Breitburn Energy Partners LP - FORM 8-K - EX-99.2

Attached files

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8-K - Breitburn Energy Partners LP	v206528_8k.htm
EX-23.1 - Breitburn Energy Partners LP	v206528_ex23-1.htm
EX-99.1 - Breitburn Energy Partners LP	v206528_ex99-1.htm

Exhibit 99.2

See Item 8.01 of the accompanying Current Report on Form 8-K for an explanation regarding the following disclosure. The following information replaces the Part I—Item 1 “—Financial Statements,” previously filed in the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 for BreitBurn Energy Partners L.P. (the “Q3 2010 10-Q”). Except as set forth in this Exhibit 99.2, the Q3 2010 10-Q has not been otherwise modified or updated.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands of dollars, except per unit amounts	2010			2009			2010			2009

Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	77,055		$	62,674		$	239,603		$	180,189
Gains (losses) on commodity derivative instruments, net (note 10)		(7,973	)		12,719			95,742			(14,520	)
Other revenue, net		719			261			1,838			930
Total revenues and other income items		69,801			75,654			337,183			166,599
Operating costs and expenses
Operating costs		33,207			33,888			108,429			100,273
Depletion, depreciation and amortization		23,636			24,130			69,599			81,393
General and administrative expenses		12,740			9,318			33,957			27,265
(Gain) loss on sale of assets		(359	)		5,470			137			5,470
Total operating costs and expenses		69,224			72,806			212,122			214,401

Operating income (loss)		577			2,848			125,061			(47,802	)

Interest and other financing costs, net		5,147			4,549			13,762			14,682
Losses on interest rate swaps (note 10)		1,629			3,792			5,290			5,557
Other income, net		(3	)		(84	)		(7	)		(124	)

Income (loss) before taxes		(6,196	)		(5,409	)		106,016			(67,917	)

Income tax expense (benefit) (note 3)		(470	)		(13	)		235			(354	)

Net income (loss)		(5,726	)		(5,396	)		105,781			(67,563	)
Less: Net income attributable to noncontrolling interest		(28	)		(12	)		(127	)		(14	)

Net income (loss) attributable to the partnership	$	(5,754	)	$	(5,408	)	$	105,654		$	(67,577	)

Basic net income (loss) per unit (note 8)	$	(0.11	)	$	(0.10	)	$	1.86		$	(1.28	)
Diluted net income (loss) per unit (note 8)	$	(0.11	)	$	(0.10	)	$	1.86		$	(1.28	)

See accompanying notes to consolidated financial statements.

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BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Balance Sheets

	September 30,			December 31,
Thousands of dollars, except units outstanding	2010			2009
ASSETS
Current assets
Cash	$	3,409		$	5,766
Accounts and other receivables, net		52,248			65,209
Derivative instruments (note 10)		75,534			57,133
Related party receivables (note 4)		2,062			2,127
Inventory (note 5)		4,621			5,823
Prepaid expenses		7,235			5,888
Intangibles		124			495
Total current assets		145,233			142,441
Equity investments		7,857			8,150
Property, plant and equipment
Property, plant and equipment		2,121,173			2,066,685
Accumulated depletion and depreciation		(392,917	)		(325,596	)
Net property, plant and equipment		1,728,256			1,741,089
Other long-term assets
Derivative instruments (note 10)		78,347			74,759
Other long-term assets		11,909			4,590

Total assets	$	1,971,602		$	1,971,029

LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	25,345		$	21,314
Derivative instruments (note 10)		23,418			20,057
Related party payables (note 4)		-			13,000
Revenue and royalties payable		16,830			18,224
Salaries and wages payable		9,272			10,244
Accrued liabilities		10,170			9,051
Total current liabilities		85,035			91,890

Long-term debt (note 6)		516,000			559,000
Deferred income taxes (note 3)		2,680			2,492
Asset retirement obligation (note 7)		37,261			36,635
Derivative instruments (note 10)		22,672			50,109
Other long-term liabilities		2,102			2,102
Total liabilities		665,750			742,228
Equity
Partners' equity (note 8)		1,305,394			1,228,373
Noncontrolling interest (note 9)		458			428
Total equity		1,305,852			1,228,801

Total liabilities and equity	$	1,971,602		$	1,971,029

Common Units outstanding (in thousands)		53,308			52,784

See accompanying notes to consolidated financial statements.

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BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Cash Flows

	Nine Months Ended
	September 30,
Thousands of dollars	2010			2009

Cash flows from operating activities
Net income (loss)	$	105,781		$	(67,563	)
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization		69,599			81,393
Unit based compensation expense		15,386			9,736
Unrealized (gains) losses on derivative instruments		(46,065	)		160,319
Income from equity affiliates, net		293			766
Deferred income tax expense (benefit)		188			(897	)
Amortization of intangibles		371			2,334
Loss on sale of assets		137			5,470
Other		2,850			2,472
Changes in net assets and liabilities
Accounts receivable and other assets		13,315			3,590
Inventory		1,202			(3,710	)
Net change in related party receivables and payables		(12,935	)		340
Accounts payable and other liabilities		(6,822	)		(10,279	)
Net cash provided by operating activities		143,300			183,971
Cash flows from investing activities
Capital expenditures		(46,418	)		(18,603	)
Proceeds from sale of assets		225			23,034
Property acquisitions		(1,550	)		-
Net cash provided (used) by investing activities		(47,743	)		4,431
Cash flows from financing activities
Distributions		(43,043	)		(28,038	)
Proceeds from long-term debt		683,500			218,475
Repayments of long-term debt		(726,500	)		(369,475	)
Book overdraft		-			(9,711	)
Long-term debt issuance costs		(11,871	)		-
Net cash used by financing activities		(97,914	)		(188,749	)
Decrease in cash		(2,357	)		(347	)
Cash beginning of period		5,766			2,546
Cash end of period	$	3,409		$	2,199

See accompanying notes to consolidated financial statements.

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Notes to Consolidated Financial Statements

1. Organization and Basis of Presentation

The accompanying unaudited consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the year ended December 31, 2009 (the “Annual Report”). The financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation of our financial position at September 30, 2010, our operating results for the three months and nine months ended September 30, 2010 and 2009, and our cash flows for the nine months ended September 30, 2010 and 2009, have been included. Operating results for the three months and nine months ended September 30, 2010 are not necessarily indicative of the results that may be expected for the year ended December 31, 2010. The consolidated balance sheet at December 31, 2009 has been derived from the audited consolidated financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements. For further information, refer to the consolidated financial statements and footnotes thereto included in our Annual Report.

We follow the successful efforts method of accounting for oil and gas activities. Depletion, depreciation and amortization of proved oil and gas properties is computed using the units-of-production method, net of any estimated residual salvage values.

As of December 31, 2009, Quicksilver Resources Inc. (“Quicksilver”) held approximately 21.3 million of our common units (“Common Units”), representing approximately 40 percent of our outstanding Common Units. On May 11, 2010, Quicksilver partially paid for an acquisition of assets from Marshall R. Young Oil Co. (“Young”) with 3.6 million Common Units. During the period from June 7, 2010 through September 23, 2010, Young sold all of these Common Units. In September 2010, Quicksilver sold 1.4 million Common Units, resulting in Quicksilver’s ownership being reduced to 16.3 million Common Units, and as of September 30, 2010, with that sale, Quicksilver owned approximately 31 percent of our Common Units.

