Breitburn Energy Partners LP - FORM 10-Q

Attached files

file	filename
EX-32.1 - Breitburn Energy Partners LP	exhibit32_1.htm
EX-31.1 - Breitburn Energy Partners LP	exhibit31_1.htm
EX-32.2 - Breitburn Energy Partners LP	exhibit32_2.htm
EX-31.2 - Breitburn Energy Partners LP	exhibit31_2.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

R Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2010

£ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ___ to ___

Commission File Number 001-33055

BreitBurn Energy Partners L.P.

(Exact name of registrant as specified in its charter)

Delaware	74-3169953
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification Number)

515 South Flower Street, Suite 4800
Los Angeles, California	90071
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (213) 225-5900

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes £ No £ (not yet applicable to registrant)

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o	Accelerated filer þ
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes £ No R

As of August 4, 2010, the registrant had 53,294,012 Common Units outstanding.



INDEX
		Page
		No.
	Cautionary Statement Regarding Forward-Looking Information	1

PART I
FINANCIAL INFORMATION

Item 1.	Financial Statements
	- Unaudited Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2010 and 2009	2
	- Unaudited Consolidated Balance Sheets at June 30, 2010 and December 31, 2009	3
	- Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009	4
	- Notes to Consolidated Financial Statements	5-16

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	17-23
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	24
Item 4.	Controls and Procedures	24

PART II
OTHER INFORMATION

Item 1.	Legal Proceedings	25
Item 1A.	Risk Factors	25-27
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28
Item 3.	Defaults Upon Senior Securities	28
Item 4.	(Removed and Reserved)	28
Item 5.	Other Information	28
Item 6.	Exhibits	29

Signatures		30

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Forward-looking statements are included in this report and may be included in other public filings, press releases, our website and oral and written presentations by management. Statements other than historical facts are forward-looking and may be identified by words such as “believe,” “expect,” “estimates,” “impact,” “future,” “affect,” “restrict,” “result,” “expand,” “pursue,” “engage,” “could,” “will,” “ongoing,” “goals,” variations of such words and words of similar meaning. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are changes in crude oil and natural gas prices; a significant reduction in the borrowing base under our bank credit facility; the impact of the current weak economic conditions on our business operations, financial condition and ability to raise capital; our level of indebtedness; the ability of financial counterparties to perform their obligations under existing agreements; delays in planned or expected drilling; the discovery of previously unknown environmental issues; the competitiveness of alternate energy sources or product substitutes; technological developments; potential disruption or interruption of our net production due to accidents or severe weather; changes in governmental regulations, including the regulation of derivatives and the oil and natural gas industry; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under “Cautionary Statement Regarding Forward-Looking Information” and Part I—Item 1A “—Risk Factors’’ of our Annual Report on Form 10-K for the year ended December 31, 2009, Part II —Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2010 and in Part II—Item 1A of this report. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

All forward-looking statements, expressed or implied, included in this report and attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

We undertake no obligation to update the forward-looking statements in this report to reflect future events or circumstances.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Operations

	Three Months Ended						Six Months Ended
	June 30,						June 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	$	82,079		$	59,872		$	162,548		$	117,515
Gains (losses) on commodity derivative instruments, net (note 10)		51,650			(97,259	)		103,715			(27,239	)
Other revenue, net		487			393			1,119			669
Total revenues and other income (loss) items		134,216			(36,994	)		267,382			90,945
Operating costs and expenses
Operating costs		39,371			32,004			75,222			66,385
Depletion, depreciation and amortization		23,909			26,962			45,963			57,263
General and administrative expenses		9,960			8,386			21,217			17,947
Loss on sale of assets		381			-			496			-
Total operating costs and expenses		73,621			67,352			142,898			141,595

Operating income (loss)		60,595			(104,346	)		124,484			(50,650	)

Interest and other financing costs, net		4,998			5,360			8,615			10,133
Losses (gains) on interest rate swaps (note 10)		1,418			(336	)		3,661			1,766
Other expense (income), net		21			(36	)		(4	)		(40	)

Income (loss) before taxes		54,158			(109,334	)		112,212			(62,509	)

Income tax expense (benefit) (note 3)		561			(809	)		705			(341	)

Net income (loss)		53,597			(108,525	)		111,507			(62,168	)
Less: Net income (loss) attributable to noncontrolling interest		(28	)		5			(99	)		(2	)

Net income (loss) attributable to the partnership	$	53,569		$	(108,520	)	$	111,408		$	(62,170	)

Basic net income (loss) per unit (note 8)	$	0.94		$	(2.06	)	$	1.96		$	(1.18	)
Diluted net income (loss) per unit (note 8)	$	0.94		$	(2.06	)	$	1.96		$	(1.18	)

See accompanying notes to consolidated financial statements.

BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Balance Sheets

		June 30,		December 31,
Thousands of dollars, except units outstanding		2010		2009
ASSETS
Current assets
Cash	$	3,347	$	5,766
Accounts and other receivables, net		59,513		65,209
Derivative instruments (note 10)		74,718		57,133
Related party receivables (note 4)		2,504		2,127
Inventory (note 5)		1,914		5,823
Prepaid expenses		5,434		5,888
Intangibles		248		495
Total current assets		147,678		142,441
Equity investments		7,848		8,150
Property, plant and equipment
Property, plant and equipment		2,095,764		2,066,685
Accumulated depletion and depreciation		(369,937)		(325,596)
Net property, plant and equipment		1,725,827		1,741,089
Other long-term assets
Derivative instruments (note 10)		97,627		74,759
Other long-term assets		12,739		4,590

Total assets	$	1,991,719	$	1,971,029

LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	21,351	$	21,314
Book overdraft		798		-
Derivative instruments (note 10)		16,594		20,057
Related party payables (note 4)		-		13,000
Revenue and royalties payable		15,978		18,224
Salaries and wages payable		5,165		10,244
Accrued liabilities		8,591		9,051
Total current liabilities		68,477		91,890

Long-term debt (note 6)		534,000		559,000
Deferred income taxes (note 3)		3,114		2,492
Asset retirement obligation (note 7)		37,332		36,635
Derivative instruments (note 10)		18,734		50,109
Other long-term liabilities		2,102		2,102
Total liabilities		663,759		742,228
Equity
Partners' equity (note 8)		1,327,497		1,228,373
Noncontrolling interest (note 9)		463		428
Total equity		1,327,960		1,228,801

Total liabilities and equity	$	1,991,719	$	1,971,029

Common Units outstanding (in thousands)		53,294		52,784

See accompanying notes to consolidated financial statements.

BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Cash Flows

	Six Months Ended
	June 30,
Thousands of dollars	2010			2009

Cash flows from operating activities
Net income (loss)	$	111,507		$	(62,168	)
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization		45,963			57,263
Unit based compensation expense		9,839			6,289
Unrealized (gains) losses on derivative instruments		(75,291	)		148,302
Income from equity affiliates, net		302			660
Deferred income tax expense (benefit)		622			(671	)
Amortization of intangibles		247			1,557
Loss on sale of assets		496			-
Other		1,757			1,648
Changes in net assets and liabilities
Accounts receivable and other assets		7,890			4,731
Inventory		3,909			(2,943	)
Net change in related party receivables and payables		(13,377	)		996
Accounts payable and other liabilities		(12,800	)		(14,129	)
Net cash provided by operating activities		81,064			141,535
Cash flows from investing activities
Capital expenditures		(24,997	)		(12,126	)
Proceeds from sale of assets		225			-
Property acquisitions		(1,550	)		-
Net cash used by investing activities		(26,322	)		(12,126	)
Cash flows from financing activities
Distributions		(21,312	)		(28,038	)
Proceeds from long-term debt		622,000			181,975
Repayments of long-term debt		(647,000	)		(277,975	)
Book overdraft		798			(5,624	)
Long-term debt issuance costs		(11,647	)		-
Net cash used by financing activities		(57,161	)		(129,662	)
Decrease in cash		(2,419	)		(253	)
Cash beginning of period		5,766			2,546
Cash end of period	$	3,347		$	2,293

See accompanying notes to consolidated financial statements.

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 fair statement have been included. Operating results for the three months and six months ended June 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. 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. For further information, refer to the consolidated financial statements and footnotes thereto included in our Annual Report.

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, resulting in Quicksilver’s ownership being reduced to approximately 17.7 million Common Units, representing approximately 33 percent of our Common Units. During the period from June 7, 2010 through July 30, 2010, Young sold approximately 1.7 million of these 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.

3. Income Taxes

Our deferred income tax liability was $3.1 million and $2.5 million at June 30, 2010 and December 31, 2009, respectively. The following table presents our income tax expense/benefit for the three months and six months ended June 30, 2010 and 2009 respectively:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Thousands of dollars	2010			2009			2010			2009
Federal current tax expense	$	18		$	2		$	147		$	25
Deferred federal tax expense (benefit) (a)		595			(948	)		622			(671	)
State income tax expense (benefit) (b)		(52	)		137			(64	)		305
Total income tax expense (benefit)	$	561		$	(809	)	$	705		$	(341	)

(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 is approximately $456,000.

At June 30, 2010 and December 31, 2009, we had current receivables of $1.8 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 first six months of 2010 and 2009, the monthly charges to BEC for indirect expenses totaled $2.8 million and $3.0 million, respectively, and charges for direct expenses including incentive compensation plan costs, direct payroll and administrative costs totaled $3.9 million and $2.3 million, respectively. For the three months and six months ended June 30, 2010, total oil and gas sales made by BEC on our behalf were approximately $0.5 million and $0.9 million, respectively. For the three months and six months ended June 30, 2009, total oil and gas sales made by BEC on our behalf were approximately $0.3 million and $0.5 million, respectively.

At June 30, 2010 and December 31, 2009, we had receivables of $0.2 million and $0.3 million, respectively, 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 six months ended June 30, 2010, total net gas sales to Quicksilver were approximately $0.6 million and $1.8 million, respectively. For the three months and six months ended June 30, 2009, total net gas sales to Quicksilver were approximately $0.5 million and $1.6 million, respectively. At June 30, 2010 and December 31, 2009, the related receivable was $0.5 million and $0.4 million, respectively.

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 applied towards reimbursement of this settlement payment. While discussions with our insurers are continuing, we expect to receive reimbursement for the full amount.

5. Inventory

Our crude oil inventory from our Florida operations at June 30, 2010 and December 31, 2009 was $1.9 million and $5.8 million, respectively. In the six months ended June 30, 2010, we sold 413 gross MBbls and produced 341 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. The decrease in inventory since December 31, 2009 reflects the higher amount of barrels sold than produced.

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, National Association, 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. Our next semi-annual borrowing base redetermination is scheduled for October 2010.

As of June 30, 2010 and December 31, 2009, we had $534.0 million and $559.0 million, respectively, in indebtedness outstanding. At June 30, 2010, the 1-month LIBOR interest rate plus an applicable spread on our long-term debt was 3.110 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.

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 June 30, 2010 and December 31, 2009, we were in compliance with the credit facilities’ 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 June 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 if we do incur such additional indebtedness, our borrowing base will be reduced by 25 percent of the original stated principal amount of such senior unsecured notes. 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 net income plus interest expense and other financing costs, 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, cumulative effect of changes in accounting principles, amortization of intangible sales contracts and amortization of intangible asset related to employment retention allowance, 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.

At June 30, 2010 and December 31, 2009, we had approximately $0.3 million in letters of credit outstanding.

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				Six Months Ended
	June 30,				June 30,
Thousands of dollars	2010		2009		2010		2009

Credit agreement (including commitment fees)	$	4,035	$	4,537	$	6,828	$	8,487
Amortization of discount and deferred issuance costs		963		823		1,787		1,646
Total	$	4,998	$	5,360	$	8,615	$	10,133

In connection with entry into the Second Amended and Restated Credit Agreement, we incurred $11.6 million in debt issuance costs.

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 June 30, 2010 and December 31, 2009 are presented in the following table:

	Six Months Ended			Year Ended
Thousands of dollars	June 30, 2010			December 31, 2009
Carrying amount, beginning of period	$	36,635		$	30,086
Liabilities settled in the current period		(280	)		(470	)
Revisions (a)		(313	)		4,883
Dispositions (b)		-			(252	)
Accretion expense		1,290			2,388
Carrying amount, end of period	$	37,332		$	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

In January 2010, 496,194 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 June 30, 2010 and December 31, 2009, we had 53,294,012 and 52,784,201 Common Units outstanding, respectively. At June 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 3,657,195 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. During the six months ended June 30, 2010, we also paid $1.3 million in cash at a rate equal to the distribution 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					Six Months Ended
	June 30,					June 30,
Thousands, except per unit amounts	2010		2009			2010		2009

Net income (loss) attributable to the partnership	$	53,569	$	(108,520	)	$	111,408	$	(62,170	)
Distributions on participating units not expected to vest		-		-			-		24
Net income (loss) attributable to common unitholders and participating securities	$	53,569	$	(108,520	)	$	111,408	$	(62,146	)

Weighted average number of units used to calculate basic and diluted earnings per unit (in thousands):
Common Units		53,294		52,770			53,294		52,737
Participating securities		3,530		-			3,411		-
Denominator for basic earnings per common unit (a)		56,824		52,770			56,705		52,737

Dilutive units (b)		136		-			127		-
Denominator for diluted earnings per common unit		56,961		52,770			56,832		52,737

Net income (loss) per common unit
Basic	$	0.94	$	(2.06	)	$	1.96	$	(1.18	)
Diluted	$	0.94	$	(2.06	)	$	1.96	$	(1.18	)

(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 and six months ended June 30, 2009 exclude 2,822 and 2,473 of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.
(b) The three months and six months ended June 30, 2010 include dilutive units potentially issuable to directors under compensation plans. The three months and six months ended June 30, 2009, exclude 106 and 105, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit.

