8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

DATE OF REPORT (DATE OF EARLIEST EVENT REPORTED)

January 7, 2008 (January 7, 2008)

BREITBURN ENERGY PARTNERS L.P.

(Exact name of registrant as specified in its charter)

Delaware	001-33055	74-3169953
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(IRS Employer Identification No.)

515 South Flower Street, Suite 4800

Los Angeles, CA 90071

(Address of principal executive office)

(213) 225-5900

(Registrant’s telephone number, including area code)

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

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

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

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

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

Item 8.01 Other Events.

We are filing the unaudited consolidated balance sheet of BreitBurn GP, LLC as of September 30, 2007, which is included as Exhibit 99.1 to this Current Report on Form 8-K. BreitBurn GP, LLC is the general partner of BreitBurn Energy Partners L.P.

Item 9.01 Financial Statements and Exhibits.

(a)	Financial Statements of Businesses Acquired.
	Not applicable.
(b)	Pro Forma Financial Information.
	Not applicable.
(c)	Shell Company Transactions.
	Not applicable.
(d)	Exhibits.
	99.1	Unaudited Consolidated Balance Sheet as of September 30, 2007

SIGNATURES

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

	BREITBURN ENERGY PARTNERS L.P.
	By:	BREITBURN GP, LLC,
		its general partner
	By:	/s/ James G. Jackson
		James G. Jackson
		Chief Financial Officer of BreitBurn GP, LLC
Dated: January 7, 2008

INDEX TO EXHIBITS

EXHIBIT NO.	DESCRIPTION
99.1	Unaudited Consolidated Balance Sheet of BreitBurn GP, LLC at September 30, 2007 and the related notes thereto.

EX-99.1

EXHIBIT 99.1

BreitBurn GP, LLC and Subsidiaries

Unaudited Consolidated Balance Sheet

	September 30,
Thousands of dollars	2007
ASSETS
Current assets:
Cash and cash equivalents	$	4,453
Accounts receivable, net		23,540
Non-hedging derivative instruments (note 12)		1,845
Related party receivables (note 8)		1,672
Inventory (note 7)		2,294
Prepaid expenses		741
Intangibles - current portion (note 5)		1,140
Other current assets		160
Total current assets		35,845
Investments		160
Property, plant and equipment
Oil and gas properties (note 5)		444,448
Non-oil and gas assets (note 5)		890
		445,338
Accumulated depletion and depreciation		(31,275	)
Net property, plant and equipment		414,063
Other long-term assets
Deposit for oil and gas properties (note 5)		35,000
Intangibles (note 5)		1,808
Other long-term assets		4,626
Total assets	$	491,502
LIABILITIES AND MEMBERS' EQUITY
Current liabilities:
Accounts payable	$	7,007
Book overdraft		3,985
Non-hedging derivative instruments (note 12)		14,132
Related party payables (note 8)		8,750
Accrued liabilities and other current liabilities		9,035
Total current liabilities		42,909
Long-term debt (note 9)		48,000
Long-term related party payables (note 8)		1,640
Deferred income taxes (note 6)		3,480
Asset retirement obligation (note 10)		15,628
Non-hedging derivative instruments (note 12)		24,051
Total liabilities		135,708
Minority interest (note 3)		353,739
Commitments and contingencies (note 14)
Members' equity (note 11)		2,055
Total liabilities and members' equity	$	491,502

See accompanying notes to consolidated balance sheet.

1

Notes to Consolidated Financial Statements

1. Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. BreitBurn GP, LLC as the general partner of BreitBurn Energy Partners L.P. follows the successful efforts method of accounting for oil and gas activities. Depreciation, depletion and amortization (“DD&A”) of proved oil and gas properties is computed using the units-of-production method net of any estimated residual salvage values. For further information, refer to the consolidated balance sheet and the footnotes thereto as of December 31, 2006 as filed in Form 8-K on November 13, 2007.

2. Organization and Operations

Breitburn GP LLC (“BreitBurn GP” or the “General Partner”) is a Delaware limited liability company formed on March 23, 2006 for the purpose of becoming the general partner of Breitburn Energy Partners L.P. (the “Partnership”). The Partnership was formed on the same date to acquire properties from its predecessor, BreitBurn Energy Company, L.P (the “Predecessor” or “BreitBurn Energy”). The Partnership engages in the acquisition, development, and production of oil and natural gas properties and conducts its operations through its wholly-owned subsidiaries BreitBurn Operating L.P. (“OLP”) and OLP’s general partner BreitBurn Operating GP, LLC (“OGP”). References in this filing to “we,” “our,” “us” or like terms refer to the General Partner and the Partnership and its subsidiaries.