2. Accounting Pronouncements

Effective January 1, 2010, we adopted guidance issued by the Financial Accounting Standards Board (“FASB”) in June 2009 related to the consolidation of variable interest entities with no impact on our financial position, results of operations or cash flows.

ASU 2010-06 “Fair Value Measurements and Disclosures.” In January 2010, the FASB issued ASU 2010-06 to make certain amendments to Subtopic 820-10 that require two additional disclosures and clarify two existing disclosures. The new disclosures require details of significant transfers in and out of level 1 and level 2 measurements and the reasons for the transfers, and a gross presentation of activity within the level 3 roll forward that presents separately information about purchases, sales, issuances and settlements. The ASU clarifies the existing disclosures with regard to the level of disaggregation of fair value measurements by class of assets and liabilities rather than major category where the reporting entities would need to apply judgment to determine the appropriate classes of other assets and liabilities. The second clarification relates to disclosures of valuation techniques and inputs for recurring and non recurring fair value measurements using significant other observable inputs and significant unobservable inputs for level 2 and level 3 measurements, respectively. ASU 2010-06 (ASC 820-10) is prospectively effective for financial statements issued for interim or annual periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years. We adopted ASU 2010-06, effective January 1, 2010. See Note 10 for the disclosures required by ASU 2010-06.

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3. Income Taxes

Our deferred income tax liability was $2.7 million and $2.5 million at September 30, 2010 and December 31, 2009, respectively. The following table presents our income tax expense/benefit for the three months and nine months ended September 30, 2010 and 2009, respectively:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands of dollars	2010			2009			2010			2009
Federal current tax expense	$	77		$	407		$	224		$	432
Deferred federal tax expense (benefit) (a)		(434	)		(276	)		188			(946	)
State income tax expense (benefit) (b)		(113	)		(144	)		(177	)		160
Total income tax expense (benefit)	$	(470	)	$	(13	)	$	235		$	(354	)

(a) Related to Phoenix Production Company, a tax-paying corporation and our wholly-owned subsidiary.

(b) Related to various forms of state taxes imposed on gross receipts, profit margin or net income in the states where we have operations.

4. Related Party Transactions

BreitBurn Management Company, LLC (“BreitBurn Management”), our wholly-owned subsidiary, operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management.

BreitBurn Management also provides administrative services to BreitBurn Energy Company L.P. (“BEC”), our predecessor, under an administrative services agreement, in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses including incentive compensation plan costs and direct payroll and administrative costs related to BEC properties and operations. In 2010, the monthly fee paid by BEC for indirect expenses is approximately $456,000.

At September 30, 2010 and December 31, 2009, we had current receivables of $1.5 million and $1.4 million, respectively, due from BEC related to the administrative services agreement, outstanding liabilities for employee related costs and oil and gas sales made by BEC on our behalf from certain properties. During the three months and nine months ended September 30, 2010, the monthly charges to BEC for indirect expenses totaled $1.2 million and $4.0 million, respectively, and charges for direct expenses including incentive compensation plan costs, direct payroll and administrative costs totaled $1.1 million and $5.0 million, respectively. During the three months and nine months ended September 30, 2009, the monthly charges to BEC for indirect expenses totaled $1.5 million and $4.5 million, respectively, and charges for direct expenses including incentive compensation plan costs, direct payroll and administrative costs totaled $1.2 million and $3.5 million, respectively. For the three months and nine months ended September 30, 2010, total oil and gas sales made by BEC on our behalf were approximately $0.4 million and $1.3 million, respectively. For the three months and nine months ended September 30, 2009, total oil and gas sales made by BEC on our behalf were approximately $0.4 million and $0.9 million, respectively.

At September 30, 2010 and December 31, 2009, we had receivables of $0.3 million due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf.

Quicksilver buys natural gas from us in Michigan. For the three months and nine months ended September 30, 2010, total net gas sales to Quicksilver were approximately $0.8 million and $2.6 million, respectively. For the three months and nine months ended September 30, 2009, total net gas sales to Quicksilver were approximately $0.5 million and $2.1 million, respectively. At September 30, 2010 and December 31, 2009, the related receivable was $0.3 million and $0.4 million, respectively.

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On October 31, 2008, Quicksilver instituted a lawsuit (the “Litigation”) against us and certain of our subsidiaries and directors in the 48th District Court in Tarrant County, Texas (the “Court”). In February 2010, we agreed to settle all claims with respect to the Litigation (the “Original Settlement”). A final settlement agreement (the “Settlement Agreement”), which superseded the Original Settlement, was executed in April 2010. Pursuant to the Settlement Agreement, the parties agreed to dismiss all pending claims before the Court and mutually released each party, its affiliates, agents, officers, directors and attorneys from any and all claims arising from the subject matter of the Litigation. At December 31, 2009, we had a $13.0 million payable to Quicksilver in connection with the monetary portion of the settlement, which was paid in April 2010 after the Settlement Agreement was executed. On April 6, 2010, an order dismissing all claims in the Litigation was entered by the Court. In June 2010, we received $3 million from our insurers as partial reimbursement. While discussions with our insurers are continuing and we may be required to invoke our legal remedies to obtain payment, we expect to receive reimbursement for the full amount paid to Quicksilver and all or substantially all related fees and costs.

5. Inventory

Our crude oil inventory from our Florida operations at September 30, 2010 and December 31, 2009 was $4.6 million and $5.8 million, respectively. In the nine months ended September 30, 2010, we sold 550 gross MBbls and produced 552 gross MBbls of crude oil from our Florida operations. Crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter. Crude oil inventory additions are at cost and represent our production costs. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded to inventory.

6. Long-Term Debt

On November 1, 2007, BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, entered into a four-year, $1.5 billion amended and restated revolving credit facility with Wells Fargo Bank, N. A., Credit Suisse Securities (USA) LLC and a syndicate of banks (the “First Amended and Restated Credit Agreement”). On June 17, 2008, we and our wholly owned subsidiaries entered into Amendment No. 1 to the Amended and Restated Credit Agreement.

On May 7, 2010, BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, entered into the Second Amended and Restated Credit Agreement, a four-year, $1.5 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (the “Second Amended and Restated Credit Agreement”). The Second Amended and Restated Credit Agreement increased our borrowing base to $735 million from $732 million and will mature on May 7, 2014.

On September 17, 2010, we entered into the First Amendment to the Second Amended and Restated Credit Agreement, which included a consent to the formation of a new wholly owned subsidiary, BreitBurn Collingwood Utica LLC (“Utica”), and its designation as an unrestricted subsidiary under our bank credit facility. Utica is not a guarantor of indebtedness under our bank credit facility. On October 6, 2010, we and BreitBurn Finance Corporation, and certain of our subsidiaries, as guarantors, issued $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the “Notes”). See Note 13 for a discussion of the Notes.

As of September 30, 2010 and December 31, 2009, we had $516.0 million and $559.0 million, respectively, in indebtedness outstanding under our credit facility. At September 30, 2010, the 1-month LIBOR interest rate plus an applicable spread on our long-term debt was 2.760 percent. The amounts reported on our consolidated balance sheets for long-term debt approximate fair value due to the variable nature of our interest rates.

