Breitburn Energy Partners LP - FORM 10-Q

Attached files

file	filename
EX-31.1 - Breitburn Energy Partners LP	exhibit31_1.htm
EX-32.2 - Breitburn Energy Partners LP	exhibit32_2.htm
EX-32.1 - Breitburn Energy Partners LP	exhibit32_1.htm
EX-10.3 - Breitburn Energy Partners LP	exhibit10_3.htm
EX-32.3 - Breitburn Energy Partners LP	exhibit32_3.htm
EX-31.2 - Breitburn Energy Partners LP	exhibit31_2.htm
EX-31.3 - Breitburn Energy Partners LP	exhibit31_3.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 September 30, 2009

£ 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 þ	Accelerated filer o
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 November 6, 2009, the registrant had 52,784,201 Common Units outstanding.

INDEX
		Page
		No.
	Cautionary Statement Relevant to Forward-Looking Information	1
	Glossary of Oil and Gas Terms; Description of References	2-4

PART I
FINANCIAL INFORMATION

Item 1.	Financial Statements
	- Unaudited Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2009 and 2008	5
	- Unaudited Consolidated Balance Sheets at September 30, 2009 and December 31, 2008	6
	- Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008	7
	- Notes to Consolidated Financial Statements	8-24

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	25-34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	35-38
Item 4.	Controls and Procedures	39

PART II
OTHER INFORMATION

Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40-43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Submission of Matters to a Vote of Security Holders	44
Item 5.	Other Information	44
Item 6.	Exhibits	45

		46
	Exhibit Index	47

CAUTIONARY STATEMENT RELEVANT TO 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 “believes,” “estimates,” “impact,” “future,” “projection,” “forecasts,” “affect,” “restrict,” “result,” “expand,” “pursue,” “engage,” “could,” “will,” 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 economic downturn 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; the uncertainty related to the litigation instituted by Quicksilver against us; potential disruption or interruption of our net production due to accidents or severe weather; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; and the factors set forth under “Cautionary Statement Relevant to Forward Looking Information” and Part I—Item 1A. “—Risk Factors’’ of our Annual Report on Form 10-K for the year ended December 31, 2008 (the “Annual Report”), Part II —Item 1A of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009, 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.

Available Information

Our internet website address is www.breitburn.com. We make available, free of charge at the “Investor Relations” portion of our website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Acts of 1934, as amended, as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”). The information contained on our website does not constitute part of this report.

GLOSSARY OF OIL AND GAS TERMS; DESCRIPTION OF REFERENCES

The following is a description of the meanings of some of the oil and gas industry terms that may be used in this report. The definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

Bbl/d: Bbl per day.

Boe: One barrel of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil.

Boe/d: Boe per day.

Btu: British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

exploitation: A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

LIBOR: London Interbank Offered Rate.

MichCon: Michigan Consolidated Gas Company.

MBbls: One thousand barrels of crude oil or other liquid hydrocarbons.

MBoe: One thousand barrels of crude oil equivalent.

MBoe/d: MBoe per day.

Mcf: One thousand cubic feet of natural gas.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent, determined using a ratio of one Bbl of crude oil to six Mcf of natural gas.

MMBtu: One million British thermal units.

MMBtu/d: One million British thermal units per day.

NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

oil: Crude oil, condensate and natural gas liquids.

proved reserves: The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

reserve: That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

West Texas Intermediate (“WTI”): Light, sweet crude oil with high API gravity and low sulfur content used as the benchmark for U.S. crude oil refining and trading. WTI is deliverable at Cushing, Oklahoma to fill NYMEX futures contracts for light, sweet crude oil.

_____________________________________

References in this filing to “the Partnership,” “we,” “our,” “us” or like terms refer to BreitBurn Energy Partners L.P. and its subsidiaries. References in this filing to “BEC” or the “Predecessor” refer to BreitBurn Energy Company L.P., our predecessor, and its predecessors and subsidiaries. References in this filing to “BreitBurn GP” or the “General Partner” refer to BreitBurn GP, LLC, our general partner and our wholly-owned subsidiary as of June 17, 2008. References in this filing to “Provident” refer to Provident Energy Trust. References in this filing to “BreitBurn Corporation” refer to BreitBurn Energy Corporation, a corporation owned by Randall Breitenbach and Halbert Washburn, the Co-Chief Executive Officers of our general partner. References in this filing to “BreitBurn Management” refer to BreitBurn Management Company, LLC, our asset manager and operator, and wholly-owned subsidiary as of June 17, 2008. References in this filing to “BOLP” or “BreitBurn Operating” refer to BreitBurn Operating L.P., our wholly-owned operating subsidiary. References in this filing to “BOGP” refer to BreitBurn Operating GP, LLC, the general partner of BOLP. References in this filing to “our properties” refer to, as of December 31, 2006, the oil and gas properties contributed to us and our subsidiaries by BEC in connection with our initial public offering. These oil and gas properties include certain fields in the Los Angeles Basin in California, including interests in the Santa Fe Springs, Rosecrans and Brea Olinda Fields, and the Wind River and Big Horn Basins in central Wyoming. As of January 1, 2007, “our properties” include any additional properties that we have acquired since that date. As of July 1, 2009, “our properties” exclude the Lazy JL Field, which was sold effective July 1, 2009. References to “Quicksilver” refer to Quicksilver Resources Inc. from whom we acquired oil and gas properties and facilities in Michigan, Indiana and Kentucky on November 1, 2007. References in this filing to “Calumet” refer to Calumet Florida L.L.C., from whom we acquired certain interests in oil leases and related assets located in Florida on May 24, 2007. References in this filing to “BEPI” refer to BreitBurn Energy Partners I, L.P. References in this filing to “TIFD” refer to TIFD X-III LLC, from whom we acquired a 99 percent limited partner interest in BEPI on May 25, 2007, which owned interests in the Sawtelle and East Coyote oil fields located in California.

_____________________________________

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands of dollars, except unit amounts	2009			2008			2009			2008

Revenues and other income items:
Oil, natural gas and natural gas liquid sales	$	62,674		$	130,249		$	180,189		$	386,060
Gains (losses) on commodity derivative instruments, net (note 14)		12,719			407,441			(14,520	)		(29,228	)
Other revenue, net (note 9)		261			806			930			2,324
Total revenues and other income items		75,654			538,496			166,599			359,156
Operating costs and expenses:
Operating costs		33,888			41,915			100,273			118,952
Depletion, depreciation and amortization		24,130			21,477			81,393			64,228
General and administrative expenses		9,318			6,479			27,265			24,073
Loss on sale of assets (note 4)		5,470			-			5,470			-
Total operating costs and expenses		72,806			69,871			214,401			207,253

Operating income (loss)		2,848			468,625			(47,802	)		151,903

Interest and other financing costs, net		4,549			9,021			14,682			19,569
Losses on interest rate swaps (note 14)		3,792			2,964			5,557			3,937
Other income, net		(84	)		(464	)		(124	)		(114	)
Total other expense		8,257			11,521			20,115			23,392

Gain (loss) before taxes		(5,409	)		457,104			(67,917	)		128,511

Income tax expense (benefit) (note 5)		(13	)		2,599			(354	)		1,262

Net income (loss)		(5,396	)		454,505			(67,563	)		127,249

Less: Net income attributable to noncontrolling interest (note 13)		(12	)		(51	)		(14	)		(175	)

Net income (loss) attributable to the partnership		(5,408	)		454,454			(67,577	)		127,074
General partner loss		-			-			-			(2,019	)

Net income (loss) attributable to limited partners	$	(5,408	)	$	454,454		$	(67,577	)	$	129,093

Basic net income (loss) per unit	$	(0.10	)	$	8.43		$	(1.28	)	$	2.06
Diluted net income (loss) per unit	$	(0.10	)	$	8.40		$	(1.28	)	$	2.06
Weighted average number of units used to calculate
Basic net income (loss) per unit		52,770,011			53,922,984			52,747,861			62,604,519
Diluted net income (loss) per unit		52,770,011			54,071,521			52,747,861			62,752,289

See accompanying notes to consolidated financial statements.

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

	September 30,			December 31,
Thousands of dollars, except unit amounts	2009			2008

ASSETS
Current assets:
Cash	$	2,199		$	2,546
Accounts receivable, net		38,198			47,221
Derivative instruments (note 14)		63,249			76,224
Related party receivables (note 6)		4,744			5,084
Inventory (note 7)		4,960			1,250
Prepaid expenses		6,880			5,300
Intangibles (note 8)		807			2,771
Other current assets		170			170
Total current assets		121,207			140,566
Equity investments (note 9)		8,686			9,452
Property, plant and equipment
Oil and gas properties		2,046,860			2,057,531
Non-oil and gas assets		8,145			7,806
		2,055,005			2,065,337
Accumulated depletion and depreciation		(300,831	)		(224,996	)
Net property, plant and equipment		1,754,174			1,840,341
Other long-term assets
Intangibles (note 8)		125			495
Derivative instruments (note 14)		97,500			219,003
Other long-term assets		8,362			6,977

Total assets	$	1,990,054		$	2,216,834
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	18,246		$	28,302
Book overdraft		160			9,871
Derivative instruments (note 14)		14,770			10,192
Revenue distributions payable		10,727			16,162
Salaries and wages payable		6,111			6,249
Accrued liabilities		14,559			9,214
Total current liabilities		64,573			79,990

Long-term debt (note 10)		585,000			736,000
Deferred income taxes (note 5)		3,385			4,282
Asset retirement obligation (note 11)		35,692			30,086
Derivative instruments (note 14)		31,322			10,058
Other long-term liabilities		2,120			2,987
Total liabilities		722,092			863,403
Equity:
Partners' equity (note 12)		1,267,528			1,352,892
Noncontrolling interest (note 13)		434			539
Total equity		1,267,962			1,353,431

Total liabilities and equity	$	1,990,054		$	2,216,834

Common units outstanding		52,770,011			52,635,634

See accompanying notes to consolidated financial statements.

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

	Nine Months Ended
	September 30,
Thousands of dollars	2009			2008

Cash flows from operating activities
Net income (loss)	$	(67,563	)	$	127,249
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization		81,393			64,228
Unit based compensation expense		9,736			5,192
Unrealized gain (loss) on derivative instruments		160,319			(39,398	)
Distributions greater than income from equity affiliates		766			772
Deferred income tax		(897	)		625
Amortization of intangibles		2,334			2,339
Loss on sale of assets		5,470			-
Other		2,472			1,803
Changes in net assets and liablities:
Accounts receivable and other assets		3,590			1,463
Inventory		(3,710	)		(2,292	)
Net change in related party receivables and payables		340			27,614
Accounts payable and other liabilities		(10,279	)		1,366
Net cash provided by operating activities		183,971			190,961
Cash flows from investing activities
Capital expenditures		(18,603	)		(86,811	)
Proceeds from sale of assets		23,034			-
Property acquisitions		-			(9,988	)
Net cash provided (used) by investing activities		4,431			(96,799	)
Cash flows from financing activities
Purchase of common units		-			(336,216	)
Distributions		(28,038	)		(93,304	)
Proceeds from the issuance of long-term debt		218,475			659,093
Repayments of long-term debt		(369,475	)		(321,493	)
Book overdraft		(9,711	)		7,603
Long-term debt issuance costs		-			(4,974	)
Net cash used by financing activities		(188,749	)		(89,291	)
Increase (decrease) in cash		(347	)		4,871
Cash beginning of period		2,546			5,929
Cash end of period	$	2,199		$	10,800

See accompanying notes to consolidated financial statements.

Notes to Consolidated Financial Statements

1. Organization and Description of Operations

We are an independent oil and gas partnership focused on the exploitation, development and acquisition of oil and gas properties in the United States. We are a Delaware limited partnership formed on March 23, 2006. Our general partner is BreitBurn GP, a Delaware limited liability company, also formed on March 23, 2006, and our wholly-owned subsidiary since June 17, 2008. The board of directors of our General Partner has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly-owned subsidiary, BOLP and BOLP’s general partner BOGP. We own all of the ownership interests in BOLP and BOGP.

