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EX-32.1 - Breitburn Energy Partners LPexhibit32_1.htm
EX-31.1 - Breitburn Energy Partners LPexhibit31_1.htm
EX-32.2 - Breitburn Energy Partners LPexhibit32_2.htm
EX-31.2 - Breitburn Energy Partners LPexhibit31_2.htm
 

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q

R      Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
  For the quarterly period ended June 30, 2010

or

£      Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
  For the transition period from ___ to ___
 

Commission File Number 001-33055

BreitBurn Energy Partners L.P.
(Exact name of registrant as specified in its charter)

Delaware
74-3169953
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification Number)
   
515 South Flower Street, Suite 4800
 
Los Angeles, California
90071
(Address of principal executive offices)
(Zip Code)

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.  (Check one):
 
Large accelerated filer o
Accelerated filer þ     
Non-accelerated filer o (Do not check if a smaller reporting company)
Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes £     No R

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


 


 
     
INDEX
   
Page
   
No.
 
     
PART I
FINANCIAL INFORMATION
     
 
 
 
 
 
     
     
PART II
OTHER INFORMATION
     
     
 



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

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

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

We undertake no obligation to update the forward-looking statements in this report to reflect future events or circumstances.
1



Item 1.  Financial Statements
 
BreitBurn Energy Partners L.P. and Subsidiaries
 
Unaudited Consolidated Statements of Operations
 
                         
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
Thousands of dollars, except per unit amounts
 
2010
   
2009
   
2010
   
2009
 
                         
Revenues and other income items
                       
Oil, natural gas and natural gas liquid sales
  $ 82,079     $ 59,872     $ 162,548     $ 117,515  
Gains (losses) on commodity derivative instruments, net (note 10)
    51,650       (97,259 )     103,715       (27,239 )
Other revenue, net
    487       393       1,119       669  
    Total revenues and other income (loss) items
    134,216       (36,994 )     267,382       90,945  
Operating costs and expenses
                               
Operating costs
    39,371       32,004       75,222       66,385  
Depletion, depreciation and amortization
    23,909       26,962       45,963       57,263  
General and administrative expenses
    9,960       8,386       21,217       17,947  
Loss on sale of assets
    381       -       496       -  
Total operating costs and expenses
    73,621       67,352       142,898       141,595  
                                 
Operating income (loss)
    60,595       (104,346 )     124,484       (50,650 )
                                 
Interest and other financing costs, net
    4,998       5,360       8,615       10,133  
Losses (gains) on interest rate swaps (note 10)
    1,418       (336 )     3,661       1,766  
Other expense (income), net
    21       (36 )     (4 )     (40 )
                                 
Income (loss) before taxes
    54,158       (109,334 )     112,212       (62,509 )
                                 
Income tax expense (benefit) (note 3)
    561       (809 )     705       (341 )
                                 
Net income (loss)
    53,597       (108,525 )     111,507       (62,168 )
Less: Net income (loss) attributable to noncontrolling interest
    (28 )     5       (99 )     (2 )
                                 
Net income (loss) attributable to the partnership
  $ 53,569     $ (108,520 )   $ 111,408     $ (62,170 )
                                 
Basic net income (loss) per unit (note 8)
  $ 0.94     $ (2.06 )   $ 1.96     $ (1.18 )
Diluted net income (loss) per unit (note 8)
  $ 0.94     $ (2.06 )   $ 1.96     $ (1.18 )
 
See accompanying notes to consolidated financial statements.
2

 
Unaudited Consolidated Balance Sheets
             
     
 June 30,
   
 December 31,
Thousands of dollars, except units outstanding
   
2010
   
2009
ASSETS
           
Current assets
           
Cash
  $
3,347
   $
5,766
Accounts and other receivables, net
   
 59,513
   
 65,209
Derivative instruments (note 10)
   
 74,718
   
 57,133
Related party receivables (note 4)
   
 2,504
   
 2,127
Inventory (note 5)
   
 1,914
   
 5,823
Prepaid expenses
   
 5,434
   
 5,888
Intangibles
   
 248
   
 495
Total current assets
   
 147,678
   
 142,441
Equity investments
   
 7,848
   
 8,150
Property, plant and equipment
           
Property, plant and equipment
   
 2,095,764
   
 2,066,685
Accumulated depletion and depreciation
   
 (369,937)
   
 (325,596)
Net property, plant and equipment
   
 1,725,827
   
 1,741,089
Other long-term assets
           
Derivative instruments (note 10)
   
 97,627
   
 74,759
Other long-term assets
   
 12,739
   
 4,590
             
Total assets
  $
1,991,719
   $
 1,971,029
             
LIABILITIES AND EQUITY
           
Current liabilities
           
Accounts payable
  $
21,351
  $
 21,314
Book overdraft
   
 798
   
 -
Derivative instruments (note 10)
   
