UNITED STATES SECURITIES AND EXCHANGE COMMISSION


Washington, D.C. 20549


Form 10-Q/A


Amendment No. 1





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


For the Quarterly Period Ended March 31, 2013





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: 000-51719











LINN ENERGY, LLC


(Exact name of registrant as specified in its charter)





Delaware65-1177591(State or other jurisdiction of incorporation or organization)(IRS EmployerIdentification No.)600 Travis, Suite 5100Houston, Texas77002(Address of principal executive offices)(Zip Code)(281) 840-4000(Registrant’s telephone number, including area code)





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 x No  ̈


Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes x No  ̈




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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filerxAccelerated filer ̈Non-accelerated filer ̈Smaller reporting company ̈


Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ̈ No x


As of March 31, 2013, there were 235,073,968 units outstanding.










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EXPLANATORY NOTE


Linn Energy, LLC (“LINN Energy” or the “Company”) is filing this Amendment No. 1 on Form 10-Q/A (the “Amended Filing”) to the Company’s Quarterly Report on Form 10-Q for the three months ended March 31, 2013 (the “Original Filing”) filed with the Securities and Exchange Commission (“SEC”) on April 25, 2013.  In connection with LinnCo, LLC’s (“LinnCo”) acquisition of Berry Petroleum Company, the Company and LinnCo filed a Registration Statement on Form S-4 and subsequent amendments to the S-4 (as amended, the “S-4”) to address the SEC’s comments to the S-4 and the Original Filing.  This Amended Filing is being filed to conform the disclosures in the Quarterly Report on Form 10-Q with the disclosures made in the S-4.


For the convenience of the reader, this Amended Filing sets forth the Original Filing in its entirety, as modified and superseded where necessary to reflect the revisions.  In the Amended Filing, the Company has updated Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations to include additional disclosure regarding the Company’s commodity hedging, its board of directors determination of the amount of cash distributions to pay unitholders (including discretionary reductions for a portion of  oil and natural gas development costs) and gains (losses) on oil and natural gas derivatives and voluntarily remove non-GAAP financial measures, among other revisions; Item 3. Quantitative and Qualitative Disclosures About Market Risk to revise disclosures with respect to commodity hedging transactions; and Item 1A. Risk Factors.


In accordance with Rule 12b-15 under the Securities Exchange Act of 1934, as amended, this Amended Filing includes certifications from our Chief Executive Officer and Chief Financial Officer dated as of the date of this filing.


The Amended Filing continues to speak as of the date of the Original Filing and, except as set forth in the sections indicated above, the Company has not updated the Original Filing to reflect events occurring subsequently to the date of the Original Filing.  Accordingly, this Amended Filing should be read in conjunction with the Company’s filings made with the SEC subsequent to the filing of the Original Filing.





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TABLE OF CONTENTS PageGlossary of TermsiiiPart I - Financial InformationItem 1.Financial StatementsCondensed Consolidated Balance Sheets as of March 31, 2013, and December 31, 20121Condensed Consolidated Statements of Operations for the three months ended March 31, 2013, and March 31, 20122Condensed Consolidated Statement of Unitholders’ Capital for the three months ended March 31, 20133Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2013, and March 31, 20124Notes to Condensed Consolidated Financial Statements5Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations19Item 3.Quantitative and Qualitative Disclosures About Market Risk33Item 4.Controls and Procedures35Part II - Other InformationItem 1.Legal Proceedings36Item 1A.Risk Factors36Item 2.Unregistered Sales of Equity Securities and Use of Proceeds36Item 3.Defaults Upon Senior Securities36Item 4.Mine Safety Disclosures36Item 5.Other Information36Item 6.Exhibits37Signature38


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GLOSSARY OF TERMS


As commonly used in the oil and natural gas industry and as used in this Quarterly Report on Form 10-Q, the following terms have the following meanings:


Bbl. One stock tank barrel or 42 United States gallons liquid volume.


Bcf. One billion cubic feet.


Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.


Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.


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


MBbls/d. MBbls per day.


Mcf. One thousand cubic feet.


Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.


MMBbls. One million barrels of oil or other liquid hydrocarbons.


MMBoe. One million barrels of oil equivalent, determined using a ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf.


MMBtu. One million British thermal units.


MMcf. One million cubic feet.


MMcf/d. MMcf per day.


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


MMcfe/d. MMcfe per day.


MMMBtu. One billion British thermal units.


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PART I – FINANCIAL INFORMATION


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|Item 1. | Financial Statements

LINN ENERGY, LLC


CONDENSED CONSOLIDATED BALANCE SHEETS


March 31, 2013December 31, 2012(Unaudited)(in thousands,except unit amounts)ASSETSCurrent assets:Cash and cash equivalents$6,034$1,243Accounts receivable – trade, net320,609371,333Derivative instruments186,716350,695Assets held for sale218,849—Other current assets67,27388,157Total current assets799,481811,428Noncurrent assets:Oil and natural gas properties (successful efforts method)11,546,10011,611,330Less accumulated depletion and amortization(2,174,273)(2,025,656)9,371,8279,585,674Other property and equipment499,727469,188Less accumulated depreciation(82,332)(73,721)417,395395,467Derivative instruments507,620530,216Other noncurrent assets123,502128,453631,122658,669Total noncurrent assets10,420,34410,639,810Total assets$11,219,825$11,451,238LIABILITIES AND UNITHOLDERS’ CAPITALCurrent liabilities:Accounts payable and accrued expenses$662,687$707,861Derivative instruments9,12026Other accrued liabilities145,047115,245Total current liabilities816,854823,132Noncurrent liabilities:Credit facility1,335,0001,180,000Senior notes, net4,858,9914,857,817Derivative instruments2,6094,114Other noncurrent liabilities160,935158,995Total noncurrent liabilities6,357,5356,200,926Commitments and contingencies (Note 10)Unitholders’ capital:235,073,968 units and234,513,243units issued and outstanding at March 31, 2013, and December 31, 2012, respectively3,976,3814,136,240Accumulated income69,055290,9404,045,4364,427,180Total liabilities and unitholders’ capital$11,219,825$11,451,238





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


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LINN ENERGY, LLC


CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


(Unaudited)


Three Months EndedMarch 31,20132012(in thousands, except per unit amounts)Revenues and other:Oil, natural gas and natural gas liquids sales$462,732$348,895Gains (losses) on oil and natural gas derivatives(108,370)2,031Marketing revenues9,8521,290Other revenues4,8461,874369,060354,090Expenses:Lease operating expenses88,72171,636Transportation expenses27,18310,562Marketing expenses7,374692General and administrative expenses58,56643,321Exploration costs2,226410Depreciation, depletion and amortization197,441117,276Impairment of long-lived assets57,053—Taxes, other than income taxes39,67125,195Losses on sale of assets and other, net3,1721,494481,407270,586Other income and (expenses):Interest expense, net of amounts capitalized(100,359)(77,519)Other, net(1,643)(3,269)(102,002)(80,788)Income (loss) before income taxes(214,349)2,716Income tax expense7,5368,918Net loss$(221,885)$(6,202)Net loss per unit:Basic$(0.96)$(0.04)Diluted$(0.96)$(0.04)Weighted average units outstanding:Basic233,176193,256Diluted233,176193,256Distributions declared per unit$0.725$0.69





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


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LINN ENERGY, LLC


CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL


(Unaudited)


UnitsUnitholders’ CapitalAccumulated IncomeTotal Unitholders’ Capital(in thousands)December 31, 2012234,513$4,136,240$290,940$4,427,180Issuance of units561(167)—(167)Distributions to unitholders(170,954)—(170,954)Unit-based compensation expenses11,262—11,262Net loss—(221,885)(221,885)March 31, 2013235,074$3,976,381$69,055$4,045,436





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





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LINN ENERGY, LLC


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


(Unaudited)


Three Months EndedMarch 31,20132012(in thousands)Cash flow from operating activities:Net loss$(221,885)$(6,202)Adjustments to reconcile net loss to net cash provided by operating activities:Depreciation, depletion and amortization197,441117,276Impairment of long-lived assets57,053—Unit-based compensation expenses11,2628,171Amortization and write-off of deferred financing fees5,4127,037(Gains) losses on sale of assets and other, net15,306(296)Deferred income tax7,5036,253Mark-to-market on derivatives:Total (gains) losses108,370(2,031)Cash settlements85,79458,517Premiums paid for derivatives—(177,541)Changes in assets and liabilities:Decrease in accounts receivable – trade, net55,54415,606Increase in other assets(1,327)(4,336)Decrease in accounts payable and accrued expenses(13,609)(5,237)Increase in other liabilities27,73018,296Net cash provided by operating activities334,59435,513Cash flow from investing activities:Acquisition of oil and natural gas properties and joint-venture funding(15,128)(1,230,304)Development of oil and natural gas properties(235,804)(220,571)Purchases of other property and equipment(25,843)(9,895)Proceeds from sale of properties and equipment and other(2,224)215Net cash used in investing activities(278,999)(1,460,555)Cash flow from financing activities:Proceeds from sale of units—761,362Proceeds from borrowings300,0002,634,802Repayments of debt(145,000)(1,700,000)Distributions to unitholders(170,954)(137,590)Financing fees, offering expenses and other, net(34,850)(113,049)Excess tax benefit from unit-based compensation—2,587Net cash provided by (used in) financing activities(50,804)1,448,112Net increase in cash and cash equivalents4,79123,070Cash and cash equivalents:Beginning1,2431,114Ending$6,034$24,184


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


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LINN ENERGY, LLC


NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


(Unaudited)


Note 1 – Basis of Presentation


Nature of Business


Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company.  LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.  The Company’s properties are located in the United States (“U.S.”), in the Mid-Continent, the Hugoton Basin, the Green River Basin, the Permian Basin, Michigan, Illinois, the Williston/Powder River Basin, California and east Texas.


Principles of Consolidation and Reporting


The condensed consolidated financial statements at March 31, 2013 , and for the three months ended March 31, 2013 , and March 31, 2012 , are unaudited, but in the opinion of management include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods.  Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.  The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.