The Second Amended and Restated Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders or repurchase units (including the restriction on our ability to make distributions unless after giving effect to such distribution, the availability to borrow under the facility is the lesser of (i) 10 percent of the borrowing base and (ii) the greater of (a) $50 million and (b) twice the amount of the proposed distribution), while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.75 to 1.00 (which is total indebtedness to EBITDAX); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.

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The Second Amended and Restated Credit Agreement no longer requires that in order to make a distribution to our unitholders, we also must have the ability to borrow 10 percent of our borrowing base after giving effect to such distribution, and remain in compliance with all terms and conditions of our credit facility. In addition, the requirement that we maintain a leverage ratio (defined as the ratio of total debt to EBITDAX) as of the last day of each quarter, on a last twelve month basis of no more than 3.50 to 1.00 was increased to 3.75 to 1.00. The Second Amended and Restated Credit Agreement continues to require us to maintain a current ratio as of the last day of each quarter, of not less than 1.00 to 1.00 and to maintain an interest coverage ratio (defined as the ratio of EBITDAX to consolidated interest expense) as of the last day of each quarter, of not less than 2.75 to 1.00. As of September 30, 2010 and December 31, 2009, we were in compliance with the credit facility’s covenants.

The pricing grid was adjusted by increasing the applicable margins (as defined in the Second Amended and Restated Credit Agreement) between 75 and 100 basis points, depending on the percentage of the borrowing base borrowed, in line with the current credit market for similar facilities. At our debt level as of September 30, 2010, the applicable margin on our borrowings was 250 basis points. The Second Amended and Restated Credit Agreement permits us to incur or guaranty additional debt up to $350 million in senior unsecured notes, and requires that our borrowing base be reduced by 25 percent of the original stated principal amount of such senior unsecured notes when we incur such additional indebtedness. See Note 13 for a discussion of Notes issued on October 6, 2010.

The Second Amended and Restated Credit Agreement also permits us to terminate derivative contracts without obtaining the consent of the lenders in the facility, provided that the net effect of such termination plus the aggregate value of all dispositions of oil and gas properties made during such period, together, does not exceed 5 percent of the borrowing base, and the borrowing base will be automatically reduced by an amount equal to the net effect of the termination.

The events that constitute an Event of Default (as defined in the Second Amended and Restated Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against us in excess of a specified amount; changes in management or control; loss of permits; certain insolvency events; and assertion of certain environmental claims.

EBITDAX is not a defined GAAP measure. The Second Amended and Restated Credit Agreement defines EBITDAX as consolidated net income plus exploration expense, interest expense, income tax provision, depletion, depreciation and amortization, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit based compensation expense, loss or gain on sale of assets (excluding gain or loss on monetization of derivative instruments), cumulative effect of changes in accounting principles, excluding adjusted EBITDAX attributable to our unrestricted entities (as defined in the Second Amended and Restated Credit Agreement) and BEPI limited partner interest and including the cash distribution received from unrestricted entities and BEPI.

Our interest and other financing costs, as reflected in interest and other financing costs, net on the consolidated statements of operations, are detailed in the following table:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Thousands of dollars	2010		2009		2010		2009
Credit agreement (including commitment fees)	$	4,084	$	3,726	$	10,912	$	12,213
Amortization of discount and deferred issuance costs		1,063		823		2,850		2,469
Total	$	5,147	$	4,549	$	13,762	$	14,682

In connection with entry into the Second Amended and Restated Credit Agreement, we incurred $11.9 million in debt issuance costs, to be amortized over the life of the debt.

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7. Asset Retirement Obligation

Our asset retirement obligation is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities together with our estimate of the future timing of the costs to be incurred. Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from less than one year to 50 years. Estimated cash flows have been discounted at our credit-adjusted risk free rate of seven percent and adjusted for inflation using a rate of two percent. Our credit-adjusted risk free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk.

ASC 820 “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are. The highest priority of Level 1 is given to unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 includes inputs other than quoted prices that are included in Level 1 and can be derived by observable data, including third party data providers. These inputs may also include observable transactions in the market place. Level 3 is defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions. We consider the inputs to our asset retirement obligation valuation to be Level 3, as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets.

Changes in the asset retirement obligation for the periods ended September 30, 2010 and December 31, 2009 are presented in the following table:

	Nine Months Ended			Year Ended
Thousands of dollars	September 30, 2010			December 31, 2009
Carrying amount, beginning of period	$	36,635		$	30,086
Liabilities settled in the current period		(1,014	)		(470	)
Revisions (a)		(313	)		4,883
Dispositions (b)		-			(252	)
Accretion expense		1,953			2,388
Carrying amount, end of period	$	37,261		$	36,635

(a) Changes to cost estimates and revisions to reserve life.

(b) Relates to disposition of the Lazy JL Field in Texas, which was sold effective July 1, 2009.

8. Partners’ Equity

During the first nine months of 2010, 510,437 Common Units were issued to employees pursuant to vested grants under our long-term incentive compensation plan, and 13,617 Common Units were issued to outside directors for phantom units and distribution equivalent rights that were granted in 2007 and vested in January 2010.

At September 30, 2010 and December 31, 2009, we had 53,308,255 and 52,784,201 Common Units outstanding, respectively. At September 30, 2010 and December 31, 2009, we had 6,700,000 units authorized for issuance under our long-term incentive compensation plans, and there were 3,640,449 and 2,961,659, respectively, of units outstanding under grants that were eligible to be paid in Common Units upon vesting.

Cash Distributions

On May 14, 2010, we paid a cash distribution of approximately $20.0 million to our common unitholders of record as of the close of business on May 10, 2010. The distribution that was paid to unitholders was $0.375 per Common Unit.

On August 13, 2010, we paid a cash distribution of approximately $20.4 million to our common unitholders of record as of the close of business on August 9, 2010. The distribution that was paid to unitholders was $0.3825 per Common Unit.

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During the nine months ended September 30, 2010, we also paid $2.7 million in cash at a rate equal to the distributions paid to our unitholders, to holders of outstanding unvested Restricted Phantom Units (“RPUs”) and Convertible Phantom Units (“CPUs”) issued under our long-term incentive plan.

Earnings per unit

ASC 260 “Earnings per Share” requires use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of common unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested RPUs and CPUs participate in distributions on an equal basis with Common Units. Accordingly, the presentation below is prepared on a combined basis and is presented as earnings per common unit.

The following is a reconciliation of net earnings and weighted average units for calculating basic net earnings per common unit and diluted net earnings per common unit.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands, except per unit amounts	2010			2009			2010		2009

Net income (loss) attributable to the partnership	$	(5,754	)	$	(5,408	)	$	105,654	$	(67,577	)
Distributions on participating units not expected to vest		15			-			15		24
Net income (loss) attributable to common unitholders and participating securities	$	(5,739	)	$	(5,408	)	$	105,669	$	(67,553	)

Weighted average number of units used to calculate basic and diluted earnings per unit (in thousands):
Common Units		53,303			52,770			53,297		52,748
Participating securities		-			-			3,442		-
Denominator for basic earnings per common unit (a)		53,303			52,770			56,739		52,748

Dilutive units (b)		-			-			133		-
Denominator for diluted earnings per common unit		53,303			52,770			56,872		52,748

Net income (loss) per common unit
Basic	$	(0.11	)	$	(0.10	)	$	1.86	$	(1.28	)
Diluted	$	(0.11	)	$	(0.10	)	$	1.86	$	(1.28	)

(a) Basic earnings per unit is based on the weighted average number of Common Units outstanding plus the weighted average number of potentially issuable RPUs and CPUs. The three months ended September 30, 2010 and 2009 and the nine months ended September 30, 2009 exclude 3,504, 2,849 and 2,599, respectively, of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.