 16,594
   
 20,057
Related party payables (note 4)
   
 -
   
 13,000
Revenue and royalties payable
   
 15,978
   
 18,224
Salaries and wages payable
   
 5,165
   
 10,244
Accrued liabilities
   
 8,591
   
 9,051
Total current liabilities
   
 68,477
   
 91,890
             
Long-term debt (note 6)
   
 534,000
   
 559,000
Deferred income taxes (note 3)
   
 3,114
   
 2,492
Asset retirement obligation (note 7)
   
 37,332
   
 36,635
Derivative instruments (note 10)
   
 18,734
   
 50,109
Other long-term liabilities
   
 2,102
   
 2,102
Total liabilities
   
 663,759
   
 742,228
Equity
           
Partners' equity (note 8)
   
 1,327,497
   
 1,228,373
Noncontrolling interest (note 9)
   
 463
   
 428
Total equity
   
 1,327,960
   
 1,228,801
             
Total liabilities and equity
  $
1,991,719
 
 1,971,029
             
Common Units outstanding (in thousands)
   
 53,294
   
 52,784
 
See accompanying notes to consolidated financial statements.
3

 
 
Unaudited Consolidated Statements of Cash Flows
 
             
   
Six Months Ended
 
   
June 30,
 
Thousands of dollars
 
2010
   
2009
 
             
Cash flows from operating activities
           
Net income (loss)
  $ 111,507     $ (62,168 )
Adjustments to reconcile to cash flow from operating activities:
               
Depletion, depreciation and amortization
    45,963       57,263  
Unit based compensation expense
    9,839       6,289  
Unrealized (gains) losses on derivative instruments
    (75,291 )     148,302  
Income from equity affiliates, net
    302       660  
Deferred income tax expense (benefit)
    622       (671 )
Amortization of intangibles
    247       1,557  
Loss on sale of assets
    496       -  
Other
    1,757       1,648  
Changes in net assets and liabilities
               
Accounts receivable and other assets
    7,890       4,731  
Inventory
    3,909       (2,943 )
Net change in related party receivables and payables
    (13,377 )     996  
Accounts payable and other liabilities
    (12,800 )     (14,129 )
Net cash provided by operating activities
    81,064       141,535  
Cash flows from investing activities
               
Capital expenditures
    (24,997 )     (12,126 )
Proceeds from sale of assets
    225       -  
Property acquisitions
    (1,550 )     -  
Net cash used by investing activities
    (26,322 )     (12,126 )
Cash flows from financing activities
               
Distributions
    (21,312 )     (28,038 )
Proceeds from long-term debt
    622,000       181,975  
Repayments of long-term debt
    (647,000 )     (277,975 )
Book overdraft
    798       (5,624 )
Long-term debt issuance costs
    (11,647 )     -  
Net cash used by financing activities
    (57,161 )     (129,662 )
Decrease in cash
    (2,419 )     (253 )
Cash beginning of period
    5,766       2,546  
Cash end of period
  $ 3,347     $ 2,293  
 
See accompanying notes to consolidated financial statements.
4

 
Notes to Consolidated Financial Statements

1.  Organization and Basis of Presentation

The accompanying unaudited consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the year ended December 31, 2009 (the “Annual Report”).  The financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X.  Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements.  In the opinion of management, all adjustments considered necessary for fair statement have been included.  Operating results for the three months and six months ended June 30, 2010 are not necessarily indicative of the results that may be expected for the year ended December 31, 2010.  The consolidated balance sheet at December 31, 2009 has been derived from the audited consolidated financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements.  We follow the successful efforts method of accounting for oil and gas activities.  Depletion, depreciation and amortization of proved oil and gas properties is computed using the units-of-production method net of any estimated residual salvage values.  For further information, refer to the consolidated financial statements and footnotes thereto included in our Annual Report.

As of December 31, 2009, Quicksilver Resources Inc. (“Quicksilver”) held approximately 21.3 million of our common units (“Common Units"), representing approximately 40 percent of our outstanding Common Units.  On May 11, 2010, Quicksilver partially paid for an acquisition of assets from Marshall R. Young Oil Co. (“Young”) with 3.6 million Common Units, resulting in Quicksilver’s ownership being reduced to approximately 17.7 million Common Units, representing approximately 33 percent of our Common Units.  During the period from June 7, 2010 through July 30, 2010, Young sold approximately 1.7 million of these Common Units.

2.  Accounting Pronouncements

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

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

5

 

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

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
Thousands of dollars
 
2010
   
2009
   
2010
   
2009
 
Federal current tax expense
  $ 18     $ 2     $ 147     $ 25  
Deferred federal tax expense (benefit) (a)
    595       (948 )     622       (671 )
State income tax expense (benefit) (b)
    (52 )     137       (64 )     305  
Total income tax expense (benefit)
  $ 561     $ (809 )   $ 705     $ (341 )
                                 
(a) Related to Phoenix Production Company, a tax-paying corporation and our wholly-owned subsidiary.
 