Prior to June 17, 2008, the membership interests in our General Partner were held by BreitBurn Management. In addition, prior to that date, 95.55 percent of the membership interests in BreitBurn Management were held by Provident and the remaining 4.45 percent of the membership interests in BreitBurn Management were held by BreitBurn Energy Corporation, a California corporation wholly-owned by the Co-Chief Executive Officers of our General Partner. On June 17, 2008, we, BreitBurn Corporation, BreitBurn Management, Provident and certain of its subsidiaries completed a series of transactions (the “Purchase, Contribution and Partnership Transactions”), pursuant to which, among other things, our General Partner and BreitBurn Management became our wholly-owned subsidiaries, the economic portion of the General Partner’s 0.66473 percent general partner interest in us was eliminated and our limited partners were given a right to nominate and vote in the election of directors to the Board of Directors of the General Partner. The General Partner has no other economic interests, does not conduct other operations, and has no assets or liabilities. See Part I—Item 1 “—Business —Ownership and Structure” in our Annual Report for a further discussion of the Purchase, Contribution and Partnership Transactions.

BreitBurn Management manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 6 for information regarding our relationship with BreitBurn Management. In connection with the acquisition of Provident’s ownership in BEC by Metalmark Capital Partners, Greenhill Capital Partners, a third party institutional investor and members of senior management, BreitBurn Management entered into the Second Amended and Restated Administrative Services Agreement to manage BEC's properties for a term of five years. In addition, we entered into an Omnibus Agreement with BEC detailing rights with respect to business opportunities and providing us with a right of first offer with respect to the sale of assets by BEC.

BreitBurn Finance Corporation was incorporated under the laws of the State of Delaware on June 1, 2009, is wholly owned by us, and has no assets or liabilities. Its activities are limited to co-issuing debt securities and engaging in other activities incidental thereto.

The following diagram depicts our organizational structure as of September 30, 2009:

2. Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair statement have been included. Operating results for the three months and nine months ended September 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009. The consolidated balance sheet at December 31, 2008 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.

In the first quarter of 2009, we began classifying regional operation management expenses as operating costs rather than general and administrative expenses to better align our operating and management costs with our organizational structure and to be more consistent with industry practices. As such, we have revised classification of these expenses for the three months and nine months ended September 30, 2008. The reclassification did not affect previously reported total revenues, net income or net cash provided by operating activities. The following table reflects all classification changes for the three months and nine months ended September 30, 2008:

	Three Months Ended			Nine Months Ended
Thousands of dollars	September 30, 2008			September 30, 2008
Operating costs
As previously reported	$	39,515		$	110,210
District expense reclass from G&A		2,400			8,742
As revised	$	41,915		$	118,952

G&A expenses
As previously reported	$	8,879		$	32,815
District expense reclass to operating costs		(2,400	)		(8,742	)
As revised	$	6,479		$	24,073

3. Recently Issued Accounting Standards

We adopted new accounting standards in the first nine months of 2009 related to fair value measurements as discussed in Notes 11 and 14, the earnings per share impact of instruments granted in share-based payment transactions as discussed in Note 12, noncontrolling interests as discussed in Note 13, disclosures about derivative instruments and hedging activities as discussed in Note 14, subsequent events as discussed in Note 17 and business combinations, which we will apply prospectively to business combinations with acquisition dates after January 1, 2009.

Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 105 “Generally Accepted Accounting Principles” establishes the FASB ASC as the source of authoritative accounting principles recognized by the FASB to be applied in the preparation of financial statements in conformity with GAAP. ASC 105 explicitly recognizes rules and interpretive releases of the SEC under federal securities laws as authoritative GAAP for SEC registrants. This topic, which has changed the way we reference GAAP, is effective for financial statements ending after September 15, 2009. This topic does not change GAAP and did not have an impact on our financial position, results of operations or cash flows.

SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”). In December 2008, the SEC issued Release 33-8995 adopting new rules for reserves estimate calculations and related disclosures. The new reserve estimate disclosures apply to all annual reports for fiscal years ending on or after December 31, 2009 and thereafter, and to all registration statements filed after that date. The new rules do not permit companies to voluntarily comply at an earlier date. The revised proved reserve definition incorporates a new definition of “reasonable certainty” using the PRMS (Petroleum Resource Management System) standard of “high degree of confidence” for deterministic method estimates, or a 90 percent recovery probability for probabilistic methods used in estimating proved reserves. The new rules also permit a company to establish undeveloped reserves as proved with appropriate degrees of reasonable certainty established absent actual production tests and without artificially limiting such reserves to spacing units adjacent to a producing well. For reserve reporting purposes, the new rules also replace the end-of-the-year oil and gas reserve pricing with an unweighted average first-day-of-the-month pricing for the past 12 fiscal months. This would impact depletion calculations. Costs associated with reserves will continue to be measured on the last day of the fiscal year. A revised tabular presentation of reserves by development category, final product type, and oil and gas activity disclosure by geographic regions and significant fields and a general disclosure of the internal controls a company uses to assure objectivity in reserves estimation will be required. We are evaluating the impact Release 33-8995 will have on our financial position, results of operations or cash flows. The adoption of Release No. 33-8995 is expected to have a material impact, which cannot be quantified at this point, on the calculation of our crude oil and natural gas reserves.

Accounting Standards Update (“ASU”) 2009-05, “Fair Value Measurement and Disclosure: Measuring Liabilities at Fair Value” (“ASU 2009-05” or ASC 820-10). In August 2009, the FASB issued ASU 2009-05 (ASC 820-10) to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. In particular, ASU 2009-05 specifies that a valuation technique should be applied that uses either the quote of the liability when traded as an asset, the quoted prices for similar liabilities when traded as assets, or another valuation technique consistent with existing fair value measurement guidance. ASU 2009-05 (ASC 820-10) is prospectively effective for financial statements issued for interim or annual periods ending after October 1, 2009. We do not expect the adoption of ASU 2009-05 (ASC 820-10) to have an impact our financial position, results of operations or cash flows.

4. Disposition of Assets

On July 17, 2009, we sold the Lazy JL Field located in the Permian Basin of West Texas to a private buyer for $23 million in cash. This transaction was effective July 1, 2009. The proceeds from this transaction were used to reduce our outstanding borrowings under our credit facility. In connection with the sale, the borrowing base under our credit facility was reduced by $3 million to $732 million.

The Lazy JL Field properties produced approximately 249 Boe per day during the first six months of 2009. 96 percent of the production was crude oil. As of December 31, 2008, these assets contained estimated proved reserves of 1.2 MMBoe, or approximately 1 percent of our total estimated proved reserves of 103.6 MMBoe. The net carrying value at the date of sale was $28.5 million, of which $28.7 million was reflected in net property, plant and equipment on the balance sheet and $0.2 million was reflected in asset retirement obligation on the balance sheet. We recognized a loss of $5.5 million in the third quarter of 2009 related to the sale of the Lazy JL Field.

5. Income Taxes

The following tables present our income tax expense or benefit during the three months and nine months ended September 30, 2009 and 2008 as well as our deferred income tax liability at September 30, 2009 and December 31, 2008:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Thousands of dollars	2009			2008		2009			2008
Federal current tax expense	$	407		$	146	$	432		$	138
Deferred federal tax expense (benefit) (a)		(276	)		2,315		(946	)		725
State income tax expense (benefit) (b)		(144	)		138		160			399

Total income tax expense (benefit)	$	(13	)	$	2,599	$	(354	)	$	1,262

	As of
Thousands of dollars	September 30, 2009		December 31, 2008
Deferred income tax liability (a)	$	3,385	$	4,282

(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 profit margin or net income, primarily in Michigan and California.

6. Related Party Transactions

BreitBurn Management 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. Prior to June 17, 2008, BreitBurn Management provided services to us and to BEC, and allocated its expenses between the two entities. On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, BreitBurn Management became our wholly-owned subsidiary and entered into an Amended and Restated Administrative Services Agreement with BEC, pursuant to which BreitBurn Management agreed to continue to provide administrative services to BEC, in exchange for a monthly fee of approximately $775,000 for indirect expenses.

Beginning on June 17, 2008, all of the costs charged to BOLP are consolidated with our results. On August 26, 2008, BreitBurn Management entered into the Second Amended and Restated Administrative Services Agreement (the “Administrative Services Agreement”) to manage BEC's properties for a term of five years. In addition to the monthly fee, BreitBurn Management charges BEC for all direct expenses including incentive plan costs and direct payroll and administrative costs related to BEC properties and operations. The monthly fee is contractually based on an annual projection of anticipated time spent by each employee who provides services to both us and BEC during the ensuing year and is subject to renegotiation annually by the parties during the term of the agreement. For 2009, each BreitBurn Management employee estimated his or her time allocation independently based on 2008. These estimates were then reviewed and approved by each employee’s manager or supervisor. The results of this process were provided to both the audit committee of the board of directors of our General Partner (composed entirely of independent directors) (the “audit committee”) and the board of representatives of BEC’s parent (the “BEC board”). The audit committee and the non-management members of the BEC board agreed on the 2009 monthly fee as provided in the Administrative Services Agreement. Effective January 1, 2009, the monthly fee was renegotiated to $500,000. The reduction in the monthly fee is attributable to the overall reduction in general and administrative expenses, excluding unit-based compensation, for BreitBurn Management for 2009, the new time allocation study described above and the fact that additional costs are being charged separately to us and BEC compared to prior years.

In addition, we entered into an Omnibus Agreement with BEC detailing rights with respect to business opportunities and providing us with a right of first offer with respect to the sale of assets by BEC.

At September 30, 2009 and December 31, 2008, we had current receivables of $4.0 million and $4.4 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 nine months of 2009, the monthly charges to BEC for indirect expenses totaled $4.5 million and charges for direct expenses including direct payroll and administrative costs totaled $3.5 million. For the three months and nine months ended September 30, 2009, total oil and gas sales made by BEC on our behalf were approximately $0.4 million and $0.9 million, respectively. For the three months and nine months ended September 30, 2008, total oil and gas sales made by BEC on our behalf were approximately $0.6 million and $1.8 million, respectively. At September 30, 2009, we had receivables of $0.5 million due from equity investments.

Pursuant to a transition services agreement through March 2008, Quicksilver provided to us services for accounting, land administration, and marketing and charged us $0.9 million for the first quarter of 2008. These charges were included in general and administrative expenses on the consolidated statements of operations. Quicksilver also buys natural gas from us in Michigan. For the three months and nine months ended September 30, 2009, total net gas sales to Quicksilver were approximately $0.5 million and $2.1 million respectively. For the three months and nine months ended September 30, 2008, total net gas sales to Quicksilver were approximately $1.7 million and $6.4 million respectively. The related receivables were $0.2 million at September 30, 2009 and $0.6 million as of December 31, 2008.

7. Inventory

Our crude oil inventory from our Florida operations at September 30, 2009 and December 31, 2008 was $5.0 million and $1.3 million, respectively. In the nine months ended September 30, 2009, we sold 388 gross MBbls of crude oil and produced 460 gross MBbls of crude oil from our Florida operations. Inventory additions are stated 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. 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.

For our properties in Florida, there are a limited number of alternative methods of transportation for our production. Substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs, or involuntary curtailment of our oil production in Florida, which could have a negative impact on our future consolidated financial position, results of operations or cash flows.

8. Intangibles

In May 2007, we acquired certain interests in Florida oil leases and related assets through the acquisition of a limited liability company from Calumet. As part of this acquisition we assumed certain crude oil sales contracts for the remainder of 2007 and for 2008 through 2010. A $3.4 million intangible asset was established to value the portion of the crude oil contracts that were above market at closing in the purchase price allocation. Realized gains or losses from these contracts being recognized as part of oil sales and the intangible asset is being amortized over the life of the contracts. As of September 30, 2009, our intangible asset related to the crude oil sales contracts was $0.7 million, of which $0.1 million is reflected in long-term intangibles on the consolidated balance sheet.

In November 2007, we acquired oil and gas properties and facilities located in Michigan, Indiana and Kentucky from Quicksilver. Included in the Quicksilver purchase price was a $5.2 million intangible asset related to retention bonuses. In connection with the acquisition, we entered into an agreement with Quicksilver which provides for Quicksilver to fund retention bonuses payable to 139 former Quicksilver employees in the event these employees remain continuously employed by BreitBurn Management from November 1, 2007 through November 1, 2009 or in the event of termination without cause, disability or death. Amortization expense of $0.5 million and $1.6 million for the three months and nine months ended September 30, 2009 is included in the operating costs line on the consolidated statements of operations. For the same periods of 2008, $0.5 million and $1.6 million of amortization expense related to Quicksilver retention bonuses was included in operating costs. As of September 30, 2009, our intangible asset related to Quicksilver retention bonuses was $0.2 million, reflected in current intangibles on the consolidated balance sheet.