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 June 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 six months ended June 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 in each period. For the three months and six months ended June 30, 2009, we recorded net income attributable to the noncontrolling interest of less than $0.1 million and net loss attributable to the noncontrolling interest of less than $0.1 million, respectively and dividends of less than $0.1 million and $0.1 million, respectively.

10. Financial Instruments

Fair Value of 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 June 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 and Toronto-Dominion Bank. We periodically obtain credit default swap information on our counterparties. As of June 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 June 30, 2010, our largest derivative asset balances were with JP Morgan Chase Bank N.A. and Credit Suisse Energy LLC, who accounted for approximately 58 percent and 21 percent of our derivative asset balance, respectively. As of June 30, 2010, our largest derivative liability balances were with Wells Fargo Bank National Association and Barclays Bank PLC, who accounted for approximately 74 percent and 21 percent of our derivative liability balance, respectively.

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 realized gains of $18.4 million and $30.6 million and unrealized gains of $33.2 million and $73.1 million for the three months and six months ended June 30, 2010, respectively, relating to our various market-based commodity contracts. We had realized gains of $51.5 million and $125.6 million and unrealized losses of $148.7 million and $152.8 million for the three months and six months ended June 30, 2009, respectively, relating to our various market-based commodity contracts. We had net financial instruments receivable relating to our commodity contracts of $146.3 million at June 30, 2010.

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

	Year
	2010			2011			2012		2013		2014
Gas Positions:
Fixed price swaps:
Hedged volume (MMBtu/d)		43,425			25,955			19,128		27,000		-
Average price ($/MMBtu)	$	8.20		$	7.26		$	7.10	$	6.92	$	-
Collars:
Hedged volume (MMBtu/d)		3,753			16,016			19,129		-		-
Average floor price ($/MMBtu)	$	9.00		$	9.00		$	9.00	$	-	$	-
Average ceiling price ($/MMBtu)	$	12.01		$	11.28		$	11.89	$	-	$	-
Total:
Hedged volume (MMBtu/d)		47,178			41,971			38,257		27,000		-
Average price ($/MMBtu)	$	8.26		$	7.92		$	8.05	$	6.92	$	-

Oil Positions:
Fixed price swaps:
Hedged volume (Bbls/d)		2,317			3,890			3,539		5,000		1,748
Average price ($/Bbl)	$	83.43		$	72.78		$	72.40	$	79.32	$	90.42
Participating swaps: (a)
Hedged volume (Bbls/d)		1,683			1,439			-		-		-
Average price ($/Bbl)	$	66.31		$	61.29		$	-	$	-	$	-
Average participation %		55.1	%		53.2	%		-		-		-
Collars:
Hedged volume (Bbls/d)		1,922			2,048			2,477		500		-
Average floor price ($/Bbl)	$	105.30		$	103.42		$	110.00	$	77.00	$	-
Average ceiling price ($/Bbl)	$	139.41		$	152.61		$	145.39	$	103.10	$	-
Floors:
Hedged volume (Bbls/d)		500			-			-		-		-
Average floor price ($/Bbl)	$	100.00		$	-		$	-	$	-	$	-
Total:
Hedged volume (Bbls/d)		6,422			7,377			6,016		5,500		1,748
Average price ($/Bbl)	$	86.76		$	79.02		$	87.88	$	79.11	$	90.42

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

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 June 30, 2010, our total debt outstanding was $534.0 million. In order to mitigate our interest rate exposure, we had the following interest rate derivative contracts in place at June 30, 2010, to fix a portion of floating LIBOR-base debt on our credit facility:

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

We had realized losses of $2.9 million and $5.8 million and unrealized gains of $1.5 million and $2.1 million for the three months and six months ended June 30, 2010, respectively, related to our interest rate derivative contracts. We had realized losses of $3.2 million and $6.3 million and unrealized gains of $3.5 million and $4.5 million for the three months and six months ended June 30, 2009, respectively, relating to our interest rate derivative contracts. We had net financial instruments payable related to our interest rate derivative contracts of $9.3 million at June 30, 2010.

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 June 30, 2010
Assets
Current assets - derivative instruments	$	25,798		$	49,264	$	-		$	(344	)	$	74,718
Other long-term assets - derivative instruments		45,020			59,375		-			(6,768	)		97,627
Total assets		70,818			108,639		-			(7,112	)		172,345

Liabilities
Current liabilities - derivative instruments		(9,137	)		-		(7,801	)		344			(16,594	)
Long-term liabilities - derivative instruments		(24,015	)		-		(1,487	)		6,768			(18,734	)
Total liabilities		(33,152	)		-		(9,288	)		7,112			(35,328	)

Net assets (liabilities)	$	37,666		$	108,639	$	(9,288	)	$	-		$	137,017

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.

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 June 30, 2010
Realized gains (losses)	$	1,424		$	17,011		$	(2,884	)	$	15,551
Unrealized gains (losses)		49,091			(15,876	)		1,466			34,681
Net gains (losses)	$	50,515		$	1,135		$	(1,418	)	$	50,232

Three Months Ended June 30, 2009
Realized gains (losses)	$	13,621		$	37,847		$	(3,191	)	$	48,277
Unrealized gains (losses)		(101,796	)		(46,931	)		3,527			(145,200	)
Net gains (losses)	$	(88,175	)	$	(9,084	)	$	336		$	(96,923	)

Six Months Ended June 30, 2010
Realized gains (losses)	$	1,732		$	28,849		$	(5,818	)	$	24,763
Unrealized gains		46,580			26,554			2,157			75,291
Net gains (losses)	$	48,312		$	55,403		$	(3,661	)	$	100,054

Six Months Ended June 30, 2009
Realized gains (losses)	$	61,183		$	64,373		$	(6,259	)	$	119,297
Unrealized gains (losses)		(144,832	)		(7,963	)		4,493			(148,302	)
Net gains (losses)	$	(83,649	)	$	56,410		$	(1,766	)	$	(29,005	)

(a) Included in gains (losses) on commodity derivative instruments, net on the consolidated statements of operations.
(b) Included in losses (gains) 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 June 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 six months ended June 30, 2010.

