,728,950	)		17,667,019			2,491,870


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions in gathering and processing facilities and transportation contracts		(341,467	)		(3,724,131	)		(3,863,125	)		(28,023,635	)		(11,650,667	)
Proceeds from the sale of furniture and fixtures		—			7,779			18,779			—			15,000
Additions to oil and gas properties		(52,819	)					(56,656	)		(52,587	)		(50,630	)
Additions to furniture and fixtures		(27,472	)		(17,574	)		(77,925	)		(327,356	)		(347,115	)


Net cash used in investing activities		(421,758	)		(3,733,926	)		(3,978,927	)		(28,403,578	)		(12,033,412	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Debt issuance costs		—			—			(427,500	)		(127,441	)		(1,249,105	)
Issuance of debt		—			14,000,000			14,000,000			22,000,000			72,700,000
Payment of debt		(98,233	)		—			(2,903,173	)		(12,000,000	)		(63,250,000	)


Net cash (used in) provided by financing activities		(98,233	)		14,000,000			10,669,327			9,872,559			8,200,895


NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(63,213	)		231,901			(38,550	)		(864,000	)		(1,340,647	)

CASH AND CASH EQUIVALENTS — Beginning of year		508,000			546,550			546,550			1,410,550			2,751,197


CASH AND CASH EQUIVALENTS — End of year	$	444,787		$	778,451		$	508,000		$	546,550		$	1,410,550


INTEREST PAID	$	1,402,575		$	572,818		$	3,664,223		$	3,428,102		$	4,946,176


INVESTMENTS IN PROPERTY, PLANT, AND EQUIPMENT FUNDED THROUGH ACCOUNTS PAYABLE	$	29,926		$	531,528		$	37,730		$	2,561,746		$	130,313


CASH PAID FOR TAXES	$	—		$	13,079,014		$	13,365,508		$	6,967		$	38,404

See notes to consolidated financial statements.

- 5 -

CERITAS HOLDINGS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business — CERITAS Holdings, LP (“the Partnership”) was formed on March 28, 2005, as a Delaware limited partnership. Energy Spectrum Partners IV, LP owns an 88.11% limited interest in the Partnership, the CERITAS Group owns a 9.79%, WMJ Operations, LP owns a 2.00% limited interest in the Partnership, and CERITAS Energy, LLC owns 0.10% of the Partnership and is the general partner. The Partnership owns 100% of Optigas, LLC (“Optigas”), 100% of CERITAS Management, LLC, 99.9% of CERITAS Gathering Company, LP, which owns 99% of Liberty Gathering Company, LP (“Liberty”), and 100% of Liberty Pipeline, LLC, which owns 1% of Liberty. Liberty owns 100% of Raywood Gas Plant, LLC (“Raywood”). CERITAS Management, LLC owns 0.10% of CERITAS Gathering Company, LP. The accompanying financial statements are consolidated and include the accounts of CERITAS Holdings, LP, CERITAS Management, LLC, CERITAS Gathering Company, LP, Liberty Pipeline, LLC, Liberty, Raywood, and Optigas. All intercompany amounts and transactions have been eliminated in consolidation. CERITAS Holdings, LP and its subsidiaries are referred to herein as the “Partnership.”

Liberty owns and operates high- and low-pressure gathering assets in Liberty County, Texas. The gathering assets were purchased in April 2005. The system is supplied with wellhead gas purchased by Liberty from multiple producers at several pipeline interconnects, transported, and then sold by Liberty to the Enterprise Products Channel intrastate pipeline at two interconnects and/or the Kinder Morgan Tejas intrastate pipeline.

Raywood was formed on July 18, 2006, as a Texas limited liability company and is wholly owned by Liberty. Raywood owns and operates a natural gas processing plant. The plant was constructed on Liberty’s pipeline system in Liberty County, Texas and began operations in November 2006.

On March 21, 2006, the Partnership acquired Optigas. Optigas is engaged in the midstream energy business with gas gathering and compression assets located in the Powder River Basin in Wyoming. Optigas provides natural gas gathering, and related services, which include compression, for natural gas producers. Optigas also owns working interests in coal bed methane gas acreage in the Powder River Basin.

Basis of Presentation — The accompanying financial statements of the Partnership were prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). Subsequent events have been evaluated through November 8, 2010, the date these financial statements were available to be issued.

The unaudited consolidated financial statements as of March 31, 2010 and for the three month periods March 31, 2010 and 2009 are unaudited and reflect all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the statement of financial condition and results of operation for the periods covered by such statements. The interim results are not necessarily indicative of the results of the full year.

Going Concern — The accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. At December 31, 2009, the Partnership’s negative working capital is attributable to the July 2010 termination of the Partnership’s line of credit. Management has undertaken a process to sell substantially all of the Partnership’s assets and believes sufficient assets can be sold prior to termination of the Partnership’s line of credit; however, no assurance can be provided that such sales will occur. Absent the timely sale of sufficient assets to pay off the line of credit, management intends to seek a forbearance which will allow them to complete the sale of the Partnership’s assets. The financial statements do not include any adjustment that might result from this uncertainty.

- 6 -

Use of Estimates in the Preparation of Financial Statements — The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenue Recognition — The Partnership’s revenue is derived from producing, gathering, transporting, processing, and marketing natural gas. Marketing revenues are recognized based on actual volumes of natural gas sold to purchasers. The Partnership’s gathering and transportation revenue is recognized based upon actual volumes delivered. Oil and gas production revenue is recognized as title passes under the sales method. Under this method, the Partnership recognizes revenue on production as it is taken and delivered to its purchasers. For processing services, the Partnership either receives fees or commodities from natural gas producers under percentage-of-proceeds contracts. The Partnership is paid for its services by keeping a percentage of the natural gas liquids produced. Commodities received are in turn sold and recognized as revenue.

Cash and Cash Equivalents — Cash and cash equivalents include all cash balances and highly liquid investments with original maturities of less than three months.

Concentrations of Credit Risk — The Partnership regularly has cash in a single financial institution, which exceeds depository insurance limits. The Partnership places such deposits with high credit quality institutions and has not experienced any credit losses. Substantially all of the Partnership’s accounts receivable at March 31, 2010 and December 31, 2009 and 2008, result from the sale, transportation, or processing of natural gas. This concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be similarly impacted by industry-wide changes in economic or other conditions. Such receivables are generally not collateralized. However, the Partnership performs credit evaluations on all customers to minimize exposure to credit risk.

During 2009, the Partnership sold 98% of its natural gas and natural gas liquids to two customers. At December 31, 2009, 96% of accounts receivable were due from one customer. During 2008, the Partnership sold 67% of its natural gas and natural gas liquids to two customers. At December 31, 2008, 69% of accounts receivable were due from three customers. During 2007, the Partnership sold 74% of its natural gas and natural gas liquids to two customers. During both of the unaudited three month periods ended March 31, 2010 and 2009, the Partnership sold 99% of its natural gas and natural gas liquids to 2 customers. At March 31, 2010 (unaudited), 96% of accounts receivable were from one customer.

Fair Value of Financial Instruments — The Partnership’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, accrued liabilities, and long-term debt. The carrying value of cash and cash equivalents, trade receivables, trade payables, accrued liabilities and long-term debt are considered to be representative of their fair market value, due to the short maturity of these instruments.