The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries.  All significant intercompany transactions and balances have been eliminated upon consolidation.  Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.  The Company’s other investment is accounted for at cost.


The condensed consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation.  Such reclassifications have no impact on previously reported net income (loss), unitholders’ capital or cash flows.


Use of Estimates


The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events.  These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses.  The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed.  As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use.  These estimates and assumptions are based on management’s best estimates and judgment.  Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances.  Such estimates and assumptions are adjusted when facts and circumstances dictate.  As future events and their effects cannot be determined with precision, actual results could differ from these estimates.  Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.


Recently Issued Accounting Standards


In December 2011, the Financial Accounting Standards Board issued an Accounting Standards Update (“ASU”) that requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position.  The ASU requires disclosure of both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement.  The ASU is to be applied retrospectively and is effective for periods beginning on or after January 1, 2013.  The Company adopted the ASU effective January 1, 2013.  The


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 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
 (Unaudited)


adoption of the requirements of the ASU, which expanded disclosures, had no effect on the Company’s financial position or results of operations.


Note 2 – Acquisitions, Joint-Venture Funding and Divestiture


For the three months ended March 31, 2013, the Company paid approximately $15 million towards the future funding commitment related to the joint-venture agreement it entered into with an affiliate of Anadarko Petroleum Corporation in April 2012.  From inception of the agreement through March 31, 2013, the Company has funded approximately $217 million towards the total commitment of $400 million .


Acquisition – Pending


On February 20, 2013, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry Petroleum Company (“Berry”) entered into a definitive merger agreement under which LinnCo would acquire all of the outstanding common shares of Berry.  Under the terms of the agreement, Berry’s shareholders will receive 1.25 LinnCo common shares for each Berry common share they own.  This transaction, which is expected to be a tax-free exchange to Berry’s shareholders, represents value of $46.2375 per common share, based on the closing price of LinnCo common shares on February 20, 2013, the last trading day before the public announcement.


The transaction has a preliminary value of approximately $4.4 billion , including the assumption of debt, and is expected to close by July 1, 2013, subject to approvals by Berry and LinnCo shareholders, LINN Energy unitholders and regulatory agencies.  In connection with the proposed transaction described above, LinnCo will contribute Berry to LINN Energy in exchange for newly issued LINN Energy units, after which Berry will be an indirect wholly owned subsidiary of LINN Energy.


Acquisitions – 2012


On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties and the Jayhawk natural gas processing plant located in the Hugoton Basin in Kansas from BP America Production Company (“BP”).  The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date.  The Company paid approximately $1.16 billion in total consideration for these properties.  The transaction was financed primarily with proceeds from the March 2012 debt offering (see Note 6).


Divestiture – Pending


On April 3, 2013, the Company entered into, through one of its wholly owned subsidiaries, a definitive asset purchase and sale agreement, together with the Company’s partners, Panther Energy, LLC and Red Willow Mid-Continent, LLC, to sell its interests in certain oil and natural gas properties located in the Mid-Continent region (“Panther Properties”) to Midstates Petroleum Company, Inc.  The sale price for the Company’s portion of its interests in the properties is approximately $220 million , subject to closing adjustments.  The sale is anticipated to close on or about June 1, 2013, subject to closing conditions.  There can be no assurance that all of the conditions to closing will be satisfied.  The Company plans to use the net proceeds from the sale to repay borrowings under its Credit Facility, as defined in Note 6.


At March 31, 2013, the Panther Properties were classified as “assets held for sale” on the Company’s condensed consolidated balance sheet.  Assets held for sale were recorded at the lesser of the carrying value or the fair value less costs to sell, which resulted in a write down of the carrying value of approximately $57 million for the three months ended March 31, 2013.  The carrying value of the assets held for sale was reduced to fair value, estimated using Level 2 inputs consisting of the mutually agreed upon selling price the Company expects to receive upon the sale of these properties.  The charge is included in “impairment of long-lived assets” on the condensed consolidated statement of operations.


Note 3 – Unitholders’ Capital


Public Offering of Units


In January 2012 , the Company sold 19,550,000 units representing limited liability company interests at $35.95 per unit ( $34.512 per unit, net of underwriting discount) for net proceeds of approximately $674 million (after underwriting discount


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 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
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and offering expenses of approximately $28 million ).  The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under its Credit Facility.


Equity Distribution Agreement


The Company has an equity distribution agreement pursuant to which it may from time to time issue and sell units representing limited liability company interests having an aggregate offering price of up to $500 million .  Sales of units, if any, will be made through a sales agent by means of ordinary brokers’ transactions, in block transactions, or as otherwise agreed with the agent.  The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.


In January 2012 , the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $2 million in commissions and professional service expenses).  The Company used the net proceeds for general corporate purposes, including the repayment of a portion of the indebtedness outstanding under its Credit Facility.  At March 31, 2013, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.


Distributions


Under the Company’s limited liability company agreement, the Company’s unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses.  Distributions paid by the Company are presented on the condensed consolidated statement of unitholders’ capital and the condensed consolidated statements of cash flows.  On April 23, 2013, the Company’s Board of Directors declared a cash distribution of $0.725 per unit with respect to the first quarter of 2013.  The distribution, totaling approximately $171 million , will be paid on May 15, 2013, to unitholders of record as of the close of business on May 8, 2013.


Note 4 – Oil and Natural Gas Properties


Oil and Natural Gas Capitalized Costs


Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:


March 31, 2013December 31, 2012(in thousands)Proved properties:Leasehold acquisition$8,464,014$8,603,888Development2,707,8842,553,127Unproved properties374,202454,31511,546,10011,611,330Less accumulated depletion and amortization(2,174,273)(2,025,656)$9,371,827$9,585,674





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Note 5 – Unit-Based Compensation


During the three months ended March 31, 2013 , the Company granted 612,240 restricted units and 105,530 phantom units to employees, primarily as part of its annual review of its nonexecutive employees’ compensation, with an aggregate fair value of approximately $27 million .  The restricted units and phantom units vest over three years.  A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:


Three Months Ended March 31,20132012(in thousands)General and administrative expenses$9,865$7,622Lease operating expenses1,397549Total unit-based compensation expenses$11,262$8,171Income tax benefit$4,161$3,019


Note 6 – Debt


The following summarizes debt outstanding:


March 31, 2013December 31, 2012Carrying ValueFair Value(1)Carrying ValueFair Value(1)(in millions, except percentages)Credit facility(2)$1,335$1,335$1,180$1,18011.75% senior notes due 2017414441449.875% senior notes due 2018141514156.50% senior notes due May 20197507827507556.25% senior notes due November 20191,8001,8341,8001,8028.625% senior notes due 20201,3001,4331,3001,4147.75% senior notes due 20211,0001,0691,0001,061Less current maturities————6,240$6,5126,085$6,271Unamortized discount(46)(47)Total debt, net of discount$6,194$6,038


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|(1) | The carrying value of the Credit Facility is estimated to be substantially the same as its fair value.  Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions.

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|(2) | Variable interest rates of1.96%and1.97%atMarch 31, 2013, and December 31, 2012, respectively.

Credit Facility


The Company’s Fifth Amended and Restated Credit Agreement (“Credit Facility”) provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount.  At March 31, 2013, the Credit Facility had a borrowing base of $4.5 billion with a maximum commitment amount of $3.0 billion .  The maturity date is April 2017 .  At March 31, 2013 , the borrowing capacity under the Credit Facility was approximately $1.7 billion , which includes a $5 million reduction in availability for outstanding letters of credit.


On April 24, 2013, the Company entered into a new Amended and Restated Credit Agreement increasing the maximum commitment amount from $3.0 billion to $4.0 billion and extending the maturity date from April 2017 to April 2018.  The borrowing base remains unchanged at $4.5 billion and does not include any assets to be acquired in the pending transaction


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with Berry.  The amended and restated agreement is substantially similar to the previous Credit Facility with revisions to permit the transactions related to the acquisition of Berry and to designate Berry as an unrestricted subsidiary under the agreement.  When considering the increased maximum commitment amount, borrowing capacity was approximately $2.7 billion at March 31, 2013, not including any proceeds to be received from the pending Panther sale.


Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October, as well as upon requested interim redeterminations, by the lenders at their sole discretion.  The Company also has the right to request one additional borrowing base redetermination per year at its discretion, as well as the right to an additional redetermination each year in connection with certain acquisitions.  Significant declines in commodity prices may result in a decrease in the borrowing base.  The Company’s obligations under the Credit Facility are secured by mortgages on its and certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in its direct and indirect material subsidiaries.  The Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on the most recent reserve report, or 2) a Collateral Coverage Ratio of at least 2.5 to 1.  Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount.  Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material subsidiaries and are required to be guaranteed by any future material subsidiaries.


At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.5% and 2.5% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.5% and 1.5% per annum (depending on the then-current level of borrowings under the Credit Facility).  Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at LIBOR.  The Company is required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum between 0.375% and 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base.  The Company is in compliance with all financial and other covenants of the Credit Facility.


Senior Notes Due November 2019


On March 2, 2012 , the Company issued $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (“November 2019 Senior Notes”) at a price of 99.989% .  The November 2019 Senior Notes were sold to a group of initial purchasers and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”).  The Company received net proceeds of approximately $1.77 billion (after deducting the initial purchasers’ discount of $198,000 and offering expenses of approximately $29 million ).  The Company used the net proceeds to fund the BP acquisition (see Note 2).  The remaining proceeds were used to repay indebtedness under the Company’s Credit Facility and for general corporate purposes.  The financing fees and expenses of approximately $29 million incurred in connection with the November 2019 Senior Notes will be amortized over the life of the notes.  Such amortized financing fees and expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.