Effective October 10, 2006, the Partnership completed its initial public offering of 6 million common units representing limited partner interests of the Partnership (“Common Units”) at a price of $18.50 per unit, or $17.205 per unit after payment of the underwriting discount, and on November 1, 2006, the Partnership closed the sale of an additional 0.9 million Common Units also at $18.50, or $17.205 net per Common Unit, pursuant to the exercise of the underwriters’ over-allotment option. Net proceeds from the sale of the Common Units were approximately $114.6 million. The Partnership used the net proceeds to make distributions of $63.2 million to Provident Energy Trust (“Provident”) and BreitBurn Energy Corporation (“BreitBurn Corporation”) and to repay $36.5 million in assumed indebtedness. The historical relationship between the Predecessor, Provident and BreitBurn Corporation are further discussed under the caption “BreitBurn Energy Company L.P.” included elsewhere in this note. The Partnership used the net proceeds from the exercise of the underwriters’ over-allotment option to redeem 0.9 million Common Units in the aggregate owned by Provident’s two indirect wholly-owned subsidiaries, Pro GP Corp. (“Pro GP”) and Pro LP Corp. (“Pro LP”), and BreitBurn Corporation. Following redemption, those Common Units were cancelled.

Additionally, on October 10, 2006:

a) The Partnership entered into a Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”). Immediately prior to the closing of the offering, the following transactions, among others, occurred pursuant to the Contribution Agreement:

§ BreitBurn Energy conveyed to OLP its interests in the Partnership properties along with its stock in three subsidiaries and OLP assumed $36.5 million of indebtedness;

§ BreitBurn Energy distributed its interest in OGP and its limited partner interest in OLP to Pro GP, Pro LP and BreitBurn Corporation in proportion to their ownership interests in BreitBurn Energy;

2

§ Pro GP, Pro LP and BreitBurn Corporation conveyed a 0.01%, 1.90% and 0.09%, respectively, interest in OLP to the General Partner in exchange for a 0.40%, 95.15% and 4.45%, respectively, member interest in the General Partner;

§ The General Partner conveyed the interest in OLP to the Partnership in exchange for a continuation of its 2% general partner interest in the Partnership; and

§ Pro GP, Pro LP and BreitBurn Corporation conveyed their remaining interests in OLP and OGP to the Partnership in exchange for (a) 15,975,758 Common Units representing limited partner interests, with a 71.24% limited partner interest in the Partnership, and (b) received approximately $63.2 million, as a distribution of the initial public offering proceeds, to reimburse them for certain capital expenditures made directly by them or through BreitBurn Energy.

§ On May 24 and 25, 2007, the Partnership sold approximately $130 million and $92 million, respectively, of Common Units in two private placements (see note 11). The Partnership issued and sold 4,062,500 and 2,967,744 Common Units at $32.00 per unit and $31.00 per unit, respectively.

As a result of these transactions, Provident and BreitBurn Corporation had an ownership interest in the aggregate of 15,075,758 common units, representing 51.97% limited partner interest and a 1.52% general partner interest. The public unit holders owned 48.03% of the limited partner units as of September 30, 2007.

3

The following table presents the net assets conveyed by BreitBurn Energy to the Partnership immediately prior to the closing of the offering including the debt assumption:

	October 10,
Thousands of dollars	2006
Cash and cash equivalents	$	16
Accounts receivable—trade		4,225
Non-hedging derivative instruments		4,007
Prepaid expenses and other current assets		459
Non-hedging derivative instruments - non-current		1,235
Property and equipment, net		183,456
Other assets		174
Total assets	$	193,572
Accounts payable	$	897
Accounts payable—affiliates		5,237
Accrued expenses and other current liabilities		328
Long-term debt		36,500
Deferred income taxes		4,343
Asset retirement obligation		7,456
Total liabilities	$	54,761
Net assets	$	138,811

The transfer of ownership of assets from the Predecessor to the Partnership was recorded at historical costs in accordance with Emerging Issues Task Force (“EITF”) Issue No. 87-21, “Change in Accounting Basis in Master Limited Partnership Transactions.”

3. Summary of Significant Accounting Policies

Principles of consolidation

As prescribed in Emerging Issues Task Force (“EITF”) No. 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights, we are including the Partnership in the accompanying Consolidated Balance Sheet. The public unitholders’ interest and the interests of the other limited partners are reflected as minority interests and at September 30, 2007 were approximately $353.7 million. The effects of all intercompany transactions have been eliminated.

4

4. New Accounting Policies

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 will be effective for us beginning January 1, 2008. We are evaluating the impact of adoption of SFAS No. 159 but do not currently expect the adoption to have a material impact on its financial position.

