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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

(Amendment No. 1)


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008


o		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: 001-14837

QUICKSILVER RESOURCES INC.

(Exact name of registrant as specified in its charter)


Delaware		75-2756163
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

777 West Rosedale St., Fort Worth, Texas		76104
(Address of principal executive offices)		(Zip Code)

817-665-5000
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered

Common Stock, $0.01 par value per share		New York Stock Exchange
Preferred Share Purchase Rights,
$0.01 par value per share		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

Yes o No þ

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 o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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


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

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

Yes o No þ

As of June 30, 2008, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $4,067,732,259 based on the closing sale price of $38.64 as reported on the New York Stock Exchange.

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


Class		Outstanding at February 13, 2009

Common Stock, $0.01 par value per share		168,752,835 shares

DOCUMENTS INCORPORATED BY REFERENCE


Document		Parts Into Which Incorporated

Proxy Statement for the Registrant’s May 20,		Part III
2009 Annual Meeting of Stockholders

TABLE OF CONTENTS


PART IV
	ITEM 15. Exhibits and Financial Statement Schedules
SIGNATURES
Exhibit Index
EXHIBIT 23.4
EXHIBIT 23.5
EXHIBIT 23.6
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1

Explanatory Note

This Amendment No. 1 to the Annual Report on Form 10-K of Quicksilver Resources Inc. (“Quicksilver”) for the year ended December 31, 2008, originally filed on March 3, 2009 (“Original Form 10-K”) is being filed to provide audited financial statements and the related footnotes of BreitBurn Energy Partners L.P. (“BBEP”) in accordance with SEC Rule 3-09 of Regulation S-X. The management of BBEP is solely responsible for the form and content of the BBEP financial statements. Quicksilver has no responsibility for the form or content of the BBEP financial statements since it does not control BBEP and is not involved in the management of BBEP.

These audited financial statements and related footnotes are included in “Item 15. Exhibits and Financial Statement Schedules.” In addition, the consents of Schlumberger Data and Consulting Services, Netherland, Sewell & Associates, Inc. and PricewaterhouseCoopers LLP and new certifications of Quicksilver’s principal chief executive officer and principal financial officer are filed as exhibits to this Amendment No. 1 under Item 15.

This Amendment No. 1 does not reflect events occuring after March 3, 2009. This Amendment also does not update or modify in any way the results of operations, financial position, cash flows or other disclosures in the Original Form 10-K.

(i)

Report of Independent Registered Public Accounting Firm

To the Board of Directors of BreitBurn GP, LLC
and Unitholders of BreitBurn Energy Partners L.P.

In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of operations, partners’ equity and cash flows present fairly, in all material respects, the financial position of BreitBurn Energy Partners L.P. and its subsidiaries (“the Partnership”) at December 31, 2008, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 14 to the financial statements, the Partnership changed the manner in which it accounts for recurring fair value measurements of financial instruments in 2008.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California
March 2, 2009

BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statement of Operations
For the Year Ended December 31, 2008




*Thousands of dollars, except per unit amounts*
Revenues and other income items:
Oil, natural gas and natural gas liquid sales	$	467,381
Gains on commodity derivative instruments, net (note 14)		332,102
Other revenue, net (note 10)		2,920

Total revenues and other income items		802,403
Operating costs and expenses:
Operating costs		149,681
Depletion, depreciation and amortization (note 5)		179,933
General and administrative expenses		43,435

Total operating costs and expenses		373,049


Operating income		429,354

Interest and other financing costs, net		29,147
Loss on interest rate swaps (note 14)		20,035
Other income, net		(191	)


Income before taxes and minority interest		380,363

Income tax expense (note 6)		1,939
Minority interest (note 19)		188


Net income		378,236


General Partner’s interest in net income (loss)		(2,019	)


Limited Partners’ interest in net income	$	380,255


Basic net income per unit (note 2)	$	6.42

Diluted net income per unit (note 2)	$	6.28

The accompanying notes are an integral part of these consolidated financial statements.

BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Balance Sheet
As of December 31, 2008



*Thousands of dollars, except unit amounts*
ASSETS
Current assets:
Cash	$	2,546
Accounts receivable, net (note 2)		47,221
Derivative instruments (note 14)		76,224
Related party receivables (note 7)		5,084
Inventory (note 8)		1,250
Prepaid expenses		5,300
Intangibles (note 9)		2,771
Other current assets		170

Total current assets		140,566
Equity investments (note 10)		9,452
Property, plant and equipment
Oil and gas properties (note 4)		2,057,531
Non-oil and gas assets (note 4)		7,806

		2,065,337
Accumulated depletion and depreciation (note 5)		(224,996	)

Net property, plant and equipment		1,840,341
Other long-term assets
Intangibles (note 9)		495
Derivative instruments (note 14)		219,003
Other long-term assets		6,977


Total assets	$	2,216,834

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	28,302
Book overdraft		9,871
Derivative instruments (note 14)		10,192
Revenue distributions payable		16,162
Derivative settlements payable		50
Salaries and wages payable		6,249
Accrued liabilities		9,164

Total current liabilities		79,990
Long-term debt (note 11)		736,000
Deferred income taxes (note 6)		4,282
Asset retirement obligation (note 12)		30,086
Derivative instruments (note 14)		10,058
Other long-term liabilities		2,987

Total liabilities		863,403
Minority interest (note 19)		539
Partners’ equity (note 13)
Limited partners’ interest (a)		1,352,892

Total liabilities and partners’ equity	$	2,216,834


(a) Limited partner units outstanding		52,635,634

The accompanying notes are an integral part of these consolidated financial statements.

BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statement of Cash Flows
For the Year Ended December 31, 2008


*Thousands of dollars*
Cash flows from operating activities
Net income	$	378,236
Adjustments to reconcile net income to cash flow from operating activities:
Depletion, depreciation and amortization		179,933
Unit-based compensation expense		6,907
Unrealized gain on derivative instruments		(370,734	)
Distributions greater than income from equity affiliates		1,198
Deferred income tax		1,207
Minority interest		188
Amortization of intangibles		3,131
Other		2,643
Changes in net assets and liabilities:
Accounts receivable and other assets		258
Inventory		4,454
Net change in related party receivables and payables		32,688
Accounts payable and other liabilities		(13,413	)

Net cash provided by operating activities		226,696

Cash flows from investing activities
Capital expenditures		(131,082	)
Property acquisitions		(9,957	)

Net cash used by investing activities		(141,039	)

Cash flows from financing activities
Purchase of common units		(336,216	)
Distributions ⁽¹⁾		(121,349	)
Proceeds from the issuance of long-term debt		803,002
Repayments of long-term debt		(437,402	)
Book overdraft		7,951
Long-term debt issuance costs		(5,026	)

Net cash used by financing activities		(89,040	)

Decrease in cash		(3,383	)
Cash beginning of period		5,929

Cash end of period	$	2,546


(1)		Includes distributions on equivalent units of $2.3 million

The accompanying notes are an integral part of these consolidated financial statements.

Notes to Consolidated Financial Statements

Note 1. Organization and Operations

BreitBurn Energy Partners L.P.

The Partnership is a Delaware limited partnership formed on March 23, 2006. In October 2006, we completed an initial public offering of 6,000,000 Common Units and completed the sale of an additional 900,000 Common Units to cover over-allotments in the initial public offering at $18.50 per unit, or $17.205 per unit, after deducting the underwriting discount. On May 24, 2007, we sold 4,062,500 Common Units in a private placement at $32.00 per unit, resulting in proceeds of approximately $130 million. The net proceeds of this private placement were used to acquire certain interests in oil leases and related assets located in Florida from Calumet Florida L.L.C. and to reduce indebtedness under our credit facility. On May 25, 2007, we sold 2,967,744 Common Units in a private placement at $31.00 per unit, resulting in proceeds of approximately $92 million. The net proceeds of this private placement were used to acquire a 99 percent limited partner interest in BreitBurn Energy Partners I, L.P. (“BEPI”) from TIFD X-III LLC which owned interests in the Sawtelle and East Coyote oil fields located in California, and to terminate existing hedges related to future production from BEPI. On November 1, 2007, we sold 16,666,667 Common Units in a private placement at $27.00 per unit, resulting in proceeds of approximately $450 million. The net proceeds from this private placement were used to fund a portion of the cash consideration for our acquisition from Quicksilver of properties located in Michigan, Indiana and Kentucky (the “Quicksilver Acquisition”). Also on November 1, 2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration for the Quicksilver Acquisition as a private placement.

Our general partner is BreitBurn GP, a Delaware limited liability company, also formed on March 23, 2006. 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.

Our wholly owned subsidiary 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 7 for information regarding our relationship with BreitBurn Management.

On June 17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at $23.26 per unit, for a purchase price of approximately $335 million (the “Common Unit Purchase”). These units have been cancelled and are no longer outstanding. This purchase was accounted for as a repurchase of issued Common Units and a cancellation of those Common Units. It increased debt by $336.2 million and decreased equity by $336.2 million, including $1.2 million in capitalized transaction costs.

On June 17, 2008, we also purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management, which owned the General Partner, for a purchase price of approximately $10 million (the “BreitBurn Management Purchase”). See Note 4 for the purchase price allocation for this transaction. Also on June 17, 2008, we entered into a contribution agreement (the “Contribution Agreement”) with the General Partner, BreitBurn Management and BreitBurn Corporation, which is wholly owned by the Co-Chief Executive Officers of the General Partner, Halbert S. Washburn and Randall H. Breitenbach, pursuant to which BreitBurn Corporation contributed its 4.45 percent limited liability company interest in BreitBurn Management to us in exchange for 19,955 Common Units, the economic value of which was equivalent to the value of their combined 4.45 percent interest in BreitBurn Management, and BreitBurn Management contributed its 100 percent limited liability company interest in the General Partner to us. On the same date, we entered into Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of the Partnership, pursuant to which the economic portion of the General Partner’s 0.66473 percent general partner interest in us was eliminated and our limited partners holding Common Units were given a right to nominate and vote in the election of directors to the Board of Directors of the General Partner. As a result of these transactions (collectively, the “Purchase, Contribution and Partnership Transactions”), the General Partner and BreitBurn Management became our wholly owned subsidiaries.

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 Amended and Restated Credit Agreement, Limited Waiver and Consent and First Amendment to Security Agreement (“Amendment No. 1 to the Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent. Amendment No. 1 to the Credit Agreement increased the borrowing base available under the Amended and Restated Credit Agreement dated November 1, 2007 from $750 million to $900 million. We used borrowings under Amendment No. 1 to the Credit Agreement to finance the Common Unit Purchase and the BreitBurn Management Purchase.

On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, the Omnibus Agreement, dated October 10, 2006, among us, the General Partner, Provident, Pro GP and BEC was terminated in all respects.

As of December 31, 2008, the public unitholders, the institutional investors in our private placements and Quicksilver owned 98.69 percent of the Common Units. BreitBurn Corporation owned 690,751 Common Units, representing a 1.31 percent limited partner interest. We own 100 percent of the General Partner, BreitBurn Management and BOLP.