The November 2019 Senior Notes were issued under an indenture dated March 2, 2012 (“November 2019 Indenture”), mature November 1, 2019 , and bear interest at 6.25% .  Interest is payable semi-annually on May 1 and November 1, beginning November 1, 2012.  The November 2019 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness.  Each of the Company’s material subsidiaries has guaranteed the November 2019 Senior Notes on a senior unsecured basis.  The November 2019 Indenture provides that the Company may redeem: (i) on or prior to November 1, 2015, up to 35% of the aggregate principal amount of the November 2019 Senior Notes at a redemption price of 106.25% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to November 1, 2015, all or part of the November 2019 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the November 2019 Indenture) and accrued and unpaid interest; and (iii) on or after November 1, 2015, all or part of the November 2019 Senior Notes at a redemption price equal to 103.125% , and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest.  The November 2019 Indenture also provides that, if a change of control (as defined in the November 2019 Indenture) occurs, the holders have


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a right to require the Company to repurchase all or part of the November 2019 Senior Notes at a redemption price equal to 101% , plus accrued and unpaid interest.


The November 2019 Indenture contains covenants substantially similar to those under the Company’s May 2019 Senior Notes, 2010 Issued Senior Notes and Original Senior Notes, as defined below, that, among other things, limit the Company’s ability to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.  The Company is in compliance with all financial and other covenants of the November 2019 Senior Notes.


In connection with the issuance and sale of the November 2019 Senior Notes, the Company entered into a Registration Rights Agreement (“November 2019 Registration Rights Agreement”) with the initial purchasers.  Under the November 2019 Registration Rights Agreement, the Company agreed to use its reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the November 2019 Senior Notes in exchange for outstanding November 2019 Senior Notes within 400 days after the notes were issued.  On March 22, 2013, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the November 2019 Senior Notes.  As of April 25, 2013, the registration statement has not been declared effective.  The deadline for registration has passed and the Company will be required to pay additional interest which is expected to be less than $1 million .


Senior Notes Due May 2019


The Company has $750 million in aggregate principal amount of 6.50% senior notes due 2019 (the “May 2019 Senior Notes”).  The indentures related to the May 2019 Senior Notes contain redemption provisions and covenants that are substantially similar to those of the November 2019 Senior Notes.  In an exchange offer that expired in October 2012, the Company exchanged all of its $750 million outstanding principal amount of May 2019 Senior Notes for an equal amount of new May 2019 Senior Notes.  The terms of the new May 2019 Senior Notes are identical in all material respects to those of the outstanding May 2019 Senior Notes, except that the transfer restrictions, registration rights and additional interest provisions relating to the outstanding May 2019 Senior Notes do not apply to the new May 2019 Senior Notes.


Senior Notes Due 2020 and Senior Notes Due 2021


The Company has $1.3 billion in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”) and $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (the “2021 Senior Notes,” and together with the 2020 Senior Notes, the “2010 Issued Senior Notes”).  The indentures related to the 2010 Issued Senior Notes contain redemption provisions and covenants that are substantially similar to those of the November 2019 Senior Notes.  However, the restrictive legends from each of the 2010 Issued Senior Notes have been removed making them freely tradable (other than with respect to persons that are affiliates of the Company), thereby terminating the Company’s obligations under each of the registration rights agreements entered into in connection with the issuance of the 2010 Issued Senior Notes.


Senior Notes Due 2017 and Senior Notes Due 2018


The Company also has $41 million (originally $250 million ) in aggregate principal amount of 11.75% senior notes due 2017 (the “2017 Senior Notes”) and $14 million (originally $256 million ) in aggregate principal amount of 9.875% senior notes due 2018 (the “2018 Senior Notes” and together with the 2017 Senior Notes, the “Original Senior Notes”).  The indentures related to the Original Senior Notes initially contained redemption provisions and covenants that were substantially similar to those of the November 2019 Senior Notes; however, in conjunction with tender offers in 2011, the indentures have been amended and most of the covenants and certain default provisions have been eliminated.  The amendments became effective upon the execution of the supplemental indentures to the indentures governing the Original Senior Notes.


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 (Unaudited)


Note 7 – Derivatives


Commodity Derivatives


The Company utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements.  The Company has historically entered into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales.  The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.  See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.


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The following table summarizes derivative positions for the periods indicated as of March 31, 2013:


April 1 - December 31, 201320142015201620172018Natural gas positions:Fixed price swaps:Hedged volume (MMMBtu)65,76697,401118,041121,841120,12236,500Average price ($/MMBtu)$5.22$5.25$5.19$4.20$4.26$5.00Puts:(1)Hedged volume (MMMBtu)64,94479,62871,85476,26966,886—Average price ($/MMBtu)$5.37$5.00$5.00$5.00$4.88$—Total:Hedged volume (MMMBtu)130,710177,029189,895198,110187,00836,500Average price ($/MMBtu)$5.29$5.14$5.12$4.51$4.48$5.00Oil positions:Fixed price swaps:(2)Hedged volume (MBbls)8,94411,90311,59911,4644,755—Average price ($/Bbl)$94.97$92.92$96.23$90.56$89.02$—Puts:Hedged volume (MBbls)2,3393,9603,4263,271384—Average price ($/Bbl)$97.86$91.30$90.00$90.00$90.00$—Total:Hedged volume (MBbls)11,28315,86315,02514,7355,139—Average price ($/Bbl)$95.57$92.52$94.81$90.44$89.10$—Natural gas basis differential positions:(3)Panhandle basis swaps:Hedged volume (MMMBtu)58,50879,38887,16219,764——Hedged differential ($/MMBtu)$(0.56)$(0.33)$(0.33)$(0.31)$—$—NWPL Rockies basis swaps:Hedged volume (MMMBtu)26,20836,02638,36239,199——Hedged differential ($/MMBtu)$(0.20)$(0.20)$(0.20)$(0.20)$—$—MichCon basis swaps:Hedged volume (MMMBtu)7,2339,4909,344———Hedged differential ($/MMBtu)$0.10$0.08$0.06$—$—$—Houston Ship Channel basis swaps:Hedged volume (MMMBtu)4,3185,2564,8914,575——Hedged differential ($/MMBtu)$(0.10)$(0.10)$(0.10)$(0.10)$—$—Permian basis swaps:Hedged volume (MMMBtu)3,4934,8915,074———Hedged differential ($/MMBtu)$(0.20)$(0.21)$(0.21)$—$—$—Oil basis differential positions:(3)Midland - Cushing basis swaps:Hedged volume (MBbls)1,513—————Hedged differential ($/Bbl)$(0.95)$—$—$—$—$—Oil timing differential positions:Trade month roll swaps:(4)Hedged volume (MBbls)5,2327,2547,2517,4466,486—Hedged differential ($/Bbl)$0.22$0.22$0.24$0.25$0.25$—





|    |                                                                                                                                                                                                                                                                                                                                    
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Includes certain outstanding natural gas puts of approximately7,964MMMBtu for the period April 1, 2013, through December 31, 2013,10,570MMMBtu for each of the years ending December 31, 2014, and December 31, 2015, and10,599MMMBtu for the year ending December 31, 2016, used to hedge revenues associated with NGL production.

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|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Includes certain outstanding fixed price oil swaps of approximately5,384MBbls which may be extended annually at a price of$100.00per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and$90.00per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year.  The extension for each year is exercisable without respect to the other years.

|    |                                                                                                                   
|--- | ------------------------------------------------------------------------------------------------------------------
|(3) | Settle on the respective pricing index to hedge basis differential associated with natural gas and oil production.

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(4) | The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions.  In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

During the three months ended March 31, 2013, the Company entered into commodity derivative contracts consisting of oil basis swaps for April 2013 through December 2013.


Settled derivatives on natural gas production for the three months ended March 31, 2013, included volumes of 42,778 MMMBtu at an average contract price of $5.29 per MMBtu.  Settled derivatives on oil production for the three months ended March 31, 2013, included volumes of 3,693 MBbls at an average contract price of $95.57 per Bbl.  Settled derivatives on natural gas production for the three months ended March 31, 2012, included volumes of 23,642 MMMBtu at an average contract price of $5.84 per MMBtu.  Settled derivatives on oil production for the three months ended March 31, 2012, included volumes of 2,578 MBbls at an average contract price of $97.93 per Bbl.  The natural gas derivatives are settled based on the closing price of NYMEX natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month.  The oil derivatives are settled based on the average closing price of NYMEX light crude oil for each day of the delivery month.


Balance Sheet Presentation


The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets.  The following summarizes the fair value of derivatives outstanding on a gross basis:


March 31,2013December 31, 2012(in thousands)Assets:Commodity derivatives$1,034,866$1,282,390Liabilities:Commodity derivatives$352,259$405,619


By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk.  Credit risk is the failure of the counterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk.  The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives.  The Credit Facility is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral.  The Company does not receive collateral from its counterparties.  The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $1.0 billion at March 31, 2013.  The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis.  In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.


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Gains (Losses) on Derivatives


Total gains and losses on derivatives, including realized and unrealized gains and losses, were a net loss of approximately $108 million and a net gain of approximately $2 million for the three months ended March 31, 2013, and March 31, 2012, respectively, and are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.”


Note 8 – Fair Value Measurements on a Recurring Basis


The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis.  The Company uses certain pricing models to determine the fair value of its derivative financial instruments.  Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.  Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets.  Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives.


The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:


March 31, 2013Level 2Netting(1)Total(in thousands)Assets:Commodity derivatives$1,034,866$(340,530)$694,336Liabilities:Commodity derivatives$352,259$(340,530)$11,729


December 31, 2012Level 2Netting(1)Total(in thousands)Assets:Commodity derivatives$1,282,390$(401,479)$880,911Liabilities:Commodity derivatives$405,619$(401,479)$4,140


|    |                                                                             
|--- | ----------------------------------------------------------------------------
|(1) | Represents counterparty netting under agreements governing such derivatives.

Note 9 – Asset Retirement Obligations


Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other noncurrent liabilities” on the condensed consolidated balance sheets.  Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations.  The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors ( 2.0% for the three months ended March 31, 2013); and (iv) a credit-adjusted risk-free interest rate (average of 6.5% for the three months ended March 31, 2013).  These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.