Imbalances — In the course of transporting natural gas and natural gas liquids for others, the Partnership may receive for redelivery different quantities of natural gas or natural gas liquids than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables that are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods, if not subject to cash-out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets and are recorded at the market price. At March 31, 2010 (unaudited) and December 31, 2009 and 2008, the Partnership had imbalance receivables of $90,014, $92,502 and $0, respectively.

- 7 -

Allowance for Doubtful Accounts — Management of the Partnership monitors the accounts receivable from its customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. The Partnership had no allowance at March 31, 2010 (unaudited) and December 31, 2009 and 2008.

Property, Plant, and Equipment — Property, plant, and equipment are recorded at cost, less accumulated depreciation and impairment losses. Maintenance and repairs are charged to expense as incurred. Expenditures that extend the useful lives of an asset are capitalized. When assets are retired or otherwise disposed of, the cost of the assets and related accumulated depreciation are removed from the accounts. Any gain or loss on retirements or dispositions is charged to income in the year in which the asset is disposed. Depreciation is provided on a straight-line basis over the following estimated useful lives:


		Years
Office furniture, equipment, and other		3–7
Equipment and easements		15
Gas plant facility		15
Gathering systems and processing facilities		7–15

The cost of assets constructed or otherwise produced for the Partnership’s own use includes the cost of interest incurred during the period of time necessary to bring them to the condition and location of their intended use. The interest capitalization period ends when the assets are substantially complete and ready for their intended use. For the year ended December 31, 2009 and 2008 and the unaudited three-months ended March 31, 2010, the Partnership capitalized no interest. For the year ended December 31, 2007, the Partnership capitalized interest of $188,881.

Oil and Gas Properties — The Partnership follows the successful efforts method of accounting for oil and gas properties. The use of this method results in the capitalization of those costs associated with the acquisition, exploration, and development of properties that produce revenue or are anticipated to produce future revenue. The Partnership does not capitalize general and administrative expenses directly identifiable with such activities. Costs of unsuccessful exploration efforts are expensed in the period it is determined that such costs are not recoverable through future revenues. Geological and geophysical costs and delay rentals are expensed as incurred. The cost of development wells are capitalized whether productive or nonproductive. The Partnership uses the units-of-production method to amortize its oil and gas properties. Changes in reserve quantities will cause corresponding changes in depletion expense in periods subsequent to the quantity revision. Upon the sale of proved properties, the cost and accumulated depletion are removed from the accounts and any gain or loss is charged to income.

Unproved properties are assessed periodically on a project-by-project basis to determine whether impairment has occurred. Management’s assessment of the results of exploration activities, commodity price outlooks, planned future sales, or the cessation of all or a portion of such projects impact the amount and timing of impairment provisions. Factors leading to recording unproved property impairments include lease expirations and an assessment of the lack of exploration opportunities existing on a lease. Future changes in any of the above-referenced factors could result in the Partnership’s recording unproved property impairment charges in future periods. Sales proceeds from unproved oil and natural gas properties are credited to related costs of the prospect sold until such costs are recovered and then to net gain or loss on sales of unproved oil and natural gas properties. The Partnership has no unproved properties.

- 8 -

Proved properties are assessed when an impairment indicator exists to determine whether impairment has occurred. Management’s assessment of future operating expenses and capital requirements for proved reserves impacts the determination and amount of impairment. Product valuation, using future pricing, also affects the determination and amount of impairment. Actual impairment charges are recorded using an estimate of discounted future cash flows. Impairment charges for the year ended December 31, 2009 and 2008 and the unaudited three-months ended March 31, 2010 and 2009 were $55,428, $0, $0 and $0, respectively.

Intangibles — As part of the purchase of the gathering assets of Liberty in April 2005 and the acquisition of Optigas in March 2006, the Partnership acquired the transportation and purchase contracts for the gathering systems. From the purchase price allocation, the contracts were recorded at their estimated fair value. Because these contracts have finite lives, they are being amortized over the life of the contract. Contracts amortization for the year ended December 31, 2009, 2008 and 2007 and the unaudited three-months ended March 31, 2010 and 2009 was $4,154,154, $4,895,747, $5,601,592, $1,012,717, and $1,165,898 respectively. Estimated aggregate amortization expense for each of the five succeeding years as of December 31, 2009 is as follows:


December 31
2010	$	3,468,173
2011		3,273,940
2012		3,273,940
2013		818,488
2014		—

Asset Retirement Obligation — The Partnership records the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred and retirement activity in which the times and/or method of settlement are conditional upon a future event that may or may not be within our control. When the liability is initially recorded, an entity increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Activities related to the Partnership’s ARO for reclamation costs it expect to incur to its coal methane producing properties and gathering systems during each of the three years in the period ended December 31, 2009 and the unaudited three-months ended March 31, 2010, are as follows:


Balance of ARO — December 31, 2007	$	1,166,132

Accretion expense		94,798


Balance of ARO — December 31, 2008		1,260,930

Accretion expense		95,385


Balance of ARO — December 31, 2009		1,356,315

Accretion expense (unaudited)		23,699


Balance of ARO — March 31, 2010 (unaudited)	$	1,380,014

Impairment of Long-Lived Assets — The carrying value of long-lived assets, principally property and equipment, is reviewed for potential impairment when events or changes in circumstances indicate the carrying amount of such assets may not be recoverable. For property and equipment, the determination of recoverability is made based upon the estimated undiscounted future net cash flows of the related asset or group of assets being evaluated. Actual impairment charges are recorded using an estimate of discounted future cash flows. There were no impairment charges of non-oil and gas properties for the year ended December 31, 2009, 2008 and 2007 and for the unaudited three month periods ended March 31, 2010 and 2009.

- 9 -

Income Taxes — The Partnership is a limited partnership and is not subject to federal income tax. As such, the ultimate owners of the Partnership are taxed on their proportionate share of net income.

The liability for deferred federal taxes included within current liabilities of discontinued operation (see note 8) in the Partnership’s consolidated financial statements at December 31, 2008, are those of its subsidiary, Optigas, which was converted to a LLC on July 1, 2008.

Prior to the conversion, Optigas operations were subject to corporate income tax. During those periods, income taxes were calculated on the basis of separate company income and deductions related to Optigas in accordance with established practices. Deferred income taxes were provided for temporary differences between the accounting principles generally accepted in the United States of America and tax carrying amounts of assets and liabilities. These differences create taxable or tax deductible amounts for future periods.

The Partnership continues to be subject to Texas income (margin) tax.

Uncertain Tax Positions — On January 1, 2009, the Partnership adopted a GAAP pronouncement that clarified the accounting for uncertainty in income taxes recognized in the financial statements. The pronouncement provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax position not meeting the more likely than not threshold must be recognized as a liability on the financial statements. This pronouncement also provides guidance on measurement, de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The open tax years are 2006-2009. The Partnership believes there are no material uncertain tax positions.