(b) Related to various forms of state taxes imposed on gross receipts, profit margin or net income in the states where we have operations.
 
 
4.  Related Party Transactions

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

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

At June 30, 2010 and December 31, 2009, we had current receivables of $1.8 million and $1.4 million, respectively, due from BEC related to the administrative services agreement, outstanding liabilities for employee related costs and oil and gas sales made by BEC on our behalf from certain properties.  During the first six months of 2010 and 2009, the monthly charges to BEC for indirect expenses totaled $2.8 million and $3.0 million, respectively, and charges for direct expenses including incentive compensation plan costs, direct payroll and administrative costs totaled $3.9 million and $2.3 million, respectively.  For the three months and six months ended June 30, 2010, total oil and gas sales made by BEC on our behalf were approximately $0.5 million and $0.9 million, respectively.  For the three months and six months ended June 30, 2009, total oil and gas sales made by BEC on our behalf were approximately $0.3 million and $0.5 million, respectively.

At June 30, 2010 and December 31, 2009, we had receivables of $0.2 million and $0.3 million, respectively, due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf.

Quicksilver buys natural gas from us in Michigan.  For the three months and six months ended June 30, 2010, total net gas sales to Quicksilver were approximately $0.6 million and $1.8 million, respectively.  For the three months and six months ended June 30, 2009, total net gas sales to Quicksilver were approximately $0.5 million and $1.6 million, respectively.  At June 30, 2010 and December 31, 2009, the related receivable was $0.5 million and $0.4 million, respectively.

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


5.  Inventory

Our crude oil inventory from our Florida operations at June 30, 2010 and December 31, 2009 was $1.9 million and $5.8 million, respectively.  In the six months ended June 30, 2010, we sold 413 gross MBbls and produced 341 gross MBbls of crude oil from our Florida operations.  Crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter.  Crude oil inventory additions are at cost and represent our production costs.  We match production expenses with crude oil sales.  Production expenses associated with unsold crude oil inventory are recorded to inventory.  The decrease in inventory since December 31, 2009 reflects the higher amount of barrels sold than produced.

6.  Long-Term Debt

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

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

As of June 30, 2010 and December 31, 2009, we had $534.0 million and $559.0 million, respectively, in indebtedness outstanding.  At June 30, 2010, the 1-month LIBOR interest rate plus an applicable spread on our long-term debt was 3.110 percent.  The amounts reported on our consolidated balance sheets for long-term debt approximate fair value due to the variable nature of our interest rates.

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

 The Second Amended and Restated Credit Agreement no longer requires that in order to make a distribution to our unitholders, we also must have the ability to borrow 10 percent of our borrowing base after giving effect to such distribution, and remain in compliance with all terms and conditions of our credit facility.  In addition, the requirement that we maintain a leverage ratio (defined as the ratio of total debt to EBITDAX) as of the last day of each quarter, on a last twelve month basis of no more than 3.50 to 1.00 was increased to 3.75 to 1.00.  The Second Amended and Restated Credit Agreement continues to require us to maintain a current ratio as of the last day of each quarter, of not less than 1.00 to 1.00 and to maintain an interest coverage ratio (defined as the ratio of EBITDAX to consolidated interest expense) as of the last day of each quarter, of not less than 2.75 to 1.00.  As of June 30, 2010 and December 31, 2009, we were in compliance with the credit facilities’ covenants.
7


The pricing grid was adjusted by increasing the applicable margins (as defined in the Second Amended and Restated Credit Agreement) between 75 and 100 basis points, depending on the percentage of the borrowing base borrowed, in line with the current credit market for similar facilities.  At our debt level as of June 30, 2010, the applicable margin on our borrowings was 250 basis points.  The Second Amended and Restated Credit Agreement permits us to incur or guaranty additional debt up to $350 million in senior unsecured notes, and if we do incur such additional indebtedness, our borrowing base will be reduced by 25 percent of the original stated principal amount of such senior unsecured notes.  The Second Amended and Restated Credit Agreement also permits us to terminate derivative contracts without obtaining the consent of the lenders in the facility, provided that the net effect of such termination plus the aggregate value of all dispositions of oil and gas properties made during such period, together, does not exceed 5 percent of the borrowing base, and the borrowing base will be automatically reduced by an amount equal to the net effect of the termination.

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

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

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

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

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
Thousands of dollars
 
2010
   
2009
   
2010
   
2009
 
                         
Credit agreement (including commitment fees)
  $ 4,035     $ 4,537     $ 6,828     $ 8,487  
Amortization of discount and deferred issuance costs
    963       823       1,787       1,646  
Total
  $ 4,998     $ 5,360     $ 8,615     $ 10,133  
 
In connection with entry into the Second Amended and Restated Credit Agreement, we incurred $11.6 million in debt issuance costs.