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The following presents a reconciliation of the asset retirement obligations (in thousands):


Asset retirement obligations at December 31, 2012$151,974Liabilities added from drilling590Current year accretion expense2,764Settlements(1,981)Revision of estimates(269)Asset retirement obligations at March 31, 2013$153,078





Note 10 – Commitments and Contingencies


The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations.  The Company has established reserves that management currently believes are adequate to provide for potential liabilities based upon its evaluation of these matters.  For a certain statewide class action royalty payment dispute where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the court, will result in no loss to the Company.  Discovery related to class certification has concluded.  Briefing and the hearing on class certification have been deferred by court order pending the Tenth Circuit Court of Appeals’ resolution of interlocutory appeals of two unrelated class certification orders.  As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any.  In addition, the Company is involved in various other disputes arising in the ordinary course of business.  The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.


Note 11 – Earnings Per Unit


Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period.  Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents.  The Company uses the treasury stock method to determine the dilutive effect.


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The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net loss:


Net Loss(Numerator)Units(Denominator)Per UnitAmount(in thousands)Three months ended March 31, 2013:Net loss:Allocated to units$(221,885)Allocated to participating securities(1,301)$(223,186)Net loss per unit:Basic net loss per unit233,176$(0.96)Dilutive effect of unit equivalents——Diluted net loss per unit233,176$(0.96)Three months ended March 31, 2012:Net loss:Allocated to units$(6,202)Allocated to participating securities(1,375)$(7,577)Net loss per unit:Basic net loss per unit193,256$(0.04)Dilutive effect of unit equivalents——Diluted net loss per unit193,256$(0.04)





Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 5 million and 2 million unit options and warrants for the three months ended March 31, 2013 , and March 31, 2012, respectively.  All equivalent units were anti-dilutive for the three months ended March 31, 2013, and March 31, 2012.


Note 12 – Income Taxes


The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders.  Limited liability companies are subject to Texas margin tax.  In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes.  As such, with the exception of the state of Texas and certain subsidiaries, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company.  Amounts recognized for income taxes are reported in “income tax expense” on the condensed consolidated statements of operations.


Note 13 – Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows


“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:


March 31,2013December 31, 2012(in thousands)Accrued compensation$13,886$35,431Accrued interest123,40772,668Other7,7547,146$145,047$115,245


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Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:


Three Months Ended March 31,20132012(in thousands)Cash payments for interest, net of amounts capitalized$44,209$42,517Cash payments for income taxes$—$20Noncash investing activities:In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follows:Fair value of assets acquired$8,101$1,257,765Fair value of liabilities assumed15,093(28,233)Receivables from sellers(1,212)772Payables to sellers(6,854)—Cash paid$15,128$1,230,304


For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.  Restricted cash of approximately $5 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at March 31, 2013, and December 31, 2012, and represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.


The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facility.  At December 31, 2012, reclassified net outstanding checks of approximately $35 million were included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet.  There was no such balance at March 31, 2013.  The Company presents these net outstanding checks as cash flows from financing activities on the condensed consolidated statements of cash flows.


Note 14 – Related Party Transactions


LinnCo


LinnCo, an affiliate of LINN Energy, was formed on April 30, 2012, for the sole purpose of owning units in LINN Energy.  In October 2012, LinnCo completed its IPO and used the net proceeds of approximately $1.2 billion from the offering to acquire 34,787,500 of LINN Energy’s units which represent approximately 15% of LINN Energy’s outstanding units at March 31, 2013.  All of LinnCo’s common shares are held by the public.  As of March 31, 2013, LinnCo had no significant assets or operations other than those related to its interest in LINN Energy.  In connection with the pending acquisition of Berry (see Note 2), LinnCo intends to amend its limited liability company agreement to permit the acquisition and subsequent contribution of assets to LINN Energy.


LINN Energy has agreed to provide to LinnCo, or to pay on LinnCo’s behalf, any legal, accounting, tax advisory, financial advisory and engineering fees, printing costs or other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with any public offering of shares in LinnCo or incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, printing costs, independent auditor fees and expenses, legal counsel fees and expenses, limited liability company governance and compliance expenses and registrar and transfer agent fees.  In addition, the Company has agreed to indemnify LinnCo and its officers and directors for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities.


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For the three months ended March 31, 2013 , LinnCo incurred total general and administrative expenses and certain offering costs of approximately $12 million , of which approximately $2 million had been paid by LINN Energy on LinnCo’s behalf as of March 31, 2013 .  The expenses included approximately $11 million of transaction costs related to professional services rendered by third parties in connection with the pending acquisition of Berry (see Note 2).  The expenses also included approximately $462,000 related to services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses.  The offering costs of approximately $361,000 were incurred in connection with LinnCo’s registration statement on Form S-4 related to the pending acquisition of Berry.  All expenses and costs paid by LINN Energy on LinnCo’s behalf are accounted for as investment at cost.


In February 2013, the Company paid approximately $25 million in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy.


Other


One of the Company’s directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company.  For the three months ended March 31, 2013, the Company paid approximately $6 million to Superior and its subsidiaries for services rendered to the Company.  The transactions associated with these payments were consummated on terms equivalent to those that prevail in arm’s-length transactions.


Note 15 – Subsidiary Guarantors


The November 2019 Senior Notes, the May 2019 Senior Notes, the 2010 Issued Notes and the Original Senior Notes are guaranteed by all of the Company’s material subsidiaries.  The Company is a holding company and has no independent assets or operations of its own, the guarantees under each series of notes are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor.  There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.


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

The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance.  The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control.  The Company’s actual results could differ materially from those discussed in these forward-looking statements.  Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement” below and in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2012, and elsewhere in the Annual Report.  In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.


The following discussion and analysis should be read in conjunction with the financial statements and related notes included in this Quarterly Report on Form 10-Q and in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.  A reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”


Executive Overview


LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.  LINN Energy is an independent oil and natural gas company that began operations in March 2003 and completed its initial public offering in January 2006.  The Company’s properties are located in eight operating regions in the United States (“U.S.”):


|  |                                                                                                                                                                            
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays);

|  |                                                                                                      
|- | -----------------------------------------------------------------------------------------------------
|• | Hugoton Basin, which includes properties located primarily in Kansas and the Shallow Texas Panhandle;

|  |                                                                           
|- | --------------------------------------------------------------------------
|• | Green River Basin, which includes properties located in southwest Wyoming;

|  |                                                                            
|- | ---------------------------------------------------------------------------
|• | Permian Basin, which includes areas in west Texas and southeast New Mexico;

|  |                                                                                                                         
|- | ------------------------------------------------------------------------------------------------------------------------
|• | Williston/Powder River Basin, which includes the Bakken formation in North Dakota and the Powder River Basin in Wyoming;

|  |                                                                                                                                       
|- | --------------------------------------------------------------------------------------------------------------------------------------
|• | Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois;

|  |                                                                               
|- | ------------------------------------------------------------------------------
|• | California, which includes the Brea Olinda Field of the Los Angeles Basin; and

|  |                                                             
|- | ------------------------------------------------------------
|• | East Texas, which includes properties located in east Texas.

Results for the three months ended March 31, 2013, included the following:


|  |                                                                                                                     
|- | --------------------------------------------------------------------------------------------------------------------
|• | oil, natural gas and NGL sales of approximately $463 million compared to $349 million for the first quarter of 2012;

|  |                                                                                               
|- | ----------------------------------------------------------------------------------------------
|• | average daily production of 796 MMcfe/d compared to 471 MMcfe/d for the first quarter of 2012;

|  |                                                                                             
|- | --------------------------------------------------------------------------------------------
|• | net loss of approximately $222 million compared to $6 million for the first quarter of 2012;

|  |                                                                                                                               
|- | ------------------------------------------------------------------------------------------------------------------------------
|• | net cash provided by operating activities of approximately $335 million compared to $36 million for the first quarter of 2012;

|  |                                                                                                                                        
|- | ---------------------------------------------------------------------------------------------------------------------------------------
|• | capital expenditures, excluding acquisitions, of approximately $272 million compared to $259 million for the first quarter of 2012; and

|  |                                                                                                               
|- | --------------------------------------------------------------------------------------------------------------
|• | 113 wells drilled (all successful) compared to 81 wells drilled (79 successful) for the first quarter of 2012.

Acquisition – Pending


On February 20, 2013, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry Petroleum Company (“Berry”) entered into a definitive merger agreement under which LinnCo would acquire all of the outstanding common shares of Berry.  Under the terms of the agreement, Berry’s shareholders will receive 1.25 LinnCo common shares for each Berry common share they own.  This transaction, which is expected to be a tax-free exchange to Berry’s shareholders, represents value of $46.2375 per common share, based on the closing price of LinnCo common shares on February 20, 2013, the last trading day before the public announcement.


The transaction has a preliminary value of approximately $4.4 billion, including the assumption of debt, and is expected to close by July 1, 2013, subject to approvals by Berry and LinnCo shareholders, LINN Energy unitholders and regulatory


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agencies.  In connection with the proposed transaction described above, LinnCo will contribute Berry to LINN Energy in exchange for newly issued LINN Energy units, after which Berry will be an indirect wholly owned subsidiary of LINN Energy.


Divestiture – Pending


On April 3, 2013, the Company entered into, through one of its wholly owned subsidiaries, a definitive asset purchase and sale agreement, together with the Company’s partners, Panther Energy, LLC and Red Willow Mid-Continent, LLC, to sell its interests in certain oil and natural gas properties located in the Mid-Continent region to Midstates Petroleum Company, Inc.  The sale price for the Company’s portion of its interests in the properties is approximately $220 million, subject to closing adjustments.  The sale is anticipated to close on or about June 1, 2013, subject to closing conditions.  There can be no assurance that all of the conditions to closing will be satisfied.  The Company plans to use the net proceeds from the sale to repay borrowings under the Company’s Credit Facility.