Deferred Charges — Financing fees are deferred and amortized over the life of the applicable debt instrument. Unamortized deferred financing fees at December 31, 2009 and 2008 and March 31, 2010 (unaudited), were $467,822, $693,485 and $263,799, respectively. Financing fees at December 31, 2009 and 2008 and March 31, 2010 (unaudited), relate to the revolving line of credit obtained in 2007, increased in 2008, and modified in 2009. Financing fees amortized for the years ended December 31, 2009, 2008 and 2007 and for the unaudited three month periods ended March 31, 2010 and 2009, were $653,163, $386,835, $1,233,247, $204,023 and $109,498, respectively.

Derivatives — The Partnership recognizes all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The Partnership’s forward natural gas and crude oil purchase and sales contracts are designated as normal purchases and sales. During 2009, 2008 and 2007, the Partnership used derivatives to mitigate the risks to cash flows resulting from changes in commodity prices. The Partnership realized a loss of $5,871 in 2009, a gain of $1,354,756 in 2008 and a loss of $415,096 in 2007, included in (loss) income from discontinued operation in the consolidated statements of operations related to these instruments.

2.	OPTIGAS/CERITAS MERGER

On March 21, 2006, the Partnership acquired Optigas, a Delaware corporation, in an agreement and plan of merger. As a result of the merger transaction, all outstanding shares of the Optigas common stock were converted into the right to receive an aggregate amount of $85,000,000 in cash plus the amount of working capital. $5,000,000 of the merger consideration was placed in escrow. At December 31, 2007, $5,000,000 was on the Partnership’s consolidated balance sheet as restricted cash and was accounted for as contingent consideration; therefore, it was not included in the purchase price or purchase price allocation, and no liability was recorded. On March 22, 2008, the escrow balance of $5,000,000 was transferred directly to the former shareholders of Optigas and was recorded on the Partnership’s balance sheet as an addition to goodwill.

- 10 -

3.	GOODWILL

Goodwill, which is included in other assets held for sale, is tested for impairment at least annually at the reporting unit level using a two-step impairment test. The Partnership recorded goodwill of $404,735 when the gathering assets were purchased by the Partnership in April 2005. During 2006, a purchase price adjustment related to the Liberty acquisition increased goodwill by $266,440. In 2008, goodwill in the amount of $5,000,000 was added by the transfer of restricted cash to the previous owners of Optigas. During 2009 and 2008, the Partnership tested goodwill for impairment and determined no impairment had occurred.

DEBT

The Partnership obtained a revolving line of credit (RLOC) from Merrill Lynch Capital and a three-bank syndicate of $75,000,000 on July 26, 2007, with a maturity date of July 26, 2010. During 2008, Merrill Lynch Capital assigned their interest in the RLOC to its administrative agent, General Electric Capital Corporation. This assignment did not change the terms of the loan or the covenants. The facility bears interest at London InterBank Offered Rate (LIBOR) plus a margin determined based on the debt to earnings before interest, taxes, depreciation and amortization (EBITDA) ratio as defined in the agreement. The facility was used to consolidate all Partnership bank financings. The facility is secured by all material assets and is guaranteed by all subsidiaries of the Partnership.

On July 1, 2008, the RLOC was increased to $100,000,000 by amendment. On August 4, 2009, the RLOC was decreased, by amendment, to $85,500,000 and decreases each subsequent quarter by the amount of excess cash flow. On March 9, 2010, the agreement was amended to change certain covenant requirements and to waive compliance with these covenants at December 31, 2009 and to reset the financial covenants as of March 31, and June 30, 2010.

At March 31, 2010 (unaudited) and December 31, 2009 and 2008, the outstanding amount of the RLOC was $78,098,594, $78,196,827 and $67,100,000. The Partnership was in compliance with all terms and conditions as amended as of March 31, 2010 and December 31, 2009.

5.	COMMITMENTS AND CONTINGENCIES

Lease Commitments — The Partnership leases office space under noncancelable operating leases through October 2011. The Partnership also leases various compressors under noncancelable operating leases over various lease periods. The total lease expense for the year ended December 31, 2009, 2008 and 2007 and the unaudited three-months ended March 31, 2010 and 2009, was $1,322,490, $4,113,422, $5,464,206, $199,850 and $359,267, respectively. Future payments under these leases as of December 31, 2009 are as follows:


Years Ending
December 31
2010	$	566,340
2011		351,687
2012		25,200


Total	$	943,227

- 11-

Legal Proceedings — The Partnership is from time to time involved in various legal proceedings characterized as incidental to the business. Management does not believe that the outcome of current legal proceedings will have a materially adverse impact on the Partnership’s consolidated financial position, results of operations, or cash flows.

6.	INCOME TAXES

Income taxes on Optigas operations prior to the July 1, 2008, limited liability company conversion were calculated on the basis of their separate company income and deductions in accordance with established practices. The Partnership used the asset and liability method of accounting for deferred taxes to record the tax effects on Optigas. Deferred tax assets and liabilities were determined based on the difference between the consolidated financial statements and tax bases of assets and liabilities as measured by the enacted tax rates which will be in effect when these differences reverse. Deferred tax expense is the result of changes in deferred tax assets and liabilities.

The components of the provision (benefit) for income taxes included in discontinued operations are as follows:


	For the		For the
	Three-Months		Three-Months
	Ended		Ended		For the Year Ended
	March 31,		March 31,		December 31,		December 31,			December 31,
	2010		2009		2009		2008			2007
	(unaudited)		(unaudited)
Current federal	$	—	$	—	$	—	$	13,079,014		$	38,408
Deferred federal		—		—		—		(14,833,289	)		(1,233,600	)
Current state		—		—		—		326,676			—
Deferred state		7,087		24,000		162,841		(361,284	)		—


Net provision (benefit)	$	7,087	$	24,000	$	162,841	$	(1,788,883	)	$	(1,195,192	)

In conjunction with the conversion to a limited liability company, $1,754,275 of federal income tax liabilities outstanding at June 30, 2008, were eliminated and recorded in (loss) income from discontinued operations as a benefit to income tax expense (benefit) on the consolidated statements of operations. The balance of federal income tax liabilities were reclassified on the Partnership’s consolidated balance sheets to current federal income taxes payable (a component of total liabilities of discontinued operations) for the year ended December 31, 2008.

The Partnership is subject to Texas Franchise Tax based on taxable margin (TMT). The first annual taxable period began January 1, 2007, and the first returns were due in 2008. The Partnership uses the liability method of accounting for TMT. Deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at the end of the period. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The deferred tax provisions presented on the accompanying consolidated balance sheets relate to the effect of temporary book/tax timing differences associated with depreciation and depletion.

- 12 -

Significant components of the Partnership’s total net deferred tax assets and liabilities included in other assets held for sale are as follows:


	March 31,			December 31,			December 31,
	2010			2009			2008
	(Unaudited)
Deferred tax assets — other	$	277,870		$	288,161		$	361,284
Deferred tax liability — PP&E		(86,514	)		(89,718	)		—


Net deferred tax asset	$	191,356		$	198,443		$	361,284

After the July 1, 2008, conversion of Optigas, there are no longer federal or state net operating loss carryforwards. The Partnership is not subject to federal income tax, but rather the taxable income or loss of these entities is reported on the income tax returns of the respective members.