On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark Capital Partners (“Metalmark”), Greenhill Capital Partners (“Greenhill”) and a third-party institutional investor, completed the acquisition of BEC, our Predecessor. This transaction included the acquisition of a 96.02 percent indirect interest in BEC, previously owned by Provident, and the remaining indirect interests in BEC, previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of the our senior management. BEC was a separate U.S. subsidiary of Provident and was our Predecessor.

2. Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. Investments in affiliated companies with a 20 percent or greater ownership interest, and in which we do not have control, are accounted for on the equity basis. Investments in affiliated companies with less than a 20 percent ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than 50 percent interest are consolidated. Investments in which we own less than a 50 percent interest but are deemed to have control or where we have a variable interest in an entity where we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The effects of all intercompany transactions have been eliminated.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation, amortization, asset retirement obligations and impairment of oil and gas properties.

We account for business combinations using the purchase method, in accordance with SFAS No. 141 Accounting for Business Combinations. We use estimates to record the assets and liabilities acquired. All purchase price allocations are finalized within one year from the acquisition date.

Basis of Presentation

Our financial statements are prepared in conformity with U.S. generally accepted accounting principles.

Business segment information

SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, establishes standards for reporting information about operating segments. Segment reporting is not applicable because our oil and gas operating areas have similar economic characteristics and meet the criteria for aggregation as defined in SFAS No. 131. We acquire, exploit, develop and explore for and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas.

Revenue recognition

Revenues associated with sales of our crude oil and natural gas are recognized when title passes from us to our customer. Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest (“entitlement” method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As a result, we have no material natural gas producer imbalance positions.

Cash and cash equivalents

We consider all investments with original maturities of three months or less to be cash equivalents. At December 31, 2008 we had no such investments.

Accounts Receivable

Our accounts receivable are primarily from purchasers of crude oil and natural gas and counterparties to our financial instruments. Crude oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. During 2008 we terminated our crude oil derivative instruments with Lehman Brothers due to their bankruptcy, and at December 31, 2008, we had an allowance of $4.6 million related to these contracts.

Inventory

Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded as inventory.

Investments in Equity Affiliates

Income from equity affiliates is included as a component of operating income, as the operations of these affiliates are associated with the processing and transportation of our natural gas production.

Property, plant and equipment

Oil and gas properties

We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred, including internal acquisition costs, relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred.

Upon sale or retirement of proved properties, the cost thereof and the accumulated depletion, depreciation and amortization (“DD&A”) are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, are computed on a property-by-property basis and recognized using the units-of-production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using straight line, generally over 20 years.

Non-oil and gas assets

Buildings and non-oil and gas assets are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from 3 to 30 years.

Oil and natural gas reserve quantities

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports.

Asset retirement obligations

We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. The computation of our asset retirement obligations (“ARO”) is prepared in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations. This accounting standard applies to the fair value of a liability for an asset retirement obligation that is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and expensed. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of crude oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO

estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.

Impairment of assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” as amended. Under SFAS 144, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted cash flows are forecast using five-year NYMEX forward strip prices at the end of the period and escalated thereafter at 2.5 percent. For impairment charges, the associated property’s expected future net cash flows are discounted using a rate of approximately ten percent. Reserves are calculated based upon reports from third-party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Because of the low commodity prices that existed at year end 2008, and the uncertainty surrounding future commodity prices and costs, we performed impairment tests on our long-lived assets at December 31, 2008.

We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. In 2008, we recorded $51.9 million in impairments and $34.5 million in price related depletion and depreciation adjustments. See Note 5 — Impairments and Price Related Depletion and Depreciation Adjustments. The charge was included in DD&A on the consolidated statement of operations.

Debt issuance costs

The costs incurred to obtain financing have been capitalized. Debt issuance costs are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.

Equity-based compensation

BreitBurn Management had various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 15.

Effective January 1, 2006, the Predecessor adopted the fair value recognition provisions of SFAS No. 123 (revised 2004) (SFAS No. 123(R)), Share Based Payments, using the modified-prospective transition method. Under this transition method, unit based compensation awards granted prior to but not yet vested as of January 1, 2006 that are classified as liabilities are charged to compensation expense based on the fair value provisions of SFAS No. 123(R). We and the Predecessor recognized these compensation costs on a graded-vesting method. Under the graded-vesting method a company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award was, in substance, multiple awards.

Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period.

Fair market value of financial instruments

The carrying amount of our cash, accounts receivable, accounts payable, and accrued expenses, approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt approximates fair value; however, changes in the credit markets at year-end may impact our ability to enter into future credit facilities at similar terms.

Accounting for business combinations

We have accounted for all business combinations using the purchase method, in accordance with SFAS No. 141, Accounting for Business Combinations. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and

liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets. We have not recognized any goodwill from any business combinations.

Concentration of credit risk

We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings.

Derivatives

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of all derivative instruments as assets or liabilities in our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. For derivatives designated as cash flow hedges, changes in fair value are recognized in other comprehensive income, to the extent the hedge is effective, until the hedged item is recognized in earnings. Hedge effectiveness is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by SFAS No.133, is recognized immediately in earnings. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities. We currently do not designate any of our derivatives as hedges for accounting purposes.

Effective January 1, 2008, we adopted SFAS No. 157,“Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value measurement under SFAS No. 157 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 SFAS No. 157 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.

Income taxes

Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided.

We have three wholly owned subsidiaries, which are subject to corporate income taxes. We account for the taxes associated with one entity in accordance with SFAS No. 109, “Accounting for Income Taxes.” Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities.

Effective January 1, 2007, we implemented FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109 (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies.

We performed an evaluation as of December 31, 2008 and concluded that there were no uncertain tax positions requiring recognition in the financial statements. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows.

Net Income per unit

Weighted average units outstanding for computing basic and diluted net income per unit were:


	Year Ended
	December 31,
	2008
Weighted average number of Common Units used to calculate basic and diluted net income or loss per unit:
Basic		59,238,588
Dilutive		1,322,107

Diluted		60,560,695

We had 6,700,000 Common Units authorized for issuance under our long-term incentive compensation plans and there were approximately 1,422,171 partnership-based units outstanding that are eligible for receiving Common Units upon vesting at December 31, 2008.

Environmental expenditures

We review, on an annual basis, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. We do not discount any of these liabilities. At December 31, 2008, we had a $2.0 million environmental liability related to a closure of a drilling pit in Michigan, which we assumed in the Quicksilver Acquisition.

3. Accounting Pronouncements

SFAS No. 157, Fair Value Measurements. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 12, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Earlier adoption is permitted, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. Effective January 1, 2008, we adopted SFAS No. 157, as amended by FSP 157-2. Adoption of SFAS No. 157 did not have a material impact on our results from operations or financial position.

SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FAS 115” (“SFAS No. 159”). In February 2007, the FASB issued SFAS No. 159 which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value in situations in which they are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. The provisions of SFAS No. 159 became effective for us on January 1, 2008. We have elected not to adopt the fair value option allowed by SFAS No. 159, and, therefore, it had no impact on our financial position, results from operations or cash flows.

SFAS No. 141(revised 2007) “Business Combinations” (“SFAS No. 141R”). In December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141R was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and increased transparency through expanded disclosures. It changes how business acquisitions are accounted for and will impact financial statements at the acquisition date and in subsequent periods. Certain of these changes will introduce more volatility into earnings. The acquirer must now record all assets and liabilities of the acquired business at fair value, and related transaction and restructuring costs will be expensed rather than the previous method of being capitalized as part of the acquisition. SFAS No. 141R also impacts the goodwill impairment test associated with acquisitions, including those that close before the effective date of SFAS No. 141R. The definitions of a “business” and a “business combination” have been expanded, resulting in more transactions qualifying as business combinations. SFAS No. 141R is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. We may experience a financial statement impact depending on the nature and extent of any new business combinations entered into after the effective date of SFAS No. 141R.

SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS No. 160”). In December 2007, the FASB issued SFAS No. 160 which requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. SFAS No. 160 also 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. SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS No. 160 is not expected to have a material impact on our results from operations or financial position.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS No. 161”). In March 2008, the FASB issued SFAS No. 161 which requires enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 has the same scope as Statement 133, and, accordingly, applies to all entities. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. This statement will require the additional disclosures detailed above.

FSP 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP 142-3”). In April 2008, the FASB issued FSP 142-3, which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The intent of this FSP is to improve consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combination” and other U.S. generally accepted accounting principles. FSP 142-3 is effective for fiscal years beginning after December 15, 2008. We do not expect the adoption of FSP 142-3 to have a material impact on our financial position, results of operations or cash flows.

SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). In May 2008, the FASB issued SFAS No. 162 which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States (the GAAP hierarchy). SFAS No. 162 became effective November 13, 2008. The adoption of SFAS No. 162 did not have an impact on our results from operations or financial position.

FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). In June 2008, the FASB issued FSP EITF 03-6-1. Under this FSP, unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether they are paid or unpaid, are considered participating securities and should be included in the computation of earnings per share pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. In addition, all prior period earnings per share data presented should be adjusted retrospectively and early application is not permitted. We are currently evaluating the impact adoption of FSP EITF 03-6-1 may have on our earnings per share disclosures.

On December 31, 2008, the SEC issued Release No. 33-8995 for guidelines on new 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. It does 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 guideline also permits 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, it also replaces 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. The adoption of SEC 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.

4. Acquisitions

On June 17, 2008, we purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management for a purchase price of approximately $10.0 million. This transaction resulted in BreitBurn Management becoming our wholly owned subsidiary and was accounted for as a business combination. The following table presents the purchase price allocation of the BreitBurn Management Purchase:


*Thousands of dollars*
Related party receivables — current, net	$	10,662
Other current assets		21
Oil and gas properties		8,451
Non-oil and gas assets		4,343
Related party receivables — non-current		6,704
Current liabilities		(13,510	)
Long-term liabilities		(6,704	)

	$	9,967

Certain of the current and long-term related party receivables are with the Partnership, so they are now eliminated in consolidation.

5. Impairments and Price Related Depletion and Depreciation Adjustments

Because of the low commodity prices at year end 2008, and the uncertainty surrounding future commodity prices as well as future costs, we performed impairment tests on our long-lived assets at December 31, 2008. For the year ended December 31, 2008, we recorded approximately $51.9 million for total impairments and $34.5 million for price related adjustments to depletion and depreciation expense.

We assess our developed and undeveloped oil and gas properties and other long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved-reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for market supply and demand conditions for crude oil and natural gas. The impairment reviews and calculations are based on assumptions that are consistent with our business plans. See “Impairment of Assets” in Note 2. The low commodity price environment that existed at December 31, 2008 influenced our future commodity price projections. As a result, the expected discounted cash flows for many of our fields (i.e., fair values) were negatively impacted resulting in a charge to depletion and depreciation expense of approximately $51.9 million for field impairments for the year ended December 31, 2008.