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 June 30, 2010 and December 31, 2009:

Thousands of dollars	Level 1		Level 2			Level 3		Total

As of June 30, 2010
Assets (liabilities):
Commodity derivatives (swaps, put and call options)	$	-	$	31,296		$	115,009	$	146,305
Other derivatives (interest rate swaps)		-		(9,288	)		-		(9,288	)
Total	$	-	$	22,008		$	115,009	$	137,017

As of December 31, 2009
Assets (liabilities):
Commodity derivatives (swaps, put and call options)	$	-	$	(29,303	)	$	102,475	$	73,172
Other derivatives (interest rate swaps)		-		(11,446	)		-		(11,446	)
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					Six Months Ended
	June 30,					June 30,
Thousands of dollars	2010		2009			2010		2009
Assets:
Beginning balance	$	108,716	$	154,344		$	102,475	$	153,218
Realized and unrealized gains		6,293		(34,959	)		12,534		(33,833	)
Settlement (a)		-		(6,030	)		-		(6,030	)
Ending balance	$	115,009	$	113,355		$	115,009	$	113,355

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

For the three months and six months ended June 30, 2010, realized gains of $5.8 million and $10.7 million and unrealized gains of $0.5 million and $1.8 million 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 six months ended June 30, 2009, realized gains of $4.4 million and $14.3 million and unrealized losses of $39.4 million and $48.1 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. 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 six months ended June 30, 2010, 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 three months and six months ended June 30, 2009, we had $6.0 million in settlements impacting the fair value of our derivatives 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 six months ended June 30, 2010 was $5.0 million and $9.8 million, respectively, and for the three months and six months ended June 30, 2009 was $3.1 million and $6.3 million, respectively.

During the three months and six months ended June 30, 2010, the board of directors of BreitBurn GP, LLC (our “General Partner”) approved the grant of 512 and 1,474,622 RPUs, respectively, to employees of BreitBurn Management under our First Amended and Restated 2006 Long-Term Incentive Plan (“LTIP”). Our outside directors were granted 12,568 and 59,784 phantom units under our LTIP during the three months and six months ended June 30, 2010, respectively. The fair market value of the RPUs granted during 2010 for computing the compensation expense under ASC 718 “Compensation—Stock Compensation” averaged $13.74 per unit.

In January 2010, 496,194 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 six months ended June 30, 2010, we paid $0 and less than $0.1 million, respectively, for various liability-classified compensation plans. For the three months and six months ended June 30, 2009, we paid $0 and approximately $0.1 million, respectively, in cash for various liability-classified compensation plans. For the three months ended June 30, 2010, we paid $1.3 million in cash, at a rate equal to the distribution paid to our unitholders, to holders of unvested RPUs and CPUs.

As of June 30, 2010, we had $37.7 million of total unrecognized compensation costs for all outstanding plans. This amount is expected to be recognized over the period from July 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 June 30, 2010 and December 31, 2009, we had various surety bonds for $11.0 million and $10.6 million, respectively. At June 30, 2010 and December 31, 2009, we had approximately $0.3 million in letters of credit outstanding.

13. Subsequent Events

On July 30, 2010, we announced a cash distribution to unitholders for the second quarter of 2010 at the rate of $0.3825 per Common Unit, to be paid on August 13, 2010 to the record holders of common units at the close of business on August 9, 2010.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis in conjunction with Management’s Discussion and Analysis in Part II—Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2009 (the “Annual Report”) and the consolidated financial statements and related notes therein. Our Annual Report contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual obligations. You should also read the following discussion and analysis together with Part II—Item 1A “—Risk Factors” of this report, Part II—Item 1A “—Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2010 and the “Cautionary Statement Regarding Forward Looking Information” in this report and in our Annual Report and Part I—Item 1A “—Risk Factors’’ of our Annual Report.

Overview

We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States. Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. Our assets consist primarily of producing and non-producing crude oil and natural gas reserves located primarily in the Antrim Shale and other formations in Northern Michigan, the Los Angeles Basin in California, the Wind River and Big Horn Basins in central Wyoming, the Sunniland Trend in Florida and the New Albany Shale in Indiana and Kentucky.

Our core investment strategies include:

·	Acquire long-lived assets with low-risk exploitation and development opportunities;

·	Use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;

·	Reduce cash flow volatility through commodity price and interest rate derivatives; and

·	Maximize asset value and cash flow stability through operating and technical expertise.

We are continuing to consider alternatives for increasing our liquidity on terms acceptable to us which may include additional hedge monetizations, asset sales, issuance of new equity or debt securities and other transactions. We continue to believe that maintaining our financial flexibility by reducing our bank debt should remain a priority. Maintaining financial flexibility in 2010 supports our long-term goals of providing cash flow stability and distribution growth, and following our core investment strategies.

Quarterly Highlights

In April 2010, we acquired interests in certain wells in Michigan for a purchase price of $1.6 million.

In April 2010, we paid Quicksilver $13 million in connection with the settlement of a lawsuit it had filed against us in late 2008. In June 2010, we received $3 million as a partial reimbursement from our insurers. While discussions with our insurers are continuing, we expect to receive reimbursement for the full amount. With the settlement of this lawsuit, we are now able to focus on growth strategies in 2010 including acquisition opportunities consistent with our long-term goals.

On April 28, 2010, we announced a cash distribution to unitholders for the first quarter of 2010 at the rate of $0.375 per Common Unit, which was paid on May 14, 2010.

In early May 2010, we completed an infill development well located in Raccoon Point in the Sunniland Trend. This well produced approximately 1,100 gross Bbls/d, or approximately 900 net Bbls/d, in June 2010, following a normal decline pattern, bringing our Florida production to approximately 2,200 net Bbls/d. We are currently drilling a second well to the same formation. The second well required a side-track and we now expect results in the third quarter of 2010.

On May 7, 2010, we entered into the Second Amended and Restated Credit Agreement, which set our borrowing base at $735 million.

We hold more than 470,000 net acres in Northern Michigan. We have completed a review of our land holdings in the area now believed to be prospective in the developing Collingwood-Utica shale play in Michigan. We own more than 120,000 net acres in this prospective area. We also own and operate significant midstream assets in Michigan. We believe that we are well positioned to be a leading participant in this potential new shale play.

Operational Focus and Capital Expenditures

In the first six months of 2010, we spent approximately $28 million on crude oil and natural gas capital expenditures, compared to approximately $11 million in the first six months of 2009. We spent approximately $11 million in Florida, $9 million in Michigan, Indiana and Kentucky, $4 million in California and $4 million in Wyoming. In the first six months of 2010, we drilled and completed five wells and completed three optimization projects in Florida, California and Wyoming, and we drilled and completed eight wells and completed seven optimization projects in Michigan, Indiana and Kentucky.

We expect our full year 2010 crude oil and natural gas capital spending program to be in the range of $72 million to $78 million, compared with approximately $29 million in 2009. We anticipate spending approximately 60 percent in California, Florida and Wyoming and approximately 40 percent in Michigan, Indiana and Kentucky. We expect to drill or redrill approximately 40 wells with 59 percent of our total capital spending focused on drilling, 21 percent on mandatory projects and 20 percent on optimization projects. As a result of our increased capital spending, but without considering potential acquisitions, we expect our 2010 production to be in the range of 6.3 million barrels of oil equivalent (“MMBoe”) to 6.7 MMBoe.