7.	RELATED-PARTY TRANSACTIONS AND BALANCES

WMJ Operations, LP (WMJO) owns a 2% interest in the Partnership. An affiliate of WMJO, WMJ Investments, Corp. (WMJI) receives gas from Liberty. Prior to 2008, WMJI delivered gas to, and received gas from, Liberty. These transactions are accounted for as purchases and sales, respectively. At month-end, a statement is prepared and presented to WMJI that summarizes the purchases and sales for the month. A netting agreement is in place that allows the net amount to be paid to, or received from, WMJI. Under this arrangement in 2009, Liberty sold gas valued at $40,673. In 2008, Liberty sold gas valued at $368,235. In 2007, Liberty sold gas valued at $592,405 and purchased gas valued at $20,193. During the unaudited three month periods ended March 31, 2010 and March 31, 2009, Liberty sold gas valued at $14,121 and $12,336 respectively. At March 31, 2010 (unaudited), WMJI owed Liberty $18,027. At December 31, 2009, WMJI owed Liberty $3,906. At December 31, 2008, Liberty owed WMJI $14,165.

Other liabilities of $99,000 represent a payable to an affiliate.

The Partnership provides management, accounting, and administrative services to Ceritas Holdings II, LLC (CHII). CHII is an unconsolidated affiliate of the Partnership. In April 2008, the Partnership entered into an agreement with CHII that provides compensation for these services. Under this agreement, the Partnership invoices CHII a percentage of the general and administrative expenses that benefit both entities. The percentage for 2010 and 2009 and 2008 was 50%, 50%, and 40% respectively. The Partnership accounts for this re-bill on the consolidated operating statement as a reduction of general and administrative expenses. For the year ended December 31, 2009 and 2008, the amounts invoiced for these services totaled $2,233,088 and $1,031,790 respectively. For the unaudited three-months ended March 31, 2010 and March 31, 2009, the amounts invoiced for these services totaled $396,808 and $612,340 respectively.

CHII holds an equity interest in Ute Energy, LLC (UE). In June and August 2009, the partnership entered into commodity transactions with J.P. Morgan Ventures Energy Corporation (JPM) on behalf of, and for the benefit of UE. UE reimbursed the partnership for their payments to JPM and receipts from JPM were forwarded to UE. No fees or commissions were charged or received by the partnership. All commodity positions were settled by December 31, 2009 and there were no outstanding receivables or payables between any of the parties related to these transactions.

- 13 -

8.	DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

During the unaudited three month period ended March 31, 2010, the Partnership undertook an active process to market its Raywood, Liberty and Optigas midstream businesses. The Partnership engaged a third party advisor in connection with these plans. The accompanying financial statements have been retrospectively adjusted to present these businesses as discontinued operations. Management of the Partnership expects the Raywood and Liberty businesses to be sold in June 2010 and the Optigas midstream business to be sold by the end of 2010. The Partnership classified these businesses as held for sale and ceased depreciating and amortizing these assets in mid-February 2010.

The Partnership’s remaining operations not classified as held for sale at March 31, 2010 include the Partnership’s working interests in coal bed methane gas acreage in the Powder River Basin.

The following table summarizes the results classified as Discontinued Operations, net of tax, in the consolidated statements of operations.

Discontinued Operations


	March 31, 2010									March 31, 2009
	(Unaudited)									(Unaudited)
				Raywood									Raywood
	Optigas			Liberty			Total			Optigas			Liberty			Total
REVENUES:
Natural gas sales	$	—		$	4,151,221		$	4,151,221		$	—		$	6,226,857		$	6,226,857
Gathering fees		2,690,916			—			2,690,916			3,900,865			—			3,900,865
Natural gas liquids and condensate sales		—			8,244,125			8,244,125			—			5,199,517			5,199,517
Risk management activity		—			—			—			—			(5,871	)		(5,871	)


Total revenues		2,690,916			12,395,346			15,086,262			3,900,865			11,420,503			15,321,368


COST AND EXPENSES:
Cost of natural gas and natural gas liquids		—			10,148,068			10,148,068			—			9,510,965			9,510,965
Operating, transporting, and compression costs		1,107,458			372,895			1,480,353			1,535,850			573,497			2,109,347
Depreciation and amortization		1,332,808			346,694			1,679,502			2,596,787			812,671			3,409,458
Accretion expense		21,870			1,830			23,700			21,870			1,830			23,700
General and administrative		481,333			122,968			604,301			560,186			125,108			685,294
Loss on sale of property		—			—			—			449			—			449


Total cost and expenses		2,943,469			10,992,455			13,935,924			4,715,142			11,024,071			15,739,213


OPERATING (LOSS) INCOME		(252,553	)		1,402,891			1,150,338			(814,277	)		396,432			(417,845	)

INTEREST EXPENSE		(1,573,368	)		—			(1,573,368	)		(644,084	)		—			(644,084	)

INTEREST AND OTHER INCOME		—			—			—			—			(244	)		(244	)


(LOSS) INCOME BEFORE INCOME TAX		(1,825,921	)		1,402,891			(423,030	)		(1,458,361	)		396,188			(1,062,173	)

INCOME TAX (EXPENSE) BENEFIT		—			(7,087	)		(7,087	)		—			(24,000	)		(24,000	)


(LOSS) INCOME FROM DISCONTINUED OPERATIONS	$	(1,825,921	)	$	1,395,804		$	(430,117	)	$	(1,458,361	)	$	372,188		$	(1,086,173	)

- 14 -


	December 31, 2009									December 31, 2008								December 31, 2007
				Raywood									Raywood								Raywood
	Optigas			Liberty			Total			Optigas			Liberty		Total			Optigas			Liberty			Total
REVENUES:
Natural gas sales	$	—		$	17,336,209		$	17,336,209		$	—		$	39,706,852	$	39,706,852		$	—		$	23,444,669		$	23,444,669
Gathering fees		13,848,899			—			13,848,899			15,638,592			—		15,638,592			15,862,751			—			15,862,751
Natural gas liquids and condensate sales		—			23,200,822			23,200,822			—			47,232,607		47,232,607			—			31,333,161			31,333,161
Risk management activity		(5,871	)		—			(5,871	)		—			1,379,456		1,379,456			—			(415,096	)		(415,096	)


Total revenues		13,843,028			40,537,031			54,380,059			15,638,592			88,318,915		103,957,507			15,862,751			54,362,734			70,225,485


COST AND EXPENSES:
Cost of natural gas and natural gas liquids		—			32,686,379			32,686,379			—			72,241,740		72,241,740			—			43,576,802			43,576,802
Operating, transporting, and compression costs		5,275,546			1,527,547			6,803,093			7,762,898			1,355,297		9,118,195			7,414,953			1,468,530			8,883,483
Depreciation and amortization		10,516,618			2,800,378			13,316,996			9,728,874			3,253,560		12,982,434			8,540,897			3,368,430			11,909,327
Accretion expense		87,480			7,909			95,389			87,480			7,320		94,800
General and administrative		2,370,239			479,841			2,850,080			2,234,730			495,365		2,730,095			2,170,854			611,127			2,781,981
Loss on sale of property		3,168			—			3,168			—			—		—			—			41,199			41,199