SFAS No. 157, Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, which will become effective for us on January 1, 2008. This standard 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. The impact, if any, to us from the adoption of SFAS No. 157 in 2008 will depend on our assets and liabilities at that time that are required to be measured at fair value.

5. Acquisitions

Third Quarter 2007

On September 11, 2007, the Partnership deposited in escrow $35 million relating to the Quicksilver Acquisition which was applied to the cash consideration at closing on November 1, 2007. See note 15 - Subsequent Events for a detailed description of the Quicksilver Acquisition.

Second Quarter 2007

On May 24, 2007, OLP entered into an Amended and Restated Asset Purchase Agreement with Calumet Florida, L.L.C. (“Calumet”), to acquire certain interests in oil leases and related assets located along the Sunniland Trend in South Florida through the acquisition of a limited liability company that owned all of the purchased assets (the “Calumet Acquisition” or “Calumet Properties”). The Calumet Properties are comprised of five separate oil fields, one 23-mile pipeline serving one field, one storage terminal and rights in a shipping terminal. The transaction closed on May 24, 2007. The purchase price was $100 million with an effective date of January 1, 2007. After adjustments for costs and revenues for the period between the effective date and the closing, including interest paid to the seller and after taking into account approximately 218,000 barrels of crude oil held in storage as of the closing date, and including acquisition related costs, the Partnership’s purchase price was approximately $108.1 million. The acquisition was financed through the Partnership’s sale of Common Units through a private placement (see note 11 for additional information on the private placement). The acquiring subsidiary is a partnership and thus no deferred taxes were recognized for this transaction. The Partnership has made a preliminary allocation of the purchase price of $108.1 million, including approximately $0.4 million in acquisition costs to the assets acquired and liabilities assumed as follows:

Thousands of dollars
Inventories	$	10,533
Intangible assets		3,377
Oil and gas properties		98,131
Non oil and gas assets		672
Asset retirement obligation		(3,843	)
Other current liabilities		(777	)
	$	108,093

5

The preliminary purchase price allocation is based on discounted cash flows, quoted market prices and estimates made by management. The most significant assumptions related to the estimated fair values assigned to oil and gas properties with proved reserves. To estimate the fair values of these properties, estimates of oil and gas reserves were prepared by management in consultation with independent engineers. We applied estimated future prices to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a cost of capital rate determined to be appropriate at the time of the acquisition. There were no estimated quantities of hydrocarbons other than proved reserves allocated in the purchase price of the Calumet Acquisition. The purchase price included the fair value attributable to the oil inventories held in storage at the closing date. The Partnership assumed certain crude oil sales contracts for the remainder of 2007 and for 2008 through 2010. An 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 from these contracts will be recognized as part of oil sales and the intangible asset will be amortized over the life of the contracts. The purchase price allocation is subject to final closing adjustments which are expected to be completed in the fourth quarter.

On May 25, 2007, OLP entered into a Purchase and Sale Agreement with TIFD X-III LLC (“TIFD”), pursuant to which it acquired TIFD’s 99% limited partner interest in BreitBurn Energy Partners I, L.P. (“BEPI”) for a total purchase price of approximately $82 million (the “BEPI Acquisition”). BEPI owns properties in the East Coyote and Sawtelle Fields in the Los Angeles Basin in California. The general partner of BEPI is an affiliate of ours in which we have no ownership interest. As part of the transaction, BEPI distributed to an affiliate of TIFD a 1.5% overriding royalty interest in the oil and gas produced by BEPI from the two fields. The burden of the 1.5% override will be borne solely through the Partnership’s interest in BEPI. In connection with the acquisition, the Partnership also paid approximately $10.4 million to terminate existing hedge contracts related to future production from BEPI.

The BEPI Acquisition, including the termination of existing hedge contracts, was financed through the Partnership’s sale of Common Units in a private placement (see note 11 for additional information on the private placement). The acquiring subsidiary is a partnership and thus no deferred taxes were recognized for this transaction. The Partnership has made a preliminary allocation of the purchase price of $92.5 million including approximately $0.1 million in acquisition costs to the assets acquired and liabilities assumed as follows:

Thousands of dollars
Current assets	$	2,813
Oil and gas properties		92,980
Current liabilities		(2,282	)
Asset retirement obligation		(582	)
Other liabilities		(398	)
	$	92,531

The preliminary purchase price allocation is based on discounted cash flows, quoted market prices and estimates made by management. The most significant assumptions related to the estimated fair values assigned to oil and gas properties with proved reserves. To estimate the fair values of these properties, estimates of oil and gas reserves were prepared by management in consultation with independent engineers. We applied estimated future prices to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a cost of capital rate determined appropriate at the time of the acquisition. There were no quantities of hydrocarbons other than proved reserves identified with the BEPI Acquisition. The purchase price allocation is subject to final closing adjustments which are expected to be completed within one year of the acquisition date.