Commodity Prices

In the second quarter of 2010, the WTI spot price averaged $78 per barrel, compared with approximately $60 per barrel in the second quarter of 2009. In the first six months of 2010, WTI averaged $78 per barrel compared to $52 per barrel a year earlier. The average WTI spot price in July 2010 was approximately $76 per barrel. In 2009, the WTI spot price averaged approximately $62 per barrel.

In the second quarter of 2010, the NYMEX wholesale natural gas price averaged $4.35 per MMBtu compared with approximately $3.81 per MMBtu in the second quarter of 2009. In the first six months of 2010, the NYMEX wholesale natural gas price ranged from a low of $3.84 per MMBtu to a high of $6.01 per MMBtu. The average NYMEX wholesale natural gas price in July 2010 was approximately $4.60 per MMBtu. During 2009, the NYMEX wholesale natural gas price ranged from a low of $2.51 per MMBtu to a high of $6.07 per MMBtu.

Results of Operations

The table below summarizes certain of the results of operations for the periods indicated. The data for both periods reflects our results as they are presented in our unaudited consolidated financial statements included elsewhere in this report.

	Three Months											Six Months
	Ended June 30,					Increase /						Ended June 30,					Increase /
Thousands of dollars, except as indicated	2010		2009			Decrease			%			2010		2009			Decrease			%
Total production (MBoe)		1,663		1,654			9			1	%		3,258		3,257			1			0	%
Oil and NGL (MBoe)		812		762			50			7	%		1,539		1,504			35			2	%
Natural gas (MMcf)		5,106		5,349			(243	)		-5	%		10,313		10,518			(205	)		-2	%
Average daily production (Boe/d)		18,270		18,172			98			1	%		17,998		17,993			5			0	%
Sales volumes (MBoe)		1,725		1,635			90			5	%		3,319		3,218			101			3	%

Average realized sales price (per Boe) (a) (b) (c)	$	58.30	$	52.97		$	5.33			10	%	$	58.23	$	53.74		$	4.49			8	%
Oil and NGL (per Boe) (a) (b) (c)		69.99		65.47			4.52			7	%		71.26		63.95			7.31			11	%
Natural gas (per Mcf) (a) (b)		7.70		7.09			0.61			9	%		7.68		7.53			0.15			2	%

Oil, natural gas and NGL sales (d)	$	82,079	$	59,872		$	22,207			37	%	$	162,548	$	117,515		$	45,033			38	%
Realized gains on commodity derivative instruments (e)		18,435		51,468			(33,033	)		-64	%		30,581		125,556			(94,975	)		-76	%
Unrealized gains (losses) on commodity derivative instruments (e)		33,215		(148,727	)		181,942			n/a			73,134		(152,795	)		225,929			n/a
Other revenues, net		487		393			94			24	%		1,119		669			450			67	%
Total revenues		134,216		(36,994	)		171,210			n/a			267,382		90,945			176,437			n/a

Lease operating expenses and processing fees		29,627		28,442			1,185			4	%		60,118		57,668			2,450			4	%
Production and property taxes (f)		4,224		4,188			36			1	%		9,803		8,893			910			10	%
Total lease operating expenses		33,851		32,630			1,221			4	%		69,921		66,561			3,360			5	%

Transportation expenses		1,231		851			380			45	%		2,078		2,099			(21	)		-1	%
Purchases		74		21			53			n/a			126		40			86			n/a
Change in inventory		4,215		(1,498	)		5,713			n/a			3,097		(2,415	)		5,512			n/a
Uninsured loss		-		-			-			n/a			-		100			(100	)		-100	%
Total operating costs	$	39,371	$	32,004		$	7,367			23	%	$	75,222	$	66,385		$	8,837			13	%

Lease operating expenses pre taxes per Boe (g)	$	17.82	$	16.88		$	0.94			6	%	$	18.45	$	17.39		$	1.06			6	%
Production and property taxes per Boe		2.54		2.53			0.01			1	%		3.01		2.73			0.28			10	%
Total lease operating expenses per Boe		20.36		19.41			0.95			5	%		21.46		20.12			1.34			7	%

Depletion, depreciation and amortization (DD&A)	$	23,909	$	26,962		$	(3,053	)		-11	%	$	45,963	$	57,263		$	(11,300	)		-20	%
DD&A per Boe		14.38		16.30			(1.92	)		-12	%		14.11		17.58			(3.47	)		-20	%

(a) Includes realized gains on commodity derivative instruments.
(b) Excludes the effect of the early termination of oil and natural gas hedge contracts monetized in January 2009 for $45,632 and June 2009 for $24,955.
(c) Excludes amortization of an intangible asset related to crude oil sales contracts. Includes crude oil purchases.
(d) The three months and six months ended June 30, 2010 and 2009 include approximately $123, $247, $260 and $518, respectively, of amortization of an intangible asset related to crude oil sales contracts.
(e) Includes the effect of the early termination of oil and natural gas hedge contracts monetized in January 2009 for $45,632 and June 2009 for $24,955.
(f) Includes ad valorem and severance taxes.
(g) Includes lease operating expenses, district expenses and processing fees. 2009 excludes amortization of intangible asset related to the Quicksilver Acquisition.

Comparison of Results for the Three Months and Six Months Ended June 30, 2010 and 2009

The variances in our results were due to the following components:

Production

For the quarter ended June 30, 2010, production was in-line with the same period a year ago, at 1.7 MMBoe. Effective July 1, 2009, we sold our Lazy JL Field properties, which produced approximately 20 MBoe in the second quarter of 2009. The decrease in second quarter of 2010 production related to the impact of the sale of the Lazy JL Field, as well as a slight decrease in natural gas production in Michigan, Indiana and Kentucky compared to last year was offset primarily by increased production in Florida related to the new Raccoon Point well. For the six months ended June 30, 2010, production was in-line with the same period a year ago, at 3.3 MMBoe, primarily due to the decrease due to the sale of the Lazy JL Field, offset by higher Florida and California production related to production from new wells.

Revenues

Total oil, natural gas liquids (“NGL”) and natural gas sales revenues increased $22.2 million in the second quarter of 2010 as compared to the second quarter of 2009 primarily due to higher crude oil prices and higher sales volumes, primarily related to production from the new Florida well. Realized gains from commodity derivative instruments during the second quarter of 2010 were $18.4 million compared to realized gains of $51.5 million in the second quarter of 2009. Unrealized gains on commodity derivative instruments were $33.2 million compared to unrealized losses of $148.7 million in the second quarter of 2009. Realized and unrealized gains and losses on commodity derivative instruments for the second quarter of 2009 include the effect of $25.0 million in hedge contracts monetized in June 2009. Excluding the effect of the monetization, realized gains on commodity derivatives for the second quarter of 2009 would have been $26.5 million and unrealized losses would have been $123.7 million. Lower realized gains compared to the second quarter of 2009 are primarily due to higher commodity prices in the second quarter of 2010. Unrealized gains in the second quarter of 2010 as compared to unrealized losses in the second quarter of 2009, excluding the effect of the 2009 monetization, are primarily due to the decrease in commodity prices during the second quarter of 2010 compared to the increase in commodity prices during the second quarter of 2009.

