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, 2011, 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, 2011. 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 IPO 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;

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

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

• 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 September 30, 2012, included the following:

• oil, natural gas and NGL sales of approximately $444 million compared to $292 million for the third quarter of 2011;

• average daily production of 782 MMcfe/d compared to 379 MMcfe/d for the third quarter of 2011;

• realized gains on commodity derivatives of approximately $109 million compared to $92 million for the third quarter of 2011;

• adjusted EBITDA of approximately $402 million compared to $243 million for the third quarter of 2011;

• adjusted net income of approximately $90 million compared to $79 million for the third quarter of 2011;

• capital expenditures, excluding acquisitions, of approximately $258 million compared to $211 million for the third quarter of 2011; and

• 95 wells drilled (94 successful) compared to 78 wells drilled (all successful) for the third quarter of 2011.

Results for the nine months ended September 30, 2012, included the following:

• oil, natural gas and NGL sales of approximately $1,140 million compared to $836 million for the nine months ended September 30, 2011;

• average daily production of 628 MMcfe/d compared to 350 MMcfe/d for the nine months ended September 30, 2011;

• realized gains on commodity derivatives of approximately $282 million compared to $190 million for the nine months ended September 30, 2011;

• adjusted EBITDA of approximately $1.0 billion compared to $717 million for the nine months ended September 30, 2011;

• adjusted net income of approximately $199 million compared to $224 million for the nine months ended September 30, 2011;

• capital expenditures, excluding acquisitions, of approximately $815 million compared to $461 million for the nine months ended September 30, 2011; and

• 276 wells drilled (272 successful) compared to 179 wells drilled (177 successful) for the nine months ended September 30, 2011.

Adjusted EBITDA and adjusted net income are non-GAAP financial measures used by management to analyze Company performance. Adjusted EBITDA is a measure used by Company management to evaluate cash flow and the Company's ability to sustain or increase distributions. The most significant reconciling items between net income (loss) and adjusted EBITDA are interest expense and noncash items, including the change in fair value of derivatives, and depreciation, depletion and amortization. Adjusted net income is used by Company management to evaluate its operational performance from oil and natural gas properties, prior to unrealized (gains) losses on derivatives, realized (gains) losses on canceled derivatives, realized gain on recovery of bankruptcy claim, impairment of long-lived assets, loss on extinguishment of debt and (gains) losses on sale of assets, net. See "Non-GAAP Financial Measures" on page 39 for a reconciliation of each non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Acquisitions

On July 31, 2012, the Company completed the acquisition of certain oil and natural gas properties in the Jonah Field located in the Green River Basin of southwest Wyoming from BP America Production Company ("BP") for total consideration of approximately $990 million. The acquisition included approximately 806 Bcfe of proved reserves as of the acquisition date.

On May 1, 2012, the Company completed the acquisition of certain oil and natural gas properties located in east Texas for total consideration of approximately $168 million. The acquisition included approximately 110 Bcfe of proved reserves as of the acquisition date.

On April 3, 2012, the Company entered into a joint-venture agreement
("Agreement") with an affiliate of Anadarko Petroleum Corporation ("Anadarko")
whereby the Company participates as a partner in the CO2 enhanced oil recovery development of the Salt Creek Field, located in the Powder River Basin of Wyoming. Anadarko assigned the Company 23% of its interest in the field in exchange for future funding of $400 million of Anadarko's development costs. As of September 30, 2012, the Company has paid approximately $119 million towards the future funding commitment. The acquisition included approximately 16 MMBoe (96 Bcfe) of proved reserves as of the Agreement date.

On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin in Kansas from BP for total consideration of approximately $1.16 billion. The acquisition included approximately 701 Bcfe of proved reserves as of the acquisition date. During the nine months ended September 30, 2012, the Company completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The Company, in the aggregate, paid approximately $52 million in total consideration for these properties.

Proved reserves as of the acquisition date for all of the above referenced acquisitions were estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month.

Financing and Liquidity

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 services 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 September 30, 2012, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.

In January 2012, the Company completed a public offering of units for net proceeds of approximately $674 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.

In March 2012, the Company issued $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (see Note 6) and used the net proceeds of approximately $1.77 billion to fund the Hugoton acquisition (see Note 2). The remaining proceeds were used to repay indebtedness under the Company's Credit Facility and for general corporate purposes.

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. In May 2012, the Company entered into an amendment to its Credit Facility to increase the borrowing base to $3.5 billion and extend the maturity date from April 2016 to April 2017. In July 2012, the Company entered into an amendment to its Credit Facility to increase the maximum commitment amount from $2.0 billion to $3.0 billion.