An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable, given the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

Lower commodity prices also negatively impacted our oil and gas reserves in the fourth quarter of 2008 resulting in significant price related adjustments to our depletion and depreciation expense in the fourth quarter of 2008 as compared to the fourth quarter of 2007. These price

related reserve reductions in 2008 resulted in additional depletion and depreciation charges of approximately $34.5 million for the fourth quarter and for the year ended December 31, 2008.

6. Income Taxes

We, and all of our subsidiaries, with the exception of Phoenix Production Company, Alamitos Company and BreitBurn Management, are partnerships or limited liability companies treated as partnerships for federal and state income tax purposes. Essentially all of our taxable income or loss, which may differ considerably from the net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our partners. As such, we have not recorded any federal income tax expense for those pass-through entities. State income tax expenses are recorded for certain operations that are subject to state taxation in various states, primarily Michigan, California and Texas. The total state taxes paid were $0.5 million in 2008.

Our wholly-owned subsidiary, Phoenix Production Company, is a tax-paying corporation. We record an income tax provision in accordance with SFAS No. 109 “Accounting for Income Taxes.” In 2008, Phoenix Production Company recorded $0.1 million for alternative minimum taxes. Phoenix Production Company also recorded a deferred federal income tax expense of $1.2 million in 2008. The following is a reconciliation for Phoenix Production Company of federal income taxes at the statutory rates to federal income tax expense or benefit as reported in the consolidated statements of operations.


	Year Ended
	December 31,
*Thousands of dollars*	2008
Income before taxes and minority interest	$	380,363
Partnership income not subject to tax		376,459

Income subject to tax		3,904
Federal income tax rate		34

Income tax at statutory rate		1,327
Other		—

Income tax expense	$	1,327

At December 31, 2008, a net deferred federal income tax liability of $4.3 million was included in our consolidated balance sheet for Phoenix Production Company. As shown in the table below, the net deferred federal income tax liability primarily consisted of the tax effect of book and tax basis differences of certain assets and liabilities and the deferred federal income tax asset for net operating loss carry forwards. Management expects to utilize $2.3 million of estimated unused operating loss carry forwards to offset future taxable income. As such, no valuation allowance has been recorded against the deferred federal income tax asset.


	December 31,
*Thousands of dollars*	2008
Deferred tax assets:
Net operating loss carryforwards	$	767
Asset retirement obligation		337
Unrealized hedge loss		—
Other		103
Deferred tax liabilities:
Depreciation, depletion and intangible drilling costs		(3,404	)
Other		(2,085	)

Net deferred tax liability	$	(4,282	)

In 2008, our other wholly-owned tax-paying corporation, Alamitos Company, incurred a current federal tax expense of $0.1 million. No deferred federal or state income tax is recognized for this company as the temporary differences between the tax basis and the reported financial amounts of its assets and liabilities are immaterial. BreitBurn Management became our wholly-owned subsidiary and a taxable entity on June 17, 2008. However, no federal or state income tax expense is expected due to the nature of its business as expenses incurred are essentially offset by amounts recovered for services provided to the operating companies.

Cash paid for federal and state income taxes was $0.6 million in 2008.

New Accounting Pronouncement

7. 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 $775,000 for indirect expenses. In addition to the monthly fee, BreitBurn Management agreed to continue to charge BEC for direct expenses including incentive plan costs and direct payroll and administrative costs. Beginning on June 17, 2008, all of the costs charged to BOLP are consolidated with our results.

On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark, Greenhill and a third-party institutional investor, completed the acquisition of BEC, our Predecessor. This transaction included the acquisition of a 96.02 percent indirect interest in BEC previously owned by Provident and the remaining indirect interests in BEC previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of our senior management. BEC was an indirectly owned subsidiary of Provident.

In connection with the acquisition of Provident’s ownership in BEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, BreitBurn Management entered into a five year Administrative Services Agreement to manage BEC’s properties. The monthly fee charged to BEC remained $775,000 for indirect expenses through December 31, 2008. We expect this fee to be renegotiated annually during the term of the agreement and expect a monthly fee of less than $775,000 in 2009. In addition, we have 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 December 31, 2008, we had current receivables of $4.4 million 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. In 2008, total oil and gas sales made on our behalf for these properties were approximately $2.1 million.

Mr. Greg L. Armstrong is the Chairman of the Board and Chief Executive Officer of Plains All American GP LLC (“PAA”). Mr. Armstrong was a director of our General Partner until March 26, 2008 when his resignation became effective. We sell all of the crude oil produced from our Florida properties to Plains Marketing, L.P., a wholly owned subsidiary of PAA. In 2008, prior to Mr. Armstrong’s resignation on March 26, 2008, we sold $19.3 million of our crude oil to Plains Marketing, L.P.

Through a transition services agreement through March 2008, Quicksilver provided services to us for accounting, land administration, and marketing and charged us $0.9 million for the first three months 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 year ended

December 31, 2008, total net gas sales to Quicksilver were approximately $8.0 million and the related receivable was $0.6 million as of December 31, 2008.

At December 31, 2008, we had a receivable of $0.1 million for management fees due from equity affiliates and operational expenses incurred on behalf of equity affiliates.

8. Inventory

Our crude oil inventory from our Florida operations at December 31, 2008 was $1.3 million. For the year ended December 31, 2008, we sold 762 MBbls of crude oil and produced 707 MBbls from our Florida operations. Crude oil inventory additions are at cost and represent our production costs. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded to inventory. 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.

We carry inventory at the lower of cost or market. When using lower of cost or market to value inventory, market should not exceed the net realizable value or the estimated selling price less costs of completion and disposal. During the fourth quarter of 2008, commodity prices decreased substantially. As a result, we assessed our crude oil inventory for possible write-down, and recorded $1.2 million to write-down the Florida crude oil inventory to our net realizable value at December 31, 2008.

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.

9. Intangibles

In May 2007, we acquired certain interests in oil leases and related assets through the acquisition of a limited liability company from Calumet Florida, L.L.C. 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 are recognized as part of oil sales and the intangible asset will be amortized over the life of the contracts. As of December 31, 2008, our intangible asset related to the crude oil sales contracts was $1.6 million.

In November 2007, we acquired oil and gas properties and facilities 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. The amortization expense of $2.1 million for 2008 is included in the total operating expenses line on the consolidated statement of operations. As of December 31, 2008, our intangible asset related to Quicksilver retention bonuses was $1.7 million.

10. Equity Investments

We had equity investments at December 31, 2008 of $9.5 million. These investments are reported in the “Equity investments” line caption on the consolidated balance sheet and primarily represent investments in natural gas processing facilities. For the year ended December 31, 2008, we recorded $0.8 million in earnings from equity investments. Earnings from equity investments are reported in the “Other Revenue” line caption on the consolidated statement of operations.

At December 31, 2008, our equity investments consisted primarily of a 24.5 percent limited partner interest and a 25.5 percent general partner interest in Wilderness Energy Services LP, with a combined carrying value of $8.2 million. The remaining $1.3 million consists of smaller interests in several other investments.

11. 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. Under the Amended and Restated Credit Agreement, borrowings were allowed to be used (i) to pay a portion of the purchase price for the Quicksilver Acquisition, (ii) for standby letters of credit, (iii) for working capital purposes, (iv) for general company purposes and (v) for certain permitted acquisitions and payments enumerated by the credit facility. Borrowings under the Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of the Partnership’s and certain of its subsidiaries’ assets, representing not less than 80 percent of the total value of their oil and gas properties.

The Amended and Restated Credit Agreement contains (i) financial covenants, including leverage, current assets and interest coverage ratios, and (ii) customary covenants, including restrictions on the Partnership’s ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to unitholders or repurchase units if aggregated letters of credit and outstanding loan amounts exceed 90 percent of its borrowing base; make dispositions; or enter into a merger or sale of its property or assets, including the sale or transfer of interests in its subsidiaries.

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 the Partnership 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. At December 31, 2008, the Partnership was in compliance with the credit facility’s covenants.

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 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.

As of December 31, 2008, approximately $736.0 million in indebtedness was outstanding under the Amended and Restated Credit Agreement. The credit facility will mature on November 1, 2011. At December 31, 2008, the LIBOR interest rate, a weighted average interest rate of our four outstanding LIBOR loans, was 2.350 percent on the LIBOR portion of $736.0 million.

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 in our ability to make distributions if aggregated letters of credit and outstanding loan amounts exceed 90 percent of our borrowing base); 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 December 31, 2008, we were in compliance with the credit facility’s covenants. At December 31, 2008, we had $0.3 million in letters of credit outstanding.

Our interest expense is detailed in the following table:


	Year Ended
	December 31,
*Thousands of dollars*	2008
Credit facility	$	25,487
Commitment fees		1,047
Amortization of discount and deferred issuance costs		2,613

Total	$	29,147
Cash paid for interest on Credit facility (including realized losses on interest rate swaps)	$	29,767

12. 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. The total undiscounted amount of future cash flows required to settle our asset retirement obligations is estimated to be $256.8 million at December 31, 2008. 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. Changes in the asset retirement obligation for the year ended December 31, 2008 are presented in the following table:


	Year Ended December 31,
*Thousands of dollars*	2008
Carrying amount, beginning of period	$	27,819
Liabilities settled in the current period		(1,054	)
Revisions (1)		1,363
Acquisitions		—
Accretion expense		1,958


Carrying amount, end of period	$	30,086


(1)		Increased cost estimates and revisions to reserve life.

13. Partners’ Equity

At December 31, 2008, we had 52,635,634 Common Units outstanding.

On June 17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at $23.26 per unit, for a purchase price of approximately $335 million. These units have been cancelled and are no longer outstanding. This transaction was accounted for as a repurchase of issued Common Units and a cancellation of those Common Units. This transaction decreased equity by $336.2 million, including $1.2 million in capitalized transaction costs. We also purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management, which owned the General Partner. Also on June 17, 2008, we entered into a Contribution Agreement with the General Partner, BreitBurn Management and BreitBurn Corporation, pursuant to which BreitBurn Corporation contributed its 4.45 percent limited liability company interest in BreitBurn Management to us in exchange for 19,955 Common Units and BreitBurn Management contributed its 100 percent limited liability company interest in the General Partner to us. On the same date, we entered into Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of the Partnership, pursuant to which the economic portion of the General Partner’s 0.66473 percent general partner interest in us was eliminated. As a result of these transactions, the General Partner and BreitBurn Management became our wholly owned subsidiaries.

On December 22, 2008, we entered into a Unit Purchase Rights Agreement, dated as of December 22, 2008 (the “Rights Agreement”), between us and American Stock Transfer & Trust Company LLC, as Rights Agent. Under the Rights Agreement, each holder of Common Units at the close of business on December 31, 2008 automatically received a distribution of one unit purchase right (a “Right”), which entitles the registered holder to purchase from us one additional Common Unit at a price of $40.00 per Common Unit, subject to adjustment. We entered into the Rights agreement to increase the likelihood that our unitholders receive fair and equal treatment in the event of a takeover proposal.