Oil, NGL and natural gas sales revenues increased $45.0 million in the first six months of 2010 as compared to the first six months of 2009. Realized gains from commodity derivative instruments during the first six months of 2010 were $30.6 million compared to realized gains of $125.6 million in the first six months of 2009. Unrealized gains on commodity derivative instruments were $73.1 million in the first six months of 2010 compared to unrealized losses of $152.8 million in the first six months of 2009. The effect of net proceeds of $45.6 million in hedge contracts monetized in January 2009 and $25.0 million in June 2009 are reflected in realized and unrealized gains and losses on commodity derivative instruments in the first six months of 2009. Excluding the effect of the monetizations, realized gains on commodity derivatives in the first six months of 2009 would have been $55.0 million and unrealized losses would have been $82.2 million.

Lease operating expenses

Pre-tax lease operating expenses, including district expenses and processing fees, for the second quarter of 2010 totaled $29.6 million, which was $1.2 million higher than the second quarter of 2009. On a per Boe basis, pre-tax lease operating expenses were $17.82 for the second quarter of 2010. Pre-tax lease operating expenses, excluding amortization of intangible asset, were $16.88 per Boe for the second quarter of 2009. The increase is primarily attributable to higher operating costs in California and Florida related to higher oil prices in the second quarter of 2010 as compared to the second quarter of 2009.

Production and property taxes for the second quarter of 2010 totaled $4.2 million, or $2.54 per Boe, which is in line with the second quarter of 2009.

Pre-tax lease operating expenses and processing fees, for the first six months of 2010 totaled $60.1 million, or $18.45 per Boe, which is 6 percent higher per Boe than the first six months of 2009. The increase in per Boe lease operating expenses is primarily attributable to increasing service costs related to significantly higher oil prices during the first six months of 2010, compared to the first six months of 2009. Production and property taxes for the first six months of 2010 totaled $9.8 million, or $3.01 per Boe, which is 10 percent higher per Boe than the first six months of 2009.

Transportation expenses

In Florida, our crude oil sales are transported from the field by trucks and pipeline and then transported by barge to the sale point. Transportation costs incurred in connection with such operations are reflected in operating costs on the consolidated statements of operations. In the second quarter of 2010 and 2009, transportation costs totaled $1.2 million and $0.9 million, respectively. The increase in transportation costs is primarily due to higher Florida sales volumes in the second quarter of 2010, compared to the second quarter of 2009. In the first six months of 2010 and 2009, transportation costs totaled $2.1 million in each period.

Change in inventory

In Florida, our 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. Sales occur on average every six to eight weeks. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are credited to operating costs through the change in inventory account. Production expenses are charged to operating costs through the change in inventory account when they are sold. For the second quarter of 2010 and 2009, the change in inventory account amounted to a charge of $4.2 million and a credit of $1.5 million, respectively. For the first six months of 2010 and 2009, the change in inventory account amounted to a charge of $3.1 million and a credit of $2.4 million, respectively. The charges to inventory during the second quarter and first six months of 2010 reflect the higher amount of barrels sold than produced during the periods. The credits to inventory during the second quarter and first six months of 2009 reflect the higher amount of barrels produced than sold during the periods.

Depletion, depreciation and amortization

Depletion, depreciation and amortization expense (“DD&A”) totaled $23.9 million, or $14.38 per Boe, in the second quarter of 2010, a decrease of approximately 12 percent per Boe from the same period a year ago. DD&A expense totaled $46.0 million, or $14.11 per Boe, for the first six months of 2010, a decrease of approximately 20 percent per Boe from the same period a year ago. The decrease in DD&A compared to last year is primarily due to the decrease in 2010 DD&A rates due to higher 2010 commodity prices compared to the increase in 2009 DD&A rates due to the impact of year end 2008 price related reserve revisions.

General and administrative expenses

Our general and administrative (“G&A”) expenses totaled $10.0 million and $8.4 million for the quarters ended June 30, 2010 and 2009, respectively. This included $5.0 million and $3.1 million, respectively, in non-cash unit-based compensation expense related to management incentive plans. The increase in non-cash unit-based compensation expense was primarily due to new awards granted in the first quarter of 2010 and the overall increase in the value of the new awards due to the increase in unit price between year end and the grant date. For the second quarter of 2010 and 2009, G&A expenses, excluding non-cash unit-based compensation, were $5.0 million and $5.3 million, respectively.

G&A expenses totaled $21.2 million and $17.9 million for the six months ended June 30, 2010 and 2009, respectively. This included $9.8 million and $6.3 million, respectively, in non-cash unit-based compensation expense related to management incentive plans. The increase in non-cash unit-based compensation expense was primarily due to new awards granted in first quarter of 2010. For the first six months of 2010, G&A expenses, excluding non-cash unit-based compensation, were $11.4 million, which was $0.2 million lower than the first six months of 2009.

Interest and other financing costs

Our interest and financing costs totaled $5.0 million and $5.4 million for the quarters ended June 30, 2010 and 2009, respectively. This decrease in interest expense is primarily attributable to lower interest rates and lower debt balance. We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. See Note 10 to the consolidated financial statements within this report for a discussion of our interest rate derivative contracts. We had realized losses of $2.9 million and $3.2 million for the quarters ended June 30, 2010 and 2009 respectively, relating to our interest rate derivative contracts. We had unrealized gains of $1.5 million and $3.5 million for the quarters ended June 30, 2010 and 2009 respectively, relating to our interest rate derivative contracts.

Our interest and financing costs totaled $8.6 million and $10.1 million for the six months ended June 30, 2010 and 2009, respectively. This decrease in interest expense is primarily attributable to lower interest rates and lower debt balance. We had realized losses of $5.8 million and $6.3 million for the six months ended June 30, 2010 and 2009, respectively, relating to our interest rate derivative contracts. We had unrealized gains of $2.1 million and $4.5 million for the six months ended June 30, 2010 and 2009, respectively, relating to our interest rate derivative contracts.

Interest expense including realized losses on interest rate derivative contracts and excluding debt amortization and unrealized gains or losses on interest rate derivative contracts totaled $6.9 million and $7.7 million for the quarters ended June 30, 2010 and 2009, respectively. Interest expense including realized losses on interest rate derivative contracts and excluding debt amortization and unrealized gains or losses on interest rate derivative contracts totaled $12.6 million and $14.7 million for the six months ended June 30, 2010 and 2009, respectively.