On May 8, 2012, the Company filed a registration statement on Form S-4 to register exchange notes that 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 notes do not apply to the exchange notes. On September 24, 2012, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $750 million outstanding principal amount of May 2019 Senior Notes for an equal amount of new May 2019 Senior Notes. The offer expired on October 23, 2012.

On October 17, 2012, LinnCo, LLC ("LinnCo"), a wholly owned subsidiary of LINN Energy at September 30, 2012, completed its initial public offering (the "LinnCo IPO") of 34,787,500 of its common shares representing limited liability company interests for net proceeds of approximately $1.2 billion. The net proceeds LinnCo received from the offering were used to acquire 34,787,500 LINN Energy units which are equal to the number of LinnCo shares sold in the offering. The Company used the proceeds from the sale of the units to LinnCo to pay the expenses of the offering and repay a portion of the outstanding indebtedness under its Credit Facility.

Results of Operations

Three Months Ended September 30, 2012, Compared to Three Months Ended
September 30, 2011
                                                     Three Months Ended
                                                       September 30,
                                                    2012           2011           Variance
                                                               (in thousands)
Revenues and other:
Natural gas sales                               $  101,984     $    66,667     $     35,317
Oil sales                                          247,354         178,559           68,795
NGL sales                                           94,744          47,256           47,488
Total oil, natural gas and NGL sales               444,082         292,482          151,600
Gains (losses) on oil and natural gas
derivatives (1)                                   (411,405 )       824,240       (1,235,645 )
Marketing and other revenues                        15,651           2,761           12,890
                                                    48,328       1,119,483       (1,071,155 )
Expenses:
Lease operating expenses                            91,990          62,907           29,083
Transportation expenses                             18,274           7,821           10,453
Marketing expenses                                  14,923             850           14,073
General and administrative expenses (2)             45,166          29,891           15,275
Exploration costs                                      390             503             (113 )
Depreciation, depletion and amortization           167,695          88,328           79,367
Taxes, other than income taxes                      37,885          20,875           17,010
(Gains) losses on sale of assets and other, net         16             358             (342 )
                                                   376,339         211,533          164,806
Other income and (expenses)                       (106,944 )       (67,461 )        (39,483 )
Income (loss) before income taxes                 (434,955 )       840,489       (1,275,444 )
Income tax benefit (expense)                         4,950          (2,862 )          7,812
Net income (loss)                               $ (430,005 )   $   837,627     $ (1,267,632 )

Adjusted EBITDA (3)                             $  402,446     $   243,266     $    159,180
Adjusted net income (3)                         $   89,847     $    78,554     $     11,293

(1) In September 2011, the Company canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in realized gains of approximately $27 million.

(2) General and administrative expenses for the three months ended September 30, 2012, and September 30, 2011, include approximately $7 million and $5 million, respectively, of noncash unit-based compensation expenses.

(3) This is a non-GAAP measure used by management to analyze the Company's performance. See "Non-GAAP Financial Measures" on page 39 for a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

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



                                             Three Months Ended
                                                September 30,
                                               2012           2011      Variance
Average daily production:
Natural gas (MMcf/d)                            409             170      141  %
Oil (MBbls/d)                                  30.8            22.6       36  %
NGL (MBbls/d)                                  31.4            12.2      157  %
Total (MMcfe/d)                                 782             379      106  %

Weighted average prices (hedged): (1)
Natural gas (Mcf)                        $     5.17         $  8.05      (36 )%
Oil (Bbl)                                $    92.98         $ 88.62        5  %
NGL (Bbl)                                $    32.83         $ 42.01      (22 )%

Weighted average prices (unhedged): (2)
Natural gas (Mcf)                        $     2.71         $  4.26      (36 )%
Oil (Bbl)                                $    87.22         $ 85.89        2  %
NGL (Bbl)                                $    32.83         $ 42.01      (22 )%

Average NYMEX prices:
Natural gas (MMBtu)                      $     2.80         $  4.19      (33 )%
Oil (Bbl)                                $    92.22         $ 89.76        3  %

Costs per Mcfe of production:
Lease operating expenses                 $     1.28         $  1.80      (29 )%
Transportation expenses                  $     0.25         $  0.22       14  %
General and administrative expenses (3)  $     0.63         $  0.86      (27 )%
Depreciation, depletion and amortization $     2.33         $  2.53       (8 )%
Taxes, other than income taxes           $     0.53         $  0.60      (12 )%

(1) Includes the effect of realized gains on derivatives of approximately $109 million and $65 million (excluding $27 million realized gains on canceled contracts) for the three months ended September 30, 2012, and September 30, 2011, respectively.