Financing and Liquidity


The Company’s Fifth Amended and Restated Credit Agreement (“Credit Facility”) provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) maximum commitment amount.  On April 24, 2013, the Company entered into a new Amended and Restated Credit Agreement increasing the maximum commitment amount from $3.0 billion to $4.0 billion and extending the maturity date from April 2017 to April 2018.  The borrowing base remains unchanged at $4.5 billion and does not include any assets to be acquired in the pending transaction with Berry.  The amended and restated agreement is substantially similar to the previous Credit Facility with revisions to permit the transactions related to the acquisition of Berry and to designate Berry as an unrestricted subsidiary under the agreement.  When considering the increased maximum commitment amount, borrowing capacity was approximately $2.7 billion at March 31, 2013, not including any proceeds to be received from the pending Panther sale.





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Results of Operations


Three Months Ended March 31, 2013, Compared to Three Months Ended March 31, 2012


Three Months Ended March 31,20132012Variance(in thousands)Revenues and other:Natural gas sales$134,744$65,785$68,959Oil sales241,798231,16510,633NGL sales86,19051,94534,245Total oil, natural gas and NGL sales462,732348,895113,837Gains (losses) on oil and natural gas derivatives(108,370)2,031(110,401)Marketing and other revenues14,6983,16411,534369,060354,09014,970Expenses:Lease operating expenses88,72171,63617,085Transportation expenses27,18310,56216,621Marketing expenses7,3746926,682General and administrative expenses(1)58,56643,32115,245Exploration costs2,2264101,816Depreciation, depletion and amortization197,441117,27680,165Impairment of long-lived assets57,053—57,053Taxes, other than income taxes39,67125,19514,476Losses on sale of assets and other, net3,1721,4941,678481,407270,586210,821Other income and (expenses)(102,002)(80,788)(21,214)Income (loss) before income taxes(214,349)2,716(217,065)Income tax expense7,5368,918(1,382)Net loss$(221,885)$(6,202)$(215,683)





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|(1) | General and administrative expenses for the three months ended March 31, 2013, and March 31, 2012, include approximately $10 million and $8 million, respectively, of noncash unit-based compensation expenses.




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Three Months Ended March 31,20132012VarianceAverage daily production:Natural gas (MMcf/d)44322993%Oil (MBbls/d)30.126.115%NGL (MBbls/d)28.714.2102%Total (MMcfe/d)79647169%Weighted average prices (unhedged):(1)Natural gas (Mcf)$3.38$3.167%Oil (Bbl)$89.13$97.25(8)%NGL (Bbl)$33.38$40.21(17)%Average NYMEX prices:Natural gas (MMBtu)$3.34$2.7422%Oil (Bbl)$94.37$102.93(8)%Costs per Mcfe of production:Lease operating expenses$1.24$1.67(26)%Transportation expenses$0.38$0.2552%General and administrative expenses(2)$0.82$1.01(19)%Depreciation, depletion and amortization$2.76$2.741%Taxes, other than income taxes$0.55$0.59(7)%





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|(1) | Does not include the effect of gains (losses) on derivatives.

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|(2) | General and administrative expenses for the three months ended March 31, 2013, and March 31, 2012, include approximately $10 million and $8 million, respectively, of noncash unit-based compensation expenses.




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Revenues and Other


Oil, Natural Gas and NGL Sales


Oil, natural gas and NGL sales increased approximately $114 million or 33% to approximately $463 million for the three months ended March 31, 2013, from approximately $349 million for the three months ended March 31, 2012, due to higher production volumes and higher natural gas prices partially offset by lower oil and NGL prices.  Higher natural gas prices resulted in an increase in revenues of approximately $9 million.  Lower oil and NGL prices resulted in a decrease in revenues of approximately $22 million and $18 million, respectively.


Average daily production volumes increased to 796 MMcfe/d during the three months ended March 31, 2013, from 471 MMcfe/d during the three months ended March 31, 2012.  Higher natural gas, NGL and oil production volumes resulted in an increase in revenues of approximately $60 million, $52 million and $33 million, respectively.


The following sets forth average daily production by region:


Three Months Ended March 31,20132012VarianceAverage daily production (MMcfe/d):Mid-Continent3242735119%Hugoton Basin14339104263%Green River Basin143—143—Permian Basin8089(9)(10)%Williston/Powder River Basin39211883%Michigan/Illinois3436(2)(4)%East Texas21—21—California1213(1)(8)%79647132569%


The increase in average daily production volumes in the Mid-Continent region primarily reflects the Company’s 2012 and 2013 capital drilling programs in the Granite Wash formation.  The increase in average daily production volumes in the Hugoton Basin region primarily reflects the impact of the acquisition from BP America Production Company (“BP”) on March 30, 2012.  Average daily production volumes in the Green River Basin region reflect the impact of the acquisition from BP in July 2012.  The decrease in average daily production volumes in the Permian Basin region primarily reflects downtime from third parties’ infrastructure as well as the impact of winter weather.  The increase in average daily production volumes in the Williston/Powder River Basin region reflects the impact of the joint-venture agreement entered into with Anadarko Petroleum Corporation in April 2012.  The Michigan/Illinois and California regions consist of low-decline asset bases and continue to produce at consistent levels.  Average daily production volumes in the East Texas region reflect the impact of the acquisition in May 2012.


Gains (Losses) on Oil and Natural Gas Derivatives


Gains (losses) on oil and natural gas derivatives decreased by approximately $110 million to losses of approximately $108 million for the three months ended March 31, 2013, from gains of approximately $2 million for the three months ended March 31, 2012.  Gains (losses) on oil and natural gas derivatives decreased primarily due to the changes in fair value on unsettled derivatives contracts, partially offset by increased cash settlements during the period.  The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives.  If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.


During the three months ended March 31, 2013, the Company had commodity derivative contracts for approximately 107% of its natural gas production, including natural gas put options used to indirectly hedge NGL revenues, and 136% of its oil production.  During the three months ended March 31, 2012, the Company had commodity derivative contracts for approximately 114% of its natural gas production, including natural gas put options used to indirectly hedge NGL revenues, and 108% of its oil production.


The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis.  See Item 3. “Quantitative and Qualitative Disclosures About Market


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


Risk” and Note 7 and Note 8 for additional information about the Company’s commodity derivatives.  For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.


Marketing and Other Revenues


Marketing revenues represent third-party activities associated with company-owned gathering systems and plants.  Marketing and other revenues increased by approximately $12 million or 365% to approximately $15 million for the three months ended March 31, 2013, from approximately $3 million for the three months ended March 31, 2012, primarily due to revenues generated from the Jayhawk natural gas processing plant acquired from BP on March 30, 2012.


Expenses


Lease Operating Expenses


Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses.  Lease operating expenses increased by approximately $17 million or 24% to approximately $89 million for the three months ended March 31, 2013, from approximately $72 million for the three months ended March 31, 2012.  Lease operating expenses increased primarily due to costs associated with properties acquired during 2012.  Lease operating expenses per Mcfe decreased to $1.24 per Mcfe for the three months ended March 31, 2013, from $1.67 per Mcfe for the three months ended March 31, 2012, primarily due to lower rates on newly acquired properties and cost saving initiatives.


Transportation Expenses


Transportation expenses increased by approximately $16 million or 157% to approximately $27 million for the three months ended March 31, 2013, from approximately $11 million for the three months ended March 31, 2012, primarily due to acquisitions in 2012.


Marketing Expenses


Marketing expenses represent third-party activities associated with company-owned gathering systems and plants.  Marketing expenses increased by approximately $7 million or 966% to approximately $7 million for the three months ended March 31, 2013, from approximately $692,000 for the three months ended March 31, 2012, primarily due to expenses associated with the Jayhawk natural gas processing plant acquired from BP on March 30, 2012.


General and Administrative Expenses


General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees.  General and administrative expenses increased by approximately $16 million or 35% to approximately $59 million for the three months ended March 31, 2013, from approximately $43 million for the three months ended March 31, 2012.  The increase was primarily due to an increase in salaries and benefits related expenses of approximately $9 million, driven primarily by increased employee headcount, and an increase in acquisition related expenses of approximately $5 million.  Although general and administrative expenses increased, the unit rate decreased to $0.82 per Mcfe for the three months ended March 31, 2013, from $1.01 per Mcfe for the three months ended March 31, 2012, as a result of efficiencies gained from being a larger, more scalable organization.


Depreciation, Depletion and Amortization


Depreciation, depletion and amortization increased by approximately $80 million or 68% to approximately $197 million for the three months ended March 31, 2013, from approximately $117 million for the three months ended March 31, 2012.  Higher total production volumes were the primary reason for the increased expense.  Depreciation, depletion and amortization per Mcfe increased slightly to $2.76 per Mcfe for the three months ended March 31, 2013, from $2.74 per Mcfe for the three months ended March 31, 2012.


Impairment of Long-Lived Assets


During the three months ended March 31, 2013, the Company recorded a noncash impairment charge, before and after tax, of approximately $57 million associated with the write down of the carrying value of the Company’s assets held for sale (see Note 2).  The Company recorded no impairment charge for the three months ended March 31, 2012.


Taxes, Other Than Income Taxes


Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, increased by approximately $15 million or 58% to approximately $40 million for the three months ended March 31, 2013, from approximately $25 million for the three months ended March 31, 2012.  Severance taxes, which are a function of revenues generated from production,


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


increased approximately $2 million compared to the three months ended March 31, 2012, primarily due to higher production volumes partially offset by lower oil and NGL prices.  Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased by approximately $12 million compared to the three months ended March 31, 2012, primarily due to property acquisitions in 2012 and higher rates on the Company’s base properties.


Other Income and (Expenses)


Three Months Ended March 31,20132012Variance(in thousands)Interest expense, net of amounts capitalized$(100,359)$(77,519)$(22,840)Other, net(1,643)(3,269)1,626$(102,002)$(80,788)$(21,214)


Other income and (expenses) increased by approximately $21 million for the three months ended March 31, 2013, compared to the three months ended March 31, 2012.  Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with the November 2019 Senior Notes, as defined in Note 6, and amendments made to the Company’s Credit Facility during 2012.  See “Debt” in “Liquidity and Capital Resources” below for additional details.