Credit and Counterparty Risk

Our derivative financial instruments are exposed to credit risk from counterparties. See Note 10 to the consolidated financial statements within this report for a discussion of our derivative contracts and counterparties.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations and amounts available under our revolving credit facility. Historically, our primary uses of cash have been for our operating expenses, capital expenditures, cash distributions to unitholders and unit repurchase transactions. To fund certain acquisition transactions, we have also accessed the private placement markets and have issued equity as partial consideration for the acquisition of oil and gas properties. As market conditions have permitted, we have also engaged in asset sale transactions. In the future, we may look to the public and private capital markets to fund our acquisitions and refinancing transactions.

In February 2010, we announced our intention to reinstate quarterly cash distributions to our unitholders, beginning with the first quarter of 2010. On May 14, 2010, we paid a cash distribution to unitholders for the first quarter of 2010 at the rate of $0.375 per Common Unit. On July 30, 2010, we announced a cash distribution to unitholders for the second quarter of 2010 at the rate of $0.3825 per Common Unit, to be paid on August 13, 2010.

Operating activities. Our cash flow from operating activities for the six months ended June 30, 2010 was $81.1 million, compared to $141.5 million for the six months ended June 30, 2009. Included in cash flow from operating activities in the 2009 period was the effect of $45.6 million and $25.0 million in hedge contract monetizations completed in January and June 2009, respectively. Excluding the effect of the hedge contract monetization in 2009, cash from operating activities was higher during the six months ended June 30, 2010 compared to the same period of 2009, primarily due to higher oil prices.

Investing activities. Net cash used in investing activities during the six months ended 2010 and 2009 was $26.3 million and $12.1 million, respectively, which was predominantly spent on capital expenditures, primarily on drilling and completions, including drilling of the new Raccoon Point well in Florida.

Financing activities. Net cash used in financing financing activities for the six months ended June 30, 2010 and June 30, 2009 was $57.2 million and $129.7 million, respectively. We had outstanding borrowings under our credit facility of $534.0 million at June 30, 2010 and $559.0 million at December 31, 2009. For the six months ended June 30, 2010, we made cash distributions of $21.3 million, borrowed $622.0 million and repaid $647.0 million under the credit facility. For the six months ended June 30, 2009, we made cash distributions of $28.0 million, borrowed $182.0 million and repaid $278.0 million. During the six months ended June 30, 2010, we paid $11.6 million in debt issuance costs in connection with the Second Amended and Restated Credit Agreement. See “—Credit Agreement” below.

Credit Agreement

On May 7, 2010, BOLP, as borrower, and we and our wholly owned subsidiaries, as guarantors, Wells Fargo Bank National Association, as administrative agent, and the lenders party thereto, entered into a Second Amended and Restated Credit Agreement, which set our borrowing base at $735 million. We had outstanding borrowings under our credit facility of $522 million at July 31, 2010. Our next semi-annual borrowing base redetermination is scheduled for October 2010. As amended, the credit facility will mature on May 7, 2014.

As of July 31, 2010, the lending group under the Second Amended and Restated Credit Agreement included 15 banks. Of the $735 million in total commitments under the credit facility, Wells Fargo Bank National Association held approximately 12.4 percent of the commitments. 11 banks held between 5 percent and 7.5 percent of the commitments, including Union Bank, N.A., Bank of Montreal, The Bank of Nova Scotia, Houston Branch, BNP Paribas, Citibank, N.A., Royal Bank of Canada, U.S. Bank National Association, Bank of Scotland plc, Barclays Bank PLC, The Royal Bank of Scotland plc and Credit Suisse AG, Cayman Islands Branch, with each remaining lenders holding less than 5 percent of the commitments. In addition to our relationships with these institutions under the credit facility, from time to time we engage in other transactions with a number of these institutions. Such institutions or their affiliates may serve as underwriter or initial purchaser of our debt and equity securities and/or serve as counterparties to our commodity and interest rate derivative agreements.

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 June 30, 2010, we were in compliance with these 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 June 30, 2010, the applicable margin on our borrowings was 250 basis points. The Second Amended and Restated Credit Agreement is less restrictive than the First Amended and Restated Credit Facility in that it also permits us to incur or guaranty additional debt up to $350 million in senior unsecured notes, and if we do incur such additional indebtedness, our borrowing base will be reduced by 25 percent of the original stated principal amount of such senior unsecured notes. 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.

Please see Part II—Item 1A “—Risk Factors — Risks Related to Our Business — Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2010 for more information on the effect of an event of default under the Second Amended and Restated Credit Agreement.

We did not have any off-balance sheet arrangements as of June 30, 2010. As of June 30, 2010 and December 31, 2009, our asset retirement obligation was $37.3 million and $36.6 million, respectively.

Recently issued accounting pronouncements

See Note 2 to the consolidated financial statements within this report for a discussion of recently issued accounting pronouncements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Part II—Item 7A in our Annual Report. Also, see Note 10 to the consolidated financial statements within this report for additional discussion related to our financial instruments, including a summary of our derivative contracts as of June 30, 2010.

Changes in Fair Value

The fair value of our outstanding oil and gas commodity derivative instruments was a net asset of approximately $146.3 million at June 30, 2010 and approximately $73.2 million at December 31, 2009. With a $5.00 per barrel increase or decrease in the price of oil, and a corresponding $1.00 per Mcf change in natural gas, the fair value of our outstanding oil and gas commodity derivative instruments at June 30, 2010, would have decreased or increased our net asset by approximately $85 million.

Price risk sensitivities were calculated by assuming across-the-board increases in price of $5.00 per barrel for oil and $1.00 per Mcf for natural gas regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of actual changes in prompt month prices equal to the assumptions, the fair value of our derivative portfolio would typically change by less than the amounts given due to lower volatility in out-month prices.

The fair value of our outstanding interest rate derivative instruments was a net liability of approximately $9.3 million and $11.4 million at June 30, 2010 and December 31, 2009, respectively. With a one percent increase or decrease in the LIBOR rate, the fair value of our outstanding interest rate derivative instruments at June 30, 2010 would have decreased or increased our net liability by approximately $4 million.

Item 4. Controls and Procedures

Controls and Procedures

We maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Our management, with the participation of our General Partner’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2010. Based on that evaluation, our General Partner’s Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2010 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

In February 2010, we and Quicksilver Resources Inc. (“Quicksilver”) agreed to settle all claims with respect to the litigation filed by Quicksilver in October 2008 pursuant to a settlement agreement dated February 3, 2010 (the “Original Settlement”).

On April 5, 2010, we, our general partner, BreitBurn GP, LLC (the “General Partner”), Quicksilver, Provident Energy Trust (“Provident”), Halbert S. Washburn and Randall H. Breitenbach entered into a definitive settlement agreement (the “Settlement Agreement”), confirming certain terms of the Original Settlement, wherein the parties agreed to settle all claims with respect to the litigation filed by Quicksilver against us, the General Partner, certain of our subsidiaries and directors and Provident pending in the 48th District Court in Tarrant County, Texas (the “Court”). The Settlement Agreement supersedes the Original Settlement agreement dated February 3, 2010 in its entirety.