The issuance of the Rights was not taxable to the holders of the Common Units, had no dilutive effect, will not affect our reported earnings per Common Unit, and will not change the method of trading the Common Units. The Rights will not trade separately from the Common Units unless the Rights become exercisable. The Rights will become exercisable if a person or group acquires beneficial ownership of 20 percent or more of the outstanding Common Units or commences, or announces its intention to commence, a tender offer that could result in beneficial ownership of 20 percent or more of the outstanding Common Units. If the Rights become exercisable, each Right will entitle holders, other than the acquiring party, to purchase a number of Common Units having a market value of twice the then-current exercise price of the Right. Such provision will not apply to any person who, prior to the adoption of the Rights Agreement, beneficially owns 20 percent or more of the outstanding Common Units until such person acquires beneficial ownership of any additional Common Units.

The Rights Agreement has a term of three years and will expire on December 22, 2011, unless the term is extended, the Rights are earlier redeemed or we terminate the Rights Agreement.

Cash Distributions

The partnership agreement requires us to distribute all of our available cash quarterly. Available cash is cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of reserves for future capital expenditures and operational needs. We may fund a portion of capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. The partnership agreement does not restrict our ability to borrow to pay distributions. The cash distribution policy reflects a basic judgment that unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.

Distributions are not cumulative. Consequently, if distributions on Common Units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future.

Distributions are paid within 45 days of the end of each fiscal quarter to holders of record on or about the first or second week of each such month. If the distribution date does not fall on a business day, the distribution will be made on the business day immediately preceding the indicated distribution date.

We do not have a legal obligation to pay distributions at any rate except as provided in the partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under the partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves the General Partner determines is necessary or appropriate to provide for the conduct of the business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters. The partnership agreement provides that any determination made by the General Partner in its capacity as general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity.

On February 14, 2008, we paid a cash distribution of approximately $30.5 million to our General Partner and common unitholders of record as of the close of business on February 11, 2008. The distribution that was paid to unitholders was $0.4525 per Common Unit.

On May 15, 2008, we paid a cash distribution of approximately $33.7 million to our General Partner and common unitholders of record as of the close of business on May 9, 2008. The distribution that was paid to unitholders was $0.50 per Common Unit.

On August 14, 2008, we paid a cash distribution of approximately $27.4 million to our common unitholders of record as of the close of business on August 11, 2008. The distribution that was paid to unitholders was $0.52 per Common Unit.

On November 14, 2008, we paid a cash distribution of approximately $27.4 million to our common unitholders of record as of the close of business on November 10, 2008. The distribution that was paid to unitholders was $0.52 per Common Unit.

During the year ended December 31, 2008, we made payments equivalent to the distributions made to unitholders of $2.3 million on Restricted Phantom Units and Convertible Phantom Units issued under our Long-Term Incentive Plans.

2007 Private Placements

On May 24, 2007, we sold 4,062,500 Common Units, at a negotiated purchase price of $32.00 per unit, to certain investors (the “Purchasers”). We used $108 million from such sale to fund the cash consideration for the Calumet Acquisition and the remaining $22 million of the proceeds was used to repay indebtedness under our credit facility. Most of the debt repaid was associated with our first quarter 2007 acquisition of the Lazy JL Field properties in West Texas.

On May 25, 2007, we sold an additional 2,967,744 Common Units to the same Purchasers at a negotiated purchase price of $31.00 per unit. We used the proceeds of approximately $92 million to fund the BEPI Acquisition, including the termination of existing hedge contracts related to future production from BEPI.

On November 1, 2007, we sold 16,666,667 Common Units, at a negotiated purchase price of $27.00 per unit, to certain investors in a third private placement. We used the proceeds from such sale to fund a portion of the cash consideration for the Quicksilver Acquisition. Also on November 1, 2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration for the Quicksilver Acquisition as a private placement.

In connection with the private placements of Common Units to finance the Quicksilver Acquisition, we entered into registration rights agreements with the institutional investors in our private placements and Quicksilver to file shelf registration statements to register the resale of the Common Units sold or issued in the Private Placements and to use our commercially reasonable efforts to cause the registration statements to become effective with respect to the Common Units sold to the institutional investors not later than August 2, 2008 and, with respect to the Common Units issued to Quicksilver, within one year from November 1, 2007. Quicksilver is prohibited from selling any of the Common Units issued to it prior to the first anniversary of November 1, 2007 or more than 50 percent of such Common Units prior to eighteen months after November 1, 2007. In addition, the agreements give the institutional investors and Quicksilver piggyback registration rights under certain circumstances. These registration rights are transferable to affiliates of the institutional investors and Quicksilver and, in certain circumstances, to third parties.

On July 31, 2008, the registration statement relating to the resale of the Common Units issued in the private placement to the institutional investors was declared effective. On October 28, 2008, the registration statement relating to the resale of the Common Units issued in the private placement to Quicksilver was declared effective.

14. Financial Instruments

Fair Value of Financial Instruments

Our commodity price risk management program is intended to reduce our exposure to commodity prices and to assist with stabilizing cash flow and distributions. Routinely, we utilize derivative financial instruments to reduce this volatility. During 2008, there has been extreme volatility and disruption in the capital and credit markets which has reached unprecedented levels and may adversely affect the financial condition of our derivative counterparties. Although each of our derivative counterparties carried an S&P credit rating of A or above at December 31, 2008, we could be exposed to losses if a counterparty fails to perform in accordance with the terms of the contract. This risk is managed by diversifying the derivative portfolio among counterparties meeting certain financial criteria.

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 SFAS No. 133. Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges and instead recognize changes in the fair value immediately in earnings. For the year ended December 31, 2008 we had realized losses of $55.9 million and unrealized gains of $388.0 million relating to our market based commodity contracts. We had net financial instruments receivable relating to our commodity contracts of $292.3 million at December 31, 2008.

On September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated our crude oil derivative instruments with Lehman Brothers. Our derivative contract with Lehman Brothers, commonly referred to as a “zero cost collar,” was for oil volumes of 1,000 Bbls/d for the full year 2011. This represented approximately 8 percent of our total 2011 oil and natural gas hedge portfolio. The floor price for the collar was $105.00 per Bbl and the ceiling price was $174.50 per Bbl. This contract was replaced with contracts by substantially similar terms, with different counterparties, for oil volumes of 1,000 Bbls/d covering January 1, 2011 to January 31, 2011 and March 1, 2011 to December 31, 2011.

We had the following contracts in place at December 31, 2008:


	Year			Year			Year			Year
	2009			2010			2011			2012
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMBtu/d)		45,802			43,869			25,955			19,129
Average Price ($/MMBtu)	$	8.14		$	8.20		$	9.21		$	10.12
Collars:
Hedged Volume (MMBtu/d)		1,740			3,405			16,016			19,129
Average Floor Price ($/MMBtu)	$	9.00		$	9.00		$	9.00		$	9.00
Average Ceiling Price ($/MMBtu)	$	16.36		$	12.79		$	11.28		$	11.89
Total:
Hedged Volume (MMMBtu/d)		47,542			47,275			41,971			38,257
Average Price ($/MMBtu)	$	8.17		$	8.26		$	9.13		$	9.56

Oil Positions:
Fixed Price Swaps:
Hedged Volume (Bbls/d)		1,838			2,308			2,116			1,939
Average Price ($/Bbl)	$	75.51		$	83.12		$	88.26		$	90.00
Participating Swaps: ^(a)
Hedged Volume (Bbls/d)		2,847			1,993			1,439			—
Average Price ($/Bbl)	$	62.86		$	64.40		$	61.29		$	—
Average Part. %		60.9	%		55.5	%		53.2	%		—
Collars:
Hedged Volume (Bbls/d)		594			1,279			2,048			3,077
Average Floor Price ($/Bbl)	$	92.31		$	102.84		$	103.43		$	110.00
Average Ceiling Price ($/Bbl)	$	122.92		$	136.16		$	152.61		$	145.39
Floors:
Hedged Volume (Bbls/d)		500			500			—			—
Average Floor Price ($/Bbl)	$	100.00		$	100.00		$	—		$	—
Total:
Hedged Volume (Bbls/d)		5,778			6,080			5,603			5,016
Average Price ($/Bbl)	$	73.12		$	82.52		$	86.88		$	102.27


(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 December 31, 2008, our total debt outstanding was $736.0 million. In order to mitigate our interest rate exposure, we had the following interest rate swaps in place at December 31, 2008, to fix a portion of floating LIBOR-base debt on our credit facility:


*Notional amounts in thousands of dollars*	Notional Amount		Fixed Rate
Period Covered
January 1, 2009 to January 8, 2009	$	50,000		3.6200	%
January 1, 2009 to January 20, 2009		200,000		3.6825	%
January 1, 2009 to July 8, 2009		50,000		3.0450	%
January 1, 2009 to January 8, 2010		100,000		3.3873	%
January 20, 2009 to July 20, 2009		250,000		3.6825	%
July 20, 2009 to December 20, 2010		300,000		3.6825	%
December 20, 2010 to October 20, 2011		200,000		2.9900	%

On September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated, at no cost, our interest rate swap with Lehman Brothers on $50 million at a fixed rate of 3.438 percent, which covered the period from January 8, 2008 to July 8, 2009. On October 2, 2008, we entered into a new interest rate swap on $50 million at a fixed rate of 3.0450 percent, for the period from September 8, 2008 to July 8, 2009. These transactions are reflected in the table above.

For the year ended December 31, 2008, we had realized losses of $2.7 million and unrealized losses of $17.3 million relating to our interest rate swaps. We had net financial instruments payable related to our interest rate swaps of $17.3 million at December 31, 2008.

Balance Sheet presentation of commodity and interest derivatives is as follows:


	Oil			Natural Gas
	Commodity			Commodity		Interest Rate			Total Financial
*Thousands of dollars*	Derivatives			Derivatives		Derivatives			Instruments
Balance, December 31, 2008
Short-term assets	$	44,086		$	32,138	$	—		$	76,224
Long-term assets		145,061			73,942		—			219,003

Total assets		189,147			106,080		—			295,227

Short-term liabilities		(1,115	)		—		(9,077	)		(10,192	)
Long-term liabilities		(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

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.

Effective January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value measurement under SFAS No. 157 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 SFAS No. 157 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.

SFAS No. 157 requires valuation techniques consistent with the market approach, income approach or the 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.

SFAS No. 157 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 SFAS No. 157 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 SFAS 157. As of December 31, 2008, our Level 3 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 7, our wholly owned subsidiary BreitBurn Management provides us with general management services, including risk management activities. Pursuant to a transition services agreement that terminated on December 31, 2008, BreitBurn Management contracted with Provident for the risk management 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 were also 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 used 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 included 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 were 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 receive 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.