Income Tax Expense


The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders.  Limited liability companies are subject to Texas margin tax.  In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes.  The Company recognized income tax expense of approximately $8 million for the three months ended March 31, 2013, compared to income tax expense of approximately $9 million for the three months ended March 31, 2012.  Income tax expense decreased primarily due to lower income from the Company’s taxable subsidiaries during the three months ended March 31, 2013, compared to the same period in 2012.


Net Loss


Net loss increased by approximately $216 million to approximately $222 million for the three months ended March 31, 2013, from approximately $6 million for the three months ended March 31, 2012.  The increase was primarily due to higher losses on oil and natural gas derivatives and higher expenses, including interest, partially offset by higher production revenues.  See discussions above for explanations of variances.


Liquidity and Capital Resources


The Company utilizes funds from debt and equity offerings, borrowings under its Credit Facility and net cash provided by operating activities for capital resources and liquidity.  To date, the primary use of capital has been for acquisitions and the development of oil and natural gas properties.  For the three months ended March 31, 2013, the Company’s capital expenditures, excluding acquisitions, were approximately $272 million.  For 2013, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $1.15 billion, including approximately $1 billion related to the Company’s oil and natural gas capital program and approximately $67 million related to its plant and pipeline capital.  This estimate reflects amounts for the development of properties associated with acquisitions (see Note 2), is under continuous review and subject to ongoing adjustment.  The Company expects to fund these capital expenditures primarily with net cash provided by operating activities and borrowings under its Credit Facility.


As the Company pursues growth, it continually monitors the capital resources available to meet future financial obligations and planned capital expenditures.  The Company’s future success in growing reserves and production volumes will be highly dependent on the capital resources available and its success in drilling for or acquiring additional reserves.  The Company actively reviews acquisition opportunities on an ongoing basis.  If the Company were to make significant additional acquisitions for cash, it would need to borrow additional amounts under its Credit Facility, if available, or obtain additional debt


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or equity financing.  The Company’s Credit Facility and indentures governing its November 2019 Senior Notes, May 2019 Senior Notes, 2010 Issued Senior Notes and Original Senior Notes impose certain restrictions on the Company’s ability to obtain additional debt financing.  Based upon current expectations, the Company believes liquidity and capital resources will be sufficient to conduct its business and operations.  For additional information about the risk that the Company may not have sufficient net cash provided by operating activities to maintain its distribution and other risk factors that could affect the Company, see Item 1A. “Risk Factors.”


Statements of Cash Flows


The following is a comparative cash flow summary:


Three Months Ended March 31,20132012Variance(in thousands)Net cash:Provided by operating activities(1)$334,594$35,513$299,081Used in investing activities(278,999)(1,460,555)1,181,556Provided by (used in) financing activities(50,804)1,448,112(1,498,916)Net increase in cash and cash equivalents$4,791$23,070$(18,279)





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|(1) | The three months ended March 31, 2012, are net of payments made for commodity derivative premiums of approximately $178 million.

Operating Activities


Cash provided by operating activities for the three months ended March 31, 2013, was approximately $335 million, compared to approximately $36 million for the three months ended March 31, 2012.  The increase was primarily due to no premiums paid for derivatives during the three months ended March 31, 2013, compared to approximately $178 million in premiums paid during the same period in 2012.  Premiums paid for commodity derivatives decreased primarily due to reduced acquisition activity during the three months ended March 31, 2013, as compared to the three months ended March 31, 2012.  Lower premiums and higher revenues primarily due to increased production volumes were partially offset by higher expenses.


Premiums paid during the three months ended March 31, 2012, were for commodity derivative contracts that hedge future production.  The Company hedges a substantial portion of its production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions.  The majority of the Company’s hedges are in the form of fixed price swaps, which are entered into on market terms and without cost.  The Company’s ability to enter into swaps is governed by covenants under its Credit Facility which limit the maximum percentage of forecasted future production that may be hedged using swaps to 80% for the current calendar year and the following four calendar years and 70% thereafter.  In prior years, the Company has chosen to purchase put options, primarily in connection with acquisitions, to hedge certain volumes in excess of volumes already hedged with swaps to achieve greater downside commodity price protection.  Put options require the payment of a premium, which the Company pays in cash at the time of execution and no additional amounts are payable in the future under the contracts.


When the Company evaluates new hedging plans, it considers a variety of factors, including general characteristics of the asset to be hedged, such as commodity type and expectations for production growth, general availability of a liquid market to enter into new hedges, volumes, prices and duration of swaps that comply with the Credit Facility covenants, and attributes associated with put options, such as time value, volatility and premiums for various strike prices relative to swap reference prices.  Specifically, for acquisitions which it chose to hedge in part with put options, the Company typically set a budget of approximately 10% of the acquisition contract price to purchase put options covering associated production volumes for multiple years into the future.


The appropriate level of production to be hedged is an ongoing consideration and is based on a variety of factors, including current and future expected commodity market prices, cost and availability of put option contracts, the level of acquisition activity and the Company’s overall risk profile, including leverage and size and scale considerations.  As a result, the appropriate percentage of production volumes to be hedged may change over time.  See Note 7 and Note 8 for additional details about the Company’s commodity derivatives.


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Investing Activities


The following provides a comparative summary of cash flow from investing activities:


Three Months Ended March 31,20132012(in thousands)Cash flow from investing activities:Acquisition of oil and natural gas properties and joint-venture funding$(15,128)$(1,230,304)Capital expenditures(261,647)(230,466)Proceeds from sale of properties and equipment and other(2,224)215$(278,999)$(1,460,555)


The primary use of cash in investing activities is for capital spending, including acquisitions and the development of the Company’s oil and natural gas properties.  The decrease was primarily due to the acquisition of properties in the Hugoton Basin region during the three months ended March 31, 2012, compared to no significant acquisitions during the same period in 2013.  See Note 2 for additional details of acquisitions.  Capital expenditures increased primarily due to capital additions for pipelines and supporting facilities in the Granite Wash formation, as well as development activities of properties acquired in 2012 in the Williston/Powder River Basin region.


Financing Activities


Cash used in financing activities for the three months ended March 31, 2013, was approximately $51 million, compared to cash provided by financing activities of approximately $1.4 billion for the three months ended March 31, 2012.  The decrease in financing cash flow needs was primarily attributable to decreased acquisitions activity during the three months ended March 31, 2013.  The following provides a comparative summary of proceeds from borrowings and repayments of debt:


Three Months EndedMarch 31,20132012(in thousands)Proceeds from borrowings:Credit facility$300,000$835,000Senior notes—1,799,802$300,000$2,634,802Repayments of debt:Credit facility$(145,000)$(1,700,000)


Debt


The Company’s Fifth Amended and Restated Credit Agreement (“Credit Facility”) provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount.  At March 31, 2013, the Credit Facility had a borrowing base of $4.5 billion with a maximum commitment amount of $3.0 billion.  The maturity date is April 2017.  At March 31, 2013, the borrowing capacity under the Credit Facility was approximately $1.7 billion, which includes a $5 million reduction in availability for outstanding letters of credit.


On April 24, 2013, the Company entered into a new Amended and Restated Credit Agreement increasing the maximum commitment amount from $3.0 billion to $4.0 billion and extending the maturity date from April 2017 to April 2018.  The borrowing base remains unchanged at $4.5 billion and does not include any assets to be acquired in the pending transaction with Berry.  The amended and restated agreement is substantially similar to the previous Credit Facility with revisions to permit the transactions related to the acquisition of Berry and to designate Berry as an unrestricted subsidiary under the agreement.  When considering the increased maximum commitment amount, borrowing capacity was approximately $2.7 billion at March 31, 2013, not including any proceeds to be received from the pending Panther sale.





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As of March 31, 2013, the Company was in compliance with all financial and other covenants of the Credit Facility.  If an event of default would occur and were continuing, the Company would be unable to make borrowings and its financial condition and liquidity would be adversely affected.  For information related to the Credit Facility, see Note 6.


The Company depends, in part, on its Credit Facility for future capital needs.  In addition, the Company has drawn on the Credit Facility to fund or partially fund quarterly cash distribution payments.  Absent such borrowings, the Company would have at times experienced a shortfall in cash available to pay the declared quarterly cash distribution.   For additional information, see “Distribution Practices” below.  If an event of default occurs and is continuing under the Credit Facility, the Company would be unable to make borrowings to fund distributions.  For additional information about this matter and other risk factors that could affect the Company, see Item 1A. “Risk Factors.”


Counterparty Credit Risk


The Company accounts for its commodity derivatives at fair value.  The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives.  The Credit Facility is secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral.  The Company does not receive collateral from its counterparties.  The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis.  In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.


Distributions


Under the Company’s limited liability company agreement, unitholders are entitled to receive a distribution of available cash, which includes cash on hand plus borrowings less any reserves established by the Company’s Board of Directors to provide for the proper conduct of the Company’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions over the next four quarters.  The following provides a summary of distributions paid by the Company during the three months ended March 31, 2013:


Date PaidPeriod Covered by DistributionDistributionPer UnitTotalDistributions(in millions)February 2013October 1 – December 31, 2012$0.725$171


On April 23, 2013, the Company’s Board of Directors declared a cash distribution of $0.725 per unit, or $2.90 per unit on an annualized basis, with respect to the first quarter of 2013.  The distribution, totaling approximately $171 million, will be paid on May 15, 2013, to unitholders of record as of the close of business on May 8, 2013.


Off-Balance Sheet Arrangements


The Company does not currently have any off-balance sheet arrangements.