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 filed by Quicksilver before the Court. On April 6, 2010, pursuant to the Settlement Agreement, we paid Quicksilver $13 million and in June 2010, we received $3 million as part of the reimbursement we expect from our insurers. However, discussions with our insurers are ongoing. The terms of the Settlement Agreement were effective on April 6, 2010 when the Court entered an order dismissing the lawsuit.

Please see Part I—Item 3 “—Legal Proceedings” in our Annual Report for more information on the lawsuit instituted by Quicksilver. Please also see our Current Report on Form 8-K filed on April 9, 2010 for more information on the terms of the Settlement Agreement.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject.

Item 1A. Risk Factors

Except as set forth below and in Part II—Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, there have been no material changes to the Risk Factors disclosed in Part I—Item 1A “—Risk Factors” of our Annual Report. The following risk factors update and amend certain of the “Risks Related to Our Business” included in our Annual Report.

Risks Related to Our Business

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas exploration, production, gathering and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, in California, there have been proposals at the legislative and executive levels over the past two years for tax increases which have included a severance tax as high as 12.5 percent on all oil production in California. Although the proposals have not passed the California Legislature, the financial crisis in the State of California could lead to a severance tax on oil being imposed in the future. For example, there is currently an Assembly Bill, AB 1604, being proposed in the California Legislature that includes a 10 percent severance tax on oil production. A severance tax on oil and gas production has been discussed by California legislators and such a tax could be included in a final budget proposal for the State that will be negotiated over the next several months. We have significant oil production in California and while we cannot predict the impact of such a tax without having more specifics, the imposition of such a tax could have severe negative impacts on both our willingness and ability to incur capital expenditures in California to increase production, could severely reduce or completely eliminate our California profit margins and would result in lower oil production in our California properties due to the need to shut-in wells and facilities made uneconomic either immediately or at an earlier time than would have previously been the case. There also is currently proposed federal legislation in three areas (tax, climate change and hydraulic fracturing) that if adopted could significantly affect our operations. The following are brief descriptions of the proposed laws:

Tax Legislation. President Obama’s proposed Fiscal Year 2011 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination or postponement of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Each of these changes is proposed to be effective for taxable years beginning, or in the case of costs described in (ii) and (iv), costs paid or incurred, after December 31, 2010. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and thus could negatively impact our limited partners or the holders of our debt obligations.

Climate Change. Federal and state governments and agencies are currently evaluating and promulgating climate-related legislation and regulations that would restrict emissions of greenhouse gases (“GHGs”) in areas in which we conduct business. The Environmental Protection Agency (“EPA”) is taking steps to require monitoring and reporting of GHG emissions and to regulate GHGs as pollutants under the Clean Air Act. On September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. Additionally, on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs, present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which would regulate emissions of GHGs from large stationary sources of emissions, such as power plants or industrial facilities. The motor vehicle rule became effective in March 2010, but it does not require immediate reductions in GHG emissions. The EPA has asserted that the final motor vehicle GHG emission standards will trigger construction and operating permit requirements for stationary sources. Further, on May 13, 2010, the EPA issued a pre-publication version of its final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V programs. The final rule tailors the PSD and Title V permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, beginning January 2, 2011, with the largest sources becoming subject to permitting first.

The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. For example, our production in Michigan could be adversely affected by such regulations, because the production of natural gas in Michigan from the Antrim Shale also produces a significant quantity of carbon dioxide.

Further, legislation is pending in both houses of Congress to reduce emissions of GHGs, and almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. It is not possible at this time to predict how potential future laws or regulations addressing greenhouse gas emissions would impact our business, but any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas we produce.

Hydraulic Fracturing Legislation. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions but is not subject to regulation at the federal level. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

In addition, a change in the jurisdictional characterization of our gathering assets by federal, state or local regulatory agencies or a change in policy by those agencies with respect to those assets may result in increased regulation of those assets.

Failure to comply with federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you. Please read “Business—Environmental Matters and Regulation” and “Business—Other Regulation of the Oil and Gas Industry” in our Annual Report for a description of the laws and regulations that affect us.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Partnership, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the Securities and Exchange Commission (the “SEC”) to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and make distributions to our unitholders. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, our results of operations and our ability to make distributions to unitholders.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

There were no sales of unregistered equity securities during the period covered by this report.

Item 3. Defaults Upon Senior Securities

None.

Item 4. (Removed and Reserved)

None.

Item 5. Other Information

2011 Annual Meeting

On July 29, 2010, the board of directors (the “Board”) of the General Partner determined that the 2011 Annual Meeting of the Limited Partners of the Partnership (the “2011 Annual Meeting”) will be held on June 23, 2011 at a time and location in Los Angeles, California to be determined by the authorized officers of the General Partner and specified in the proxy statement for the 2011 Annual Meeting.

Nomination Period for the 2011 Annual Meeting

In accordance with the provisions of Section 13.4(b)(vi)(A)(2) of the First Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of October 10, 2006, as amended, the Board of the General Partner has determined that for purposes of the 2011 Annual Meeting, a Limited Partner’s notice of nominations of persons for election to the Board of the General Partner will be considered timely if such notice is delivered to the General Partner not later than the close of business on March 25, 2011, nor earlier than the close of business on February 23, 2011.

Record Date for the 2011 Annual Meeting

The Board of the General Partner has established the close of business on April 25, 2011 as the record date for the determination of the limited partners entitled to receive notice of and to vote at the 2011 Annual Meeting and at any adjournments or postponements thereof.

Item 6. Exhibits

NUMBER		DOCUMENT
3.1		First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2006).
3.2		Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
3.3		Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2009).
3.4		Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 1, 2009).
3.5		Amendment No.4 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
3.6		Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
4.1		First Amendment to Registration Rights Agreement between BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
10.1		Second Amended and Restated Credit Agreement dated May 7, 2010, by and among BreitBurn Operating L.P, as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank National Association as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the period ended March 31, 2010 (File No. 001-33055) filed on May 10, 2010).
10.2		Settlement Agreement dated April 5, 2010 by and among Quicksilver Resources, Inc., BreitBurn Energy Partners L.P., BreitBurn GP LLC, Provident Energy Trust, Randall H. Breitenbach and Halbert S. Washburn (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
31.1*		Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.

** Furnished herewith.

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 thereunto duly authorized.

BREITBURN ENERGY PARTNERS L.P.

	By:	BREITBURN GP, LLC,
		its General Partner
Dated: August 4, 2010	By:	/s/ Halbert S. Washburn
		Halbert S. Washburn
		Chief Executive Officer
Dated: August 4, 2010	By:	/s/ James G. Jackson
		James G. Jackson
		Chief Financial Officer

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