7.  Asset Retirement Obligation

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

ASC 820 “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are.  The highest priority of Level 1 is given to unadjusted quoted prices in active markets for identical assets or liabilities.  Level 2 includes inputs other than quoted prices that are included in Level 1 and can be derived by observable data, including third party data providers.  These inputs may also include observable transactions in the market place.  Level 3 is defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.  We consider the inputs to our asset retirement obligation valuation to be Level 3, as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets.
8


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

   
Six Months Ended
   
Year Ended
 
Thousands of dollars
 
June 30, 2010
   
December 31, 2009
 
Carrying amount, beginning of period
  $ 36,635     $ 30,086  
Liabilities settled in the current period
    (280 )     (470 )
Revisions (a)
    (313 )     4,883  
Dispositions (b)
    -       (252 )
Accretion expense
    1,290       2,388  
Carrying amount, end of period
  $ 37,332     $ 36,635  
                 
(a) Changes to cost estimates and revisions to reserve life.
         
(b) Relates to disposition of the Lazy JL Field in Texas, which was sold effective July 1, 2009.
 

8.  Partners’ Equity

In January 2010, 496,194 Common Units were issued to employees pursuant to vested grants under our long-term incentive compensation plan, and 13,617 Common Units were issued to outside directors for phantom units and distribution equivalent rights that were granted in 2007 and vested in January 2010.

At June 30, 2010 and December 31, 2009, we had 53,294,012 and 52,784,201 Common Units outstanding, respectively.  At June 30, 2010 and December 31, 2009, we had 6,700,000 units authorized for issuance under our long-term incentive compensation plans, and there were 3,657,195 and 2,961,659, respectively, of units outstanding under grants that were eligible to be paid in Common Units upon vesting.

Cash Distributions

On May 14, 2010, we paid a cash distribution of approximately $20.0 million to our common unitholders of record as of the close of business on May 10, 2010.  The distribution that was paid to unitholders was $0.375 per Common Unit.  During the six months ended June 30, 2010, we also paid $1.3 million in cash at a rate equal to the distribution paid to our unitholders, to holders of outstanding, unvested Restricted Phantom Units (“RPUs”) and Convertible Phantom Units (“CPUs”) issued under our long-term incentive plan.

Earnings per unit

ASC 260 “Earnings per Share” requires use of the “two-class” method of computing earnings per unit for all periods presented.  The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of common unit and participating security as if all earnings for the period had been distributed.  Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation.  Our unvested RPUs and CPUs participate in distributions on an equal basis with Common Units.  Accordingly, the presentation below is prepared on a combined basis and is presented as earnings per Common Unit.
9

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

   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
Thousands, except per unit amounts
 
2010
   
2009
   
2010
   
2009
 
                         
Net income (loss) attributable to the partnership
  $ 53,569     $ (108,520 )   $ 111,408     $ (62,170 )
Distributions on participating units not expected to vest
    -       -       -       24  
Net income (loss) attributable to common unitholders and participating securities
  $ 53,569     $ (108,520 )   $ 111,408     $ (62,146 )
                                 
Weighted average number of units used to calculate basic and diluted earnings per unit (in thousands):
                               
Common Units
    53,294       52,770       53,294       52,737  
Participating securities
    3,530       -       3,411       -  
Denominator for basic earnings per common unit (a)
    56,824       52,770       56,705       52,737  
                                 
Dilutive units (b)
    136       -       127       -  
Denominator for diluted earnings per common unit
    56,961       52,770       56,832       52,737  
                                 
Net income (loss) per common unit
                               
Basic
  $ 0.94     $ (2.06 )   $ 1.96     $ (1.18 )
Diluted
  $ 0.94     $ (2.06 )   $ 1.96     $ (1.18 )
                                 
(a) Basic earnings per unit is based on the weighted average number of Common Units outstanding plus the weighted average number of potentially issuable RPUs and CPUs. The three months and six months ended June 30, 2009 exclude 2,822 and 2,473 of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.
 
(b) The three months and six months ended June 30, 2010 include dilutive units potentially issuable to directors under compensation plans. The three months and six months ended June 30, 2009, exclude 106 and 105, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit.
 