Total cost and expenses		18,253,051			37,502,054			55,755,105			19,813,982			77,353,282		97,167,264			18,126,704			49,066,088			67,192,792


OPERATING (LOSS) INCOME		(4,410,023	)		3,034,977			(1,375,046	)		(4,175,390	)		10,965,633		6,790,243			(2,263,953	)		5,296,646			3,032,693

INTEREST EXPENSE		(4,317,385	)		—			(4,317,385	)		(3,606,708	)		—		(3,606,708	)		(6,030,279	)		(264,830	)		(6,295,109	)

INTEREST AND OTHER INCOME		733			6,509			7,242			22,234			30,782		53,016			28,208			76,792			105,000


(LOSS) INCOME BEFORE INCOME TAX		(8,726,675	)		3,041,486			(5,685,189	)		(7,759,864	)		10,996,415		3,236,551			(8,266,024	)		5,108,608			(3,157,416	)

INCOME TAX (EXPENSE) BENEFIT		—			(162,841	)		(162,841	)		1,754,275			34,608		1,788,883			1,195,196			—			1,195,196


(LOSS) INCOME FROM DISCONTINUED OPERATIONS	$	(8,726,675	)	$	2,878,645		$	(5,848,030	)	$	(6,005,589	)	$	11,031,023	$	5,025,434		$	(7,070,828	)	$	5,108,608		$	(1,962,220	)

- 15 -

Summarized Balance Sheet Information for Assets and Associated Liabilities Held for Sale


	March 31, 2010 (Unaudited)									December 31, 2009									December 31, 2008
	Optigas			Raywood Liberty			Total			Optigas			Raywood Liberty			Total			Optigas			Raywood Liberty			Total
ASSETS

CURRENT ASSETS:
Accounts receivable	$	1,598,578		$	3,985,393		$	5,583,971		$	2,016,193		$	4,100,410		$	6,116,603		$	2,011,829		$	5,475,968		$	7,487,797
Inventory		—			18,405			18,405			—			18,405			18,405			—			7,157			7,157
Prepayments and other current assets		127,763			95,446			223,209			146,925			94,282			241,207			258,689			55,838			314,527


Total current assets of discontinued operations	$	1,726,341		$	4,099,244		$	5,825,585		$	2,163,118		$	4,213,097		$	6,376,215		$	2,270,518		$	5,538,963		$	7,809,481


PROPERTY, PLANT, AND EQUIPMENT:
Property easements	$	—		$	4,349,530		$	4,349,530$		$	—		$	4,349,530		$	4,349,530		$	—		$	4,275,728		$	4,275,728
Gathering assets and equipment		—			10,949,625			10,949,625			—			10,892,393			10,892,393			—			10,448,172			10,448,172
Gas processing facility		—			18,284,925			18,284,925			—			18,291,990			18,291,990			—			16,927,443			16,927,443
Gathering and processing facilities		90,516,805			—			90,516,805			90,233,309			—			90,233,309			88,215,026			—			88,215,026
Accumulated depreciation		(23,160,595	)		(5,152,500	)		(28,313,095	)		(22,253,866	)		(4,902,923	)		(27,156,789	)		(15,142,904	)		(2,982,758	)		(18,125,662	)


Total gathering and processing facilities — net		67,356,210			28,431,580			95,787,790			67,979,443			28,630,990			96,610,433			73,072,122			28,668,585			101,740,707

Office furniture and equipment		693,605			—			693,605			666,133			—			666,133			737,095			—			737,095
Accumulated depreciation		(312,235	)		—			(312,235	)		(295,398	)		—			(295,398	)		(271,242	)		—			(271,242	)


Total office furniture and equipment — net		381,370			—			381,370			370,735			—			370,735			465,853			—			465,853

INTANGIBLES — Contracts — net		10,231,065			97,116			10,328,181			10,640,308			194,233			10,834,541			13,914,248			1,074,445			14,988,693

GOODWILL		5,000,000			671,175			5,671,175			5,000,000			671,175			5,671,175			5,000,000			671,175			5,671,175

DEFERRED TAX ASSET		—			191,356			191,356			—			198,443			198,443			—			361,284			361,284

OTHER ASSETS		36,200			300			36,500			36,200			300			36,500			36,200			300			36,500


Total non-current assets of discontinued operations	$	83,004,845		$	29,391,527		$	112,396,372		$	84,026,686		$	29,695,141		$	113,721,827		$	92,488,423		$	30,775,789		$	123,264,212

LIABILITIES

CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	686,218		$	3,291,990		$	3,978,208		$	917,043		$	3,722,889			4,639,932		$	1,041,351		$	5,630,703		$	6,672,054
Federal income taxes payable		—			—			—			—			—			—			13,079,014			—			13,079,014


Total current liabilities of discontinued operations	$	686,218		$	3,291,990		$	3,978,208		$	917,043		$	3,722,889		$	4,639,932		$	14,120,365		$	5,630,703		$	19,751,068


Total asset retirement obligation of discontinued operations	$	1,222,009		$	108,325		$	1,330,334		$	1,200,992		$	106,496		$	1,307,488		$	1,116,947		$	98,590		$	1,215,537

9.	SUBSEQUENT EVENTS (UNAUDITED)

On June 4, 2010, the company executed a purchase and sale agreement to sell its consolidated subsidiary, CERITAS Gathering Company, LP (CGATH), to a third party. CGATH holds the assets and liabilities for the Raywood and Liberty operations. The transaction was completed on June 29, 2010, and the proceeds were used to pay down the Partnerships line of credit.

* * * * * *

- 16 -

DCP Midstream Partners, LP condensed consolidated financial statements

Exhibit 99.3

UNAUDITED DCP MIDSTREAM PARTNERS, LP PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

References to we, us or our, refer to DCP Midstream Partners, LP and its consolidated subsidiaries. On November 4, 2010, we entered into a transaction (the “Transaction”) which is scheduled to close in January 2011 with DCP Midstream, LLC (“Midstream”), to acquire a 33.33% interest in the Southeast Texas Midstream Business (the “Southeast Texas Business” or, including Ceritas, the “Joint Venture”) for $150 million. Ceritas represents the Liberty Gathering Company, LP and Raywood Gas Plant, LLC purchased from Ceritas Holdings, LP by the Southeast Texas Business on June 29, 2010. The Joint Venture is a fully integrated midstream business which includes: 675 miles of natural gas pipelines; three natural gas processing plants totaling 350 MMcf/d of processing capacity; natural gas storage assets with 9 Bcf of existing storage capacity; and NGL market deliveries direct to Exxon Mobil and to Mont Belvieu via our Black Lake NGL pipeline.

As part of the closing of the Transaction, the assets, liabilities and operations of the Joint Venture, except for any financial derivative instruments and certain working capital and other liabilities, will reside in a new legal entity, DCP Southeast Texas Holdings, GP. We will own a 33.33% interest and Midstream will own a 66.67% interest in DCP Southeast Texas Holdings, GP, and Midstream will continue to direct the Joint Venture’s operations. The Joint Venture does not currently and is not expected to have any employees. Midstream and its affiliates’ employees are responsible for conducting the Joint Venture’s business and operating its assets.