In April 2007, the Partnership also completed the purchase of interests in certain oil and gas properties in Wyoming for approximately $0.9 million in cash.

6

First Quarter 2007

On January 23, 2007, the Partnership completed the purchase of certain oil and gas properties, known as the “Lazy JL” in the Permian Basin of Texas, including related property and equipment. The purchase price for the Lazy JL acquisition was approximately $29.0 million in cash, and was financed through borrowings under the Partnership’s existing revolving credit facility. The transaction was accounted for using the purchase method in accordance with SFAS No. 141 and was effective January 1, 2007. The purchase price was allocated to the assets acquired and liabilities assumed as follows:

Thousands of dollars
Oil and gas properties	$	29,309
Asset retirement obligation		(282	)
Other		2
	$	29,029

In March 2007, the Partnership also completed the purchase of certain oil and gas properties in California for approximately $1.0 million in cash.

6. Income Taxes

As a limited liability company and as the Partnership and most of its subsidiaries are partnerships or limited liability companies, we are treated as partnerships for federal and state income tax purposes. Essentially all of the Partnership’s 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 its members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements. State income taxes were immaterial. However, the Partnership has two wholly owned subsidiaries, which are Subchapter C-corporations, as defined in the Internal Revenue Code that are subject to federal and state income taxes. At September 30, 2007, the Partnership’s net deferred tax liability was $3.5 million.

Effective January 1, 2007, the Partnership 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.

The Partnership performed an evaluation as of January 1, 2007 and concluded that there were no uncertain tax positions requiring recognition in its financial statements. The adoption of this standard did not have an impact on the Partnership’s financial position.

7

7. Inventory

The Partnership, through its Calumet Acquisition (see note 5 - Acquisitions), had oil inventories at September 30, 2007. Oil inventories are carried at the lower of cost to produce or market price. Inventories purchased through the acquisition are carried in inventory based on the purchase price allocation detailed in note 5 - Acquisitions. At May 24, 2007, the Partnership allocated $10.5 million to the inventories purchased. After the acquisition date, the Partnership sold this purchased inventory. After May 24, 2007, inventory additions were at cost and represent the Partnership’s production costs. At September 31, 2007, inventory was approximately $2.3 million as shown in the following table:

Thousands of dollars
Beginning inventory (Acquisition -May 24, 2007)	$	10,533
Cost of sales - purchased inventory		(10,533	)
Cost of sales - produced inventory		(4,669	)
Production costs including associated DD&A		6,409
Royalty owner share		554
Carrying amount, end of period	$	2,294

8. Related Party Transactions

We do not have any employees. We have entered into an Administrative Services Agreement with BreitBurn Management Company, LLC (“Breitburn Management”), our asset manager and operator, pursuant to which it operates the Partnership’s assets and performs other administrative services for us. The Administrative Services Agreement requires that employees of BreitBurn Management (including the persons who are our executive officers) devote such portion of their time as may be reasonable and necessary for the operation of the Partnership’s business. The executive officers currently devote a majority of their time to our business, and we expect them to continue to do so for the foreseeable future.

Under the Administrative Services Agreement, the Partnership reimburses BreitBurn Management for all direct and indirect expenses it incurs in connection with the services it performs for the Partnership (including salary, bonus, incentive compensation and other amounts paid to executive officers). To the extent that the services performed by BreitBurn Management benefit both the Partnership and BreitBurn Energy, each of the Partnership and BreitBurn Energy are required to reimburse BreitBurn Management in proportion to the benefits each of them receives. BreitBurn Management generally allocates the costs of the services of BreitBurn Management personnel providing services to both entities based on BreitBurn Management’s good-faith determination of actual time spent performing the services, plus expenses. During 2006, if services performed by BreitBurn Management benefiting both the Partnership and BreitBurn Energy could not be allocated on the basis of actual time spent on each entity, then such expenses were allocated to each entity in the same proportion as the aggregate barrels of oil equivalents produced by each entity related to the aggregate barrels of oil equivalents produced by both entities combined during the same period. For 2007, the allocation methodology has been changed to reflect the fact that the most intense portion of the Partnership’s initial public offering startup is now complete and a more balanced allocation of resources between the Partnership and BreitBurn Energy is expected. BreitBurn Management currently allocates its expenses between us and BreitBurn Energy on the basis of which entity received the services to which specific expenses relate or, in instances where expenses relate to services provided for the benefit of both entities, by allocating 51% of such expenses to the Partnership and 49% of such expenses to BreitBurn Energy. This allocation split for 2007 was derived from a weighted average of three components that were forecasted for the Partnership and BreitBurn Energy: (i) the proportionate level of 2007 forecastedgross barrels of oil equivalents production; (ii) the proportionate level of 2007 forecasted operating expenses; and (iii) the proportionate level of 2007 forecasted capital expenditures. BreitBurn Management will continue from time to time to review the methodology utilized to allocate costs, including reviewing the impacts of acquisitions, capital programs, and other factors, and may modify the methodology to appropriately reflect the value attributable to the Partnership.