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 were:


	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 of our derivative instruments classified as Level 3:


	Year Ended
*Thousands of dollars*	December 31, 2008
Assets (Liabilities):
Beginning balance	$	44,236
Realized and unrealized gains, net		106,154
Purchases and issuances		7,452
Settlements		(4,624	)

Balance at December 31, 2008	$	153,218

Following the termination of the Lehman Brothers interest rate swap and crude oil zero cost collar, we entered into similar contracts with other counterparties. Our net cost to replicate the terminated Lehman contracts was $4.2 million and we have recorded a provision related to the contract default in 2008. We have a claim of approximately $4.6 million in the Lehman bankruptcy case relating to the terminations.

Unrealized gains of $112.2 million for the year ended December 31, 2008 related to our derivative instruments classified as Level 3 are included in gains on commodity derivative instruments, net on the consolidated statements of operations. Realized losses of $6.0 million for the year ended December 31, 2008 related to our derivative instruments classified as Level 3 are also included in gains on commodity derivative instruments, net on the consolidated statements of operations. Determination of fair values incorporates various factors as required by SFAS No. 157 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

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. 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 $775,000 for indirect expenses. In addition to the monthly fee, BreitBurn Management agreed to continue to charge BEC for direct expenses including incentive plan costs and direct payroll and administrative costs. Beginning on June 17, 2008, all of BMC’s costs that were not charged to BEC are consolidated with our results.

Prior to June 17, 2008, BreitBurn Management provided services to us and to BEC, and allocated its expenses between the two entities. We were managed by our General Partner, the executive officers of which were and are employees of BreitBurn Management. We had entered into an Administrative Services Agreement with BreitBurn Management. Under the Administrative Services Agreement, we reimbursed BreitBurn Management for all direct and indirect expenses it incurred in connection with the services it performed on our behalf (including salary, bonus, certain incentive compensation and other amounts paid to executive officers and other employees).

Effective on the initial public offering date of October 10, 2006, BreitBurn Management adopted the existing Long-Term Incentive Plan (BreitBurn Management LTIP) and the Unit Appreciation Rights Plan (UAR plan) of the predecessor as previously amended. The predecessor’s Executive Phantom Option Plan, Unit Appreciation Plan for Officers and Key Individuals (Founders Plan), and the Performance Trust Units awarded to the Chief Financial Officer during 2006 under the BreitBurn Management LTIP, were adopted by BreitBurn Management with amendments at the initial public offering date as described in the subject plan discussions below.

We may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. We also have the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the Common Units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire when units are no longer available under the plan for grants or, if earlier, its termination by us.

Unit Based Compensation

Effective January 1, 2006, our predecessor adopted the fair value recognition provisions of SFAS No. 123(R), Share-Based Payments , using the modified-prospective transition method. BreitBurn Management as successor is following the same method as BEC, our predecessor. Unit based compensation awards granted prior to but not yet vested as of January 1, 2006 that are classified as liabilities were charged to compensation expense based on the fair value provisions of SFAS No. 123(R). For the liability-based plans, we recognize these compensation expenses on a graded-vesting method. Under the graded-vesting method, a company recognizes compensation expense over the requisite service period for each separately vesting tranche of the award as though the award were, in substance, multiple awards. For our RPU and CPU equity-based plans, we recognize our compensation expense on a straight line basis over the annual vesting periods as prescribed in the award agreements.

Awards classified as liabilities are revalued at each reporting period using the Black-Scholes option pricing model and changes in the fair value of the options are recognized as compensation expense over the vesting schedules of the awards. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period(s). Option awards outstanding at the end of 2008 are liability-classified because the awards are settled in cash or have the option of being settled in cash or units at the choice of the holder, and they are indexed to either our Common Units or to Provident Trust Units. The liability-classified option awards are distribution-protected awards through either an Adjustment Ratio as defined in the plan or the holders receive cumulative distribution amounts upon vesting equal to the actual distribution amounts per Common Unit of the underlying notional Units. In the Black-Scholes option pricing model, the expected volatilities are based primarily on the historical volatility of Provident’s units for Provident indexed units and the Alerian MLP Index for Partnership indexed units. We and our predecessor use historical data to estimate option exercises and employee terminations within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding. The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates. Due to the distribution protection provision of the plans, zero distribution yield is assumed in the pricing model; however, compensation cost is recognized based on the units adjusted for the Adjustment Ratio and for certain plans, it includes distribution amounts accumulated to the reporting date.

Founders Plan

Under the Founders Plan, participants received unit appreciation rights which provide cash compensation in relation to the appreciation in the value of a specified number of underlying notional phantom units. The value of the unit appreciation rights was determined on the basis of a valuation of the predecessor at the end of the fiscal period plus distributions during the period less the value of the predecessor at the beginning of the period. The base price and vesting terms were determined by BreitBurn Management at the time of the grant. Outstanding unit appreciation rights vest in the following manner: one-third vest three years after the grant date, one-third vest four years after the grant date and one-third vest five years after the grant date and are subject to specified service requirements.

Effective on the initial public offering date of October 10, 2006, all outstanding unit appreciation rights under the Founders Plan were adopted by BreitBurn Management and converted into three separate awards. The first award represented 2.2 million unit appreciation rights at a weighted average grant price of $0.76 per unit with respect to the operations of the properties that were not transferred to us. The value of these unit appreciation rights at year-end 2006 was determined on the basis of an assessment of the valuation of the properties at the original grant date as compared to an assessment of the valuation of the properties at the end of the fiscal period plus distributions paid. The second award represented 309,570 unit appreciation rights at a weighted average grant price of $4.70 per unit with respect to the operations of the properties that were transferred to us for the period from the original date of grant to the initial public offering date of October 10, 2006. The value of the unit appreciation rights was determined on the basis of an assessment of the valuation of the properties at the original grant date as compared to the valuation of the properties at the end of the fiscal period as determined using the initial public offering price plus distributions paid.

The third award represented 309,570 Partnership unit appreciation rights at a base price of $18.50 per unit with respect to the operations of the properties that were transferred to us for the period beginning on the initial public offering date of October 10, 2006. The award is liability-classified and is being charged to us as compensation expense over the remaining vesting schedule. The value of the outstanding Partnership unit appreciation rights is remeasured each period using a Black-Scholes option pricing model. A market prices of $7.05 was used in the model for the period ending December 31, 2008. Expected volatility ranged from 9 percent to 21 percent and had a weighted average volatility of 9.8 percent. The average risk free rate used was approximately 3.3 percent. The expected option terms ranged from one half year to two and one half years.

We recorded approximately $(0.3) million of compensation expense/(income) under the plan for the year ended December 31, 2008. The aggregate value of the vested unit appreciation rights was $0.4 million and the unvested obligation was zero at December 31, 2008.

The following table summarizes information about Appreciation Rights Units issued under the Founders Plan:


	December 31, 2008
	Number of			Weighted
	Appreciation			Average
	Rights Units			Exercise Price
Outstanding, beginning of period		214,107		$	18.50
Exercised		(91,463	)		18.50

Outstanding, end of period		122,644		$	18.50


Exercisable, end of period		—		$	—

BreitBurn Management LTIP and the Partnership LTIP

In September 2005, certain employees of the predecessor were granted restricted units (RTUs) and/or performance units (PTUs), both of which entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units indexed to Provident Energy Trust Units. The grants are based on personal performance objectives. This plan replaced the Unit Appreciation Right Plan for Employees and Consultants for the period after September 2005 and subsequent years. RTUs vest one third at the end of year one, one third at end of year two and one third at the end of year three after grant. In general, cash payments equal to the value of the

underlying notional units were made on the anniversary dates of the RTU to the employees entitled to receive them. PTUs vest three years from the end of third year after grant and payout can range from zero to two hundred percent of the initial grant depending on the total return of the underlying notional units as compared to the returns of selected peer companies. The total return of the Provident Energy Trust unit is compared with the return of 25 selected Canadian trusts and funds. The Provident indexed PTUs granted in 2005 and 2006 entitle employees to receive cash payments equal to the market price of the underlying notional units. Under our LTIP, Partnership indexed PTUs were granted in 2007 and are payable in cash or may be paid in Common Units of the Partnership if elected at least 60 days prior to vesting by the grantees. The total return of the Partnership unit is compared with the return of 49 companies in the Alerian MLP Index for the payout multiplier. All of the grants are liability-classified. Underlying notional units are established based on target salary LTIP threshold for each employee. The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio. The estimated fair value associated with RTUs and PTUs is expensed in the statement of income over the vesting period.

On June 17, 2008, we entered into the BreitBurn Management Purchase agreement with Pro LP and Pro GP. The BreitBurn Management Purchase Agreement contains certain covenants of the parties relating to the allocation of responsibility for liabilities and obligations under certain pre-existing equity-based compensation plans adopted by BreitBurn Management, BEC and us. The pre-existing compensation plans include the outstanding 2005 and 2006 LTIP grants which are indexed to the Provident Trust Units. As a result, we paid $0.9 million for our share of the 2005 LTIP grants that vested in June 2008 in accordance with the agreed allocation of liability.

In September 2008, BreitBurn Management made an offer to holders of the 2006 LTIP grants to cash out their Provident-indexed units at $10.32 per share before the normal vesting date of December 31, 2008. By the end of September 2008, the offer was accepted by all employees who had outstanding 2006 LTIP grants. Consequently, compensation expense was recognized for the full amount of the remaining unvested liability during 2008. BreitBurn Management paid employees $0.6 million in 2008 for its share of the 2006 LTIP grants in accordance with the agreed allocation of liability.

Under our LTIP, Partnership-indexed restricted units (RTUs) and/or performance units (PTUs) were granted in 2007 and are payable in cash or in Common Units of the Partnership if elected by the grantee at least 60 days prior to the vesting date. For PTUs, a performance multiplier is applied and is determined by comparing our total return to the returns of 49 companies in the Alerian MLP Index. All of the grants are liability-classified. Underlying notional units are established based on target salary LTIP threshold for each employee. The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio. The estimated fair value associated with RTUs and PTUs is expensed in the statement of income over the vesting period.

We recognized $(0.5) of compensation expense/(income) for the year ended December 31, 2008. Our share of the aggregate liability under the BreitBurn Management LTIP was $0.8 million at December 31, 2008. The aggregate value of the vested and unvested units under the plan was $0.6 million and $0.2 million respectively, at December 31, 2008.

The following table summarizes information at December 31, 2008 about the restricted/performance units granted in 2005 and 2006:


				Weighted
	Number of			Average
	Units			Grant Price
Outstanding, beginning of period		267,702		$	10.77
Granted		—			—
Exercised		(267,351	)		10.77
Cancelled		(351	)		10.73

Outstanding, end of period		—		$	10.77


Exercisable, end of period		—		$	—

The following table summarizes information about the restricted/performance units granted in 2007. A market price of $7.05 was used in the model for the period ending December 31, 2008. Expected volatility ranged from 9

percent to 15 percent and had a weighted average volatility of 9.8 percent. The average risk free rate ranged from 2 to 3.3 percent. The expected option terms ranged from one year to two years.