Distributions to us will generally approximate our share of earnings from unconsolidated affiliates of the Joint Venture plus depreciation and amortization expense and other non-cash charges of the Joint Venture. The terms of the joint venture agreement provide that distributions to us from the Joint Venture for the first seven years related to storage and transportation gross margin will be pursuant to a fee-based agreement, 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 and Midstream’s respective ownership interests.

The unaudited pro forma condensed consolidated financial statements present the impact on our financial position and results of operations of our acquisition of a 33.33% interest the Joint Venture. The unaudited pro forma condensed consolidated financial statements as of June 30, 2010, and for the six months ended June 30, 2010 have been prepared based on certain pro forma adjustments to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and for the years ended December 31, 2009, 2008 and 2007, have been prepared based on certain pro forma adjustments to our historical consolidated financial statements set forth in our Current Report on Form 8-K, filed on May 26, 2010 with the Securities and Exchange Commission, and are qualified in their entirety by reference to such historical consolidated financial statements and related notes contained therein. The unaudited pro forma condensed consolidated financial statements should be read in conjunction with the accompanying notes and with the historical consolidated financial statements and related notes thereto.

The unaudited pro forma condensed consolidated balance sheet as of June 30, 2010 has been prepared as if the Transaction had occurred on that date. The unaudited pro forma condensed consolidated statements of operations for the six months ended June 30, 2010, and the years ended December 31, 2009, 2008 and 2007, have been prepared as if the Southeast Texas Business transaction had occurred on January 1, 2007 and the Ceritas transaction had occurred on January 1, 2009. Since this is a transaction between entities under common control, the unaudited pro forma condensed consolidated financial statements are combined on an “as if” pooling basis. Accordingly, the historic impact of the acquired assets and liabilities are carried forward.

The pro forma adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. Management believes, however, that the assumptions provide a reasonable basis for presenting the significant effects of the Transaction as contemplated, and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma condensed consolidated financial statements.

The unaudited pro forma condensed consolidated financial statements may not be indicative of the results that actually would have occurred if we had owned an interest in the Joint Venture during the periods presented.

DCP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

JUNE 30, 2010

($ in millions)


	DCP Midstream Partners, LP			The Southeast Texas Midstream Business		Pro Forma Adjustments - Elimination			Pro Forma Adjustments - Other				DCP Midstream Partners, LP Pro Forma
						(b)
ASSETS
Current assets:
Cash and cash equivalents	$	4.8		$	—	$	—		$	82.5		(c)	$	4.8
										67.5		(d)
										(150.0	)	(e)
Accounts receivable		104.4			47.1		(47.1	)		—				104.4
Other		25.5			36.6		(36.6	)		—				25.5

Total current assets		134.7			83.7		(83.7	)		—				134.7
Property, plant and equipment, net		1,008.5			260.6		(260.6	)		—				1,008.5
Goodwill and intangible assets, net		151.0			46.7		(46.7	)		—				151.0
Investments in unconsolidated affiliates		109.8			—		—			102.4		(e)		212.2
Other non-current assets		9.2			2.3		(2.3	)		—				9.2

Total assets	$	1,413.2		$	393.3	$	(393.3	)	$	102.4			$	1,515.6


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	86.3		$	51.6	$	(51.6	)	$	—			$	86.3
Other		54.5			27.7		(27.7	)		—				54.5

Total current liabilities		140.8			79.3		(79.3	)		—				140.8
Long-term debt		615.0			—		—			67.5		(d)		682.5
Other long-term liabilities		53.6			6.7		(6.7	)		—				53.6

Total liabilities		809.4			86.0		(86.0	)		67.5				876.9


Commitments and contingent liabilities

Equity:
Predecessor equity		—			307.3		(307.3	)		—				—
Common unitholders		419.1			—		—			82.5		(c)		454.0
										(47.6	)	(e)
General partner unitholders		(5.8	)		—		—			—				(5.8	)
Accumulated other comprehensive income		(33.7	)		—		—			—				(33.7	)

Total partners’ equity		379.6			307.3		(307.3	)		34.9				414.5
Noncontrolling interests		224.2			—		—			—				224.2

Total equity		603.8			307.3		(307.3	)		34.9				638.7

Total liabilities and equity	$	1,413.2		$	393.3	$	(393.3	)	$	102.4			$	1,515.6

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2010

($ in millions, except per unit amounts)


	DCP Midstream Partners, LP			The Southeast Texas Midstream Business			Ceritas Holdings, LP			Pro Forma Adjustments - Elimination			Pro Forma Adjustments - Other				DCP Midstream Partners, LP Pro Forma
							(a)			(b)
Total operating revenues	$	681.2		$	401.7		$	1.3		$	(403.0	)	$	—			$	681.2


Operating costs and expenses:
Purchases of natural gas, propane and NGLs		538.5			367.7			—			(367.7	)		—				538.5
Operating and maintenance expense		39.6			8.0			0.3			(8.3	)		—				39.6
Depreciation and amortization expense		36.5			6.2			0.1			(6.3	)		—				36.5
General and administrative expense		16.8			4.9			0.9			(5.8	)		—				16.8
Other, net		(3.5	)		—						—			—				(3.5	)

Total operating costs and expenses		627.9			386.8			1.3			(388.1	)		—				627.9

Operating income		53.3			14.9			—			(14.9	)		—				53.3
Interest expense, net		(14.5	)		—			—			—			(1.5	)	(f)		(16.0	)
Earnings from unconsolidated affiliates		14.5			—			—			—			7.5		(g)		22.3
														0.7		(h)
														(0.4	)	(i)

Income before income taxes		53.3			14.9			—			(14.9	)		6.3				59.6
Income tax expense		(0.4	)		(0.3	)		—			0.3			—				(0.4	)

Net income from continuing operations		52.9			14.6			—			(14.6	)		6.3				59.2
Net (loss) income from discontinued operations, net of taxes		—			—			(0.9	)		0.9			—				—
Net income attributable to noncontrolling interests		(1.1	)		—			—			—			—				(1.1	)

Net income attributable to partners	$	51.8		$	14.6		$	(0.9	)	$	(13.7	)	$	6.3			$	58.1

Less:
General partner interest in net income		(8.0	)															(8.5	)

Net income allocable to limited partners	$	43.8															$	49.6


Net income per limited partner unit — basic and diluted	$	1.27															$	1.34


Weighted-average limited partner units outstanding — basic and diluted		34.6																37.1

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2009

($ in millions, except per unit amounts)


	DCP Midstream Partners, LP			The Southeast Texas Midstream Business			Ceritas Holdings, LP			Pro Forma Adjustments - Elimination			Pro Forma Adjustments - Other				DCP Midstream Partners, LP Pro Forma
							(a)			(b)
Total operating revenues	$	942.4		$	535.5		$	2.1		$	(537.6	)	$	—			$	942.4


Operating costs and expenses:
Purchases of natural gas, propane and NGLs		776.2			472.1			—			(472.1	)		—				776.2
Operating and maintenance expense		69.7			14.5			0.7			(15.2	)		—				69.7
Depreciation and amortization expense		64.9			12.0			0.7			(12.7	)		—				64.9
General and administrative expense		32.3			10.8			2.0			(12.8	)		—				32.3
Other, net		—			0.5			—			(0.5	)		—				—