(b) The nine months ended September 30, 2010 includes dilutive units potentially issuable to directors under compensation plans. The three months ended September 30, 2010 and 2009 and the nine months ended September 30, 2009 exclude 144, 106 and 105, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit.

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9. Noncontrolling Interest

ASC 810 “Consolidation” requires that noncontrolling interests be classified as a component of equity and establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.

On May 25, 2007, we acquired the limited partner interest (99 percent) of BEPI from TIFD. As such, we are fully consolidating the results of BEPI and thus are recognizing a noncontrolling interest representing the book value of the general partner’s interests. At September 30, 2010 and December 31, 2009, the amount of this noncontrolling interest was $0.5 million and $0.4 million, respectively. For the three months and nine months ended September 30, 2010, we recorded net income attributable to the noncontrolling interest of less than $0.1 million and $0.1 million, respectively, and dividends of less than $0.1 million and $0.1 million, respectively. For the three months and nine months ended September 30, 2009, we recorded net income attributable to the noncontrolling interest of less than $0.1 million in each period, and dividends of less than $0.1 million and $0.1 million, respectively.

10. Financial Instruments

Our risk management programs are intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flow and distributions. Routinely, we utilize derivative financial instruments to reduce this volatility. To the extent we have hedged a significant portion of our expected production through commodity derivative instruments and the cost for goods and services increase, our margins would be adversely affected.

Credit and Counterparty Risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of September 30, 2010, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S Bank National Association and Toronto-Dominion Bank. We periodically obtain credit default swap information on our counterparties. As of September 30, 2010, each of these financial institutions had an investment grade credit rating. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of September 30, 2010, our largest derivative asset balances were with JP Morgan Chase Bank N.A. and Credit Suisse Energy LLC, who accounted for approximately 61 percent and 19 percent of our derivative asset balance, respectively. As of September 30, 2010, our largest derivative liability balances were with Wells Fargo Bank National Association and Barclays Bank PLC, who accounted for approximately 78 percent and 12 percent of our derivative liability balance, respectively.

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Commodity Activities

The derivative instruments we utilize are based on index prices that may and often do differ from the actual crude oil and natural gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under ASC 815 “Derivatives and Hedging.” Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial reporting purposes and instead recognize changes in fair value immediately in earnings.

We had the following commodity derivative contracts in place at September 30, 2010:

	Year
	2010			2011			2012		2013		2014
Gas Positions:
Fixed price swaps:
Hedged volume (MMBtu/d)		43,113			25,955			19,128		32,000		-
Average price ($/MMBtu)	$	8.22		$	7.26		$	7.10	$	6.70	$	-
Collars:
Hedged volume (MMBtu/d)		3,837			16,016			19,129		-		-
Average floor price ($/MMBtu)	$	9.00		$	9.00		$	9.00	$	-	$	-
Average ceiling price ($/MMBtu)	$	12.65		$	11.28		$	11.89	$	-	$	-
Total:
Hedged volume (MMBtu/d)		46,950			41,971			38,257		32,000		-
Average price ($/MMBtu)	$	8.29		$	7.92		$	8.05	$	6.70	$	-

Oil Positions:
Fixed price swaps:
Hedged volume (Bbls/d)		2,267			3,890			3,539		5,000		2,748
Average price ($/Bbl)	$	83.67		$	72.78		$	72.40	$	79.32	$	89.25
Participating swaps: (a)
Hedged volume (Bbls/d)		1,433			1,439			-		-		-
Average price ($/Bbl)	$	65.67		$	61.29		$	-	$	-	$	-
Average participation %		58.0	%		53.2	%		-		-		-
Collars:
Hedged volume (Bbls/d)		2,140			2,048			2,477		500		-
Average floor price ($/Bbl)	$	105.72		$	103.42		$	110.00	$	77.00	$	-
Average ceiling price ($/Bbl)	$	140.02		$	152.61		$	145.39	$	103.10	$	-
Floors:
Hedged volume (Bbls/d)		500			-			-		-		-
Average floor price ($/Bbl)	$	100.00		$	-		$	-	$	-	$	-
Total:
Hedged volume (Bbls/d)		6,340			7,377			6,016		5,500		2,748
Average price ($/Bbl)	$	88.33		$	79.02		$	87.88	$	79.11	$	89.25

(a) A participating swap combines a swap and a call option with the same strike price

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Interest Rate Activities

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. As of September 30, 2010, our total debt outstanding was $516.0 million. In order to mitigate our interest rate exposure, we had the following interest rate derivative contracts in place at September 30, 2010, that fixed rates for a portion of floating LIBOR-base debt under our credit facility:

Notional amounts in thousands of dollars	Notional Amount		Fixed Rate
Period Covered
October 1, 2010 to December 20, 2010		300,000		3.6825	%
October 1, 2010 to October 20, 2011		100,000		1.6200	%
December 20, 2010 to October 20, 2011		200,000		2.9900	%
November 21, 2011 to December 20, 2012		100,000		1.1550	%

Fair Value of Financial Instruments

ASC 815 requires disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for under ASC 815, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This topic requires the disclosures detailed below.

Fair value of derivative instruments not designated as hedging instruments under ASC 815:

Balance sheet location, thousands of dollars	Oil Commodity Derivatives			Natural Gas Commodity Derivatives		Interest Rate Derivatives			Commodity Derivatives Netting (a)			Total Financial Instruments

As of September 30, 2010
Assets
Current assets - derivative instruments	$	19,072		$	57,611	$	-		$	(1,149	)	$	75,534
Other long-term assets - derivative instruments		26,170			67,209		-			(15,032	)		78,347
Total assets		45,242			124,820		-			(16,181	)		153,881

Liabilities
Current liabilities - derivative instruments		(17,254	)		-		(7,313	)		1,149			(23,418	)
Long-term liabilities - derivative instruments		(37,043	)		-		(661	)		15,032			(22,672	)
Total liabilities		(54,297	)		-		(7,974	)		16,181			(46,090	)

Net assets (liabilities)	$	(9,055	)	$	124,820	$	(7,974	)	$	-		$	107,791

As of December 31, 2009
Assets
Current assets - derivative instruments	$	17,666		$	39,467	$	-		$	-		$	57,133
Other long-term assets - derivative instruments		35,382			42,620		-			(3,243	)		74,759
Total assets		53,048			82,087		-			(3,243	)		131,892

Liabilities
Current liabilities - derivative instruments		(10,234	)		-		(9,823	)		-			(20,057	)
Long-term liabilities - derivative instruments		(51,730	)		-		(1,622	)		3,243			(50,109	)
Total liabilities		(61,964	)		-		(11,445	)		3,243			(70,166	)

Net assets (liabilities)	$	(8,916	)	$	82,087	$	(11,445	)	$	-		$	61,726

(a) Represents counterparty netting under derivative netting agreements. These contracts are reflected net on the balance sheet.