At September 30, 2007, the Partnership had the following receivables and payables with the Predecessor and BreitBurn Management (“affiliated companies”).

8

	September 30,
Thousands of dollars	2007
Related party receivables
Provident	$	-
Affiliated companies		1,672
Current related party receivables	$	1,672
Related party payables
Provident	$	654
Affiliated companies		8,096
Current related party payables		8,750
Affiliated companies		1,640
Long term related party payables	$	1,640

At September 30, 2007, the receivables from affiliated companies included receivables from BreitBurn Energy for oil and gas sales made on behalf of the Partnership from certain properties. At September 30, 2007, the current payables to affiliated companies included payables to BreitBurn Management that represent amounts due under the Administrative Services Agreement, which are mostly reflected as general and administrative expenses, including outstanding liabilities for employee related costs for equity-based compensation accruals. The long-term payables relate to BreitBurn Management and represent the long-term portion of equity-based compensation accruals.

In connection with the BEPI acquisition, the Partnership paid approximately $10.4 million to terminate existing hedge contracts related to future production from BEPI. The partnership had an affiliated company receivable of $0.1 million outstanding at September 30, 2007 for BEPI’s general partner share of the disposed hedge contracts.

At September 30, 2007, the Partnership had a net payable to Provident of $0.7 million related to management services. During the nine months ended September 30, 2007, the Partnership did not make any payments to Provident.

9. Long-Term Debt

The long-term debt balances are summarized as follows:

	At September 30,
Thousands of dollars	2007
$400 million credit facility	$	48,000

The credit facility’s borrowing base was $175 million at September 30, 2007. The credit facility was amended and restated on November 1, 2007 (see Note 15 - Subsequent Events). At September 30, 2007, the interest rate was the Prime Rate of 8.0% on the Prime Debt portion of $2.0 million and the LIBOR rate of 7.05% on the LIBOR portion of $46.0 million.

At September 30, 2007, the Partnership was in compliance with the credit facility’s covenants. At September 30, 2007, the Partnership had $0.249 million in letters of credit outstanding.

9

10. 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 reclaim those wells and facilities as well as our estimate of the future timing of the costs to be incurred. On October 10, 2006, in connection with the Partnership’s initial public offering, the Predecessor contributed certain properties to the Partnership along with their related asset retirement obligation (see note 2 for details on the contribution). The total undiscounted amount of future cash flows required to settle asset retirement obligations for the Partnership was estimated to be $118.5 million at September 30, 2007. The increase from year-end is attributable to various acquisitions (see note 5 - Acquisitions). Payments to settle asset retirement obligations occur over the operating lives of the assets, which are estimated to be from 3 to 50 years. Estimated cash flow have been discounted at the Partnership’s credit adjusted risk free rate of 7% and is partially offset by an inflation rate of 2%. The following table presents changes in the asset retirement obligation of the Partnership:

	Nine Months
	Ended September,
Thousands of dollars	2007
Carrying amount, beginning of period	$	10,253
Acquisitions		4,711
Accretion expense		664
Carrying amount, end of period	$	15,628

11. Partnership’s Equity & General Partner’s Equity

Private Placements - Partnership

On May 24, 2007, the Partnership sold 4,062,500 Common Units, at a negotiated purchase price of $32.00 per unit, to certain investors (the “Purchasers”). The Partnership 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 the Partnership’s credit facility. Most of the debt repaid was associated with the Partnership’s first quarter 2007 acquisition of certain properties in West Texas.

On May 25, 2007, the Partnership sold an additional 2,967,744 Common Units to the same Purchasers at a negotiated purchase price of $31.00 per unit. The Partnership 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.

In connection with the closing of these two private placements (the “Private Placements”), the Partnership entered into agreements with the Purchasers to file a shelf registration statement to register the Common Units sold in the private placements and use its commercially reasonable efforts to cause the registration statement to become effective within 275 days of the applicable closing dates. In addition, the agreements give the Purchasers piggyback registration rights under certain circumstances. These registration rights are transferable to affiliates of the Purchasers and, in certain circumstances, to third parties.