9. Equity Investments

We had equity investments at September 30, 2009 and December 31, 2008 of $8.7 million and $9.5 million, respectively. These investments are reported in the “Equity investments” line on the consolidated balance sheets and primarily represent investments in natural gas processing facilities. For the three months and nine months ended September 30, 2009, we recorded an immaterial amount and $0.1 million respectively, in earnings from equity investments and an immaterial amount and $0.7 million respectively, in dividends. For the three months and nine months ended September 30, 2008, we recorded $0.1 million and $0.6 million, respectively, in earnings from equity investments. Amounts recorded for dividends during the three months and nine months ended September 30, 2008 were $1.1 million and $1.2 million, respectively. Earnings from equity investments are reported in the “Other revenue, net” line on the consolidated statements of operations.

10. Long-Term Debt

On November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, entered into a four-year, $1.5 billion amended and restated revolving credit facility with Wells Fargo Bank, N.A., Credit Suisse Securities (USA) LLC and a syndicate of banks (the “Amended and Restated Credit Agreement”). The initial borrowing base of the Amended and Restated Credit Agreement was $700 million and was increased to $750 million on April 10, 2008.

On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, we and our wholly-owned subsidiaries entered into the First Amendment to the Amended and Restated Credit Agreement (“Amendment No. 1 to the Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent (the “Agent”). Amendment No. 1 to the Credit Agreement increased the borrowing base available under the Amended and Restated Credit Agreement, from $750 million to $900 million. In addition, Amendment No. 1 to the Credit Agreement enacted certain additional amendments, waivers and consents to the Amended and Restated Credit Agreement and the related Security Agreement, dated November 1, 2007, among BOLP, certain of its subsidiaries and the Agent, necessary to permit the Amendment No. 1 to the First Amended and Restated Limited Partnership Agreement and the transactions consummated in the Purchase, Contribution and Partnership Transactions. Under Amendment No. 1 to the Credit Agreement, the interest margins applicable to borrowings, the letter of credit fee and the commitment fee under the Amended and Restated Credit Agreement were increased by amounts ranging from 12.5 to 25 basis points.

In January 2009, we monetized certain in-the-money commodity hedges for approximately $46 million, the net proceeds of which were used to reduce outstanding borrowings under our credit facility. In April 2009, in connection with a scheduled redetermination, our borrowing base under our Amended and Restated Credit Agreement was redetermined at $760 million. In June 2009, we monetized additional in-the-money commodity hedges for approximately $25 million, the net proceeds of which were used to reduce outstanding borrowings under our credit facility. As a result of the monetization, our borrowing base was reset at $735 million.

On July 17, 2009, we sold the Lazy JL Field for $23 million in cash. The proceeds from this transaction were used to reduce outstanding borrowings under our credit facility and our borrowing base was reduced by $3 million to $732 million.

In October 2009, in connection with our semi-annual borrowing base redetermination, our borrowing base was reaffirmed at $732 million (see Note 17).

As of September 30, 2009 and December 31, 2008, we had approximately $585.0 million and $736.0 million, respectively, in indebtedness outstanding under the Amended and Restated Credit Agreement. The credit facility will mature on November 1, 2011. At September 30, 2009, the 1-month LIBOR interest rate plus an applicable spread was 2.000 percent on the 1-month LIBOR portion of $484.0 million, the 6-month LIBOR interest rate plus an applicable spread was 3.210 percent on the 6-month LIBOR portion of $100.0 million and the prime rate plus an applicable spread was 4.000 percent on the prime debt portion of $1.0 million. 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 credit facility contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders (including the restriction on our ability to make distributions unless after giving effect to such distribution, our outstanding debt is less than 90 percent of the borrowing base, and we have the ability to borrow at least 10 percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 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.

As of September 30, 2009 and December 31, 2008, we were in compliance with the credit facility’s covenants. At September 30, 2009 and December 31, 2008, we had $0.3 million in letters of credit outstanding.

Our interest expense is detailed in the following table:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Thousands of dollars	2009		2008		2009		2008
Credit agreement (including commitment fees)	$	3,726	$	8,202	$	12,213	$	17,793
Amortization of discount and deferred issuance costs		823		819		2,469		1,776
Total	$	4,549	$	9,021	$	14,682	$	19,569

Cash paid for interest (including realized gains/losses on interest rate swaps)	$	7,136	$	8,842	$	21,521	$	18,916

11. 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 as well as 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 7 to 50 years. Estimated cash flows have been discounted at our credit adjusted risk free rate of 7 percent and adjusted for inflation using a rate of 2 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 given to unobservable inputs. 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 nine months ended September 30, 2009 and the year ended December 31, 2008 are presented in the following table:


	Nine Months Ended			Year Ended
Thousands of dollars	September 30, 2009			December 31, 2008
Carrying amount, beginning of period	$	30,086		$	27,819
Liabilities settled in the current period		-			(1,054	)
Revisions (a)		4,073			1,363
Acquisitions (dispositions) (b)		(252	)		-
Accretion expense		1,785			1,958

Carrying amount, end of period	$	35,692		$	30,086

(a) Increased cost estimates and revisions to reserve life.
(b) Relates to disposition of Lazy JL field.

12. Partners’ Equity

At September 30, 2009, we had 52,770,011 Common Units outstanding representing limited partner interests in us (“Common Units”), and at December 31, 2008, we had 52,635,634 Common Units outstanding.

At September 30, 2009 and December 31, 2008, we had 6,700,000 units authorized for issuance under our long-term incentive compensation plans. At September 30, 2009 and December 31, 2008, there were 2,960,731 and 1,422,171, respectively, of partnership-based units outstanding that are eligible to be paid in Common Units upon vesting.

Earnings per Common 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 restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”) participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security. 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. For the three months and nine months ended September 30, 2009, RPUs and CPUs have been excluded from the calculation of basic earnings per unit, as we were in a net loss position.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Thousands of dollars, except unit amounts	2009			2008		2009			2008
Net income (loss) attributable to limited partners	$	(5,408	)	$	454,454	$	(67,577	)	$	129,093
Distributions on participating units not expected to vest		-			6		24			16
Net income (loss) attributable to common unitholders and participating securities	$	(5,408	)	$	454,460	$	(67,553	)	$	129,109

Weighted average number of units used to calculate basic and diluted net income (loss) per unit:
Common Units		52,770,011			52,635,634		52,747,861			61,455,638
Participating securities (a)		-			1,287,350		-			1,148,880
Denominator for basic earnings per Common Unit		52,770,011			53,922,984		52,747,861			62,604,519

Dilutive units (b)		-			148,537		-			147,770
Denominator for diluted earnings per Common Unit		52,770,011			54,071,521		52,747,861			62,752,289

Net income (loss) per common unit
Basic	$	(0.10	)	$	8.43	$	(1.28	)	$	2.06
Diluted	$	(0.10	)	$	8.40	$	(1.28	)	$	2.06

(a) The three and nine months ended September 30, 2009 exclude 2,848,962 and 2,599,438 potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position. For the three months and nine months ended September 30, 2008, basic earnings per unit is based upon the weighted average number of Common Units outstanding plus the weighted average number of potentially issuable RPUs and CPUs.
(b) The three months and nine months ended September 30, 2009, exclude 106,280 and 105,460 weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per Common Unit. The three months and nine months ended September 30, 2008 includes dilutive units potentially issuable under compensation plans.

Cash Distributions

On February 13, 2009, we paid a cash distribution of approximately $27.4 million to our common unitholders of record as of the close of business on February 9, 2009. The distribution that was paid to unitholders was $0.52 per Common Unit. During the three months ended March 31, 2009, we also paid cash equivalent to the distribution paid to our unitholders of $0.7 million to holders of outstanding Restricted Phantom Units and Convertible Phantom Units issued under our Long-Term Incentive Plans.

With the borrowing base redetermination in April 2009 (see Note 10), our borrowings exceeded 90 percent of the reset borrowing base and, therefore, under the terms of our credit facility we were restricted from making a distribution for the first quarter of 2009. Although we were not restricted from making distributions under the terms of our credit facility for the second and third quarters of 2009, we elected not to declare distributions in light of total leverage levels and other factors. We are restricted from paying distributions under our credit facility unless, after giving effect to such distribution, our outstanding debt is less than 90 percent of the borrowing base and we have the ability to borrow at least 10 percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX).

13. 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 liability representing the book value of the general partner’s interests. At September 30, 2009 and December 31, 2008, the amount of this noncontrolling interest liability was $0.4 million and $0.5 million, respectively.

BEPI’s general partner interest is held by a wholly owned subsidiary of BEC. The general partner of BEPI holds a 35 percent reversionary interest under the existing limited partnership agreement applicable to the properties. This reversionary interest is expected to occur at a defined payout, which is estimated to occur in 2013 based on quarter-end price and cost projections.

14. 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. Routinely, we utilize derivative financial instruments to reduce this volatility. To the extent we have hedged prices for a significant portion of our expected production through commodity derivative instruments and the cost for goods and services increase, our margins would be adversely affected.

Credit and Counterparty Risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of September 30, 2009, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse Energy LLC, Union Bank, Wells Fargo Bank N.A., JP Morgan Chase Bank N.A., Royal Bank of Scotland plc, The Bank of Nova Scotia and Toronto-Dominion Bank. We terminated all derivative financial instruments with Lehman Brothers on September 19, 2008. Our counterparties are all lenders under our Amended and Restated Credit Agreement. During 2008, there was extreme volatility and disruption in the capital and credit markets which reached unprecedented levels. Continued volatility and disruption may adversely affect the financial condition of our derivative counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. As of September 30, 2009, each of these financial institutions carried an S&P credit rating of A- or above. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of September 30, 2009, our largest derivative asset balances were with JP Morgan Chase Bank N.A., who accounted for approximately 61 percent of our derivative asset balances, and Credit Suisse International and Credit Suisse Energy LLC, who together accounted for approximately 27 percent of our derivative asset balances.

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 the fair value immediately in earnings. We had a realized gain of $24.3 million and an unrealized loss of $11.6 million for the three months ended September 30, 2009 relating to our various market-based commodity contracts. We had a realized gain of $149.9 million and an unrealized loss of $164.4 million for the nine months ended September 30, 2009 relating to our various market-based commodity contracts. We had net financial instruments receivable relating to our commodity contracts of $127.9 million at September 30, 2009.

In January 2009, we terminated a portion of our 2011 and 2012 crude oil derivative contracts and replaced them with new contracts with the same counterparty for the same volumes at market prices. We realized $32.3 million from this termination. In January 2009, we also terminated a portion of our 2011 and 2012 natural gas derivative contracts and replaced them with new contracts with the same counterparty for the same volumes at market prices. We realized $13.3 million from this termination. Proceeds from these contracts were used to pay down outstanding borrowings under our credit facility.

In June 2009, we terminated an additional portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts for the same volumes at market prices. We realized $18.9 million from the termination of natural gas derivative contracts and $6.1 million from the termination of crude oil contracts. Proceeds from these contracts were used to pay down outstanding borrowings under our credit facility.