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The location of gains and losses on derivative instruments not designated as hedging instruments under ASC 815 are detailed below:

Income Statement location, thousands of dollars	Oil Commodity Derivatives (a)			Natural Gas Commodity Derivatives (a)			Interest Rate Derivatives (b)			Total Financial Instruments
Three Months Ended September 30, 2010
Realized gains (losses)	$	6,298		$	16,269		$	(2,943	)	$	19,624
Unrealized gains (losses)		(46,721	)		16,181			1,314			(29,226	)
Net gains (losses)	$	(40,423	)	$	32,450		$	(1,629	)	$	(9,602	)

Three Months Ended September 30, 2009
Realized gains (losses)	$	3,646		$	20,710		$	(3,411	)	$	20,945
Unrealized gains (losses)		9,728			(21,365	)		(381	)		(12,018	)
Net gains (losses)	$	13,374		$	(655	)	$	(3,792	)	$	8,927

Nine Months Ended September 30, 2010
Realized gains (losses)	$	8,030		$	45,118		$	(8,761	)	$	44,387
Unrealized gains (losses)		(141	)		42,735			3,471			46,065
Net gains (losses)	$	7,889		$	87,853		$	(5,290	)	$	90,452

Nine Months Ended September 30, 2009
Realized gains (losses)	$	64,829		$	85,083		$	(9,670	)	$	140,242
Unrealized gains (losses)		(135,104	)		(29,328	)		4,113			(160,319	)
Net gains (losses)	$	(70,275	)	$	55,755		$	(5,557	)	$	(20,077	)

(a) Included in gains (losses) on commodity derivative instruments, net on the consolidated statements of operations.

(b) Included in losses on interest rate swaps on the consolidated statements of operations.

ASC 820 “Fair Value Measurements and Disclosures” defines fair value, establishes a framework for measuring fair value and establishes required disclosures about fair value measurements. ASC 820 also establishes a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are. We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third party market participants. We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements. The fair value hierarchy established by ASC 820 gives the highest priority of Level 1 to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 to unobservable inputs. We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are. The three levels of inputs as defined in ASC 820 are described further as follows:

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2 – Inputs other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. We consider the over the counter (“OTC”) commodity and interest rate swaps in our portfolio to be Level 2. Level 3 – Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. As of September 30, 2010 and December 31, 2009, our Level 3 derivative assets and liabilities consisted entirely of OTC commodity put and call options.

Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data or the interpretation of Level 2 criteria is modified in practice to include non-binding market corroborated data. Effective January 1, 2010, we adopted ASU 2010-06 “Fair Value Measurements and Disclosures.” ASU 2010-06 requires detailed disclosures of significant transfers in and out of Level 1 and Level 2 categories and the reasons for those transfers. We had no such transfers during the nine months ended September 30, 2010.

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Our Treasury/Risk Management group calculates the fair value of our commodity and interest rate swaps and options. We compare these fair value amounts to the fair value amounts that we receive from the counterparties on a monthly basis. Any differences are resolved and any required changes are recorded prior to the issuance of our financial statements.

The model we utilize to calculate the fair value of our commodity derivative instruments is a standard option pricing model. Inputs to the option pricing models include fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility and interest rate factors and time to expiry. Model inputs are obtained from our counterparties and third party data providers and are verified to published data where available (e.g., NYMEX). Additional inputs to our Level 3 derivatives include option volatility, forward commodity prices and risk-free interest rates for present value discounting. We use the standard swap contract valuation method to value our interest rate derivatives, and inputs include LIBOR forward interest rates, one-month LIBOR rates and risk-free interest rates for present value discounting.

Financial assets and liabilities carried at fair value on a recurring basis are presented in the table below. Our assessment of the significance of an input to its fair value measurement requires judgment and can affect the valuation of the assets and liabilities as well as the category within which they are classified.

Recurring fair value measurements at September 30, 2010 and December 31, 2009:

Thousands of dollars	Level 1		Level 2			Level 3		Total

As of September 30, 2010
Assets (liabilities):
Commodity derivatives (swaps, put and call options)	$	-	$	18,623		$	97,142	$	115,765
Other derivatives (interest rate swaps)		-		(7,974	)		-		(7,974	)
Total	$	-	$	10,649		$	97,142	$	107,791

As of December 31, 2009
Assets (liabilities):
Commodity derivatives (swaps, put and call options)	$	-	$	(29,304	)	$	102,475	$	73,171
Other derivatives (interest rate swaps)		-		(11,445	)		-		(11,445	)
Total	$	-	$	(40,749	)	$	102,475	$	61,726

The following table sets forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Thousands of dollars	2010			2009		2010			2009
Assets:
Beginning balance	$	115,009		$	113,355	$	102,475		$	153,218
Realized and unrealized gains (losses)		(17,867	)		5,954		(5,333	)		(27,879	)
Settlement (a)		-			-		-			(6,030	)
Ending balance	$	97,142		$	119,309	$	97,142		$	119,309

(a) Settlement reflects the monetization of oil contracts in June 2009.

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For the three months and nine months ended September 30, 2010, realized gains of $8.1 million and $18.8 million and unrealized losses of $26.0 million and $24.1 million, respectively, related to our derivative instruments classified as Level 3 are included in gains (losses) on commodity derivative instruments, net on the consolidated statements of operations. For the three months and nine months ended September 30, 2009, realized gains of $0.6 million and $15.0 million and unrealized gains of $5.4 million and unrealized losses of $42.9 million, respectively, related to our derivative instruments classified as Level 3 are included in gains (losses) on commodity derivative instruments, net on the consolidated statements of operations. Determination of fair values incorporates various factors as required by ASC 820 including, but not limited to, the credit standing of the counterparties, the impact of guarantees as well as our own abilities to perform on our liabilities. During the three months and nine months ended September 30, 2010 and the three months ended September 30, 2009, we had no changes to the fair value of our derivative instruments classified as Level 3 related to purchases, sales, issuances or settlements. During the nine months ended September 30, 2009, we had $6.0 million in settlements impacting the fair value of our derivative instruments classified as Level 3 related to the monetization of oil contracts, and no changes related to purchases, sales or issuances.

11. Unit and Other Valuation-Based Compensation Plans

Unit-based compensation expense for the three months and nine months ended September 30, 2010 was $5.5 million and $15.4 million, respectively, and for the three months and nine months ended September 30, 2009 was $3.5 million and $9.7 million, respectively.

During the three months and nine months ended September 30, 2010, the board of directors of BreitBurn GP, LLC (our “General Partner”) approved the grant of 1,062 and 1,475,684 RPUs, respectively, to employees of BreitBurn Management under our First Amended and Restated 2006 Long-Term Incentive Plan (“LTIP”). Our outside directors were issued 3,286 and 66,486 phantom units under our LTIP during the three months and nine months ended September 30, 2010, respectively. The fair market value of the RPUs granted during 2010 for computing compensation expense under ASC 718 “Compensation—Stock Compensation” averaged $13.74 per unit.

During the nine months of 2010, 510,437 Common Units were issued to employees pursuant to grants that vested under our LTIP and 13,617 Common Units were issued to outside directors for phantom units and distribution equivalent rights which were granted in 2007 and vested in January 2010. Common Units issued under our LTIP are issued net of units withheld for payment of taxes.