10

If the shelf registration statement is not effective within 275 days of the closing date, then the Partnership must pay the Purchasers liquidated damages of 0.25% of the product of the purchase price times the number of registrable securities held by the Purchasers per 30-day period for the first 60 days following such deadline. This amount will increase by an additional 0.25% of the product of the purchase price times the number of registrable securities held by the Purchasers per 30-day period for each subsequent 60 days, up to a maximum of 1.0% of the product of the purchase price times the number of registrable securities held by the Purchasers per 30-day period. The aggregate amount of liquidated damages the Partnership must pay will not exceed 10.0% of the aggregate purchase prices. Pursuant to the Unit Purchase Agreement for both private placements, the Partnership agreed to indemnify the Purchasers and their respective officers, directors and other representatives against certain losses resulting from any breach of the Partnership’s representations, warranties or covenants contained therein. The Private Placements were made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(2) thereof.

On November 1, 2007, the Partnership sold 16,666,667 Common Units, at a negotiated purchase price of $27.00 per unit. The Partnership used the proceeds from such sale to fund a portion of the cash consideration for the Quicksilver Acquisition (see note 15 - Subsequent Events).

Distributions

We are entitled to 2% of all distributions that are made prior to the Partnership’s liquidation. Our initial 2% interest in these distributions may be reduced if the Partnership issues additional units in the future and we do not contribute a proportionate amount of capital to the Partnership to maintain our initial 2% general partner interest. We are not obligated to contribute a proportionate amount of capital to the Partnership to maintain our current general partner interest. At September 30, 2007, our 2% interest was reduced to 1.52% due to the two private placements described earlier.

On February 14, 2007, the Partnership paid a cash distribution in respect to the period from October 4, 2006 through December 31, 2006 of approximately $8.9 million to us and the common unitholders of record as of the close of business on February 5, 2007. The distribution that was paid to unitholders was prorated to $0.399 per Common Unit from the $0.4125 that the Partnership anticipated to pay for the full quarter, reflecting the reduced period of time from the first day of trading of the Partnership’s Common Units on October 4, 2006 through December 31, 2006. Our share of the distribution was $178,945.

On May 15, 2007, the Partnership paid a cash distribution in respect of its first quarter of operations in 2007 of approximately $9.3 million, or $0.4125 per Common Unit, to us and the common unitholders of record as of the close of business on May 7, 2007. Our share of the distribution was $185,000.

On August 14, 2007, the Partnership paid a cash distribution in respect of its second quarter of operations in 2007 of approximately $12.4 million, or $0.4225 per Common Unit, to us and the common unitholders of record as of the close of business on August 7, 2007. Our share of the distribution was $189,485.

12. Financial Instruments

Fair Value of Financial Instruments

The Partnership’s commodity price risk management program is intended to reduce its exposure to commodity prices and to assist with stabilizing cash flow and distributions. From time to time, we utilize derivative financial instruments to reduce this volatility. With respect to derivative financial instruments, 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. In addition, the derivative instruments utilized by us are based on index prices that may and often do differ from the actual crude oil 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 recognizes changes in the fair value immediately in earnings.

11

In September 2007, in connection with the Quicksilver Acquisition (as defined below), the Partnership entered certain commodity swaps for crude oil and natural gas that were contingent upon the closing of the acquisition (see the following table). The crude oil contracts settle against NYMEX WTI and the natural gas contracts settle against Natural Gas - Michcon City Gate Inside FERC. During the third quarter, the Partnership recorded net unrealized losses of $12 million related to these commodity swaps (see note 15 - Subsequent Events).

Year	Product	Volume	Terms	Effective Period
2008	Crude Oil	680 Bbl/d	Swaps - $71.56 per Bbl	January 1 - December 31
2009	Crude Oil	680 Bbl/d	Swaps - $71.56 per Bbl	January 1 - December 31
2010	Crude Oil	680 Bbl/d	Swaps - $71.56 per Bbl	January 1 - December 31
2008	Natural Gas	48,643 mmbtu/d	Swaps - $8.01 per mmbtu	January 1 - December 31
2009	Natural Gas	44,071 mmbtu/d	Swaps - $8.01 per mmbtu	January 1 - December 31
2010	Natural Gas	40,471 mmbtu/d	Swaps - $8.01 per mmbtu	January 1 - December 31
2011	Natural Gas	39,838 mmbtu/d	Swaps - $8.01 per mmbtu	January 1 - March 31

The Partnership also added the following contracts in the third quarter of 2007:

Year	Product	Volume	Terms (a)	Effective Period
2009	Crude Oil	500 Bbl/d	Swap $72.25 per Bbl	April 1 - June 30
		250 Bbl/d	Swap $72.47 per Bbl	October 1 - December 31
		250 Bbl/d	Participating Swap $62.50 per Bbl (67.3% participation above $62.50 floor)	January 1 - December 31
		250 Bbl/d	Participating Swap $60.00 per Bbl (70.0% participation above $60 floor)	October 1 - December 31
		500 Bbl/d	Participating Swap $65.00 per Bbl (54.0% participation above $65 floor)	October 1 - December 31
		500 Bbl/d	Participating Swap $65.00 per Bbl (50.0% participation above $65 floor)	October 1 - December 31
2010	Crude Oil	250 Bbl/d	Swap $72.47 per Bbl	January 1 - June 30
		250 Bbl/d	Swap $71.58 per Bbl	January 1 - June 30
		500 Bbl/d	Participating Swap $65 per Bbl (50.0% participation above $65 floor)	January 1 - June 30
		250 Bbl/d	Swaps - $71.60 per Bbl	January 1 - July 31
		250 Bbl/d	Participating Swap $60.00 per Bbl (70.0% participation above $60 floor)	January 1 - June 30
		250 Bbl/d	Participating Swap $62.50 per Bbl (56.2% participation above $62.50 floor)	January 1 - December 31

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

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 increase, our margins would be adversely affected.

12

13. Stock and Other Valuation-Based Compensation Plans

During the nine months ended September 30, 2007, the Partnership granted 91,090 Partnership based performance and restricted units under the Partnership’s 2006 Long-Term Incentive Plan, of which 2,547 units were forfeited. Upon vesting, the Partnership based performance units can be settled in either cash or Common Units at the option of the holder while the restricted units are settled in cash. In addition, the Partnership granted 17,447 Partnership performance units to our non-employee directors, which can be settled in either cash or Common Units at the option of the holder.

For detailed information on the Partnership’s various compensation plans, refer to the consolidated balance sheet and the footnotes thereto as of December 31, 2006 as filed in Form 8-K on November 13, 2007.

14. Commitments and Contingencies

The Partnership is involved in various lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of the management, the resolution of these matters will not have a material effect on the Partnership’s financial position, results of operations or liquidity.

For the Partnership’s newly acquired properties in Florida, there are a limited number of alternative methods of transportation for its production. Substantially all of the Partnership’s 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 the Partnership having to find transportation alternatives, increased transportation costs, or involuntary curtailment of its oil production in Florida, which could have a negative impact on its future consolidated financial position, results of operations or cash flows.

In connection with the recent private placements of Common Units to finance the Calumet Acquisition and the BEPI Acquisition, the Partnership agreed to file a shelf registration statement to register the Common Units it sold. If the shelf registration statement is not effective within 275 days after the closing of such private placements, then the Partnership must pay the Purchasers liquidated damages. The Partnership believes that it will be able to meet these requirements and does not expect to incur any damages. See the discussion under note 11 regarding the Partnership’s responsibilities pertaining to the sale of its Common Units in the private placements. See note 15 - Subsequent Events regarding additional Common Units sold in additional private placements, which closed on November 1, 2007, and the discussion relating to liquidated damages in the event shelf registration statements are not effective within the applicable deadlines.

On October 2, 2007, the Partnership received a notice from the Internal Revenue Service (“IRS”) claiming a penalty amount due of $1.8 million for a late-filed informational Partnership return for the 2006 tax year. During 2007, the Partnership timely filed K-1 forms for each of its limited partners. The Partnership also believed that it had timely filed its 2006 tax return based on information it received from its tax advisors that the extension for its 2006 Partnership return was being timely filed. The 2006 extension was not timely filed by the Partnership's tax advisors.

The Partnership requested a waiver or a substantial reduction in the penalty from the IRS commensurate with the Partnership’s good faith belief that any necessary extensions had been requested, the technical nature of the violation with no late payment of taxes or reporting of information, the fact that all Schedule K-1 information was reported timely to all its partners, and the fact the Partnership return at issue was filed well within what would have been the automatic 6-month extension period. On November 28, the IRS waived the penalty in its entirety and we now consider the matter resolved.

13

15. Subsequent Events

Distribution

On November 14, 2007, the Partnership paid a cash distribution of approximately $29.9 million, or $0.4425 per Common Unit, in respect of its third quarter of operations in 2007 to us and the common unitholders of record as of the close of business on November 12, 2007. Our share of the distribution was $198,455.

Completion of Quicksilver Acquisition and Related Registration Rights Agreement

On November 1, 2007, the Partnership completed the acquisition of certain assets (the “QRI Assets”) and equity interests (the “Equity Interests”) in certain entities from Quicksilver Resources Inc. (“Quicksilver” or “QRI”) in exchange for $750 million in cash and 21,347,972 Common Units (the “Quicksilver Acquisition”). The issuance of Common Units to QRI was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(2) thereof. Pursuant to the terms and conditions of the Contribution Agreement entered into by OLP and QRI, dated as of September 11, 2007 (the “Contribution Agreement”), OLP completed the Quicksilver Acquisition. OLP acquired all of QRI’s natural gas, oil and midstream assets in Michigan, Indiana and Kentucky. The midstream assets in Michigan, Indiana and Kentucky consist of gathering, transportation, compression and processing assets that transport and process the Partnership’s production and third party gas.