Including the impact of the changes noted above and new contracts entered into during the quarter ended September 30, 2009, we had the following contracts in place at September 30, 2009:

	Year
	2009			2010			2011			2012		2013
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMBtu/d)		22,362			43,869			25,955			19,129		27,000
Average Price ($/MMBtu)	$	8.16		$	8.20		$	7.26		$	7.10	$	6.92
Collars:
Hedged Volume (MMBtu/d)		1,063			3,405			16,016			19,129		-
Average Floor Price ($/MMBtu)	$	9.00		$	9.00		$	9.00		$	9.00	$	-
Average Ceiling Price ($/MMBtu)	$	15.40		$	12.79		$	11.28		$	11.89	$	-
Total:
Hedged Volume (MMMBtu/d)		23,424			47,275			41,971			38,257		27,000
Average Price ($/MMBtu)	$	8.20		$	8.26		$	7.92		$	8.05	$	6.92

Oil Positions:
Fixed Price Swaps:
Hedged Volume (Bbls/d)		1,468			2,808			2,616			2,539		3,500
Average Price ($/Bbl)	$	70.18		$	81.35		$	66.22		$	67.24	$	76.79
Participating Swaps: (a)
Hedged Volume (Bbls/d)		1,205			1,993			1,439			-		-
Average Price ($/Bbl)	$	66.48		$	64.40		$	61.29		$	-	$	-
Average Participation %		60.7	%		55.5	%		53.2	%		-		-
Collars:
Hedged Volume (Bbls/d)		257			1,279			2,048			2,477		-
Average Floor Price ($/Bbl)	$	89.57		$	102.85		$	103.42		$	110.00	$	-
Average Ceiling Price ($/Bbl)	$	118.83		$	136.16		$	152.61		$	145.39	$	-
Floors:
Hedged Volume (Bbls/d)		250			500			-			-		-
Average Floor Price ($/Bbl)	$	100.00		$	100.00		$	-		$	-	$	-
Total:
Hedged Volume (Bbls/d)		3,180			6,580			6,103			5,016		3,500
Average Price ($/Bbl)	$	72.69		$	81.81		$	77.51		$	88.35	$	76.79

(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 September 30, 2009, our total debt outstanding was $585.0 million. In order to mitigate our interest rate exposure, we had the following interest rate derivative contracts in place at September 30, 2009, to fix a portion of floating LIBOR-based debt on our credit facility:

Notional amounts in thousands of dollars	Notional Amount		Fixed Rate
Period Covered
October 1, 2009 to January 8, 2010	$	100,000		3.3873	%
October 1, 2009 to December 20, 2010		300,000		3.6825	%
January 20, 2010 to October 20, 2011		100,000		1.6200	%
December 20, 2010 to October 20, 2011		200,000		2.9900	%

We had realized losses related to our interest rate derivative contracts of $3.4 million and $9.7 million for the three months and nine months ended September 30, 2009, respectively. We had unrealized losses related to our interest rate derivative contracts of $0.4 million and unrealized gains of $4.1 million for the three months and nine months ended September 30, 2009, respectively. We had net payables related to the interest rate derivative contracts of $13.2 million at September 30, 2009.

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			Total Financial Instruments

September 30, 2009
Assets
Current assets - derivative instruments	$	21,980		$	41,269		$	-		$	63,249
Other long-term assets - derivative instruments		59,358			38,142			-			97,500
Total assets		81,338			79,411			-			160,749

Liabilities
Current liabilities - derivative instruments		(4,245	)		-			(10,525	)		(14,770	)
Long-term liabilities - derivative instruments		(25,985	)		(2,660	)		(2,677	)		(31,322	)
Total liabilities		(30,230	)		(2,660	)		(13,202	)		(46,092	)

Net assets (liabilities)	$	51,108		$	76,751		$	(13,202	)	$	114,657

December 31, 2008
Assets
Current assets - derivative instruments	$	44,086		$	32,138		$	-		$	76,224
Other long-term assets - derivative instruments		145,061			73,942			-			219,003
Total assets		189,147			106,080			-			295,227

Liabilities
Current liabilities - derivative instruments		(1,115	)		-			(9,077	)		(10,192	)
Long-term liabilities - derivative instruments		(1,820	)		-			(8,238	)		(10,058	)
Total liabilities		(2,935	)		-			(17,315	)		(20,250	)

Net assets (liabilities)	$	186,212		$	106,080		$	(17,315	)	$	274,977

Gains and losses on derivative instruments not designated as hedging instruments under ASC 815:

Location of gain/loss, thousands of dollars	Oil Commodity Derivatives (a)			Natural Gas Commodity Derivatives (a)			Interest Rate Derivatives (b)			Total Financial Instruments
Three Months Ended September 30, 2009
Realized gains (losses)	$	3,646		$	20,710		$	(3,411	)	$	20,945
Unrealized gains (losses)		9,728			(21,365	)		(381	)		(12,018	)
Net gains (losses)	$	13,374		$	(655	)	$	(3,792	)	$	8,927

Three Months Ended September 30, 2008
Realized losses	$	(13,649	)	$	(10,474	)	$	(1,304	)	$	(25,427	)
Unrealized gains (losses)		213,901			217,663			(1,660	)		429,904
Net gains (losses)	$	200,252		$	207,189		$	(2,964	)	$	404,477

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

Nine Months Ended September 30, 2008
Realized losses	$	(44,916	)	$	(25,979	)	$	(1,668	)	$	(72,563	)
Unrealized gains (losses)		1,112			40,555			(2,269	)		39,398
Net gains (losses)	$	(43,804	)	$	14,576		$	(3,937	)	$	(33,165	)

(a) Included in gains (losses) on commodity derivative instruments on the consolidated statements of operations.
(b) Included in loss 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. Fair value measurement under ASC 820 is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date, considered from the perspective of a market participant that holds the asset or owes the liability. The objective of fair value measurement as defined in ASC 820 is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If there is an active market for the asset or liability, the fair value measurement shall represent the price in that market whether the price is directly observable or otherwise obtained using a valuation technique.

ASC 820 requires valuation techniques consistent with the market approach, income approach or cost approach to be used to measure fair value. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to convert future cash flows or earnings to a single present value amount and is based upon current market expectations about those future amounts. The cost approach, sometimes referred to as the current replacement cost approach, is based upon the amount that would currently be required to replace the service capacity of an asset.

We principally use the income approach for our recurring fair value measurements and strive to use the best information available. 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.

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. The highest priority of Level 1 is given to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 is given 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. Active markets are markets in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. An example of a Level 1 input would be quoted prices for exchange traded commodity futures contracts.

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. These models include industry standard models that consider standard assumptions such as quoted forward prices for commodities, interest rates, volatilities, current market and contractual prices for underlying assets as well as other relevant factors. Substantially all of these inputs are evident in the market place throughout the terms of the financial instruments and can be derived by observable data, including third party data providers. These inputs may also include observable transactions in the market place. We consider the over the counter (“OTC”) commodity and interest rate swaps in our portfolio to be Level 2. These are assets and liabilities that can be bought and sold in active markets and quoted prices are available from multiple potential counterparties.

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. These inputs generally reflect management’s estimates of the assumptions market participants would use when pricing the instruments. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Level 3 instruments primarily include derivative instruments for which we do not have sufficient corroborating market evidence, such as binding broker quotes, to support classifying the asset or liability as Level 2. Level 3 also includes complex structured transactions that sometimes require the use of non-standard models.

Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. We include these assets and liabilities in Level 3 as required by current interpretations of ASC 820. As of December 31, 2008 and September 30, 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.

As mentioned in Note 6, our wholly-owned subsidiary BreitBurn Management provides us with general management services, including risk management activities. BreitBurn Management contracted with Provident on a month to month basis for certain derivative instrument valuation services provided to us.

Provident’s risk management group calculated the fair values of our commodity swaps using risk management software that marks to market monthly fixed price delivery swap volumes using forward commodity price curves and market interest rates. This pricing approach is commonly used by market participants to value commodity swap contracts for sale to the market. Inputs are obtained from third party data providers and are verified to published data where available (e.g., NYMEX).

Fair value measurements for our interest rate swaps have also been provided by Provident. Monthly outstanding notional amounts are marked to market for each specific swap using forward interest rate curves. This pricing approach is commonly used by market participants to value interest rate swap contracts for sale to the market. Inputs are obtained from third party data providers and are verified to published data where available (e.g., LIBOR).

Provident’s risk management group uses industry standard option pricing models contained in their risk management software to calculate the fair values associated with our commodity options. 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 third party data providers and are verified to published data where available (e.g., NYMEX).

We reviewed the fair value calculations for our derivative instruments that we received from Provident’s risk management group on a monthly basis. We also compared these fair value amounts to the fair value amounts that we received from the counterparties to our derivative instruments. We investigated differences and resolved and recorded any required changes prior to the issuance of our financial statements.

Beginning in the fourth quarter of 2009, we will calculate the fair value of our commodity and interest rate swaps and options internally.

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 categorized.

Recurring fair value measurements at September 30, 2009 and December 31, 2008:

	As of September 30, 2009
Thousands of dollars	Level 1		Level 2			Level 3		Total
Assets (liabilities):
Commodity derivatives (swaps, put and call options)	$	-	$	8,550		$	119,309	$	127,859
Other dervivatives (interest rate swaps)		-		(13,202	)		-		(13,202	)
Total	$	-	$	(4,652	)	$	119,309	$	114,657

	As of December 31, 2008
Thousands of dollars	Level 1		Level 2			Level 3		Total
Assets (liabilities):
Commodity derivatives (swaps, put and call options)	$	-	$	139,074		$	153,218	$	292,292
Other derivatives (interest rate swaps)		-		(17,315	)		-		(17,315	)
Total	$	-	$	121,759		$	153,218	$	274,977

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Thousands of dollars	2009		2008			2009			2008
Assets (liabilities):
Beginning balance	$	113,355	$	78,391		$	153,218		$	44,236
Realized and unrealized gains (losses)		5,954		22,889			(33,909	)		53,754
Purchases and issuances		-		4,162			-			7,452
Settlements		-		(4,624	)		-			(4,624	)
Ending balance	$	119,309	$	100,818		$	119,309		$	100,818

For the three months and nine months ended September 30, 2009, realized gains of $0.6 million and $15.0 million respectively, related to our derivative instruments classified as Level 3 are included in Gains (losses) on commodity derivative instruments, net on the consolidated statements of operations. For the three months and nine months ended September 30, 2009, unrealized gains of $5.4 million and unrealized losses of $48.9 million respectively, related to our derivative instruments classified as Level 3 are included in Gains (losses) on commodity derivative instruments, net on the consolidated statements of operations. For the three months and nine months ended September 30, 2008, realized losses of $11.1 million and $11.9 million, respectively, related to our derivative instruments classified as Level 3 are included in Gains (losses) on commodity derivative instruments, net on the consolidated statements of operations. For the three months and nine months ended September 30, 2008, unrealized gains of $34.0 million and $65.7 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.

15. Unit and Other Valuation-Based Compensation Plans

Unit-based compensation expense for the three months and nine months ended September 30, 2009 was $3.5 million and $9.7 million, respectively, and for the three months and nine months ended September 30, 2008 was $0.5 million and $5.2 million respectively.

During the third quarter of 2009, the board of directors of the General Partner approved the grant of 39,892 RPUs to new employees of BreitBurn Management under our 2006 Long-Term Incentive Plan (“LTIP”), which brings the total RPUs granted in the first nine months to 1,790,589 units. Our outside directors were granted 56,736 phantom units under our LTIP during the first quarter of 2009. The fair market value of the RPUs granted during 2009 for computing the compensation expense under ASC 718 “Compensation—Stock Compensation” averaged $8.17 per unit.

On February 19, 2009, 134,377 Common Units were issued to employees for RPUs granted in 2008, which vested on January 1, 2009.

For the three months and nine months ended September 30, 2009, we paid nothing and approximately $0.1 million, respectively, for various liability based compensation plans. For the three months and nine months ended September 30, 2008, we paid approximately $1.0 million and $6.3 million, respectively, in cash for various liability based compensation plans. For the three months and nine months ended September 30, 2009, we paid nothing and approximately $0.7 million, respectively, in cash equivalent to distributions paid to our unitholders on RPUs and CPUs. For the three months and nine months ended September 30, 2008, we paid $0.7 million and $1.7 million, respectively, in cash equivalent to distributions paid to our unitholders on RPUs and CPUs.

During October 2009, 14,190 Common Units vested and were issued to outside directors for phantom units granted in 2006. See Note 17.

For detailed information on our various compensation plans, see our Annual Report.

16. Commitments and Contingencies

Surety Bonds and Letters of Credit

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At September 30, 2009 and December 31, 2008, we had various surety bonds for $10.6 million and $10.1 million, respectively. At September 30, 2009 and December 31, 2008, we had $0.3 million in letters of credit outstanding.

Legal Proceedings

On October 31, 2008, Quicksilver, an owner of 40.44 percent of our Common Units, instituted a lawsuit in the District Court of Tarrant County, Texas naming us as a defendant along with BreitBurn GP, BOLP, BOGP, Randall H. Breitenbach, Halbert S. Washburn, Gregory J. Moroney, Charles S. Weiss, Randall J. Findlay, Thomas W. Buchanan, Grant D. Billing and Provident. On August 3, 2009, Quicksilver filed the Third Amended Petition and asserted twelve different counts against the various defendants. The primary claims are as follows: Quicksilver alleges that BOLP breached the Contribution Agreement with Quicksilver, dated September 11, 2007, based on allegations that we made false and misleading statements relating to its relationship with Provident. Quicksilver also alleges common law and statutory fraud claims against all of the defendants by contending that the defendants made false and misleading statements to induce Quicksilver to acquire Common Units in us. Finally, Quicksilver alleges claims for breach of the Partnership’s First Amended and Restated Agreement of Limited Partnership, dated as of October 10, 2006 (“Partnership Agreement”), and other common law claims relating to certain transactions and an amendment to the Partnership Agreement that occurred in June 2008. Quicksilver seeks a permanent injunction, a declaratory judgment relating primarily to the interpretation of the Partnership Agreement and the voting rights in that agreement, indemnification, punitive or exemplary damages, avoidance of BreitBurn GP's assignment to us of all of its economic interest in us, attorneys’ fees and costs, pre- and post-judgment interest, and monetary damages. Pursuant to an agreement among the parties to the lawsuit, a hearing on Quicksilver’s request for a permanent injunction and declaratory relief was scheduled for September 2009. The hearing on the permanent injunction and declaratory relief has now been rescheduled, and all of Quicksilver’s claims, including those previously set for hearing in September 2009, are set for trial in April 2010.