For the three months and nine months ended September 30, 2010, we paid less than $0.1 million and $0.1 million, respectively, for various liability-classified compensation plans. For the three months and nine months ended September 30, 2009, we paid $0 and approximately $0.1 million, respectively, in cash for various liability-classified compensation plans. For the three months and nine months ended September 30, 2010, we paid $1.4 million and $2.7 million in cash, respectively, at a rate equal to the distribution paid to our unitholders, to holders of unvested RPUs and CPUs. For the three months and nine months ended September 30, 2009, we paid $0 and approximately $0.7 million, respectively, at a rate equal to the distribution paid to our unitholders, to holders of unvested RPUs and CPUs.

As of September 30, 2010, we had $32.4 million of total unrecognized compensation costs for all outstanding plans. This amount is expected to be recognized over the period from October 1, 2010 to December 31, 2012.

For detailed information on our various compensation plans, see Note 17 to the consolidated financial statements included in our Annual Report.

12. Commitments and Contingencies

Surety Bonds and Letters of Credit

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At September 30, 2010 and December 31, 2009, we had various surety bonds for $10.9 million and $10.6 million, respectively. At September 30, 2010 and December 31, 2009, we had approximately $0.3 million in letters of credit outstanding.

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13. Subsequent Events

Senior Notes Due 2020

On October 6, 2010, we and BreitBurn Finance Corporation (the “Issuers”), and certain of our subsidiaries, as guarantors (the “Guarantors”), issued $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the “Notes”). The Notes were not registered under the Securities Act of 1933, as amended (the “Securities Act”), or any state securities laws, and unless so registered, the Notes may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. The Notes were sold pursuant to a private placement exemption from the Securities Act to a group of initial purchasers (“Initial Purchasers”) and then resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation 5 under the Securities Act. We received net proceeds of approximately $291.4 million (after deducting estimated fees and offering expenses). We used $290 million of the net proceeds to repay amounts outstanding under our bank credit facility. In connection with the Notes, we incurred financing fees and expenses of approximately $8.6 million, which will be amortized over the life of the Notes. The $5 million discount will also be amortized over the life of the Notes.

In connection with the issuance of the Notes, we entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Guarantors and Initial Purchasers. Under the Registration Rights Agreement, the Issuers and the Guarantors shall cause to be filed with the Securities and Exchange Commission a registration statement with respect to an offer to exchange the Notes for substantially identical notes that are registered under the Securities Act. The Issuers and the Guarantors will use their commercially reasonable efforts to cause such exchange offer registration statement to become effective under the Securities Act. In addition, the Issuers and the Guarantors will use their commercially reasonable efforts to cause the exchange offer to be consummated not later than 400 days after October 6, 2010. Under some circumstances, in lieu of, or in addition to, a registered exchange offer, the Issuers and the Guarantors have agreed to file a shelf registration statement with respect to the Notes. The Issuers and the Guarantors are required to pay additional interest if they fail to comply with their obligations to register the Notes within the specified time periods.

Credit Facility

On October 5, 2010, the borrowing base under our Second Amended and Restated Credit Agreement was reaffirmed at $735 million. As a result of the completion of the Notes offering, our borrowing base was automatically reduced from $735 million to $658.8 million.

Additional Subsequent Events

On October 4, 2010, we entered into crude oil fixed price swap contracts for 500 Bbl/d for the period January 2011 to March 2011 at $83.90 per Bbl, 500 Bbl/d for April 2011 to December 2014 at $88.00 per Bbl and 500 Bbl/d for the period April 2011 to December 2014 at $87.75 per Bbl. On November 2, 2010, we entered into a natural gas swap contract for 5,000 MMBtu/d for 2013 at $5.25 per MMBtu.

On October 29, 2010, we announced a cash distribution to unitholders for the third quarter of 2010 at the rate of $0.3900 per Common Unit, to be paid on November 12, 2010.

In October 2010, Quicksilver sold 0.65 million Common Units, resulting in Quicksilver’s ownership being reduced to approximately 15.7 million Common Units, and with that sale, Quicksilver now owns approximately 29 percent of our Common Units.

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Condensed Consolidating Financial Information

BreitBurn Energy Partners L.P. (the “Partnership,” “we,” “us” or “our”), BreitBurn Finance Corporation, a Delaware corporation (together with the Partnership, the “Issuers”), and certain of our 100% owned subsidiaries, as guarantors (the “Guarantors”), entered into a Purchase Agreement (the “Purchase Agreement”) with the Initial Purchasers as defined therein, pursuant to which the Issuers agreed to sell $305 million in aggregate principal amount of the Issuers’ 8.625% Senior Notes due 2020 (the “Notes”). The Notes were offered and sold in private placements to qualified institutional buyers in the United States in reliance on Rule 144A under the Securities Act of 1933, as amended.

In connection with the issuance of the Notes, we entered into a registration rights agreement requiring us to file an exchange offer registration statement with the Securities and Exchange Commission (the “SEC”) with respect to an offer to exchange the Notes for substantially identical notes that are registered under the Securities Act of 1933. Certain, but not all, of our subsidiaries have issued full, unconditional and joint and several guarantees of the Notes, will guarantee the exchange offer notes and may guarantee future issuances of debt securities, in accordance with Rule 3-10(d) of Regulation S-X.

We are, therefore, presenting condensed consolidating financial information as of September 30, 2010 and December 31, 2009 and for the three months and nine months ended September 30, 2010 and 2009 on a parent/co-issuer, guarantor subsidiaries, non-guarantor subsidiaries, eliminating entries, and consolidated basis. Eliminating entries presented are necessary to combine the parent/co-issuer, the guarantor subsidiaries and the non-guarantor subsidiaries. For purposes of the following tables, we are referred to as “Parent” and the “Guarantor Subsidiaries” are all of our subsidiaries other than BreitBurn Energy Partners I, L.P (“BEPI”, the “Non-Guarantor Subsidiary”) and our wholly owned subsidiary, BreitBurn Collingwood Utica LLC, formed in September 2010 (together the “Non-Guarantor Subsidiaries”). We hold a 99 percent limited partner interest in BEPI.

BreitBurn Finance Corporation, our wholly-owned subsidiary, was organized for the sole purpose of being a co-issuer of certain of our indebtedness, including the Notes. BreitBurn Finance Corporation has no operations and no revenue other than as may be incidental to its activities as co-issuer of our indebtedness.