	PTUs and RTUs
	December 31, 2008
				Weighted
	Number of			Average
	Units			Grant Price
Outstanding, beginning of period		108,717		$	23.64
Granted		—			—
Exercised		(20,645	)		20.39
Cancelled		(1,080	)		24.10

Outstanding, end of period		86,992		$	24.10


Exercisable, end of period		—		$	—

Unit Appreciation Right Plan

In 2004, the predecessor adopted the Unit Appreciation Right Plan for Employees and Consultants (the “UAR Plan”). Under the UAR Plan, certain employees of the predecessor were granted unit appreciation rights (“UARs”). The UARs entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units of Provident (“Phantom Units”). The exercise price and the vesting terms of the UARs were determined at the sole discretion of the Plan Administrator at the time of the grant. The UAR Plan was replaced with the BreitBurn Management LTIP at the end of September 2005. The grants issued prior to the replacement of the UAR Plan fully vested in 2008.

UARs vest one third at the end of year one, one third at the end of year two and one third at the end of year three after grant. Upon vesting, the employee is entitled to receive a cash payment equal to the excess of the market price of Provident Energy Trust’s units (PVE units) over the exercise price of the Phantom Units at the grant date, adjusted for an additional amount equal to any Excess Distributions, as defined in the plan. The predecessor settles rights earned under the plan in cash.

The total compensation expense for the UAR plan is allocated between us and our predecessor. Our share of expense was an immaterial amount in 2008 under the UAR Plan. Our share of the aggregate liability under the UAR Plan was approximately $0.1 million at December 31, 2008. The liability primarily represents accrued expense related to unpaid distributions on the fully vested UARs. In the Black-Scholes option pricing model for this plan, the expected volatility used was 29 percent and the risk rate was 3.3 percent. The expected option term is less than one half year.

The following table summarizes the information about UARs:


	BreitBurn Management Company
	PVE indexed units
	December 31, 2008
	Number of			Weighted
	Appreciation			Average
	Rights			Exercise Price
Outstanding, beginning of period		154,323		$	9.16
Exercised		(69,994	)		9.18
Cancelled		—			—

Outstanding, end of period		84,329		$	9.96


Exercisable, end of period		84,329		$	9.96

Director Performance Units

Effective with the initial public offering, we also made grants of Restricted Phantom Units in the Partnership to the non-employee directors of our General Partner. Each phantom unit is accompanied by a distribution equivalent unit right entitling the holder to an additional number of

phantom units with a value equal to the amount of distributions paid on each of our Common Units until settlement. Upon vesting, the majority of the phantom units will be paid in Common Units, except for certain directors’ awards which will be settled in cash. The unit-settled awards are classified as equity and the cash-settled awards are classified as liabilities. The estimated fair value associated with these phantom units is expensed in the statement of income over the vesting period. The accumulated compensation expense for unit-settled awards is reported in equity and for cash-settled grants, it is reflected as a liability on the consolidated balance sheet.

We recorded compensation expense for the director’s phantom units of approximately $0.1 million in 2008. Our aggregate liability under the outstanding grants was $0.8 million at December 31, 2008 of which $0.4 million represents the unvested portion.

The following table summarizes information about the Director Performance Units:


	December 31, 2008
	Number of			Weighted
	Performance			Average
	Units			Grant Price
Outstanding, beginning of period		37,473		$	21.11
Granted		20,146			27.35
Exercised		(22,190	)		23.05

Outstanding, end of period		35,429		$	23.44


Exercisable, end of period		—		$	—

Restricted Phantom Units and Convertible Phantom Units

In connection with the changes to BreitBurn Management’s executive compensation program, the board of directors of our General Partner has approved two new types of awards under our LTIP, namely, Restricted Phantom Units (RPUs) and Convertible Phantom Units (CPUs). In December 2007, seven executives of our General Partner received 188,545 units of RPUs and 681,500 units of CPUs at a grant price of $30.29 per Common Unit. Each of the awards has the vesting commencement date of January 1, 2008. In November 2007, the Co-Chief Executive Officers also received 184,400 of Restricted Phantom Units (RPUs) at a grant price of $31.68 per Common Unit under our Long-Term Incentive Plan. Those executive officers received CPU grants because they are in the best position to influence our operating results and, therefore, the amount of distributions we make to holders of our Common Units. As discussed below, payments under CPUs are significantly tied to the amount of distributions we make to holders of our Common Units. As discussed further below, the number of CPUs ultimately awarded to each of these senior executives is based upon the level of distributions to common unitholders achieved during the term of the CPUs. The CPU grants vest over a longer-term period of up to five years. Therefore, these grants will not be made on an annual basis. New grants could be made at the board’s discretion at a future date after the present CPU grants have vested. A holder of an RPU is entitled to receive payments equal to quarterly distributions in cash at the time they are made. As a result, we believe that RPUs better incentivize holders of these awards to grow stable distributions for our common unitholders than do performance units. In 2008, the board of directors of the General Partner granted 245,290 RPUs to employees at a weighted average price of $20.44.

Restricted Phantom Units (RPUs). RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual partnership units upon specified payment events. RPUs generally vest in three equal, annual installments on each anniversary of the vesting commencement date of the award. In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period. RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment.

Convertible Phantom Units (CPUs). CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the holder’s employment agreement, if applicable). Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management.

Prior to vesting, a holder of a CPU is entitled to receive payments equal to the amount of distributions made by us with respect to each of the Common Units multiplied by the number of Common Unit equivalents underlying the CPUs at the time of the distribution. Initially, one Common Unit equivalent underlies each CPU at the time it was awarded to the grantee. However, the number of Common Unit equivalents underlying the CPUs increase at a compounded rate of 25 percent upon the achievement of each 5 percent compounded increase in the distributions paid by us to our common unitholders. Conversely, the number of Common Unit equivalents underlying the CPUs decrease at a compounded rate of 25 percent if the distributions paid by us to our common unitholders decreases at a compounded rate of 5 percent.

In the event that the CPUs vest on January 1, 2013 or because the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than $3.10 per Common Unit, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time (calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters).

In the event that CPUs vest due to the death or disability of the grantee or his or her termination without cause or good reason, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time, pro-rated based on when the death or disability occurred. First, the number of Common Unit equivalents would be calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters or, if such calculation would provide for a greater number of Common Unit equivalents, the most recently announced quarterly distribution level by us on an annualized basis. Then, this number would be pro rated by multiplying it by a percentage equal to:

	•		if such termination occurs on or before December 31, 2008, a percentage equal to 40 percent;

	•		if such termination occurs on or before December 31, 2009, a percentage equal to 60 percent;

	•		if such termination occurs on or before December 31, 2010, a percentage equal to 80 percent; and

	•		if such termination occurs on or after January 1, 2011, a percentage equal to 100 percent.

In 2008, we recognized compensation expense of $7.5 million related to its CPUs and RPUs.

The following table summarizes information about the CPUs and RPUs for the year ended December 31, 2008:


	Number of			Weighted
	RPU			Average
	Units			Grant Price
Outstanding, beginning of period (a)		372,945		$	30.98
Granted		245,290			20.44
Cancelled		(10,972	)		20.83

Outstanding, end of period		607,263		$	26.91


Exercisable, end of period		—		$	—

16. Commitments and Contingencies

Lease Rental Obligations

We had operating leases for office space and other property and equipment having initial or remaining noncancelable lease terms in excess of one year. Our future minimum rental payments for operating leases at December 31, 2008 are presented below:


	Payments Due by Year
*Thousands of dollars*	2009		2010		2011		2012		2013		after 2013		Total
Operating leases	$	2,232	$	2,126	$	1,989	$	1,656	$	1,272	$	2,143	$	11,418

BreitBurn Management, our wholly owned subsidiary, has office, vehicle (primarily work vehicles used in our field operations) and office equipment leases. Net rental payments made under non-cancelable operating leases were $2.88 million in 2008.

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 December 31, 2008, we had $10.1 million in surety bonds and we had $0.3 million in letters of credit outstanding.

Other

On October 31, 2008, Quicksilver, an owner of more than five 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 December 12, 2008, Quicksilver filed an 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 temporary and 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. The parties to the lawsuit are engaged in discovery pursuant to an agreed scheduling order. On February 17, 2009, we filed a motion for summary judgment which is scheduled to be heard on March 26, 2009. A hearing on Quicksilver’s request for a temporary injunction is scheduled for April 6, 2009.

We are defending ourselves vigorously in connection with the allegations in the lawsuit. Because this lawsuit still is at an early 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.

17. Retirement Plan

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. BreitBurn Management has a defined contribution retirement plan, which covers substantially all of its employees who have completed at least three months of service. The plan provides for BreitBurn Management to make regular contributions based on employee contributions as provided for in the plan agreement. Employees fully vest in BreitBurn Management’s contributions after five years of service. BEC is charged for a portion of the matching contributions made by BreitBurn Management. For the year ended December 31, 2008, the matching contribution paid by us was $0.4 million.

18. Significant Customers

We sell oil, natural gas and natural gas liquids primarily to large domestic refiners. For the year ended December 31, 2008, our purchasers which accounted for 10 percent or more of net sales were ConocoPhillips which accounted for 25 percent of net sales and Marathon Oil Company which accounted for 13 percent of net sales.

19. Minority Interest

On May 25, 2007, BOLP entered into a Purchase and Sale Agreement with TIFD X-III LLC (“TIFD”), pursuant to which it acquired TIFD’s 99 percent limited partner interest in BreitBurn Energy Partners I, L.P. (“BEPI”) for a total purchase price of approximately $82 million (the “BEPI Acquisition”). As such, we are fully consolidating the results of BEPI and thus are recognizing a minority interest liability representing the book value of the general partner’s interests. At December 31, 2008, the amount of this minority interest liability was $0.5 million. The general partner of BEPI holds a 35 percent reversionary interest under the existing limited partnership agreement applicable to the properties. Based on year end price and cost projections, the reversionary interest payout is not expected to occur.

20. Subsequent Events

On January 22, 2009, we terminated a portion of our 2011 and 2012 crude oil swaps (1,939 Bbls/d at $90.00 per Bbl) and replaced them with new contracts with the same counterparty for the same volumes at market prices ($63.30 per Bbl). We realized $32.3 million from this termination. On January 26, 2009, we terminated a portion of our 2011 and 2012 natural gas swaps 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 debt.

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. In February 2009 we also made payments equivalent to the distribution made to unitholders of $0.7 million on Restricted Phantom Units and Convertible Phantom Units issued under our Long-Term Incentive Plans.

On February 19, 2009, 134,377 Common Units were issued to employees under our 2006 Long-Term Incentive Plan, increasing our outstanding Common Units to 52,770,011. See Note 15 for information regarding our unit based compensation plans.

21. Oil and Natural Gas Activities (Unaudited)

Costs incurred

Our oil and natural gas activities are conducted in the United States. The following table summarizes the costs incurred by us for the year ended December 31, 2008:


*Thousands of dollars*
Property acquisition costs
Proved	$	—
Unproved		—
Development costs		129,503
Asset retirement costs		1,363
Pipelines and processing facilities		—

Total	$	130,866

Capitalized costs

The following table presents the aggregate capitalized costs subject to depreciation, depletion and amortization relating to oil and gas activities, and the aggregate related accumulated allowance for the year ended December 31, 2008.