Contingencies


The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations.  The Company has established reserves that management currently believes are adequate to provide for potential liabilities based upon its evaluation of these matters.  For a certain statewide class action royalty payment dispute where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the court, will result in no loss to the Company.  Discovery related to class certification has concluded.  Briefing and the hearing on class certification have been deferred by court order pending the Tenth Circuit Court of Appeals’ resolution of interlocutory appeals of two unrelated class certification orders.  As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any.  In addition, the Company is involved in various other disputes arising in the ordinary course of business.  The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of


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operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.


During the three months ended March 31, 2013, and March 31, 2012, the Company made no significant payments to settle any legal, environmental or tax proceedings.  The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary.  Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.


Commitments and Contractual Obligations


The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in the table of contractual obligations in the 2012 Annual Report on Form 10-K.  There have been no significant changes to the Company’s contractual obligations from December 31, 2012.  See Note 6 for additional information about the Company’s debt instruments.


Distribution Practices


The Company’s Board of Directors determines the appropriate level of distributions on a periodic basis in accordance with the provisions of the Company’s limited liability company agreement.  Management considers the timing and size of planned capital expenditures and long-term views about expected results in determining the amount of its distributions.  Capital spending and resulting production and net cash provided by operating activities do not typically occur evenly throughout the year due to a variety of factors which are difficult to predict, including rig availability, weather, well performance, the timing of completions and the commodity price environment.  Consistent with practices common to publicly traded partnerships, the Company’s Board of Directors historically has not varied the distribution it declares period to period based on uneven net cash provided by operating activities.  The Company’s Board of Directors reviews historical financial results and forecasts for future periods, including development activities, as well as considers the impact of significant acquisitions in making a determination to increase, decrease or maintain the current level of distribution.  To date in 2013, the Company’s Board of Directors has considered current shortfalls in net cash provided by operating activities after distributions and discretionary adjustments as well as forecasts of expected future net cash provided by operating activities and has decided to maintain the distribution at its current level.  If shortfalls are sustained over time and forecasts demonstrate expectations for continued future shortfalls, the Company’s Board of Directors may determine to reduce, suspend or discontinue paying distributions.


The Company intends to fund interest expense, a portion of its oil and natural gas development costs and distributions to unitholders from net cash provided by operating activities.  The Company funds premiums paid for derivatives, acquisitions and other capital expenditures primarily with proceeds from debt or equity offerings, borrowings under its Credit Facility or other external sources of funding.  Although it is the Company’s practice to acquire or modify derivative instruments with external sources of funding, any cash settlements on derivatives are reported as operating cash flows and may be used to fund distributions.  See below for details regarding the discretionary adjustments considered by the Company’s Board of Directors in assessing the appropriate distribution amount for each period, as well as the extent to which sources of funding have been sufficient for the periods presented:


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Three Months EndedMarch 31,20132012(in thousands)Net cash provided by operating activities$334,594$35,513Distributions to unitholders(170,954)(137,590)Excess (shortfall) of net cash provided by operating activities after distributions to unitholders163,640(102,077)Discretionary adjustments considered by the Board of Directors:Premiums paid for derivatives(1)—177,541Cash received for acquisitions – revenues less operating expenses(2)—39,093Discretionary reductions for a portion of oil and natural gas development costs(3)(110,298)(67,369)Provision for legal matters(4)—635Changes in operating assets and liabilities and other, net(5)(73,762)(24,275)Excess (shortfall) of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors(6)$(20,420)$23,548


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|(1) | Represent premiums paid for derivatives during the period.  The Company considers the cost of premiums paid for derivatives as an investment related to its underlying oil and natural gas properties.  The Company’s statements of cash flows, prepared in accordance with GAAP, present cash settlements on derivatives and premiums paid for derivatives as operating activities.  However, for purposes of determining the amount available for distribution to unitholders, the Company considers premiums paid for derivatives as investing activities, similar to the way the initial acquisition or development costs of the Company’s oil and natural gas properties are presented as investing activities while the cash flows generated from these assets are included in net cash provided by operating activities.  The consideration of premiums paid for derivatives as investing activities for purposes of determining the amount available for distribution differs from the presentation of derivatives activities, including premiums paid, as operating activities in the Company’s financial statements prepared in accordance with GAAP.

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|(2) | Represents adjustments to the purchase price of acquisitions and divestitures, based on the Company’s contractual right to revenues less operating expenses for periods from the effective date of a transaction to the closing date of a transaction.  When the Company is the buyer, it is legally entitled to revenues less operating expenses generated during this period, and the Company’s Board of Directors has historically made a discretionary adjustment to include this cash in the amount available for distribution.  Conversely, when the Company is the seller, the Company’s Board of Directors has historically made a discretionary adjustment to reduce this cash from the amount available for distribution during the period.

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|(3) | Represent discretionary reductions for a portion of oil and natural gas development costs, an estimated component of total development costs, which are amounts established by the Board of Directors at the end of each year for the following year, allocated across four quarters, that are intended to fully offset declines in production and proved developed producing reserves during the year as compared to the prior year.  The portion of oil and natural gas development costs includes estimated drilling and development costs associated with projects to convert a portion of non-producing reserves to producing status.  However, the amounts do not include the historical cost of acquired properties as those amounts have already been spent in prior periods, were financed primarily with external sources of funding and do not affect the Company’s ability to pay distributions in the current period.  The Company’s existing reserves, inventory of drilling locations and production levels will decline over time as a result of development and production activities.  Consequently, if the Company were to limit its total capital expenditures to this portion of oil and natural gas development costs and not acquire new reserves, total reserves would decrease over time, resulting in an inability to maintain production at current levels, which could adversely affect the Company’s ability to pay a distribution at the current level or at all.  However, the Company’s current total reserves do not include reserve additions that may result from converting existing probable and possible resources to additional proved reserves, potential additional discoveries or technological advancements on the Company’s existing acreage position.  For additional information, including the risks associated with the process for determining this amount, please also see Item 1A. “Risk Factors.”

See below for total development of oil and natural gas properties as presented in the statements of cash flows:


Three Months EndedMarch 31,20132012(in thousands)Total development of oil and natural gas properties$235,804$220,571


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|(4) | Represents reserves and settlements related to legal matters.

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


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|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(5) | Represents primarily working capital adjustments.  These adjustments may or may not impact cash provided by operating activities during the respective period, but are included as discretionary adjustments considered by the Company’s Board of Directors as the Board historically has not varied the distribution it declares period to period based on uneven cash flows.  The Company’s Board of Directors, when determining the appropriate level of cash distributions, excluded the impact of the timing of cash receipts and payments; as such, this adjustment is necessary to show the historical amounts considered by the Company’s Board of Directors in assessing the appropriate distribution amount for each period.

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|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(6) | Represents the excess (shortfall) of net operating cash flow after distributions to unitholders and discretionary adjustments.  Any excess was retained by the Company for future operations, future capital expenditures, future debt service or other future obligations.  Any shortfall was funded with cash on hand and/or borrowings under the Company’s Credit Facility.

A summary of the significant sources and uses of funding for the respective periods is presented below:





Three Months EndedMarch 31,20132012(in thousands)Net cash provided by operating activities$334,594$35,513Distributions to unitholders(170,954)(137,590)Excess (shortfall) of net operating cash flow after distributions to unitholders163,640(102,077)Plus (less):Net cash provided by financing activities (excluding distributions to unitholders)120,1501,585,702Acquisition of oil and natural gas properties and joint-venture funding(15,128)(1,230,304)Development of oil and natural gas properties(235,804)(220,571)Purchases of other property and equipment(25,843)(9,895)Proceeds from sale of properties and equipment and other(2,224)215Net increase in cash and cash equivalents$4,791$23,070





Regulatory Matters


On August 15, 2012, the Environmental Protection Agency (“EPA”) issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs.  The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells.  These standards require that prior to January 1, 2015, owners/operators reduce volatile organic compounds emissions from natural gas not sent to the gathering line during well completion either by flaring or by capturing the gas using green completions with a completion combustion device.  Beginning January 1, 2015, operators must capture the gas and make it available for use or sale, which can be done through the use of green completions.  The standards are applicable to newly fractured wells as well as existing wells that are refractured.  Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment.  These rules may require changes to the Company’s operations, including the installation of new equipment to control emissions.


The Company cannot predict how future environmental laws and regulations may impact its properties or operations.  For the three months ended March 31, 2013, the Company did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of its facilities.  The Company is not aware of any environmental issues or claims that will require material capital expenditures during 2013 or that will otherwise have a material impact on its financial position, results of operations or cash flows.


Critical Accounting Policies and Estimates


The discussion and analysis of the Company’s financial condition and results of operations is based upon the condensed consolidated financial statements, which have been prepared in accordance with GAAP.  The preparation of these financial statements requires the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.  Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used.  The Company evaluates its estimates and assumptions on a regular basis.  The Company bases estimates on historical experience and various other assumptions that are


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


believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  Actual results may differ from these estimates and assumptions used in the preparation of financial statements.


Recently Issued Accounting Standards


For a discussion of recently issued accounting standards, see Note 1 of Notes to Condensed Consolidated Financial Statements.


Cautionary Statement


This Quarterly Report on Form 10-Q contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond the Company’s control.  These statements may include content about the Company’s:


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|• | business strategy;

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|• | acquisition strategy;

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|• | financial strategy;

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|• | ability to maintain or grow distributions;

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|• | drilling locations;

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|• | oil, natural gas and NGL reserves;

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|• | realized oil, natural gas and NGL prices;

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|• | production volumes;

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|• | lease operating expenses, general and administrative expenses and development costs;

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|- | -----------------------------
|• | future operating results; and

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|• | plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, are forward-looking statements.  These forward-looking statements may be found in Item 2.  In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.


The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on Company expectations, which reflect estimates and assumptions made by Company management.  These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors.  Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control.  In addition, management’s assumptions may prove to be inaccurate.  The Company cautions that the forward-looking statements contained in this Quarterly Report on For m 10-Q are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the forward-looking statements or events will occur.  Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors set forth in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q and in  the Annual Report on Form 10-K for the year ended December 31, 2012, and elsewhere in the Annual Report.  The forward-looking st atements speak only as of the date made and, other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.