We are defending ourselves vigorously in connection with the allegations in the lawsuit. At this stage, we cannot predict the manner and timing of the resolution of the lawsuit or its outcome, or estimate a range of possible losses, if any, that could result in the event of an adverse verdict in the lawsuit.

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 other than as mentioned above. 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.

We have no independent assets or operations other than those of our subsidiaries. BOLP or BOGP may guarantee debt securities that may be issued by us and BreitBurn Finance Corporation, our wholly owned subsidiary. See Note 1 for a description of BreitBurn Finance Corporation. The guarantees will be full and unconditional and joint and several.

17.	Subsequent Events

In October 2009, in connection with our semi-annual borrowing base redetermination, our borrowing base was reaffirmed at $732 million. Our next semi-annual borrowing base redetermination is scheduled for April 2010.

In October 2009, 14,190 Common Units were issued to outside directors for phantom units and distribution equivalent rights which were granted in 2006 and vested in October 2009.

On October 21, 2009, we completed the transfer and sale of our claims in the bankruptcy cases filed by Lehman Brothers Commodity Services Inc. and Lehman Brothers Holdings Inc. (together referred to as Lehman Brothers), to a third party. The claims related to amounts owed to us by Lehman Brothers for crude oil derivative contracts that were terminated on September 19, 2008 due to the commencement of the bankruptcy case.

ASC 855 “Subsequent Events” requires disclosure of the date through which an entity has evaluated subsequent events and the basis for that date, that is, whether that date represents the date the financial statements were issued or were available to be issued. We have evaluated subsequent events through November 6, 2009, the date of issuance of our financial statements for the quarter ended September 30, 2009.

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 and the consolidated financial statements and related notes herein and 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 the cautionary statement relevant to forward-looking information on page 1 of this report, Part II—Item 1A “—Risk Factors” of this report, Part II—Item 1A “—Risk Factors” of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009 and the “Cautionary Statement Relevant to Forward Looking Information” 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 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.

Given the economic climate during 2009 and the ongoing distress in the financial and credit markets, we elected to focus on financial flexibility and liquidity in 2009. Our goals for 2009 are to fund our operations, capital expenditures, interest payments and reduction of bank debt from our internally generated cash flow and to preserve financial flexibility and liquidity to maintain our assets and operations in anticipation of future improvement in the overall economic environment, commodity prices and financial markets. Consistent with these goals, we took a number of significant steps to reduce costs, conserve capital, generate cash flow and reduce debt. These included:

Capital Spending Reductions - In response to last year’s substantial decline in oil and natural gas prices, the outlook for the broader economy and the turmoil in the financing markets, we elected to significantly reduce our capital spending and drilling activity in 2009. Our original capital program was expected to be approximately $24 million in 2009, compared to approximately $129 million in 2008. However, this quarter we accelerated capital spending for the balance of 2009 in light of recent improvements in crude oil prices and declines in development costs, and currently anticipate our capital expenditures to be approximately $32 million in 2009. The increase will be focused on capital spending for our oil producing properties including spending in California for the drilling of wells and for facility optimization projects, in Michigan for several drilling projects and facility optimization projects and in Wyoming for the drilling of wells and well optimization projects.

General and Administrative Expense Reductions - We conducted a comprehensive review of costs during the first quarter of 2009 and made reductions in numerous areas. Chief among these were the consolidation of operating divisions and the elimination of a number of professional and administrative positions, as well as significant targeted reductions in other third party related expenses and incentive compensation costs. Selective headcount reductions have continued throughout the third quarter of 2009.

Hedge Monetization Program - In January 2009, we terminated a portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts for the same volumes at market prices. We realized $45.6 million in net proceeds from this termination which was used to reduce debt. In June 2009, we terminated a portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts for the same volumes at market prices. We realized $25.0 million in net proceeds from this termination which was also used to reduce debt.

d)	Sale of Non-Core Assets - On July 17, 2009, we sold the Lazy JL Field located in the Permian Basin of West Texas to a private buyer for $23 million in cash. The proceeds from this transaction were used to reduce debt.

Reduction of Bank Debt - We reduced our outstanding bank debt in 2009, by applying the proceeds from the two monetization transactions, a portion of the cash flow from operations for the first ten months of 2009 and the proceeds from the sale of the Lazy JL Field (see Note 4 to our consolidated financial statements contained elsewhere in this report). In total, we have reduced our outstanding borrowings under our credit facility by $160 million in the first ten months of 2009. As of October 31, 2009, we had approximately $576 million in borrowings outstanding under our credit facility.

We will continue 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 and other transactions. We reduced our outstanding bank debt by approximately $55 million in the third quarter and continue to believe that maintaining our financial flexibility by reducing our bank debt should remain a priority. We plan to continue applying a portion of our cash flow generated from operations to repayment of debt. Maintaining financial flexibility in 2009 supports our stated long-term goals of providing stability and growth, reinstatement of distributions to unitholders, and continuing to follow our core investment strategy, which includes the following principles:

·	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 derivatives; and

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

Operational Focus and Capital Expenditures

As discussed above and consistent with our goals for 2009, we elected to significantly reduce our capital expenditures and drilling activity in 2009. Because of the reduced capital program in 2009 and the natural decline in our production rates, we expect to produce less oil and natural gas in 2009 than we did in 2008. As crude oil prices have been improving, and operating and development costs have been declining, we recently reviewed and will continue to review the scope of our capital program and opportunities to further accelerate capital spending in 2009, primarily on our oil producing properties. We currently anticipate actual capital expenditures in 2009 to be approximately $32 million as compared to $129.5 million in 2008.

Our daily production for the third quarter of 2009 averaged 17.7 MBoe/d, which was a 4 percent decrease from the same period a year ago. Our oil and gas capital expenditures were $7.2 million in the third quarter of 2009 and $53.0 million in the third quarter of 2008.

Outlook

Our revenues and net income are sensitive to oil and natural gas prices. Our operating expenses are highly correlated to oil and natural gas prices, and as commodity prices rise and fall, our operating expenses will directionally rise and fall. Significant factors that will impact near-term commodity prices include global demand for oil and natural gas, political developments in oil producing countries, the extent to which members of the OPEC and other oil exporting nations are able to manage oil supply through export quotas and variations in key North American natural gas and refined products supply and demand indicators.

In the third quarter of 2009, WTI averaged $68 per barrel, compared with approximately $118 per barrel a year earlier. In the first nine months of 2009, WTI averaged $57 per barrel, compared to $113 per barrel a year earlier. The average price for WTI in October 2009 was approximately $76 per barrel. In 2008, the NYMEX WTI spot price averaged approximately $100 per barrel. Crude-oil prices remain volatile and have decreased significantly since they peaked at approximately $145 per barrel in the middle of July 2008. Since January 2009, crude oil prices have rebounded, but they remain volatile and are significantly lower than the 2008 average.

Prices for natural gas have historically fluctuated widely and in many regional markets are more closely aligned with supply and demand conditions in those markets. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the inventory in underground storage relative to customer demand. U.S. natural gas prices are also typically higher during the winter period when demand for heating is greatest. In the first nine months of 2009, the NYMEX wholesale natural gas price was very volatile and ranged from a low of $2.51 per MMBtu to a high of $6.07 per MMBtu. The average NYMEX wholesale natural gas price in October 2009 was approximately $4.78 per MMBtu. During 2008, the monthly average NYMEX wholesale natural gas price ranged from a low of $5.79 per MMBtu for December to a high of $12.78 per MMBtu for June.

While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected.

Operating expenses are the costs incurred in the operation of producing properties. Our operating expenses have decreased by $18.7 million in the first nine months of 2009 as compared to the same period of 2008 primarily due to our cost cutting efforts including the consolidation of operating divisions and the elimination of a number of employee positions in operations. Also contributing to the decrease in operating expenses is the decline in oil and natural gas prices since July 2008. Historically operating costs have been highly correlated to commodity prices. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses. A majority of our operating cost components are variable and increase or decrease along with our levels of production. For example, we incur power costs in connection with various production related activities such as pumping to recover oil and gas, separation and treatment of water produced in connection with our oil and gas production, and re-injection of water produced into the oil producing formation to maintain reservoir pressure. Although these costs typically vary with production volumes, they are driven not only by volumes of oil and gas produced but also volumes of water produced. Consequently, fields that have a high percentage of water production relative to oil and gas production, also known as a high water cut, will experience higher levels of power costs for each Boe produced. Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased expenses in periods during which they are performed.

Starting in the first quarter of 2009, we have shifted regional operation management costs from general and administrative expenses to lease operating expenses to better align our operating and management costs with our organization structure and to be more consistent with industry practice. For comparability, the results for the quarter and nine months ended September 30, 2008 have been reclassified to reflect this shift.

Results of Operations

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

	Three Months Ended												Nine Months Ended
	September 30,						Increase /						September 30,						Increase /
Thousands of dollars, except as indicated	2009			2008			(Decrease)			%			2009			2008			(Decrease)			%
Total production (MBoe)		1,628			1,689			(61	)		-4	%		4,885			5,120			(235	)		-5	%
Oil and NGLs (MBoe)		743			762			(19	)		-2	%		2,247			2,311			(64	)		-3	%
Natural gas (MMcf)		5,308			5,564			(256	)		-5	%		15,826			16,854			(1,028	)		-6	%
Average daily production (Boe/d)		17,697			18,359			(662	)		-4	%		17,894			18,686			(792	)		-4	%
Sales volumes (MBoe)		1,605			1,657			(52	)		-3	%		4,823			5,098			(275	)		-5	%

Average realized sales price (per Boe) (a) (b) (c)	$	54.37		$	64.17			(9.79	)		-15	%	$	53.96		$	61.92		$	(7.96	)		-13	%
Oil and NGLs (per Boe) (a) (b) (c)		67.40			81.82			(14.42	)		-18	%		65.08			76.78			(11.70	)		-15	%
Natural gas (per Mcf) (a) (b)		7.30			8.38			(1.08	)		-13	%		7.45			8.30			(0.85	)		-10	%

Oil, natural gas and NGL sales (d)	$	62,674		$	130,249			(67,575	)		-52	%	$	180,189		$	386,060			(205,871	)		-53	%
Realized gains (losses) on commodity derivative instruments (e)		24,356			(24,123	)		48,479			n/a			149,912			(70,895	)		220,807			n/a
Unrealized gains (losses) on commodity derivative instruments (e)		(11,637	)		431,564			(443,201	)		-103	%		(164,432	)		41,667			(206,099	)		n/a
Other revenues, net		261			806			(545	)		-68	%		930			2,324			(1,394	)		-60	%
Total revenues	$	75,654		$	538,496			(462,842	)		-86	%	$	166,599		$	359,156			(192,557	)		-54	%

Lease operating expenses and processing fees	$	29,052		$	35,611			(6,559	)		-18	%	$	86,720		$	93,405			(6,685	)		-7	%
Production and property taxes		4,422			7,814			(3,392	)		-43	%		13,315			24,378			(11,063	)		-45	%
Total lease operating expenses	$	33,474		$	43,425			(9,951	)		-23	%	$	100,035		$	117,783			(17,748	)		-15	%

Transportation expenses		799			351			448			128	%		2,898			3,081			(183	)		-6	%
Purchases		18			118			(100	)		-85	%		58			296			(238	)		-80	%
Change in inventory		(403	)		(1,979	)		1,576			n/a			(2,818	)		(2,208	)		(610	)		n/a
Uninsured loss		-			-			-			n/a			100			-			100			n/a
Total operating costs	$	33,888		$	41,915			(8,027	)		-19	%	$	100,273		$	118,952			(18,679	)		-16	%

Lease operating expenses pre taxes per Boe (f)	$	17.53		$	20.77			(3.25	)		-16	%	$	17.43		$	17.94		$	(0.51	)		-3	%
Production and property taxes per Boe		2.72		$	4.63			(1.91	)		-41	%		2.73			4.76			(2.04	)		-43	%
Total lease operating expenses per Boe		20.25			25.40			(5.15	)		-20	%		20.16			22.70			(2.54	)		-11	%

Depletion, depreciation and amortization (DD&A)	$	24,130		$	21,477			2,653			12	%	$	81,393		$	64,228			17,165			27	%
DD&A per Boe		14.82			12.72			2.11			17	%		16.66			12.54			4.12			33	%

(a) Includes realized gains (losses) on commodity derivative instruments.
(b) Excludes the effects of the early terminations of hedge contracts monetized in January 2009 ($32,317 of oil hedges and $13,315 of natural gas hedges) and June 2009 ($6,030 of oil hedges and $18,925 of natural gas hedges).
(c) Excludes amortization of an intangible asset related to crude oil sales contracts. Includes crude oil purchases.
(d) Includes amortization of an intangible asset related to crude oil sales contracts.
(e) Includes the effects of the early terminations of hedge contracts monetized in January 2009 for $45,632 and June 2009 for $24,955.
(f) Includes lease operating expenses and processing fees. Excludes amortization of intangible asset related to the Quicksilver Acquisition.