Total operating costs and expenses		943.1			509.9			3.4			(513.3	)		—				943.1

Operating (loss) income		(0.7	)		25.6			(1.3	)		(24.3	)		—				(0.7	)
Interest expense, net		(28.0	)		—			—			—			(3.0	)	(f)		(31.0	)
Earnings from unconsolidated affiliates		18.5			—			—			—			6.0		(g)		24.8
														1.0		(h)
														(0.7	)	(i)

(Loss) income before income taxes		(10.2	)		25.6			(1.3	)		(24.3	)		3.3				(6.9	)
Income tax expense		(0.6	)		(0.4	)		—			0.4			—				(0.6	)

Net (loss) income from continuing operations		(10.8	)		25.2			(1.3	)		(23.9	)		3.3				(7.5	)
Net (loss) income from discontinued operations, net of taxes		—			—			(5.8	)		5.8			—				—
Net income attributable to noncontrolling interests		(8.3	)		—			—			—			—				(8.3	)

Net (loss) income attributable to partners	$	(19.1	)	$	25.2		$	(7.1	)	$	(18.1	)	$	3.3			$	(15.8	)

Less:
Net loss attributable to predecessor operations		1.0																1.0
General partner interest in net income		(12.7	)															(14.2	)

Net loss allocable to limited partners	$	(30.8	)														$	(29.0	)


Net loss per limited partner unit — basic and diluted	$	(0.99	)														$	(0.86	)


Weighted-average limited partner units outstanding — basic and diluted		31.2																33.7

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2008

($ in millions, except per unit amounts)


	DCP Midstream Partners, LP			The Southeast Texas Midstream Business			Pro Forma Adjustments - Elimination			Pro Forma Adjustments - Other				DCP Midstream Partners, LP Pro Forma
							(b)
Total operating revenues	$	1,830.5		$	1,142.1		$	(1,142.1	)	$	—			$	1,830.5


Operating costs and expenses:
Purchases of natural gas, propane and NGLs		1,481.0			1,065.4			(1,065.4	)		—				1,481.0
Operating and maintenance expense		77.4			17.6			(17.6	)		—				77.4
Depreciation and amortization expense		53.2			11.8			(11.8	)		—				53.2
General and administrative expense		33.3			10.6			(10.6	)		—				33.3
Other, net		(1.5	)		1.8			(1.8	)		—				(1.5	)

Total operating costs and expenses		1,643.4			1,107.2			(1,107.2	)		—				1,643.4

Operating income		187.1			34.9			(34.9	)		—				187.1
Interest expense, net		(26.7	)		—			—			(3.0	)	(f)		(29.7	)
Earnings from unconsolidated affiliates		18.2			—			—			7.0		(g)		25.2

Income before income taxes		178.6			34.9			(34.9	)		4.0				182.6
Income tax expense		(0.6	)		(0.7	)		0.7			—				(0.6	)

Net income from continuing operations		178.0			34.2			(34.2	)		4.0				182.0
Net loss attributable to noncontrolling interests		(36.1	)		—			—			—				(36.1	)

Net income attributable to partners	$	141.9		$	34.2		$	(34.2	)	$	4.0			$	145.9

Less:
Net income attributable to predecessor operations		(16.2	)												(16.2	)
General partner interest in net income		(13.0	)												(13.9	)

Net income allocable to limited partners	$	112.7												$	115.8


Net income per limited partner unit — basic and diluted	$	4.11												$	3.87

Weighted-average limited partner units outstanding — basic and diluted		27.4													29.9

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

DCP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2007

($ in millions, except per unit amounts)


	DCP Midstream Partners, LP			The Southeast Texas Midstream Business			Pro Forma Adjustments - Elimination			Pro Forma Adjustments - Other				DCP Midstream Partners, LP Pro Forma
							(b)
Total operating revenues	$	1,346.2		$	917.3		$	(917.3	)	$	—			$	1,346.2

Operating costs and expenses:
Purchases of natural gas, propane and NGLs		1,185.6			845.9			(845.9	)		—				1,185.6
Operating and maintenance expense		59.3			14.2			(14.2	)		—				59.3
Depreciation and amortization expense		40.2			11.0			(11.0	)		—				40.2
General and administrative expense		36.2			12.3			(12.3	)		—				36.2

Total operating costs and expenses		1,321.3			883.4			(883.4	)		—				1,321.3

Operating income		24.9			33.9			(33.9	)		—				24.9
Interest expense, net		(20.1	)		—			—			(3.6	)	(f)		(23.7	)
Earnings from unconsolidated affiliates		24.7			—			—			8.5		(g)		33.2

Income before income taxes		29.5			33.9			(33.9	)		4.9				34.4
Income tax expense		(0.8	)		(0.7	)		0.7			—				(0.8	)

Net income from continuing operations		28.7			33.2			(33.2	)		4.9				33.6
Net income attributable to noncontrolling interests		(29.8	)		—			—			—				(29.8	)

Net (loss) income attributable to partners	$	(1.1	)	$	33.2		$	(33.2	)	$	4.9			$	3.8

Less:
Net income attributable to predecessor operations		(18.3	)												(18.3	)
General partner interest in net income		(3.9	)												(4.5	)

Net loss allocable to limited partners	$	(23.3	)											$	(19.0	)

Net loss per limited partner unit — basic and diluted	$	(1.14	)											$	(0.83	)

Weighted-average limited partner units outstanding — basic and diluted		20.5													23.0

See accompanying notes to unaudited pro forma condensed consolidated financial statements.

NOTES TO UNAUDITED DCP MIDSTREAM PARTNERS, LP

PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1.

Basis of Presentation

The unaudited pro forma condensed consolidated financial statements present the impact on our financial position and results of operations of our acquisition from Midstream of a 33.33% interest in the Southeast Texas Business, including Ceritas which was acquired by the Southeast Texas Business from Ceritas Holdings, LP on June 29, 2010. The pro forma financial statements as of June 30, 2010, and for the six months ended June 30, 2010 have been prepared based on certain pro forma adjustments to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, and for the years ended December 31, 2009, 2008 and 2007, have been prepared based on certain pro forma adjustments to our audited consolidated financial statements set forth in our Current Report on Form 8-K filed on May 26, 2010 with the Securities and Exchange Commission, and are qualified in their entirety by reference to such historical consolidated financial statements and related notes contained in those reports. The unaudited pro forma condensed consolidated financial statements should be read in conjunction with the accompanying notes and with the historical consolidated financial statements and related notes thereto.

The unaudited pro forma condensed consolidated balance sheet as of June 30, 2010, has been prepared as if the Transactions had occurred on the balance sheet date. Since the Transaction is a transaction among entities under common control, the pro forma financial statements are combined on an “as if” pooling basis. Accordingly, the historic impact of the acquired assets and liabilities are carried forward. The Southeast Texas Business was under common control for the six months ended June 30, 2010, and the years ended December 31, 2009, 2008 and 2007, while Ceritas was only under common control since June 29, 2010. Therefore, the unaudited pro forma condensed consolidated statements of operations for the six months ended June 30, 2010, and the years ended December 31, 2009, 2008 and 2007 have been prepared as if the Southeast Texas Business transaction had occurred on January 1, 2007 and the Ceritas transaction occurred on January 1, 2009.