9.  Noncontrolling Interest

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

On May 25, 2007, we acquired the limited partner interest (99 percent) of BEPI from TIFD.  As such, we are fully consolidating the results of BEPI and thus are recognizing a noncontrolling interest representing the book value of the general partner’s interests.  At June 30, 2010 and December 31, 2009, the amount of this noncontrolling interest was $0.5 million and $0.4 million, respectively.  For the three months and six months ended June 30, 2010, we recorded net income attributable to the noncontrolling interest of less than $0.1 million and $0.1 million, respectively and dividends of less than $0.1 million in each period.  For the three months and six months ended June 30, 2009, we recorded net income attributable to the noncontrolling interest of less than $0.1 million and net loss attributable to the noncontrolling interest of less than $0.1 million, respectively and dividends of less than $0.1 million and $0.1 million, respectively.
10

 
10.  Financial Instruments

Fair Value of Financial Instruments

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

Credit and Counterparty Risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable.  Our derivatives expose us to credit risk from counterparties.  As of June 30, 2010, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia and Toronto-Dominion Bank.  We periodically obtain credit default swap information on our counterparties.  As of June 30, 2010, each of these financial institutions had an investment grade credit rating.  Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default.  As of June 30, 2010, our largest derivative asset balances were with JP Morgan Chase Bank N.A. and Credit Suisse Energy LLC, who accounted for approximately 58 percent and 21 percent of our derivative asset balance, respectively.  As of June 30, 2010, our largest derivative liability balances were with Wells Fargo Bank National Association and Barclays Bank PLC, who accounted for approximately 74 percent and 21 percent of our derivative liability balance, respectively.

Commodity Activities

The derivative instruments we utilize are based on index prices that may and often do differ from the actual crude oil and natural gas prices realized in our operations.  These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under ASC 815 “Derivatives and Hedging.”  Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial reporting purposes and instead recognize changes in fair value immediately in earnings.  We had realized gains of $18.4 million and $30.6 million and unrealized gains of $33.2 million and $73.1 million for the three months and six months ended June 30, 2010, respectively, relating to our various market-based commodity contracts.  We had realized gains of $51.5 million and $125.6 million and unrealized losses of $148.7 million and $152.8 million for the three months and six months ended June 30, 2009, respectively, relating to our various market-based commodity contracts.  We had net financial instruments receivable relating to our commodity contracts of $146.3 million at June 30, 2010.
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We had the following commodity derivative contracts in place at June 30, 2010:

   
Year
 
   
2010
   
2011
   
2012
   
2013
   
2014
 
Gas Positions:
                             
Fixed price swaps:
                             
Hedged volume (MMBtu/d)
    43,425       25,955       19,128       27,000       -  
Average price ($/MMBtu)
  $ 8.20     $ 7.26     $ 7.10     $ 6.92     $ -  
Collars:
                                       
Hedged volume (MMBtu/d)
    3,753       16,016       19,129       -       -  
Average floor price ($/MMBtu)
  $ 9.00     $ 9.00     $ 9.00     $ -     $ -  
Average ceiling price ($/MMBtu)
  $ 12.01     $ 11.28     $ 11.89     $ -     $ -  
Total:
                                       
Hedged volume (MMBtu/d)
    47,178       41,971       38,257       27,000       -  
Average price ($/MMBtu)
  $ 8.26     $ 7.92     $ 8.05     $ 6.92     $ -  
                                         
Oil Positions:
                                       
Fixed price swaps:
                                       
 Hedged volume (Bbls/d)
    2,317       3,890       3,539       5,000       1,748  
Average price ($/Bbl)
  $ 83.43     $ 72.78     $ 72.40     $ 79.32     $ 90.42  
Participating swaps: (a)
                                       
 Hedged volume (Bbls/d)
    1,683       1,439       -       -       -  
Average price ($/Bbl)
  $ 66.31     $ 61.29     $ -     $ -     $ -  
Average participation %
    55.1 %     53.2 %     -       -       -  
Collars:
                                       
Hedged volume (Bbls/d)
    1,922       2,048       2,477       500       -  
Average floor price ($/Bbl)
  $ 105.30     $ 103.42     $ 110.00     $ 77.00     $ -  
Average ceiling price ($/Bbl)
  $ 139.41     $ 152.61     $ 145.39     $ 103.10     $ -  
Floors:
                                       
Hedged volume (Bbls/d)
    500       -       -       -       -  
Average floor price ($/Bbl)
  $ 100.00     $ -     $ -     $ -     $ -  
Total:
                                       
Hedged volume (Bbls/d)
    6,422       7,377       6,016       5,500       1,748  
Average price ($/Bbl)
  $ 86.76     $ 79.02     $ 87.88     $ 79.11     $ 90.42  
                                         
(a) A participating swap combines a swap and a call option with the same strike price
         

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Interest Rate Activities

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates.  As of June 30, 2010, our total debt outstanding was $534.0 million.  In order to mitigate our interest rate exposure, we had the following interest rate derivative contracts in place at June 30, 2010, to fix a portion of floating LIBOR-base debt on our credit facility:

Notional amounts in thousands of dollars
 
Notional Amount
 
Fixed Rate
Period Covered
       
July 1, 2010 to December 20, 2010
 
 300,000
 
3.6825%
July 1, 2010 to October 20, 2011
 
 100,000
 
1.6200%
December 20, 2010 to October 20, 2011
 
 200,000
 
2.9900%
 
We had realized losses of $2.9 million and $5.8 million and unrealized gains of $1.5 million and $2.1 million for the three months and six months ended June 30, 2010, respectively, related to our interest rate derivative contracts.  We had realized losses of $3.2 million and $6.3 million and unrealized gains of $3.5 million and $4.5 million for the three months and six months ended June 30, 2009, respectively, relating to our interest rate derivative contracts.  We had net financial instruments payable related to our interest rate derivative contracts of $9.3 million at June 30, 2010.