Comparison of Results for the Three Months and Nine Months Ended September 30, 2009 and 2008

The variance in our results was due to the following components:

Production

For the quarter ended September 30, 2009 as compared to the same period a year ago, production volumes decreased by 61 MBoe, or 4 percent. This decrease was primarily due to natural field declines in Michigan, Indiana and Kentucky, which decreased by 24 MBoe (147 MMcfe), in Florida, which decreased by 11 MBbl, and in Wyoming, which decreased by 6 MBoe. We also sold our Lazy JL Field properties effective July 1, 2009, which produced 19 MBoe in the third quarter of 2008. For the nine months ended September 30, 2009 as compared to the same period a year ago, production volumes decreased by 235 MBoe, or 5 percent, primarily due to natural field declines in Michigan, Indiana and Kentucky, which accounted for 134 MBoe of the decrease. In addition, for the nine months ended September 30, 2009 as compared to the same period a year ago, Florida production was 65 MBbl lower due to natural field declines and four Florida wells that were offline for most of the first quarter of 2009, California production was 20 MBoe lower due to natural field declines and Texas production was l7 MBoe lower due to the sale of our Lazy JL Field.

Revenues

Oil, natural gas and NGLs sales revenue decreased $67.6 million in the third quarter of 2009 as compared to the third quarter of 2008, due to lower commodity prices and lower sales volume. Realized gains from commodity derivative instruments during the third quarter of 2009 were $24.3 million compared to realized losses of $24.1 million in the third quarter of 2008, due to lower commodity prices in the third quarter of 2009 as compared to the third quarter of 2008. Unrealized losses on commodity derivative instruments were $11.6 million in the third quarter of 2009, which was due to an increase in commodity futures prices in the third quarter of 2009. This compares to unrealized gains of $431.6 million in the third quarter of 2008, which was due to the significant decline in commodity prices during the third quarter of 2008.

Oil, natural gas and NGLs sales revenue decreased $205.9 million in the first nine months of 2009 as compared to the first nine months of 2008. Realized gains from commodity derivative instruments during the first nine months of 2009 were $149.9 million compared to realized losses of $70.9 million in the first nine months of 2008. Unrealized losses on commodity derivative instruments were $164.4 million in the first nine months of 2009 compared to unrealized gains of $41.7 million in the first nine months of 2008. 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 nine months of 2009.

Lease operating expenses

Pre-tax lease operating expenses and processing fees for the third quarter of 2009 totaled $29.1 million, or $17.53 per Boe, which is 16 percent lower per Boe than the third quarter of 2008. The decrease in per Boe lease operating expenses is primarily attributable to our cost cutting efforts, including the consolidation of operating divisions, and the decline in oil and natural gas prices since July 2008. For the third quarter of 2009, $2.9 million or $1.78 per Boe of regional management costs were included in lease operating expenses compared to $2.4 million or $1.42 per Boe for the third quarter of 2008.

Production and property taxes for the third quarter of 2009 totaled $4.4 million, or $2.72 per Boe, which is 41 percent lower per Boe than the third quarter of 2008. The decreases in production and property taxes compared to last year result primarily from lower commodity prices.

Pre-tax lease operating expenses and processing fees, for the first nine months of 2009 totaled $86.7 million, or $17.43 per Boe, which is 3 percent lower per Boe than the first nine months of 2008. The decrease in per Boe lease operating expenses is primarily attributable to cost cutting efforts and the lower commodity price environment in 2009. For the first nine months of 2009, $7.9 million or $1.62 per Boe of regional management costs were included in lease operating expenses compared to $8.7 million or $1.71 per Boe for the first nine months of 2008. The decrease in regional management costs as compared to the first nine months of 2008 is primarily due to the consolidation of operating divisions in early 2009. Production and property taxes for the first nine months of 2009 totaled $13.3 million, or $2.73 per Boe, which is 43 percent lower per Boe than the first nine months of 2008.

Transportation expenses

In Florida, our crude oil sales are transported from the field by trucks and pipelines and then transported by barge to the sale point. Transportation costs incurred in connection with such operations are reflected as an operating cost on the consolidated statement of operations. In the third quarter of 2009 and 2008, transportation costs totaled $0.8 million and $0.4 million, respectively. In the first nine months of 2009 and 2008, transportation costs totaled $2.9 million and $3.1 million, respectively.

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 third quarter of 2009 and 2008, the change in inventory account amounted to $(0.4) million and $(2.0) million, respectively. For the first nine months of 2009 and 2008, the change in inventory account amounted to $(2.8) million and $(2.2) million, respectively.

Depletion, depreciation and amortization

Depletion, depreciation and amortization (“DD&A”) expense totaled $24.1 million, or $14.82 per Boe, in the third quarter of 2009, an increase of approximately 17 percent per Boe from the same period a year ago. The increase in DD&A compared to last year is primarily due to price related reserve revisions at year end 2008 and their impact on 2009 DD&A rates.

DD&A expense totaled $81.4 million, or $16.66 per Boe, for the first nine months of 2009, an increase of approximately 33 percent per Boe from the same period a year ago.

General and administrative expenses

Our general and administrative (“G&A”) expenses totaled $9.3 million and $6.5 million for the quarters ended September 30, 2009 and 2008, respectively. This included $3.5 million and $0.5 million, respectively, in unit-based compensation expense related to management incentive plans. For the third quarter of 2009, G&A expenses, excluding unit-based compensation, were $5.8 million, which was $0.2 million lower than the third quarter of 2008. This decrease is primarily due to expense reductions including the elimination of a number of professional and administrative positions.

G&A expenses totaled $27.3 million and $24.1 million for the nine months ended September 30, 2009 and 2008, respectively. This included $9.7 million and $4.8 million, respectively, in unit-based compensation expense related to management incentive plans. The increase in unit-based compensation expense was primarily due to new awards granted in first quarter of 2009. For the first nine months of 2009, G&A expenses, excluding unit-based compensation, were $17.6 million, which was $1.7 million lower than the first nine months of 2008 primarily due to our focus on reducing costs.

Loss on sale of assets

Loss on sale of assets totaled $5.5 million for the quarter and nine months ended September 30, 2009. In the third quarter of 2009, we sold the Lazy JL Field and recognized a loss of $5.5 million related to the sale. We had no loss on sale of assets in 2008.

Interest and other financing costs

Our interest and financing costs totaled $4.5 million and $9.0 million for the three months ended September 30, 2009 and 2008, respectively. This decrease in interest expense is primarily attributable to a lower average debt balance and lower interest rates. We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. See Part I—Item 3 within this report for a discussion of our interest rate derivative contracts. We had realized losses of $3.4 million and $1.3 million for the three months ended September 30, 2009 and 2008, respectively, relating to our interest rate derivative contracts. We had unrealized losses of $0.4 million and $1.7 million for the quarters ended September 30, 2009 and 2008, respectively, relating to our interest rate derivative contracts.

Our interest and financing costs totaled $14.7 million and $19.6 million for the nine months ended September 30, 2009 and 2008, respectively. This decrease in interest expense is attributable to lower interest rates partially offset by a higher average debt balance. We had realized losses of $9.7 million and $1.7 million for the nine months ended September 30, 2009 and 2008, respectively, relating to our interest rate derivative contracts. We had an unrealized gain of $4.1 million and an unrealized loss of $2.3 million for the nine months ended September 30, 2009 and 2008, respectively, relating to our interest rate derivative contracts.

Credit and Counterparty Risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of September 30, 2009 and October 31, 2009, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse Energy LLC, Union Bank N.A., Wells Fargo Bank N.A., JP Morgan Chase Bank N.A., Royal Bank of Scotland plc, The Bank of Nova Scotia and Toronto-Dominion Bank. Our counterparties are all lenders who participate in our Amended and Restated Credit Agreement. During 2008 and 2009, there has been extreme volatility and disruption in the capital and credit markets which reached unprecedented levels and may adversely affect the financial condition of our derivative counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. As of September 30, 2009 and October 31, 2009, each of these financial institutions carried an S&P credit rating of A- or above. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of September 30, 2009, our largest derivative asset balances were with JP Morgan Chase Bank N.A., who accounted for approximately 61 percent of our derivative asset balances, and Credit Suisse International and Credit Suisse Energy LLC, who together accounted for approximately 27 percent of our derivative asset balances.

Accounts receivable are primarily from purchasers of oil and natural gas products. We have a portfolio of crude oil and natural gas sales contracts with large, established refiners and utilities. Because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. During the nine months ended September 30, 2009, our largest purchasers were ConocoPhillips, Marathon Oil Company and Plains Marketing and Transportation LLC, who accounted for 30 percent, 16 percent and 12 percent of total net sales revenue, respectively.

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 and cash distributions to unitholders.

In April 2009, as a result of a redetermination of our credit facility borrowing base to $760 million, we suspended making distributions to our unitholders. We reduced our outstanding bank debt by approximately $55 million in the third quarter of 2009 and continue to believe that maintaining our financial flexibility by reducing our bank debt should remain a priority. We plan to continue applying a portion of our cash flow generated from operations to repayment of that debt.

We began reducing our outstanding bank debt in 2009 by applying the proceeds from the two monetization transactions, a portion of the cash flow from operations for the first ten months of 2009 and the proceeds from the July sale of the Lazy JL Field. In total, we have reduced our outstanding borrowings under our credit facility by approximately $151 million in the first nine months of 2009. As of September 30, 2009 and October 31, 2009, we had approximately $585 million and $576 million, respectively, in borrowings outstanding under our credit facility.

Operating activities. Our cash flow from operating activities for the nine months ended September 30, 2009 was $184.0 million. Our cash flow from operations for the nine months ended September 30, 2008 was $191.0 million. Included in cash flow from operating activities in the 2009 period are realized gains on commodity derivatives of $149.9 million including net proceeds of $45.6 million and $25.0 million in hedge contract monetizations completed in January and June 2009, respectively. See “Liquidity” below. Offsetting the impact of realized gains on commodity derivatives, including the 2009 monetizations, is lower crude oil and natural gas revenues compared to prior year due to lower commodity prices.

Investing activities. Net cash provided by investing activities for the nine months ended September 30, 2009 was $4.4 million, which included proceeds from the sale of the Lazy JL Field of $23.0 million offset by capital expenditures of $18.6 million spent primarily on facility and infrastructure projects and well recompletions. Net cash used in investing activities for the nine months ended September 30, 2008 was $96.8 million, which was spent on capital expenditures, primarily drilling and completion, and on property acquisitions. We elected to reduce our capital spending and drilling activity in 2009 partially due to last year’s substantial decline in oil and natural gas prices.

Financing activities. Net cash used in financing activities for the nine months ended September 30, 2009 was $188.7 million. Our cash distributions totaled $28.0 million. We had outstanding borrowings under our credit facility of $585.0 million at September 30, 2009 and $736.0 million at December 31, 2008. For the nine months ended September 30, 2009, we borrowed $218.5 million and repaid $369.5 million under the credit facility. For the nine months ended September 30, 2008, we purchased $336.2 million in Common Units, made cash distributions of $93.3 million, borrowed $659.1 million and repaid $321.5 million.