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Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2010
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated

Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	-		$	71,354		$	5,701		$	-		$	77,055
Losses on commodity derivative instruments, net		-			(7,973	)		-			-			(7,973	)
Other revenue, net		-			719			-			-			719
Total revenues and other income items		-			64,100			5,701			-			69,801
Operating costs and expenses
Operating costs		-			30,874			2,333			-			33,207
Depletion, depreciation and amortization		92			22,978			566			-			23,636
General and administrative expenses		50			12,688			2			-			12,740
Gain on sale of assets		-			(359	)		-			-			(359	)
Total operating costs and expenses		142			66,181			2,901			-			69,224

Operating income (loss)		(142	)		(2,081	)		2,800			-			577

Interest and other financing costs, net		-			5,147			-			-			5,147
Losses on interest rate swaps		-			1,629			-			-			1,629
Other income, net		-			(2	)		(1	)		-			(3	)
Total other expense (income)		-			6,774			(1	)		-			6,773

Income (loss) before taxes		(142	)		(8,855	)		2,801			-			(6,196	)

Income tax benefit		-			(470	)		-			-			(470	)

Equity in earnings (losses) of subsidiaries		(5,612	)		2,773			-			2,839			-

Net income (loss)		(5,754	)		(5,612	)		2,801			2,839			(5,726	)
Less: Net income attributable to noncontrolling interest		-			-			-			(28	)		(28	)

Net income (loss) attributable to the partnership	$	(5,754	)	$	(5,612	)	$	2,801		$	2,811		$	(5,754	)

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Condensed Consolidating Statements of Operations

	Nine Months Ended September 30, 2010
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated

Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	-		$	222,010		$	17,593		$	-		$	239,603
Gains on commodity derivative instruments, net		-			95,742			-			-			95,742
Other revenue, net		-			1,838			-			-			1,838
Total revenues and other income items		-			319,590			17,593			-			337,183
Operating costs and expenses
Operating costs		-			101,116			7,313			-			108,429
Depletion, depreciation and amortization		307			67,469			1,823			-			69,599
General and administrative expenses		343			33,599			15			-			33,957
Loss on sale of assets		-			137			-			-			137
Total operating costs and expenses		650			202,321			9,151			-			212,122

Operating income (loss)		(650	)		117,269			8,442			-			125,061

Interest and other financing costs, net		-			13,762			-			-			13,762
Losses on interest rate swaps		-			5,290			-			-			5,290
Other income, net		-			(6	)		(1	)		-			(7	)
Total other expense (income)		-			19,046			(1	)		-			19,045

Income (loss) before taxes		(650	)		98,223			8,443			-			106,016

Income tax expense (benefit)		(25	)		259			1			-			235

Equity in earnings of subsidiaries		106,323			8,359			-			(114,682	)		-

Net income		105,698			106,323			8,442			(114,682	)		105,781
Less: Net income attributable to noncontrolling interest		-			-			-			(127	)		(127	)

Net income attributable to the partnership	$	105,698		$	106,323		$	8,442		$	(114,809	)	$	105,654

-19-

Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2009
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non-Guarantor Subsidiary		Eliminations			Consolidated

Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	-		$	57,293		$	5,381	$	-		$	62,674
Gains on commodity derivative instruments, net		-			12,719			-		-			12,719
Other revenue, net		-			261			-		-			261
Total revenues and other income items		-			70,273			5,381		-			75,654
Operating costs and expenses
Operating costs		1			31,413			2,474		-			33,888
Depletion, depreciation and amortization		-			23,765			365		-			24,130
General and administrative expenses		(1	)		9,318			1		-			9,318
Loss on sale of assets		-			5,470			-		-			5,470
Total operating costs and expenses		-			69,966			2,840		-			72,806

Operating income (loss)		-			307			2,541		-			2,848

Interest and other financing costs, net		-			4,549			-		-			4,549
Losses on interest rate swaps		-			3,792			-		-			3,792
Other income, net		-			(84	)		-		-			(84	)
Total other expense		-			8,257			-		-			8,257

Income (loss) before taxes		-			(7,950	)		2,541		-			(5,409	)

Income tax benefit		-			(13	)		-		-			(13	)

Equity in earnings (losses) of subsidiaries		(5,421	)		2,516			-		2,905			-

Net income (loss)		(5,421	)		(5,421	)		2,541		2,905			(5,396	)
Less: Net income attributable to noncontrolling interest		-			-			-		(12	)		(12	)

Net income (loss) attributable to the partnership	$	(5,421	)	$	(5,421	)	$	2,541	$	2,893		$	(5,408	)

-20-

Condensed Consolidating Statements of Operations

	Nine Months Ended September 30, 2009
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated

Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	-		$	167,131		$	13,058		$	-		$	180,189
Losses on commodity derivative instruments, net		-			(14,520	)		-			-			(14,520	)
Other revenue, net		-			930			-			-			930
Total revenues and other income items		-			153,541			13,058			-			166,599
Operating costs and expenses
Operating costs		3			94,014			6,256			-			100,273
Depletion, depreciation and amortization		387			79,587			1,419			-			81,393
General and administrative expenses		419			26,853			(7	)		-			27,265
Loss on sale of assets		-			5,470			-			-			5,470
Total operating costs and expenses		809			205,924			7,668			-			214,401

Operating income (loss)		(809	)		(52,383	)		5,390			-			(47,802	)

Interest and other financing costs, net		-			14,682			-			-			14,682
Losses on interest rate swaps		-			5,557			-			-			5,557
Other income, net		-			(123	)		(1	)		-			(124	)
Total other expense (income)		-			20,116			(1	)		-			20,115

Income (loss) before taxes		(809	)		(72,499	)		5,391			-			(67,917	)

Income tax expense (benefit)		61			(416	)		1			-			(354	)

Equity in earnings (losses) of subsidiaries		(66,747	)		5,336			-			61,411			-

Net income (loss)		(67,617	)		(66,747	)		5,390			61,411			(67,563	)
Less: Net income attributable to noncontrolling interest		-			-			-			(14	)		(14	)

Net income (loss) attributable to the partnership	$	(67,617	)	$	(66,747	)	$	5,390		$	61,397		$	(67,577	)

-21-

Condensed Consolidating Balance Sheets

	As of September 30, 2010
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets
Cash	$	12		$	1,726		$	1,671		$	-		$	3,409
Accounts and other receivables, net		10,000			40,847			1,401			-			52,248
Derivative instruments		-			75,534			-			-			75,534
Related party receivables		-			2,062			-			-			2,062
Inventory		-			4,621			-			-			4,621
Prepaid expenses		-			7,235			-			-			7,235
Intangibles		-			124			-			-			124
Total current assets		10,012			132,149			3,072			-			145,233
Investments in subsidiaries		1,307,806			46,547			-			(1,354,353	)		-
Intercompany receivables (payables)		(20,272	)		6,884			13,388			-			-
Equity investments		-			7,857			-			-			7,857
Property, plant and equipment
Property, plant and equipment		8,467			2,066,530			46,176			-			2,121,173
Accumulated depletion and depreciation		(905	)		(380,853	)		(11,159	)		-			(392,917	)
Net property, plant and equipment		7,562			1,685,677			35,017			-			1,728,256
Other long-term assets
Derivative instruments		-			78,347			-			-			78,347
Other long-term assets		277			11,558			74			-			11,909

Total assets	$	1,305,385		$	1,969,019		$	51,551		$	(1,354,353	)	$	1,971,602

LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	3		$	24,502		$	840		$	-		$	25,345
Derivative instruments		-			23,418			-			-			23,418
Revenue and royalties payable		-			15,563			1,267			-			16,830
Salaries and wages payable		-			9,272			-			-			9,272
Accrued liabilities		-			9,193			977			-			10,170
Total current liabilities		3			81,948			3,084			-			85,035