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

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

Balance sheet location, thousands of dollars
 
Oil Commodity Derivatives
   
Natural Gas Commodity Derivatives
   
Interest Rate Derivatives
   
Commodity Derivatives
Netting (a)
   
Total Financial Instruments
 
                               
As of June 30, 2010
                             
Assets
                             
Current assets - derivative instruments
  $ 25,798     $ 49,264     $ -     $ (344 )   $ 74,718  
Other long-term assets - derivative instruments
    45,020       59,375       -       (6,768 )     97,627  
Total assets
    70,818       108,639       -       (7,112 )     172,345  
                                         
Liabilities
                                       
Current liabilities - derivative instruments
    (9,137 )     -       (7,801 )     344       (16,594 )
Long-term liabilities - derivative instruments
    (24,015 )     -       (1,487 )     6,768       (18,734 )
Total liabilities
    (33,152 )     -       (9,288 )     7,112       (35,328 )
                                         
Net assets (liabilities)
  $ 37,666     $ 108,639     $ (9,288 )   $ -     $ 137,017  
                                         
As of December 31, 2009
                                       
Assets
                                       
Current assets - derivative instruments
  $ 17,666     $ 39,467     $ -     $ -     $ 57,133  
Other long-term assets - derivative instruments
    35,382       42,620       -       (3,243 )     74,759  
Total assets
    53,048       82,087       -       (3,243 )     131,892  
                                         
Liabilities
                                       
Current liabilities - derivative instruments
    (10,234 )     -       (9,823 )     -       (20,057 )
Long-term liabilities - derivative instruments
    (51,730 )     -       (1,622 )     3,243       (50,109 )
Total liabilities
    (61,964 )     -       (11,445 )     3,243       (70,166 )
                                         
Net assets (liabilities)
  $ (8,916 )   $ 82,087     $ (11,445 )   $ -     $ 61,726  
                                         
(a) Represents counterparty netting under derivative netting agreements. These contracts are reflected net on the balance sheet.
 

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

Income Statement location, thousands of dollars
 
Oil Commodity Derivatives (a)
   
Natural Gas Commodity Derivatives (a)
   
Interest Rate
Derivatives (b)
   
Total Financial Instruments
 
Three Months Ended June 30, 2010
                       
Realized gains (losses)
  $ 1,424     $ 17,011     $ (2,884 )   $ 15,551  
Unrealized gains (losses)
    49,091       (15,876 )     1,466       34,681  
Net gains (losses)
  $ 50,515     $ 1,135     $ (1,418 )   $ 50,232  
                                 
Three Months Ended June 30, 2009
                               
Realized gains (losses)
  $ 13,621     $ 37,847     $ (3,191 )   $ 48,277  
Unrealized gains (losses)
    (101,796 )     (46,931 )     3,527       (145,200 )
Net gains (losses)
  $ (88,175 )   $ (9,084 )   $ 336     $ (96,923 )
                                 
Six Months Ended June 30, 2010
                               
Realized gains (losses)
  $ 1,732     $ 28,849     $ (5,818 )   $ 24,763  
Unrealized gains
    46,580       26,554       2,157       75,291  
Net gains (losses)
  $ 48,312     $ 55,403     $ (3,661 )   $ 100,054  
                                 
Six Months Ended June 30, 2009
                               
Realized gains (losses)
  $ 61,183     $ 64,373     $ (6,259 )   $ 119,297  
Unrealized gains (losses)
    (144,832 )     (7,963 )     4,493       (148,302 )
Net gains (losses)
  $ (83,649 )   $ 56,410     $ (1,766 )   $ (29,005 )
                                 
(a) Included in gains (losses) on commodity derivative instruments, net on the consolidated statements of operations.
 
(b) Included in losses (gains) on interest rate swaps on the consolidated statements of operations.
 