Liquidity. Our goals for 2009 are to fund our operations, capital expenditures, interest payments and reduction of bank debt from our internally generated cash flow and to preserve financial flexibility and liquidity to maintain our assets and operations in anticipation of future improvement in the overall economic environment, commodity prices and the financial markets.

In response to last year’s rapid and substantial decline in oil and natural gas prices, the outlook for the broader economy and the turmoil in the financing markets, we elected to significantly reduce our capital expenditures and drilling activity in 2009. Our original capital program was expected to be approximately $24 million in 2009, compared to approximately $129 million in 2008. However, this quarter we accelerated capital spending for the balance of 2009 in light of recent improvements in crude oil prices and declines in development costs, and currently anticipate our capital expenditures to be approximately $32 million in 2009. See “Overview” section of Part I—Item 2 “—Management’s Discussion and Analysis of Financial Condition and Results of Operations.

In January 2009, we terminated a portion of our 2011 and 2012 crude oil derivative contracts and replaced them with new contracts for the same volumes at market prices. We realized $32.3 million from this termination. In January 2009, we also terminated a portion of our 2011 and 2012 natural gas derivative contracts and replaced them with new contracts with the same counterparty for the same volumes at market prices. We realized $13.3 million from this termination. Proceeds from these contracts were used to pay down outstanding borrowings under our credit facility.

In June 2009, we terminated a portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts for the same volumes at market prices. We realized $18.9 million from the termination of natural gas derivative contracts and $6.1 million from the termination of crude oil contracts. Net proceeds from these contracts were used to pay down outstanding borrowings under our credit facility.

In July 2009, we sold the Lazy JL Field located in the Permian Basin of West Texas to a private buyer for $23 million in cash. The proceeds from this transaction were used to pay down outstanding borrowings under our credit facility.

In the first nine months of 2009, we have reduced our outstanding borrowings under our credit facility by approximately $151 million. As of September 30, 2009 and October 31, 2009, we had approximately $585 million and $576 million, respectively, in borrowings outstanding under our credit facility.

Successfully pursuing acquisitions remains a part of our long-term strategy. However, a continuation of the economic downturn could result in continued reduced demand for oil and natural gas and keep downward pressure on commodity prices. As discussed, these price declines have negatively impacted our revenues and cash flows. This, together with the contraction in the debt and equity markets and the redetermination of our borrowing base, have limited our ability to pursue and complete significant acquisitions during 2009.

Credit Facility

On November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, entered into the four year, $1.5 billion Amended and Restated Credit Agreement. Our credit facility limits the amounts we can borrow to a borrowing base amount determined by the lenders at their sole discretion based on their evaluation of our proved reserves and their internal criteria. The initial borrowing base under the Amended and Restated Credit Agreement was $700 million and was increased to $750 million on April 10, 2008. On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, we and our wholly-owned subsidiaries entered into Amendment No. 1 to the Amended and Restated Credit Agreement with the Agent, which increased the borrowing base available under the Amended and Restated Credit Agreement, from $750 million to $900 million. Under the Amended and Restated Credit Agreement, borrowings may be used (i) to pay a portion of the purchase price for the Quicksilver Acquisition and related expenses, (ii) for standby letters of credit, (iii) for working capital purposes, (iv) for general company purposes and (v) for certain acquisitions and payments permitted by the credit facility. Borrowings under the Amended and Restated Credit Agreement are secured by a first-priority lien on and security interest in substantially all of our and certain of our subsidiaries’ assets. As of September 30, 2009 and December 31, 2008, we had approximately $585 million and $736 million, respectively, in indebtedness outstanding under the Amended and Restated Credit Agreement. As of October 31, 2009, we had approximately $576 million in indebtedness outstanding under our credit facility. Our credit facility will mature on November 1, 2011.

In April 2009, our borrowing base under our Amended and Restated Credit Agreement was redetermined at $760 million, primarily as a result of the steep decline in oil and natural gas prices. The redetermination was completed with no modifications to the terms of the facility, including no additional fees and no increase in borrowing rates, which are currently very advantageous for us. In June 2009, in connection with the June 2009 termination of derivative contracts, our borrowing base was reduced to $735 million. On July 17, 2009, the borrowing base was reduced by $3 million to $732 million as a result of the sale of the Lazy JL Field. See Note 17 to our consolidated financial statements contained elsewhere in this report for a discussion of the borrowing base reduction. We have no other debt outstanding other than borrowings under the facility. Our semi-annual borrowing base was redetermined in October 2009, as a result of which our borrowing base remains unchanged at $732 million. Oil and natural gas prices remain volatile, and we expect that the lenders under our credit facility may further decrease our borrowing base at the next scheduled redetermination in April 2010. We will continue 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 and other transactions.

As of October 31, 2009, the lending group under the Amended and Restated Credit Agreement included 18 banks. Of the $732 million in total commitments under the credit facility, Wells Fargo Bank, National Association held approximately 12.6 percent of the commitments. Ten banks held between 5 percent and 7.5 percent of the commitments, including Union Bank N.A., BMO Capital Markets Financing, Inc., The Bank of Nova Scotia, US Bank National Association, Credit Suisse (Cayman Islands), Bank of Scotland plc, Barclays Bank PLC, BNP Paribas, Fortis Capital Corporation and The Royal Bank of Scotland, plc, with each remaining lender 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 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 unitholders or repurchase units unless after giving effect to such distribution, our outstanding debt is less than 90 percent of the borrowing base, and we have the ability to borrow at least 10 percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX); make dispositions; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries. In 2009, we expect to continue to reduce our outstanding bank debt with cash from our operations.

The Amended and Restated Credit Agreement also requires us to 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 not more than 3.50 to 1.00. In addition, the Amended and Restated Credit Agreement requires us to maintain a current ratio as of the last day of each quarter, of not less than 1.00 to 1.00. Furthermore, we are required to maintain an interest coverage ratio (defined as the ratio of EBITDAX to consolidated interest expense) as of the last day of each quarter, of not less than 2.75 to 1.00. As of September 30, 2009, we were in compliance with these covenants.

The events that constitute an Event of Default (as defined in the 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; failure to perform under a material agreement; certain insolvency events; assertion of certain environmental claims; and occurrence of a material adverse effect.

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” below for more information on the effect of an event of default under the Amended and Restated Credit Facility.

As of September 30, 2009, we do not have any off-balance sheet arrangements. As of September 30, 2009 and December 31, 2008, our asset retirement obligation was $35.7 million and $30.1 million, respectively.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term ‘‘market risk’’ refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. Please see “Cautionary Statement Relevant to Forward-Looking Information.”

Commodity Price Risk

Due to the historical volatility of crude oil and natural gas prices, we have entered into various derivative instruments to manage exposure to volatility in the market price of crude oil and natural gas. We use options (including collars) and fixed price swaps for managing risk relating to commodity prices. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in our having lower revenues than we would otherwise have if we had not utilized these instruments in times of higher oil and natural gas prices, management believes that the resulting reduced volatility of prices and cash flow is beneficial. While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected. Please see Part I— Item 1A “—Risk Factors — Risks Related to Our Business — Our derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders. To the extent we have hedged a significant portion of our expected production and actual production is lower than expected or the costs of goods and services increase, our profitability would be adversely affected” in our Annual Report.

As of September 30, 2009, we had the following derivatives as summarized below (utilizing NYMEX WTI and NYMEX wholesale natural gas prices):

	Year
	2009			2010			2011			2012		2013
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMBtu/d)		22,362			43,869			25,955			19,129		27,000
Average Price ($/MMBtu)	$	8.16		$	8.20		$	7.26		$	7.10	$	6.92
Collars:
Hedged Volume (MMBtu/d)		1,063			3,405			16,016			19,129		-
Average Floor Price ($/MMBtu)	$	9.00		$	9.00		$	9.00		$	9.00	$	-
Average Ceiling Price ($/MMBtu)	$	15.40		$	12.79		$	11.28		$	11.89	$	-
Total:
Hedged Volume (MMMBtu/d)		23,424			47,275			41,971			38,257		27,000
Average Price ($/MMBtu)	$	8.20		$	8.26		$	7.92		$	8.05	$	6.92

Oil Positions:
Fixed Price Swaps:
Hedged Volume (Bbls/d)		1,468			2,808			2,616			2,539		3,500
Average Price ($/Bbl)	$	70.18		$	81.35		$	66.22		$	67.24	$	76.79
Participating Swaps: (a)
Hedged Volume (Bbls/d)		1,205			1,993			1,439			-		-
Average Price ($/Bbl)	$	66.48		$	64.40		$	61.29		$	-	$	-
Average Participation %		60.7	%		55.5	%		53.2	%		-		-
Collars:
Hedged Volume (Bbls/d)		257			1,279			2,048			2,477		-
Average Floor Price ($/Bbl)	$	89.57		$	102.85		$	103.42		$	110.00	$	-
Average Ceiling Price ($/Bbl)	$	118.83		$	136.16		$	152.61		$	145.39	$	-
Floors:
Hedged Volume (Bbls/d)		250			500			-			-		-
Average Floor Price ($/Bbl)	$	100.00		$	100.00		$	-		$	-	$	-
Total:
Hedged Volume (Bbls/d)		3,180			6,580			6,103			5,016		3,500
Average Price ($/Bbl)	$	72.69		$	81.81		$	77.51		$	88.35	$	76.79

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

Our location and quality discounts or differentials are not reflected in the above prices. The crude oil agreements provide for monthly settlement based on the differential between the agreement price and the actual average NYMEX WTI crude oil price. The natural gas agreements provide for monthly settlement based on the differential between the agreement price and the average actual MichCon natural gas prices. Our Los Angeles Basin crude is generally medium gravity crude. Because of its proximity to the extensive Los Angeles refinery market, it trades at only a minor discount to NYMEX WTI. Our Wyoming crude, while generally of similar quality to our Los Angeles Basin crude oil, trades at a significant discount to NYMEX WTI because of its distance from a major refining market and the fact that it is priced relative to the Bow River benchmark for Canadian heavy sour crude oil, which has historically traded at a significant discount to NYMEX WTI. Our Florida crude also trades at a significant discount to NYMEX WTI primarily because of its low gravity and other quality characteristics as well as its distance from a major refining market. Our Michigan properties have favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas. To the extent our production is not hedged, we anticipate that this supply/demand situation will allow us to sell our future natural gas production at a slight premium to industry benchmark prices.

We enter into swaps, collars and option contracts in order to mitigate the risk of market price fluctuations to achieve more predictable cash flows. While our current use of these derivative instruments limits the downside risk of adverse price movements, it also limits future revenues from favorable price movements. The use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.

In order to qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure effectiveness on a quarterly basis. Hedge accounting is discontinued prospectively when a hedge instrument is no longer considered highly effective. Our derivative instruments do not currently qualify for hedge accounting under ASC 815 due to the ineffectiveness created by variability in our price discounts or differentials. For instance, our physical oil sales contracts for our Wyoming properties are tied to the price of Bow River crude oil, while its derivative contracts are tied to NYMEX WTI crude oil prices. During 2008, the average discounts we received for our production relative to NYMEX WTI benchmark prices per barrel were $5.15, $18.86 and $14.45 for our California, Wyoming and Florida-based production, respectively. During the third quarter of 2009, the average discounts we received for our production relative to NYMEX WTI benchmark prices per barrel were $0.63, $8.91 and $14.92 for our California, Wyoming and Florida-based production, respectively. During the first nine months of 2009, the average discounts we received for our production relative to NYMEX WTI benchmark prices per barrel were $0.56, $7.57 and $14.75 for our California, Wyoming and Florida-based production, respectively.

All derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or confirmed by the counterparty. Changes in the fair value of commodity derivatives that do not qualify as a hedge or are not designated as a hedge are recorded in gains (losses) on commodity derivative instruments on the consolidated statements of operations, including a loss of $11.6 million for the third quarter of 2009 compared to a gain of $431.6 million for the same period a year ago and a loss of $164.4 million for the first nine months of 2009 compared to a gain of $41.7 million for the same period a year ago.

Interest Rate Risk

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. As of September 30, 2009 our total debt outstanding was $585.0 million and as of October 31, 2009, was $576.0 million. Therefore, from time to time we use interest rate derivatives to hedge our interest obligations.