Long-term debt		-			516,000			-			-			516,000
Deferred income taxes		-			2,680			-			-			2,680
Asset retirement obligation		-			35,811			1,450			-			37,261
Derivative instruments		-			22,672			-			-			22,672
Other long-term liabilities		-			2,102			-			-			2,102
Total liabilities		3			661,213			4,534			-			665,750
Equity
Partners' equity		1,305,382			1,307,806			47,017			(1,354,811	)		1,305,394
Noncontrolling interest		-			-			-			458			458
Total equity		1,305,382			1,307,806			47,017			(1,354,353	)		1,305,852

Total liabilities and equity	$	1,305,385		$	1,969,019		$	51,551		$	(1,354,353	)	$	1,971,602

-22-

Condensed Consolidating Balance Sheets

	As of December 31, 2009
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated

ASSETS
Current assets:
Cash	$	149		$	4,917		$	700		$	-		$	5,766
Accounts and other receivables, net		13,000			50,196			2,013			-			65,209
Derivative instruments		-			57,133			-			-			57,133
Related party receivables		-			2,127			-			-			2,127
Inventory		-			5,823			-			-			5,823
Prepaid expenses		-			5,888			-			-			5,888
Intangibles		-			495			-			-			495
Total current assets		13,149			126,579			2,713			-			142,441
Investments in subsidiaries		1,201,492			47,074			-			(1,248,566	)		-
Intercompany receivables (payables)		18,743			(32,209	)		13,466			-			-
Equity investments		-			8,150			-			-			8,150

Property, plant and equipment
Oil and gas properties		8,467			2,005,619			44,882			-			2,058,968
Non-oil and gas assets		-			7,717			-			-			7,717
		8,467			2,013,336			44,882			-			2,066,685
Accumulated depletion and depreciation		(597	)		(315,567	)		(9,432	)		-			(325,596	)
Net property, plant and equipment		7,870			1,697,769			35,450			-			1,741,089
Other long-term assets
Derivative instruments		-			74,759			-			-			74,759
Other long-term assets		74			4,459			57			-			4,590

Total assets	$	1,241,328		$	1,926,581		$	51,686		$	(1,248,566	)	$	1,971,029

LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable	$	2		$	20,386		$	926		$	-		$	21,314
Derivative instruments		-			20,057			-			-			20,057
Related party payables		13,000			-			-			-			13,000
Revenue and royalties payable		-			16,888			1,336			-			18,224
Salaries and wages payable		-			10,244			-			-			10,244
Accrued liabilities		-			8,531			520			-			9,051
Total current liabilities		13,002			76,106			2,782			-			91,890

Long-term debt		-			559,000			-			-			559,000
Deferred income taxes		-			2,492			-			-			2,492
Asset retirement obligation		-			35,280			1,355			-			36,635
Derivative instruments		-			50,109			-			-			50,109
Other long-term liabilities		-			2,102			-			-			2,102
Total liabilities		13,002			725,089			4,137			-			742,228
Equity:
Partners' equity		1,228,326			1,201,492			47,549			(1,248,994	)		1,228,373
Noncontrolling interest		-			-			-			428			428
Total equity		1,228,326			1,201,492			47,549			(1,248,566	)		1,228,801

Total liabilities and equity	$	1,241,328		$	1,926,581		$	51,686		$	(1,248,566	)	$	1,971,029

-23-

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2010
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated

Cash flows from operating activities
Net income	$	105,698		$	106,323		$	8,442		$	(114,682	)	$	105,781
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization		307			67,469			1,823			-			69,599
Unit based compensation expense		-			15,386			-			-			15,386
Unrealized gains on derivative instruments		-			(46,065	)		-			-			(46,065	)
Income from equity affiliates, net		-			293			-			-			293
Equity (earnings) losses in subsidiaries		(106,323	)		(8,359	)		-			114,682			-
Deferred income tax		-			188			-			-			188
Amortization of intangibles		-			371			-			-			371
Loss on sale of assets		-			137			-			-			137
Other		-			2,850			-			-			2,850
Changes in net assets and liabilities
Accounts receivable and other assets		2,798			9,921			596			-			13,315
Inventory		-			1,202			-			-			1,202
Net change in related party receivables and payables		(13,000	)		65			-			-			(12,935	)
Accounts payable and other liabilities		1			(7,132	)		309			-			(6,822	)
Net cash provided (used) by operating activities		(10,519	)		142,649			11,170			-			143,300
Cash flows from investing activities
Capital expenditures		-			(45,115	)		(1,303	)		-			(46,418	)
Proceeds from sale of assets		-			225			-			-			225
Property acquisitions		-			(1,550	)		-			-			(1,550	)
Net cash used by investing activities		-			(46,440	)		(1,303	)		-			(47,743	)
Cash flows from financing activities
Distributions		(43,043	)		-			-			-			(43,043	)
Proceeds from long-term debt		-			683,500			-			-			683,500
Repayments of long-term debt		-			(726,500	)		-			-			(726,500	)
Long-term debt issuance costs		-			(11,871	)		-			-			(11,871	)
Intercompany activity		53,425			(44,529	)		(8,896	)		-			-
Net cash provided (used) by investing activities		10,382			(99,400	)		(8,896	)		-			(97,914	)

Increase (decrease) in cash		(137	)		(3,191	)		971			-			(2,357	)
Cash beginning of period		149			4,917			700			-			5,766
Cash end of period	$	12		$	1,726		$	1,671		$	-		$	3,409

-24-

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2009
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated

Cash flows from operating activities
Net income (loss)	$	(67,617	)	$	(66,747	)	$	5,390		$	61,411		$	(67,563	)
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization		387			79,587			1,419			-			81,393
Unit based compensation expense		-			9,736			-			-			9,736
Unrealized losses on derivative instruments		-			160,319			-			-			160,319
Income from equity affiliates, net		-			766			-			-			766
Equity (earnings) losses in subsidiaries		66,747			(5,336	)		-			(61,411	)		-
Deferred income tax		-			(897	)		-			-			(897	)
Amortization of intangibles		-			2,334			-			-			2,334
Loss on sale of assets		-			5,470			-			-			5,470
Other		-			2,472			-			-			2,472
Changes in net assets and liabilities
Accounts receivable and other assets		-			4,851			(1,261	)		-			3,590
Inventory		-			(3,710	)		-			-			(3,710	)
Net change in related party receivables and payables		-			340			-			-			340
Accounts payable and other liabilities		(23	)		(12,356	)		2,100			-			(10,279	)
Net cash provided (used) by operating activities		(506	)		176,829			7,648			-			183,971
Cash flows from investing activities
Capital expenditures		-			(18,114	)		(489	)		-			(18,603	)
Proceeds from sale of assets		-			23,034			-			-			23,034
Net cash provided (used) by investing activities		-			4,920			(489	)		-			4,431
Cash flows from financing activities
Distributions		(28,038	)		-			-			-			(28,038	)
Proceeds from long-term debt		-			218,475			-			-			218,475
Repayments of long-term debt		-			(369,475	)		-			-			(369,475	)
Book overdraft		-			(9,711	)		-			-			(9,711	)
Intercompany activity		28,637			(20,267	)		(8,370	)		-			-
Net cash provided (used) by financing activities		599			(180,978	)		(8,370	)		-			(188,749	)

Increase (decrease) in cash		93			771			(1,211	)		-			(347	)
Cash beginning of period		2			731			1,813			-			2,546
Cash end of period	$	95		$	1,502		$	602		$	-		$	2,199

-25-

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