*Thousands of dollars*
Proved properties and related producing assets	$	1,734,932
Pipelines and processing facilities		112,726
Unproved properties		209,873
Accumulated depreciation, depletion and amortization		(223,575	)

	$	1,833,956

The average DD&A rate per equivalent unit of production for the year ended December 31, 2008 was $26.42 per Boe.

Results of operations for oil and gas producing activities

The results of operations from oil and gas producing activities below exclude non-oil and gas revenues and expenses, general and administrative expenses, interest expenses and interest income for the year ended December 31, 2008.




*Thousands of dollars*
Oil, natural gas and NGL sales	$	467,381
Realized loss on derivative instruments		(55,946	)
Unrealized gain on derivative instruments		388,048
Operating costs		(149,681	)
Depreciation, depletion, and amortization		(178,657	)
Pre-tax Income		471,145
Income tax expense		1,939

Results of producing operations	$	469,206

Supplemental reserve information

The following information summarizes our estimated proved reserves of oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the year ended December 31, 2008. The following reserve information is based upon reports by Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services, independent petroleum engineering firms. The estimates are prepared in accordance with SEC regulations.

Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of the estimated proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are

ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure of discounted net future cash flows shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Decreases in the prices of oil and natural gas and increases in operating expenses have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and revenues, profitability and cash flow.

The following table sets forth certain data pertaining to our estimated proved and proved developed reserves for the year ended December 31, 2008.


	Oil			Gas
*In Thousands*	(MBbl)			(MMcf)
Proved Reserves
Beginning balance		58,095			505,069
Revision of previous estimates ^(a)		(29,106	)		(16,251	)
Production		(3,079	)		(22,384	)


Ending balance		25,910			466,434

Proved Developed Reserves

Beginning balance		52,103			457,444
Ending balance		23,346			433,780


(a)		Additions due to infill drilling are classified in Revisions and were approximately 741 MBbl for oil and 35,834 MMcf for natural gas in 2008.

Standardized measure of discounted future net cash flows

The Standardized Measure of discounted future net cash flows relating to our estimated proved crude oil and natural gas reserves as of December 31, 2008 is presented below:


*Thousands of dollars*
Future cash inflows		3,523,524
Future development costs		(212,951	)
Future production expense		(1,843,986	)

Future net cash flows		1,466,587
Discounted at 10% per year		(874,327	)

Standardized measure of discounted future net cash flows	$	592,260

The standardized measure of discounted future net cash flows discounted at ten percent from production of proved reserves was developed as follows:

	1.		An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

	2.		In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our estimated proved properties and the present value thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. We have entered into various arrangements to fix or limit the prices relating to a portion of our oil and gas production. Arrangements in effect at December 31, 2008 are discussed in Note 14. Such risk management arrangements are not reflected in the reserve reports. Representative market prices at the as-of date for the reserve reports as of December 31, 2008 were $44.60 ($20.12 for Wyoming), per barrel of oil, and $5.71, per MMBTU of gas.

	3.		The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs. Future net cash flows assume no future income tax expense as we are essentially a non-taxable entity except for two tax paying corporations whose future income tax liabilities on a discounted basis are insignificant.

The principal sources of changes in the Standardized Measure of the future net cash flows for the year ended December 31, 2008 is presented below:


*Thousands of dollars*
*Beginning balance*	$	1,912,467
Sales, net of production expense		(317,700	)
Net change in sales and transfer prices, net of production expense		(1,306,752	)
Previously estimated development costs incurred during year		57,694
Changes in estimated future development costs		(98,064	)
Extensions, discoveries and improved recovery, net of costs		—
Purchase of reserves in place		—
Revision of quantity estimates and timing of estimated production		153,368
Accretion of discount		191,247

*Ending balance*	$	592,260

22. Quarterly Financial Data (Unaudited)


	Year Ended December 31, 2008
	First			Second			Third		Fourth
*Thousands of dollars*	Quarter			Quarter			Quarter		Quarter
Oil, natural gas and natural gas liquid sales	$	115,849		$	139,962		$	130,249	$	81,321
Gains (losses) on derivative instruments		(83,387	)		(353,282	)		407,441		361,330
Other revenue, net		875			643			806		596

Total revenue	$	33,337		$	(212,677	)	$	538,496	$	443,247

Operating income (loss) (1)		(34,455	)		(282,267	)		468,625		277,451

Net income (loss) (1)		(41,140	)		(286,240	)		454,454		251,162


Exhibits


Exhibit No.			Sequential Description

	**2	.1	Contribution Agreement, dated September 11, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference.)
	**2	.2	Purchase and Sale Agreement, dated as of July 3, 2008, among Nortex Minerals, L.P., Petrus Investment, L.P., Petrus Development, L.P., and Perot Investment Partners, Ltd., as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.1 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).
	**2	.3	Purchase and Sale Agreement, dated as of July 3, 2008, among Hillwood Oil & Gas, L.P., Burtex Minerals, L.P., Chief Resources, LP, Hillwood Alliance Operating Company, L.P., Chief Resources Alliance Pipeline LLC, Chief Oil & Gas LLC, Berry Barnett, L.P., Collins and Young, L.L.C. and Mark Rollins, as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.2 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).
	3	.1	Amended and Restated Certificate of Incorporation of Quicksilver Resources Inc. filed with the Secretary of State of the State of Delaware on May 21, 2008 (filed as Exhibit 4.1 to the Company’s Form S-3, File No. 333-151847, filed June 23, 2008 and included herein by reference).
	3	.2	Amended and Restated Certificate of Designation of Series A Junior Participating Preferred Stock of Quicksilver Resources Inc. (filed as Exhibit 3.3 to the Company’s Form 10-Q filed May 6, 2006 and included herein by reference).
	3	.3	Amended and Restated Bylaws of Quicksilver Resources Inc. (filed as Exhibit 3.1 to the Company’s Form 8-K filed November 16, 2007 and included herein by reference).
	4	.1	Indenture Agreement for 1.875% Convertible Subordinated Debentures Due 2024, dated as of November 1, 2004, between Quicksilver Resources Inc., as Issuer, and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 8-K filed November 1, 2004 and included herein by reference).
	4	.2	Indenture, dated as of December 22, 2005, between Quicksilver Resources Inc. and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.7 to the Company’s Form S-3, File No. 333-130597, filed December 22, 2005 and included herein by reference).
	4	.3	First Supplemental Indenture, dated as of March 16, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 8-K filed March 21, 2006 and included herein by reference).
	4	.4	Third Supplemental Indenture, dated as of September 26, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 10-Q filed November 7, 2006 and included herein by reference).
	4	.5	Fifth Supplemental Indenture, dated as of June 27, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed June 530, 2008 and included herein by reference).
	4	.6	Sixth Supplemental Indenture, dated as of July 10, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed July 10, 2008 and included herein by reference).


Exhibit No.			Sequential Description

	4	.7	Amended and Restated Rights Agreement, dated as of December 20, 2005, between Quicksilver Resources Inc. and Mellon Investor Services LLC, as Rights Agent (filed as Exhibit 4.1 to the Company’s Form 8-A/A (Amendment No. 1) filed December 21, 2005 and included herein by reference).
	10	.1	Master Gas Purchase and Sale Agreement, dated March 1, 1999, between Quicksilver Resources Inc. and Reliant Energy Services, Inc. (filed as Exhibit 10.10 to the Company’s Form S-1, File No. 333-89229, filed November 1, 2004 and included herein by reference).
	10	.2	Wells Agreement dated as of December 15, 1970, between Union Oil Company of California and Montana Power Company (filed as Exhibit 10.5 to the Company’s Predecessor, MSR Exploration Ltd.’s Form S-4/A, File No. 333-29769, filed August 21, 1997 and included herein by reference).]
	+ 10	.3	Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.4	Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
	+ 10	.5	Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
	+ 10	.6	Form of Retention Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
	+ 10	.7	Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
	+ 10	.8	Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).
	+ 10	.9	Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
	+ 10	.10	Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 18, 2005 and included herein by reference).
	+ 10	.11	Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.12	Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.13	Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.14	Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement (Cash Settlement) pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.15	Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement (Stock Settlement) pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).


Exhibit No.			Sequential Description

	+ 10	.16	Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.5 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.17	Form of Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.18	Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (One-Year Vesting) (filed as Exhibit 10.8 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.19	Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.5 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.20	Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (One-Year Vesting) (filed as Exhibit 10.7 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.21	Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).
	+ 10	.22	Description of Non-Employee Director Compensation for Quicksilver Resources Inc. (filed as Exhibit 10.11 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.23	Quicksilver Resources Inc. 2007 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed April 16, 2007 and included herein by reference).
	+ 10	.24	Description of 2007 Cash Bonus (filed as Exhibit 10.3 to the Company’s Form 10-Q filed May 9, 2007 and included herein by reference).
	+ 10	.25	Quicksilver Resources Inc. 2008 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed December 14, 2007 and included herein by reference).
	+ 10	.26	Quicksilver Resources Inc. 2009 Executive Bonus Plan (filed as Exhibit 10.10 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.27	Quicksilver Resources Inc. Amended and Restated Change in Control Retention Incentive Plan (filed as Exhibit 10.9 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.28	Quicksilver Resources Inc. Second Amended and Restated Key Employee Change in Control Retention Incentive Plan (filed as Exhibit 10.8 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.29	Quicksilver Resources Inc. Amended and Restated Executive Change in Control Retention Incentive Plan (filed as Exhibit 10.7 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.30	Form of Director and Officer Indemnification Agreement (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 26, 2005 and included herein by reference).
	10	.31	Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Inc. and the lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed February 12, 2007 and included herein by reference).
	10	.32	Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Canada Inc. and the lenders and/or agents identified therein (filed as Exhibit 10.2 to the Company’s Form 8-K filed February 12, 2007 and included herein by reference).


Exhibit No.			Sequential Description

	10	.33	Fourth Amendment to Combined Credit Agreements, dated as of June 20, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 25, 2008 and included herein by reference).
	10	.34	Fifth Amendment to Combined Credit Agreements, dated as of August 4, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 5, 2008 and included herein by reference).
	10	.35	Credit Agreement, dated as of August 8, 2008, among Quicksilver Resources Inc., the lenders party thereto and Credit Suisse, Cayman Islands Branch, as administrative agent (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 8, 2008 and included herein by reference).
	10	.36	Registration Rights Agreement, dated as of November 1, 2007, between Quicksilver Resources Inc. and BreitBurn Energy L.P. (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference).
	+10	.37	2007 Equity Plan (filed as Exhibit 99.1 to Quicksilver Gas Services LP’s Form S-8, File No. 333-145326, filed August 10, 2007 and included herein by reference).
	+10	.38	Form of Phantom Unit Award Agreement for Non-Directors (Cash) (filed as Exhibit 10.10 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference).
	+10	.39	Form of Phantom Unit Award Agreement for Non-Directors (Units) (filed as Exhibit 10.11 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 25, 2007 and included herein by reference).
	+10	.40	Quicksilver Gas Services LP Annual Bonus Plan (filed as Exhibit 10.1 to Quicksilver Gas Services LP’s Form 8-K, File No. 001-33631, filed December 13, 2007 and included herein by reference).
	+10	.41	Form of Indemnification Agreement by and between Quicksilver Gas Services GP LLC and its officers and directors (filed as Exhibit 10.7 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference).
	*** 21	.1	List of subsidiaries of Quicksilver Resources Inc.
	*** 23	.1	Consent of Deloitte & Touche LLP.
	*** 23	.2	Consent of Schlumberger Data and Consulting Services.
	*** 23	.3	Consent of LaRoche Petroleum Consultants, Ltd.
	* 23	.4	Consent of Schlumberger Data and Consulting Services
	* 23	.5	Consent of Netherland, Sewell & Associates, Inc.
	* 23	.6	Consent of PricewaterhouseCoopers LLP
	*** 24	.1	Power of Attorney
	* 31	.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	* 31	.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	* 32	.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Filed herewith.