In 2009, in order to mitigate our interest rate exposure, we had the following interest rate derivative contracts in place at September 30, 2009, to fix a portion of floating LIBOR-based debt on our credit facility:

Notional amounts in thousands of dollars	Notional Amount		Fixed Rate
Period Covered
October 1, 2009 to January 8, 2010	$	100,000		3.3873	%
October 1, 2009 to December 20, 2010		300,000		3.6825	%
January 20, 2010 to October 20, 2011		100,000		1.6200	%
December 20, 2010 to October 20, 2011		200,000		2.9900	%

If interest rates on the floating portion of our variable interest rate debt of $185.0 million increase or decrease by 1 percent, our annual interest cost would increase or decrease by approximately $1.9 million.

Changes in Fair Value

The fair value of our outstanding oil and gas commodity derivative instruments was a net asset of approximately $127.9 million at September 30, 2009 and approximately $292.3 million at December 31, 2008. 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 September 30, 2009, would have increased or decreased our liability 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 $13.2 million and $17.3 million at September 30, 2009 and December 31, 2008. With a one percent increase or decrease in the LIBOR rate, the fair value of our outstanding interest rate derivative instruments at September 30, 2009 would have decreased or increased our net liability by approximately $7 million.

ASC 820 defines fair value, establishes a framework for measuring fair value and establishes required disclosures about fair value measurements. ASC 815 requires enhanced 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 hedge items affect an entity’s financial position, financial performance, and cash flows. Please see Note 14 to our consolidated financial statements contained elsewhere in this report for disclosures required by these pronouncements.

Item 4. Controls and Procedures

Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities and Exchange Act of 1934, as amended (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 principal executive officers and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. See “Management’s Report to Unitholders on Internal Control Over Financial Reporting” and “Reports of Independent Registered Public Accounting Firm” in our Annual Report.

Our General Partner’s Chief Executive Officers and Chief Financial Officer, after evaluating the effectiveness of our “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of September 30, 2009, 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 three months ended September 30, 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Please see Part I—Item 3 “—Legal Proceedings” in our Annual Report and Note 16 within this report for more information on the pending lawsuit instituted by Quicksilver.

Item 1A. Risk Factors

Except as set forth below, there have been no material changes to the Risk Factors disclosed in our Annual Report and in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009, respectively. The following risk factors update and amend certain of the “Risks Related to Our Business” included in our Annual Report and in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009, respectively.

Risks Related to Our Business

Even if we are able to pay quarterly distributions on our Common Units under the terms of our credit facility, we may not elect to pay quarterly distributions on our Common Units because we do not have sufficient cash flow from operations following establishment of cash reserves, reduction of debt and payment of fees and expenses.

Our credit facility limits the amounts we can borrow to a borrowing base amount, which is determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. For example, in April 2009, our borrowing base was decreased from $900 million to $760 million as a result of a scheduled borrowing base redetermination; in June 2009, it was decreased to $735 million as a result of the monetization of $25 million in crude oil and natural gas derivative contracts; and in July 2009, it was decreased to $732 million as a result of our sale of the Lazy JL Field. Our semi-annual borrowing base was redetermined in October 2009, as a result of which our borrowing base remains unchanged at $732 million. While we currently are not restricted by our credit facility from declaring a distribution as we were in April 2009, we may again be restricted from paying a distribution in the future. We may be restricted from making distributions in the future under the terms of our credit facility unless, after giving effect to such distribution, our outstanding debt is less than 90 percent of the borrowing base, and we have the ability to borrow at least 10 percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX).

Even if we are able to pay quarterly distributions on our Common Units under the terms of our credit facility, we may not have sufficient available cash each quarter to pay quarterly distributions on our Common Units. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses, debt reduction and the amount of any cash reserve amounts that our general partner establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. In the future we may reserve a substantial portion of our cash generated from operations to develop our oil and natural gas properties and to acquire additional oil and natural gas properties in order to maintain and grow our level of oil and natural gas reserves.

The amount of cash we actually generate will depend upon numerous factors related to our business that may be beyond our control, including among other things:

·	the amount of oil and natural gas we produce, which we expect to decline in 2009 due to decreased capital expenditures;

·	demand for and prices of our oil and natural gas, which prices decreased significantly beginning in the third quarter of 2008;

·	the level of our operating costs, including reimbursement of expenses to our general partner;

·	prevailing distressed economic conditions;

·	unexpected defense and other costs associated with our ongoing litigation with Quicksilver

·	continued development of oil and natural gas wells and proved undeveloped reserves;

·	the level of competition we face;

·	fuel conservation measures;

·	alternate fuel requirements;

·	government regulation and taxation; and

·	technical advances in fuel economy and energy generation devices.

In addition, the actual amount of cash that we will have available for distribution will depend on other factors, including:

·	our ability to borrow under our credit facility to pay distributions;

·	debt service requirements and restrictions on distributions contained in our credit facility or future debt agreements;

·	the level of our capital expenditures;

·	sources of cash used to fund acquisitions;

·	fluctuations in our working capital needs;

·	general and administrative expenses;

·	cash settlement of hedging positions;

·	timing and collectability of receivables; and

·	the amount of cash reserves established for the proper conduct of our business.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read Part I—Item 2 “—Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.

As of October 31, 2009, we had approximately $576 million in borrowings outstanding under our credit facility. Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. For example, in April 2009, our borrowing base was decreased from $900 million to $760 million as a result of a scheduled borrowing base redetermination; in June 2009; it was decreased to $735 million as a result of the monetization of $25 million in crude oil and natural gas derivative contracts in June 2009; and in July 2009, it was decreased to $732 million as a result of the sale of the Lazy JL Field. The borrowing base is redetermined semi-annually and the available borrowing amount could be further decreased as a result of such redeterminations. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements or regulations or certain other circumstances. Our semi-annual borrowing base was redetermined in October 2009, as a result of which our borrowing base remains unchanged at $732 million Oil and natural gas prices remain volatile, and we expect that the lenders under our credit facility may further decrease our borrowing base at the next scheduled redetermination in April 2010. A future decrease in our borrowing base could be substantial and could be to a level below our outstanding borrowings. Outstanding borrowings in excess of the borrowing base are required to be repaid, or we are required to pledge other oil and natural gas properties as additional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our credit facility or sell assets or debt or Common Units. We may not be able obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to make the required repayment could result in a default under our credit facility, which could adversely affect our business, financial condition and results or operations.

The operating and financial restrictions and covenants in our credit facility restrict and any future financing agreements likely will restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions. Our credit facility restricts and any future credit facility likely will restrict our ability to:

·	incur indebtedness;

·	grant liens;

·	make certain acquisitions and investments;

·	lease equipment;

·	make capital expenditures above specified amounts;

·	redeem or prepay other debt;

·	make distributions to unitholders or repurchase units;

·	enter into transactions with affiliates; and

·	enter into a merger, consolidation or sale of assets.

Our credit facility restricts our ability to make distributions to unitholders or repurchase units unless after giving effect to such distribution, our outstanding debt is less than 90 percent of the borrowing base, and we have the ability to borrow at least 10 percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX). While we currently are not restricted by our credit facility from declaring a distribution as we were in April 2009, we may again be restricted from paying a distribution in the future.

We also are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. In light of the current weak economic conditions and the deterioration of oil and natural gas prices, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders can seek to foreclose on our assets. See Part I—Item 2 “—Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility” for a discussion of our credit facility covenants.

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, there is currently proposed federal legislation in four areas (tax, climate change, derivatives and hydraulic fracturing) that if adopted could significantly affect our operations. The following are brief descriptions of the proposed laws:

With respect to proposed tax legislation, President Obama’s Proposed 2010 Fiscal Year Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. 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 any such change could negatively affect our financial condition and results of operations.

On June 26, 2009, the U.S. House of Representatives acted on climate change legislation by approving the adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. The purpose of ACESA is to control and reduce emissions of carbon dioxide, methane and other “greenhouse gases,” or “GHGs,” in the United States. ACESA would require a reduction in emissions of GHGs by 17 percent (from 2005 levels) by 2020 and by more than 80 percent by 2050, which would necessitate a very significant reduction in the use of carbon-based fuels such as oil and natural gas. The Senate is currently considering similar legislation that, if approved, would need to be reconciled with ACESA before it could become law. 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. A Senate committee approved its own version of GHG cap-and-trade legislation on November 5, 2009, but the bill has not yet been scheduled for consideration by the full Senate and, if adopted, the bill would need to be reconciled with ACESA and reapproved by both houses of Congress before it could be adopted as law.

Congress is also currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. Separately, two committees of the House of Representatives, the Financial Services and Agriculture Committees, acted on October 15 and October 21, 2009, respectively, to adopt legislation that would impose comprehensive regulation on the over-the-counter (OTC) derivatives marketplace. This legislation would subject swap dealers and major swap participants to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants, and would provide the CFTC with authority to impose position limits in the OTC derivatives markets. A major swap participant generally would be someone other than a dealer who maintains a "substantial" position in outstanding swaps other than swaps used for commercial hedging, or whose positions create substantial exposure to its counterparties or the system. Any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies, and the proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process. These bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

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.

Our business is subject to 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. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you. Please read Part I—Item 1 of our Annual Report “—Business—Operations—Environmental Matters and Regulation” and “—Business—Operations—Other Regulation of the Oil and Gas Industry” for a description of the laws and regulations that affect us.

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. Submission of Matters to a Vote of Security Holders

None.

Item 5. Other Information

None.

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 dated October 10, 2006 and filed 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 dated June 17, 2008 and filed 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 dated April 7, 2009 and filed April 9, 2009).
3.4		Second 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 dated June 17, 2008 and filed June 23, 2008).
3.5		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 dated August 27, 2009 and filed September 1, 2009).
10.1		Indemnity Agreement between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Halbert S. Washburn, together with a schedule identifying other substantially identical agreements between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and each of its executive officers and non-employee directors identified on the schedule (incorporated herein by reference to Exhibit 10.1 to the Current Report on form 8-K dated October 29, 2009 and filed November 4, 2009).
10.2		First Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.2 to the Current Report on form 8-K dated October 29, 2009 and filed November 4, 2009).
10.3*		First Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan effective October 29, 2009.
31.1*		Certification of Registrant’s Co-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 Co-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.
31.3*		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 Co-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. This certification is being furnished solely to accompany this Quarterly Report on Form 10-Q and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Partnership.
32.2*		Certification of Registrant’s Co-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. This certification is being furnished solely to accompany this Quarterly Report on Form 10-Q and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Partnership.
32.3*		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. This certification is being furnished solely to accompany this Quarterly Report on Form 10-Q and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Partnership.

* Filed 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: November 6, 2009	By:	/s/ HALBERT S. WASHBURN
		Halbert S. Washburn
		Co-Chief Executive Officer
Dated: November 6, 2009	By:	/s/ RANDALL H. BREITENBACH
		Randall H. Breitenbach
		Co-Chief Executive Officer
Dated: November 6, 2009	By:	/s/ JAMES G. JACKSON
		James G. Jackson
		Chief Financial Officer

EXHIBIT INDEX

NUMBER		DOCUMENT
3.1		First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1to the Current Report on form 8-K dated October 10, 2006 and filed 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 3.1to the Current Report on form 8-K dated June 17, 2008 and filed 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 3.1to the Current Report on form 8-K dated April 7, 2009 and filed April 9, 2009).
3.4		Second 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 dated June 17, 2008 and filed June 23, 2008).
3.5		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 3.1to the Current Report on form 8-K dated August 27, 2009 and filed September 1, 2009).
10.1		Indemnity Agreement between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and Halbert S. Washburn, together with a schedule identifying other substantially identical agreements between BreitBurn Energy Partners L.P., BreitBurn GP, LLC and each of its executive officers and non-employee directors identified on the schedule (incorporated herein by reference to Exhibit 10.1 to the Current Report on form 8-K dated October 29, 2009 and filed November 4, 2009).
10.2		First Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Convertible Phantom Unit Agreements (incorporated herein by reference to Exhibit 10.2 to the Current Report on form 8-K dated October 29, 2009 and filed November 4, 2009).
10.3*		First Amended and Restated BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan effective October 29, 2009.
31.1*		Certification of Registrant’s Co-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 Co-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.
31.3*		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 Co-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. This certification is being furnished solely to accompany this Quarterly Report on Form 10-Q and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Partnership.
32.2*		Certification of Registrant’s Co-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. This certification is being furnished solely to accompany this Quarterly Report on Form 10-Q and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Partnership.
32.3*		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. This certification is being furnished solely to accompany this Quarterly Report on Form 10-Q and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Partnership.

* Filed herewith.

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