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|Item 3. | Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about potential exposure to market risks.  The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates.  The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.  This forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures.  All of the Company’s market risk sensitive instruments were entered into for purposes other than trading.


The following should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Company’s 2012 Annual Report on Form 10-K.  A reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”


Commodity Price Risk


An important part of the Company’s business strategy includes hedging a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions.  The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production.  As a result, currently, the Company directly hedges only its oil and natural gas production.  By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices.


The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside.  The Company enters into these transactions with respect to a portion of its projected production to provide an economic hedge of the risk related to the future commodity prices received.  The Company does not enter into derivative contracts for trading purposes.  There have been no significant changes to the Company’s objectives, general strategies or instruments used to manage the Company’s commodity price risk exposures from the year ended December 31, 2012.


The Company maintains a substantial portion of its hedges in the form of swap contracts.  From time to time, the Company has chosen to purchase put option contracts primarily in connection with acquisition activity to hedge volumes in excess of those already hedged with swap contracts.  The appropriate level of production to be hedged is an ongoing consideration and is based on a variety of factors, including current and future expected commodity market prices, cost and availability of put option contracts, the level of acquisition activity and the Company’s overall risk profile, including leverage and size and scale considerations.  As a result, the appropriate percentage of production volumes to be hedged may change over time.  To date in 2013, the Company has not purchased any put options.


In certain historical periods, the Company paid an incremental premium to increase the fixed price floors on existing put options because the Company typically hedges multiple years in advance and in some cases commodity prices had increased significantly beyond the initial hedge prices.  As a result, the Company determined that the existing put option strike prices did not provide reasonable downside protection in the context of the current market.


At March 31, 2013, the fair value of fixed price swaps and put contracts was a net asset of approximately $714 million.  A 10% increase in the index oil and natural gas prices above the March 31, 2013, prices would result in a net liability of approximately $157 million, which represents a decrease in the fair value of approximately $871 million; conversely, a 10% decrease in the index oil and natural gas prices would result in a net asset of approximately $1.6 billion, which represents an increase in the fair value of approximately $894 million.


At December 31, 2012, the fair value of fixed price swaps and put option contracts was a net asset of approximately $899 million.  A 10% increase in the index oil and natural gas prices above December 31, 2012, prices would result in a net liability of approximately $29 million, which represents a decrease in the fair value of approximately $928 million; conversely, a 10% decrease in the index oil and natural gas prices below December 31, 2012, prices would result in a net asset of approximately $1.8 billion, which represents an increase in the fair value of approximately $946 million.


The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis.  Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.  Company management validates the


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data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets.


The prices of oil, natural gas and NGL have been extremely volatile, and the Company expects this volatility to continue.  Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for such commodities, market uncertainty and a variety of additional factors that are beyond its control.  Actual gains or losses recognized related to the Company’s derivative contracts will likely differ from those estimated at March 31, 2013, and December 31, 2012, and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.


The Company cannot be assured that its counterparties will be able to perform under its derivative contracts.  If a counterparty fails to perform and the derivative arrangement is terminated, the Company’s cash flow and ability to pay distributions could be impacted.


Interest Rate Risk


At March 31, 2013, the Company had long-term debt outstanding under its Credit Facility of approximately $1.3 billion, which incurred interest at floating rates (see Note 6).  A 1% increase in the London Interbank Offered Rate (“LIBOR”) would result in an estimated $13 million increase in annual interest expense.


At December 31, 2012, the Company had long-term debt outstanding under its Credit Facility of approximately $1.2 billion, which incurred interest at floating rates.  A 1% increase in the LIBOR would result in an estimated $12 million increase in annual interest expense.


Counterparty Credit Risk


The Company accounts for its commodity derivatives at fair value on a recurring basis (see Note 8).  The fair value of these derivative financial instruments includes the impact of assumed credit risk adjustments, which are based on the Company’s and counterparties’ published credit ratings, public bond yield spreads and credit default swap spreads, as applicable.


At March 31, 2013, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 2.47%.  A 1% increase in the average public bond yield spread would result in an estimated $58,000 increase in net income for the three months ended March 31, 2013.  At March 31, 2013, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 2.56%.  A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $10 million decrease in net income for the three months ended March 31, 2013.


At December 31, 2012, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 2.47%.  A 1% increase in the average public bond yield spread would result in an estimated $131,000 increase in net income for the year ended December 31, 2012.  At December 31, 2012, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 3.22%.  A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $9 million decrease in net income for the year ended December 31, 2012.


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Item 4.    Controls and Procedures


Evaluation of Disclosure Controls and Procedures


The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, and the Company’s Audit Committee of the Board of Directors, as appropriate, to allow timely decisions regarding required disclosure.  In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.


The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report.  Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2013.


Changes in the Company’s Internal Control Over Financial Reporting


The Company’s management is also responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act.  The Company’s internal controls were designed to provide reasonable assurance as to the reliability of its financial reporting and the preparation and presentation of the condensed consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States.


Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements.  Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


There were no changes in the Company’s internal controls over financial reporting during the first quarter of 2013 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.


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Part II - Other Information


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|Item 1. | Legal Proceedings

For a discussion of legal proceedings, see Note 10 of Notes to Condensed Consolidated Financial Statements.


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|-------- | ------------
|Item 1A. | Risk Factors

Our business has many risks.  Factors that could materially adversely affect our business, financial position, results of operations, liquidity or the trading price of our units are described in Item 1A. “Risk Factors” in our Amendment No. 1 to the Annual Report on Form 10-K/A for the year ended December 31, 2012.  As of the date of this report, these risk factors have not changed materially.  This information should be considered carefully, together with other information in this report and other reports and materials we file with the United States Securities and Exchange Commission (“SEC”).


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

Issuer Purchases of Equity Securities


In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases.  The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time.  The Company did not repurchase any units during the three months ended March 31, 2013.  At March 31, 2013, approximately $56 million was available for unit repurchase under the program.


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|Item 3. | Defaults Upon Senior Securities

None


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|Item 4. | Mine Safety Disclosures

Not applicable


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|Item 5. | Other Information

The Company is a limited liability company and its units representing limited liability company interests (“units”) are listed on the NASDAQ Global Select Market.  The SEC’s taxonomy for interactive data reporting does not contain tags that include the term “units” for all existing equity accounts; therefore, in certain instances, the Company has used tags that refer to “shares” or “stock” rather than “units” in its interactive data exhibit.  These tags were selected to enhance comparability between the Company and its peers and it should not be inferred from the usage of these tags that an investment in the Company is in any form other than “units” as described above.  The Company’s interactive data files are included as Exhibit 101 to this Quarterly Report on Form 10-Q.


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|        |         
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|Item 6. | Exhibits

Exhibit NumberDescription2.1—Agreement and Plan of Merger, dated as of February 20, 2013, by and among Berry Petroleum Company, Bacchus HoldCo, Inc., Bacchus Merger Sub, Inc., LinnCo, LLC, Linn Acquisition Company, LLC and Linn Energy, LLC (incorporated herein by reference to Annex A of Part I of the document included in the Registration Statement on Form S-4 (File No. 333-187484) filed on March 22, 2013)2.2—Contribution Agreement, dated as of February 20, 2013, by and between LinnCo, LLC and Linn Energy, LLC (incorporated herein by reference to Annex B of Part I of the document included in the Registration Statement on Form S-4 (File No. 333-187484)  filed on March 22, 2013)2.3—Asset Purchase and Sale Agreement, dated as of April 3, 2013, between Linn Energy Holdings, LLC, Panther Energy, LLC and Red Willow Mid-Continent, LLC, as Sellers and Midstates Petroleum Company, Inc., as Buyer (incorporated herein by reference to Exhibit 2.3 to Quarterly Report on Form 10-Q filed on April 25, 2013)3.1—Amendment No. 1, dated April 23, 2013, to Third Amended and Restated LLC Agreement of Linn Energy, LLC, dated September 3, 2010 (incorporated herein by reference to Exhibit 3.1 to Quarterly Report on Form 10-Q filed on April 25, 2013)10.1—Sixth Amended and Restated Credit Agreement dated as of April 24, 2013, among Linn Energy, LLC as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and the Lenders and agents Party thereto (incorporated herein by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed on April 25, 2013)31.1*—Section 302 Certification of Mark E. Ellis, Chairman, President and Chief Executive Officer of Linn Energy, LLC31.2*—Section 302 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC32.1*—Section 906 Certification of Mark E. Ellis, Chairman, President and Chief Executive Officer of Linn Energy, LLC32.2*—Section 906 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC101.INS—XBRL Instance Document (previously furnished as Exhibit 101.INS to Quarterly Report on Form 10-Q filed on April 25, 2013)101.SCH—XBRL Taxonomy Extension Schema Document (previously furnished as Exhibit 101.SCH to Quarterly Report on Form 10-Q filed on April 25, 2013)101.CAL—XBRL Taxonomy Extension Calculation Linkbase Document (previously furnished as Exhibit 101.CAL to Quarterly Report on Form 10-Q filed on April 25, 2013)101.DEF—XBRL Taxonomy Extension Definition Linkbase Document (previously furnished as Exhibit 101.DEF to Quarterly Report on Form 10-Q filed on April 25, 2013)101.LAB—XBRL Taxonomy Extension Label Linkbase Document (previously furnished as Exhibit 101.LAB to Quarterly Report on Form 10-Q filed on April 25, 2013)101.PRE—XBRL Taxonomy Extension Presentation Linkbase Document (previously furnished as Exhibit 101.PRE to Quarterly Report on Form 10-Q filed on April 25, 2013)





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|* | Filed herewith.










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SIGNATURE


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.


LINN ENERGY, LLC(Registrant)Date: November 5, 2013/s/ David B. RottinoDavid B. RottinoSenior Vice President of Finance, Business Developmentand Chief Accounting Officer(As Duly Authorized Officer and Chief Accounting Officer)





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