**		Excludes schedules and exhibits we agree to furnish supplementally to the SEC upon request.

***		Filed with the Company’s original Annual Report on Form 10-K filed on March 3, 2009.

+		Identifies management contracts and compensatory plans or arrangements.

Exhibit Index


Exhibit No.			Sequential Description

	**2	.1	Contribution Agreement, dated September 11, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference.)
	**2	.2	Purchase and Sale Agreement, dated as of July 3, 2008, among Nortex Minerals, L.P., Petrus Investment, L.P., Petrus Development, L.P., and Perot Investment Partners, Ltd., as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.1 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).
	**2	.3	Purchase and Sale Agreement, dated as of July 3, 2008, among Hillwood Oil & Gas, L.P., Burtex Minerals, L.P., Chief Resources, LP, Hillwood Alliance Operating Company, L.P., Chief Resources Alliance Pipeline LLC, Chief Oil & Gas LLC, Berry Barnett, L.P., Collins and Young, L.L.C. and Mark Rollins, as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.2 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).
	3	.1	Amended and Restated Certificate of Incorporation of Quicksilver Resources Inc. filed with the Secretary of State of the State of Delaware on May 21, 2008 (filed as Exhibit 4.1 to the Company’s Form S-3, File No. 333-151847, filed June 23, 2008 and included herein by reference).
	3	.2	Amended and Restated Certificate of Designation of Series A Junior Participating Preferred Stock of Quicksilver Resources Inc. (filed as Exhibit 3.3 to the Company’s Form 10-Q filed May 6, 2006 and included herein by reference).
	3	.3	Amended and Restated Bylaws of Quicksilver Resources Inc. (filed as Exhibit 3.1 to the Company’s Form 8-K filed November 16, 2007 and included herein by reference).
	4	.1	Indenture Agreement for 1.875% Convertible Subordinated Debentures Due 2024, dated as of November 1, 2004, between Quicksilver Resources Inc., as Issuer, and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 8-K filed November 1, 2004 and included herein by reference).
	4	.2	Indenture, dated as of December 22, 2005, between Quicksilver Resources Inc. and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.7 to the Company’s Form S-3, File No. 333-130597, filed December 22, 2005 and included herein by reference).
	4	.3	First Supplemental Indenture, dated as of March 16, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 8-K filed March 21, 2006 and included herein by reference).
	4	.4	Third Supplemental Indenture, dated as of September 26, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 10-Q filed November 7, 2006 and included herein by reference).
	4	.5	Fifth Supplemental Indenture, dated as of June 27, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed June 530, 2008 and included herein by reference).
	4	.6	Sixth Supplemental Indenture, dated as of July 10, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed July 10, 2008 and included herein by reference).

	4	.7	Amended and Restated Rights Agreement, dated as of December 20, 2005, between Quicksilver Resources Inc. and Mellon Investor Services LLC, as Rights Agent (filed as Exhibit 4.1 to the Company’s Form 8-A/A (Amendment No. 1) filed December 21, 2005 and included herein by reference).


Exhibit No.			Sequential Description
	10	.1	Master Gas Purchase and Sale Agreement, dated March 1, 1999, between Quicksilver Resources Inc. and Reliant Energy Services, Inc. (filed as Exhibit 10.10 to the Company’s Form S-1, File No. 333-89229, filed November 1, 2004 and included herein by reference).
	10	.2	Wells Agreement dated as of December 15, 1970, between Union Oil Company of California and Montana Power Company (filed as Exhibit 10.5 to the Company’s Predecessor, MSR Exploration Ltd.’s Form S-4/A, File No. 333-29769, filed August 21, 1997 and included herein by reference).]
	+ 10	.3	Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.4	Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
	+ 10	.5	Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
	+ 10	.6	Form of Retention Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
	+ 10	.7	Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
	+ 10	.8	Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).
	+ 10	.9	Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
	+ 10	.10	Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 18, 2005 and included herein by reference).
	+ 10	.11	Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.12	Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.13	Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.14	Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement (Cash Settlement) pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.15	Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement (Stock Settlement) pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.16	Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.5 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).


Exhibit No.			Sequential Description

	+ 10	.17	Form of Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.18	Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (One-Year Vesting) (filed as Exhibit 10.8 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.19	Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.5 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.20	Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (One-Year Vesting) (filed as Exhibit 10.7 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
	+ 10	.21	Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).
	+ 10	.22	Description of Non-Employee Director Compensation for Quicksilver Resources Inc. (filed as Exhibit 10.11 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.23	Quicksilver Resources Inc. 2007 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed April 16, 2007 and included herein by reference).
	+ 10	.24	Description of 2007 Cash Bonus (filed as Exhibit 10.3 to the Company’s Form 10-Q filed May 9, 2007 and included herein by reference).
	+ 10	.25	Quicksilver Resources Inc. 2008 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed December 14, 2007 and included herein by reference).
	+ 10	.26	Quicksilver Resources Inc. 2009 Executive Bonus Plan (filed as Exhibit 10.10 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.27	Quicksilver Resources Inc. Amended and Restated Change in Control Retention Incentive Plan (filed as Exhibit 10.9 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.28	Quicksilver Resources Inc. Second Amended and Restated Key Employee Change in Control Retention Incentive Plan (filed as Exhibit 10.8 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.29	Quicksilver Resources Inc. Amended and Restated Executive Change in Control Retention Incentive Plan (filed as Exhibit 10.7 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
	+ 10	.30	Form of Director and Officer Indemnification Agreement (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 26, 2005 and included herein by reference).
	10	.31	Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Inc. and the lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed February 12, 2007 and included herein by reference).
	10	.32	Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Canada Inc. and the lenders and/or agents identified therein (filed as Exhibit 10.2 to the Company’s Form 8-K filed February 12, 2007 and included herein by reference).

	10	.33	Fourth Amendment to Combined Credit Agreements, dated as of June 20, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 25, 2008 and included herein by reference).


Exhibit No.			Sequential Description

	10	.34	Fifth Amendment to Combined Credit Agreements, dated as of August 4, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 5, 2008 and included herein by reference).
	10	.35	Credit Agreement, dated as of August 8, 2008, among Quicksilver Resources Inc., the lenders party thereto and Credit Suisse, Cayman Islands Branch, as administrative agent (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 8, 2008 and included herein by reference).
	10	.36	Registration Rights Agreement, dated as of November 1, 2007, between Quicksilver Resources Inc. and BreitBurn Energy L.P. (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference).
	+10	.37	2007 Equity Plan (filed as Exhibit 99.1 to Quicksilver Gas Services LP’s Form S-8, File No. 333-145326, filed August 10, 2007 and included herein by reference).
	+10	.38	Form of Phantom Unit Award Agreement for Non-Directors (Cash) (filed as Exhibit 10.10 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference).
	+10	.39	Form of Phantom Unit Award Agreement for Non-Directors (Units) (filed as Exhibit 10.11 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 25, 2007 and included herein by reference).
	+10	.40	Quicksilver Gas Services LP Annual Bonus Plan (filed as Exhibit 10.1 to Quicksilver Gas Services LP’s Form 8-K, File No. 001-33631, filed December 13, 2007 and included herein by reference).
	+10	.41	Form of Indemnification Agreement by and between Quicksilver Gas Services GP LLC and its officers and directors (filed as Exhibit 10.7 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference).
	*** 21	.1	List of subsidiaries of Quicksilver Resources Inc.
	*** 23	.1	Consent of Deloitte & Touche LLP.
	*** 23	.2	Consent of Schlumberger Data and Consulting Services.
	*** 23	.3	Consent of LaRoche Petroleum Consultants, Ltd.
	* 23	.4	Consent of Schlumberger Data and Consulting Services
	* 23	.5	Consent of Netherland, Sewell & Associates, Inc.
	* 23	.6	Consent of PricewaterhouseCoopers LLP
	*** 24	.1	Power of Attorney
	* 31	.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	* 31	.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	* 32	.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Filed herewith.

**		Excludes schedules and exhibits we agree to furnish supplementally to the SEC upon request.

***		Filed with the Company’s original Annual Report on Form 10-K filed on March 3, 2009.

+		Identifies management contracts and compensatory plans or arrangements.


	Limited			General
*Thousands of dollars*	Partners			Partner			Total
Balance, January 1, 2008	$	1,423,418		$	1,390		$	1,424,808
Redemption of common units from predecessors (a)		(336,216	)		—			(336,216	)
Distributions		(118,580	)		(427	)		(119,007	)
Distributions paid on unissued units under incentive plans		(2,335	)		(7	)		(2,342	)
Unit-based compensation		7,383			—			7,383
Net income (loss) (b)		380,255			(2,019	)		378,236
Contribution of general partner interest to the partnership		(1,063	)		1,063			—
Other		30			—			30

Balance, December 31, 2008	$	1,352,892		$	—		$	1,352,892


	Year Ended December 31, 2008
	First			Second			Third		Fourth
*Thousands of dollars*	Quarter			Quarter			Quarter		Quarter
Limited Partners’ interest in loss (1)		(40,867	)		(284,494	)		454,454		251,162


Basic net loss per limited partner unit (2)		(0.61	)		(4.39	)		8.63		4.77
Diluted net loss per limited partner unit (2)		(0.61	)		(4.39	)		8.41		4.65


Basic units outstanding		67,020,641			64,807,563			52,635,634		52,635,634
Diluted units outstanding		67,020,641			64,807,563			54,062,291		54,019,830


		Quicksilver Resources Inc.
		(the “Registrant”)

	By:	/s/ Philip Cook
		Philip Cook
Dated: March 9, 2009		Senior Vice President — Chief Financial Officer


(a)		Reflects the purchase of 14.405 million Common Units from subsidiaries of Provident.

(b)		General partner interests were purchased as of June 17, 2008.


(1)		Fourth quarter 2008 includes $86.4 million for total impairments and price related adjustments and depreciation expense.

(2)		Due to changes in the number of weighted average common units outstanding that may occur each quarter, the earnings per unit amounts for certain quarters may not be additive.