The preliminary purchase price allocations are based on preliminary reserve reports, quoted market prices and estimates by management. To estimate the fair values of acquired oil and gas reserves, we utilized our reserve engineers’ estimates of oil and natural gas proved reserves to arrive at estimates of future cash flows net of operating and development costs. The estimated future net cash flows were discounted at a weighted average cost of capital. An independent firm was retained to review the Partnership’s valuation process and the firm concluded the Partnership’s cash flow analysis is reasonable. The firm also assisted the Partnership in a preliminary valuation review of the acquired fixed assets including gas plants, pipelines and compression facilities. The preliminary purchase price allocation is subject to final closing adjustments and determination of tangible assets related to wells and facilities. As the Partnership has more access to the QRI Assets’ operating and financial data, there could be changes in valuation of the acquired assets and liabilities. The Partnership expects to finalize the purchase price allocation within one year of the acquisition date.

The Partnership’s preliminary purchase price allocation is presented below:

Purchase Price (Thousands of dollars)
Proceeds from sale of units to private investors *	$	441,495
Proceeds from borrowings		316,382
Total cash		757,877
Fair market value of units issued to Quicksilver		700,000
Total Purchase Price	$	1,457,877
* Net of fees and other costs of approximately $8.5 million.

14

In connection with the Quicksilver Acquisition, the Partnership entered into a registration rights agreement with QRI (the “QRI Registration Rights Agreement”), dated November 1, 2007. Pursuant to the QRI Registration Rights Agreement, the Partnership is required to file a shelf registration statement to register the common units issued to QRI pursuant to the Contribution Agreement entered into by the Partnership and QRI, and use its commercially reasonable efforts to cause the registration statement to become effective within one year of the closing date (the “QRI Registration Deadline”). In addition, the QRI Registration Rights Agreement gives QRI piggyback registration rights under certain circumstances. These registration rights are transferable to affiliates of QRI and, in certain circumstances, third parties. If the shelf registration statement is not effective by the QRI Registration Deadline, then the Partnership must pay QRI liquidated damages.

In connection with the Quicksilver Acquisition, the Partnership entered into a Transition Services Agreement (the “Transition Services Agreement”) with QRI. Under the terms of the Transition Services Agreement, QRI agreed to provide OLP certain land administrative, accounting and marketing services. In consideration for the land administrative and accounting services, the Partnership agreed to pay QRI monthly fees of $30,000 and $220,000, respectively. In consideration for the marketing services, the Partnership agreed to pay QRI a monthly fee determined by multiplying the total number of Mcfs sold during the previous month multiplied by $0.02. The term of the Transition Services Agreement commences on November 1, 2007 and terminates on the earlier of (i) March 31, 2008 or (ii) the date on which OLP has assumed responsibility for all of the services provided for in the Transition Services Agreement.

Unit Purchase Agreement and Related Registration Rights Agreement

On November 1, 2007, the Partnership sold 16,666,667 Common Units, at a negotiated purchase price of $27.00 per unit, to certain investors (the “Investors”). The Partnership used the proceeds from such sale to fund a portion of the cash consideration for the Quicksilver Acquisition.

In connection with the closing of the private placement, the Partnership entered into an agreement with the Investors to file a shelf registration statement to register the Common Units sold in the private placement and use its commercially reasonable efforts to cause the registration statement to become effective within 275 days of the applicable closing date. In addition, the agreement gives the Investors piggyback registration rights under certain circumstances. These registration rights are transferable to affiliates of the Investors and, in certain circumstances, to third parties. If the shelf registration statement is not effective within 275 days of the closing date, then the Partnership must pay the Investors liquidated damages. The private placement was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(2) thereof.   

Amended and Restated Credit Agreement

On November 1, 2007, in connection with the Quicksilver Acquisition, OLP, as borrower, and the Partnership and its 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 is $700 million. Under the Amended and Restated Credit Agreement, borrowings may be used (i) to pay a portion of the purchase price for the Quicksilver Acquisition, (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 a first-priority lien on and security interest in all of the Partnership’s and certain of its subsidiaries’ assets. OLP borrowed approximately $316.4 million under the Amended and Restated Credit Agreement to fund a portion of the cash consideration for the Quicksilver Acquisition and to pay related transaction expenses.  As of November 2, 2007, approximately $328 million in indebtedness was outstanding under the Amended and Restated Credit Agreement.

15

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% 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.

16