The pro forma condensed consolidated financial statements reflect the Transaction as follows:

•

the assumed borrowing of $67.5 million under our existing credit facility to finance the acquisition;

•

the assumed issuance of 2,500,000 common limited partner units to finance the acquisition;

•

the acquisition of a 33.33% interest in the Joint Venture;

•

the retention by Midstream of any financial derivative instruments and certain working capital and other liabilities; and

•

the aggregate consideration paid to Midstream, consisting of $150.0 million in cash.

Note 2.

Pro Forma Adjustments and Assumptions

(a)

Reflects adjustments to account for Ceritas Holdings, LP activity. For the six months ended June 30, 2010, the Ceritas Holdings, LP amounts for the period January 1, 2010 through June 29, 2010 (the date the Southeast Texas Business purchased Ceritas from Ceritas Holdings, LP) are derived based upon the unaudited historical consolidated statement of operations of Ceritas Holdings, LP for the three months ended March 31, 2010 as attached in Exhibit 99.2. For the year ended December 31, 2009, the Ceritas Holdings, LP amounts are reflective of the audited historical consolidated statement of operations of Ceritas Holdings, LP for the year ended December 31, 2009 as attached in Exhibit 99.2.

(b)

Reflects adjustments to eliminate the Joint Venture’s activity and operating assets and liabilities, including elimination of the activity and operating assets of Ceritas Holdings, LP not purchased by the Southeast Texas Business, as our 33.33% interest will be accounted for under the equity method of accounting.

(c)

Reflects assumed net proceeds to us of $82.5 million from the sale of 2,500,000 of our common units. Consistent with our overall targeted debt and equity ratio to finance our growth, the proposed financing of the Transaction is assumed to consist of 55% from the sale of common units and 45% from borrowings. Actual debt and equity that will be used to finance the Transaction may be different than the assumed ratio. The assumed common unit price, $35.68, is the closing price of our units for the last trading day in October 2010 less estimated offering costs and underwriting discounts of $6.7 million. The actual common unit price, offering costs and underwriting discounts for the financing of the Transaction may be different than our assumptions.

(d)

Reflects assumed proceeds to us from borrowings under our revolving credit facility of $67.5 million. Consistent with our overall targeted debt and equity ratio to finance our growth, the proposed financing of the Transaction is assumed to consist of 45% from borrowings and 55% from the sale of common units. Actual debt and equity that will be used to finance the Transaction may be different than the assumed ratio.

(e)

Reflects the Transaction, along with the related distributions to Midstream of the aggregate consideration. This acquisition will be recorded at Midstream’s cost as it is considered to be a transaction among entities under common control. The consideration was allocated as follows ($ in millions):


	June 30, 2010
Consideration	$	150.0
Less: Historical cost of 33.33% interest in the Joint Venture		102.4

Adjustment to net parent equity for excess consideration	$	47.6

The adjustment to net parent equity was allocated to the common units.

(f)

Reflects the increase in interest expense associated with the incremental debt for the Transaction. The following presents the weighted average interest rates used to calculate the increase in interest expense for the respective periods:


	Weighted Average Interest Rate
Six months ended June 30, 2010		4.34	%
Year ended December 31, 2009		4.41	%
Year ended December 31, 2008		4.48	%
Year ended December 31, 2007		5.34	%

The effect of a 0.125% variance in interest rates on pro forma interest expense would have been approximately $0.1 million annually.

(g)

Reflects the increase in earnings from unconsolidated affiliates associated with the acquisition of a 33.33% interest in the Southeast Texas Business.

For the first seven years following the closing of the Transaction, our portion of the earnings and cash attributable to the Southeast Texas Business’ storage and transportation gross margin will be pursuant to a fee-based arrangement, based on storage capacity and tailgate volumes. Earnings related to the gathering and processing business, along with reductions for all expenditures, will be pursuant to our and Midstream’s respective ownership interests.

The following table reflects the historical net income of the Southeast Texas Business, the removal of the historical storage and transportation gross margin, the replacement with the storage and transportation gross margin adjusted for this fee-based arrangement applied to our historical storage capacity and tailgate volumes, and our resulting adjustment to earnings from unconsolidated affiliates:


	Six Months Ended June 30, 2010			Year Ended December 31, 2009			Year Ended December 31, 2008			Year Ended December 31, 2007
	(Millions)
The historical Southeast Texas Business net income	$	14.6		$	25.2		$	34.2		$	33.2
The historical Southeast Texas Business storage and transportation gross margin		(1.6	)		(24.1	)		(30.0	)		(24.6	)
The Southeast Texas Business storage and transportation gross margin under the fee-based arrangement		9.4			16.8			16.7			16.8

The adjusted Southeast Texas Business net income	$	22.4		$	17.9		$	20.9		$	25.4

Our 33.33% interest in the adjusted Southeast Texas Business net income (earnings from unconsolidated affiliates)	$	7.5		$	6.0		$	7.0		$	8.5

(h)

Reflects the increase in earnings from unconsolidated affiliates associated with the acquisition of a 33.33% interest in Ceritas.

The following table reflects the historical net income of Ceritas, and our resulting adjustment to earnings from unconsolidated affiliates:


	Six Months Ended June 30, 2010		Year Ended December 31, 2009
	(Millions)
The historical Ceritas net income	$	2.0	$	2.9

Our 33.33% interest in the historical Ceritas net income (earnings from unconsolidated affiliates)	$	0.7	$	1.0

(i)

Reflects the adjustment for depreciation and amortization of fixed assets and intangibles recognized on the acquisition of Ceritas, acquired by the Southeast Texas Business from Ceritas Holdings, LP on June 29, 2010. The change in expense represents the difference between historical carrying value and the fair value of the tangible and intangible assets acquired, as well as an adjustment to the assets’ lives. The acquisition of Ceritas was accounted for by the Southeast Texas Business under the purchase method of accounting. The following table reflects the calculation of the depreciation and amortization expense adjustment:


	Six Months Ended June 30, 2010			Year Ended December 31, 2009
	(Millions)
The historical Ceritas depreciation and amortization expense	$	1.2		$	2.8
The adjusted Ceritas depreciation and amortization expense		2.3			5.0

The depreciation and amortization expense adjustment	$	(1.1	)	$	(2.2	)

Our 33.33% interest in depreciation and amortization expense adjustment (earnings from unconsolidated affiliates)	$	(0.4	)	$	(0.7	)

Note 3.

Pro Forma Net Income Per Limited Partner Unit

Our net income or loss is allocated to the general partner and the limited partners, including the holders of the subordinated units, through the date of subordinated conversion, in accordance with their respective ownership percentages, after allocating Available Cash generated during the period in accordance with our partnership agreement.

Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

These required disclosures do not impact our overall net income or loss or other financial results; however, in periods in which aggregate net income exceeds our Available Cash it will have the impact of reducing net income per limited partner unit, or LPU.

Basic and diluted net income or loss per LPU is calculated by dividing limited partners’ interest in net income or loss, by the weighted-average number of outstanding LPUs during the period, assuming 2,500,000 common limited partner units were issued in connection with the Transaction on January 1, 2007.