 
ASC 820 “Fair Value Measurements and Disclosures” defines fair value, establishes a framework for measuring fair value and establishes required disclosures about fair value measurements.  ASC 820 also establishes a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are.  We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third party market participants.  We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements.  The fair value hierarchy established by ASC 820 gives the highest priority of Level 1 to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 to unobservable inputs.  We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are.  The three levels of inputs as defined in ASC 820 are described further as follows:

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

Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data or the interpretation of Level 2 criteria is modified in practice to include non-binding market corroborated data.  Effective January 1, 2010, we adopted ASU 2010-06 “Fair Value Measurements and Disclosures.”  ASU 2010-06 requires detailed disclosures of significant transfers in and out of Level 1 and Level 2 categories and the reasons for those transfers.  We had no such transfers during the six months ended June 30, 2010.
14

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

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

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

Recurring fair value measurements at June 30, 2010 and December 31, 2009:
 
Thousands of dollars
 
Level 1
   
Level 2
   
Level 3
   
Total
 
                         
As of June 30, 2010
                       
Assets (liabilities):
                       
Commodity derivatives (swaps, put and call options)
  $ -     $ 31,296     $ 115,009     $ 146,305  
Other derivatives (interest rate swaps)
    -       (9,288 )     -       (9,288 )
Total
  $ -     $ 22,008     $ 115,009     $ 137,017  
                                 
As of December 31, 2009
                               
Assets (liabilities):
                               
Commodity derivatives (swaps, put and call options)
  $ -     $ (29,303 )   $ 102,475     $ 73,172  
Other derivatives (interest rate swaps)
    -       (11,446 )     -       (11,446 )
Total
  $ -     $ (40,749 )   $ 102,475     $ 61,726  
 
The following table sets forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3:
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
Thousands of dollars
 
2010
   
2009
   
2010
   
2009
 
Assets:
                       
Beginning balance
  $ 108,716     $ 154,344     $ 102,475     $ 153,218  
Realized and unrealized gains
    6,293       (34,959 )     12,534       (33,833 )
Settlement (a)
    -       (6,030 )     -       (6,030 )
Ending balance
  $ 115,009     $ 113,355     $ 115,009     $ 113,355  
                                 
(a) Settlement reflects the monetization of oil contracts in June 2009.
         
 
For the three months and six months ended June 30, 2010, realized gains of $5.8 million and $10.7 million and unrealized gains of $0.5 million and $1.8 million related to our derivative instruments classified as Level 3 are included in gains (losses) on commodity derivative instruments, net on the consolidated statements of operations.  For the three months and six months ended June 30, 2009, realized gains of $4.4 million and $14.3 million and unrealized losses of $39.4 million and $48.1 million, respectively, related to our derivative instruments classified as Level 3 are included in gains (losses) on commodity derivative instruments, net on the consolidated statements of operations.  Determination of fair values incorporates various factors as required by ASC 820 including, but not limited to, the credit standing of the counterparties, the impact of guarantees as well as our own abilities to perform on our liabilities.  During the three months and six months ended June 30, 2010, we had no changes to the fair value of our derivative instruments classified as Level 3 related to purchases, sales, issuances or settlements.  During the three months and six months ended June 30, 2009, we had $6.0 million in settlements impacting the fair value of our derivatives instruments classified as Level 3 related to the monetization of oil contracts, and no changes related to purchases, sales or issuances.
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11.  Unit and Other Valuation-Based Compensation Plans

Unit-based compensation expense for the three months and six months ended June 30, 2010 was $5.0 million and $9.8 million, respectively, and for the three months and six months ended June 30, 2009 was $3.1 million and $6.3 million, respectively.

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

In January 2010, 496,194 Common Units were issued to employees pursuant to grants that vested under our LTIP and 13,617 Common Units were issued to outside directors for phantom units and distribution equivalent rights which were granted in 2007 and vested in January 2010.  Common Units issued under our LTIP are issued net of units withheld for payment of taxes.

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

As of June 30, 2010, we had $37.7 million of total unrecognized compensation costs for all outstanding plans.  This amount is expected to be recognized over the period from July 1, 2010 to December 31, 2012.

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

12.  Commitments and Contingencies

Surety Bonds and Letters of Credit

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit.  These obligations primarily cover self-insurance and other programs where governmental organizations require such support.  These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon.  At June 30, 2010 and December 31, 2009, we had various surety bonds for $11.0 million and $10.6 million, respectively.  At June 30, 2010 and December 31, 2009, we had approximately $0.3 million in letters of credit outstanding.
 
13.  Subsequent Events
 
On July 30, 2010, we announced a cash distribution to unitholders for the second quarter of 2010 at the rate of $0.3825 per Common Unit, to be paid on August 13, 2010 to the record holders of common units at the close of business on August 9, 2010.
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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

Overview

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

Our core investment strategies include:

·  
Acquire long-lived assets with low-risk exploitation and development opportunities;
·  
Use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;
·  
Reduce cash flow volatility through commodity price and interest rate derivatives; and
·  
Maximize asset value and cash flow stability through operating and technical expertise.

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

Quarterly Highlights

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

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

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

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

On May 7, 2010, we entered into the Second Amended and Restated Credit Agreement, which set our borrowing base at $735 million.
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We hold more than 470,000 net acres in Northern Michigan.  We have completed a review of our land holdings in the area now believed to be prospective in the developing Collingwood-Utica shale play in Michigan.  We own more than 120,000 net acres in this prospective area.  We also own and operate significant midstream assets in Michigan.  We believe that we are well positioned to be a leading participant in this potential new shale play.

Operational Focus and Capital Expenditures

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

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

Commodity Prices

In the second quarter of 2010, the WTI spot price averaged $78 per barrel, compared with approximately $60 per barrel in the second quarter of 2009.  In the first six months of 2010, WTI averaged $78 per barrel compared to $52 per barrel a year earlier.  The average WTI spot price in July 2010 was approximately $76 per barrel.  In 2009, the WTI spot price averaged approximately $62 per barrel.
 
In the second quarter of 2010, the NYMEX wholesale natural gas price averaged $4.35 per MMBtu compared with approximately $3.81 per MMBtu in the second quarter of 2009.  In the first six months of 2010, the NYMEX wholesale natural gas price ranged from a low of $3.84 per MMBtu to a high of $6.01 per MMBtu.  The average NYMEX wholesale natural gas price in July 2010 was approximately $4.60 per MMBtu.  During 2009, the NYMEX wholesale natural gas price ranged from a low of $2.51 per MMBtu to a high of $6.07 per MMBtu.
 

 
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Results of Operations

The table below summarizes certain of the results of operations for the periods indicated.  The data for both periods reflects our results as they are presented in our unaudited consolidated financial statements included elsewhere in this report.
 
   
Three Months
         
Six Months
       
   
Ended June 30,
   
Increase /
       
Ended June 30,
   
Increase /
       
Thousands of dollars, except as indicated
 
2010
 
2009
   
Decrease
 
%
   
2010
 
2009
   
Decrease
   
%
 
Total production (MBoe)
    1,663     1,654       9     1 %     3,258     3,257       1       0 %
     Oil and NGL (MBoe)
    812     762       50     7 %     1,539     1,504       35       2 %
     Natural gas (MMcf)
    5,106     5,349       (243 )   -5 %     10,313     10,518       (205 )     -2 %
Average daily production (Boe/d)
    18,270     18,172       98     1 %     17,998     17,993       5       0 %
Sales volumes (MBoe)
    1,725     1,635       90     5 %     3,319     3,218       101       3 %
                                                           
Average realized sales price (per Boe) (a) (b) (c)
  $ 58.30   $ 52.97     $ 5.33     10 %   $ 58.23   $ 53.74     $ 4.49       8 %
     Oil and NGL (per Boe) (a) (b) (c)
    69.99     65.47       4.52     7 %     71.26     63.95       7.31       11 %
     Natural gas (per Mcf) (a) (b)
    7.70     7.09       0.61     9 %     7.68     7.53       0.15       2 %
                                                           
Oil, natural gas and NGL sales (d)
  $ 82,079   $ 59,872     $ 22,207     37 %   $ 162,548   $ 117,515     $ 45,033       38 %
Realized gains on commodity derivative instruments (e)
    18,435     51,468       (33,033 )   -64 %     30,581     125,556       (94,975 )     -76 %
Unrealized gains (losses) on commodity derivative instruments (e)
    33,215     (148,727 )     181,942     n/a       73,134     (152,795 )     225,929       n/a  
Other revenues, net
    487     393       94     24 %     1,119     669       450       67 %
    Total revenues
    134,216     (36,994 )     171,210     n/a       267,382     90,945       176,437       n/a  
                                                           
Lease operating expenses and processing fees
    29,627     28,442       1,185     4 %     60,118     57,668       2,450       4 %
Production and property taxes (f)
    4,224     4,188       36     1 %     9,803     8,893       910       10 %
    Total lease operating expenses
    33,851     32,630       1,221     4 %     69,921     66,561       3,360       5 %
                                                           
Transportation expenses
    1,231     851       380     45 %     2,078     2,099       (21 )     -1 %
Purchases
    74     21       53     n/a       126     40       86       n/a  
Change in inventory
    4,215     (1,498 )     5,713     n/a       3,097     (2,415 )     5,512       n/a  
Uninsured loss
    -     -       -     n/a       -     100       (100 )     -100 %
    Total operating costs
  $ 39,371   $ 32,004     $ 7,367     23 %   $ 75,222   $ 66,385     $ 8,837       13 %
                                                           
Lease operating expenses pre taxes per Boe (g)
  $ 17.82   $ 16.88     $ 0.94     6 %   $ 18.45   $ 17.39     $ 1.06       6 %
Production and property taxes per Boe
    2.54     2.53       0.01     1 %     3.01     2.73       0.28       10 %
Total lease operating expenses per Boe
    20.36     19.41       0.95     5 %     21.46     20.12       1.34       7 %
                                                           
Depletion, depreciation and
amortization (DD&A)
  $ 23,909   $ 26,962     $ (3,053 )   -11 %   $ 45,963   $ 57,263     $ (11,300 )     -20 %
DD&A per Boe
    14.38     16.30       (1.92 )   -12 %    <