(2) Does not include the effect of realized gains (losses) on derivatives.

(3) General and administrative expenses for the three months ended September 30, 2012, and September 30, 2011, include approximately $7 million and $5 million, respectively, of noncash unit-based compensation expenses. Excluding these amounts, general and administrative expenses for the three months ended September 30, 2012, and September 30, 2011, were $0.54 per Mcfe and $0.70 per Mcfe, respectively. This is a non-GAAP measure used by management to analyze the Company's performance.

Revenues and Other

Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales increased approximately $152 million or 52% to approximately $444 million for the three months ended September 30, 2012, from approximately $292 million for the three months ended September 30, 2011, due to higher production volumes and higher oil prices partially offset by lower natural gas and NGL prices. Higher oil prices resulted in an increase in revenues of approximately $4 million. Lower natural gas and NGL prices resulted in a decrease in revenues of approximately $58 million and $26 million, respectively.

Average daily production volumes increased to 782 MMcfe/d during the three months ended September 30, 2012, from 379 MMcfe/d during the three months ended September 30, 2011. Higher natural gas, NGL and oil production volumes resulted in an increase in revenues of approximately $93 million, $74 million and $65 million, respectively.

The following sets forth average daily production by region:

                                         Three Months Ended
                                           September 30,
                                            2012           2011       Variance
Average daily production (MMcfe/d):
Mid-Continent                            351                198    153      78  %
Hugoton Basin                            150                 40    110     276  %
Green River Basin                         98                  -     98       -
Permian Basin                             82                 75      7       9  %
Michigan/Illinois                         35                 36     (1 )    (2 )%
Williston/Powder River Basin              28                 15     13      76  %
East Texas                                25                  -     25       -
California                                13                 15     (2 )   (12 )%
                                         782                379    403     106  %

The 78% increase in average daily production volumes in the Mid-Continent region primarily reflects the Company's 2011 and 2012 capital drilling programs in the Granite Wash formation, as well as the impact of the acquisition from Plains in December 2011. The increase in average daily production volumes in the Hugoton Basin region primarily reflects the impact of the acquisition from BP in March 2012. Average daily production volumes in the Green River Basin region reflect the impact of the acquisition from BP in July 2012. Average daily production volumes in the Permian Basin region reflect the impact of acquisitions in 2011 and subsequent development capital spending. The Michigan/Illinois and California regions consist of low-decline asset bases and continue to produce at consistent levels. 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 in April 2012. Average daily production volumes in the East Texas region reflect the impact of the acquisition in May 2012 (see Note 2).

Gains (Losses) on Oil and Natural Gas Derivatives 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 Risk," Note 7 and Note 8 for additional information about the Company's commodity derivatives. During the three months ended September 30, 2012, the Company had commodity derivative contracts for approximately 107% of its natural gas production and 104% of its oil production, which resulted in realized gains of approximately $109 million. During the three months ended September 30, 2011, the Company had commodity derivative contracts for approximately 103% of its natural gas production and 102% of its oil production and recognized realized gains of approximately $92 million (including realized gains on canceled contracts of approximately $27 million). Unrealized gains and losses result from changes in market valuations of derivatives 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, unrealized losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, unrealized gains are recognized. During the third quarter of 2012, expected future oil and natural gas prices increased, which resulted in net unrealized losses of approximately $520 million for the three months ended September 30, 2012. During the third quarter of 2011, expected future oil and natural gas prices decreased, which resulted in net unrealized gains on derivatives of approximately $732 million for the three months ended September 30, 2011. 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 $13 million or 467% to approximately $16 million for the three months ended September 30, 2012, from approximately $3 million for the three months ended September 30, 2011, primarily due to the acquisition of the Jayhawk natural gas processing plant from BP in March 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 $29 million or 46% to approximately $92 million for the three months ended September 30, 2012, from approximately $63 million for the three months ended September 30, 2011. Lease operating expenses increased primarily due to costs associated with properties acquired during 2011 and 2012 (see Note 2). Lease operating expenses per Mcfe decreased to $1.28 per Mcfe for the three months ended September 30, 2012, from $1.80 per Mcfe for the three months ended September 30, 2011, primarily due to lower rates on newly acquired properties.

Transportation Expenses
Transportation expenses increased by approximately $10 million or 134% to approximately $18 million for the three months ended September 30, 2012, from approximately $8 million for the three months ended September 30, 2011, primarily due to acquisitions in late 2011 and early 2012.

Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems and plants. Marketing expenses increased by approximately $14 million or 1,656% to approximately $15 million for the three months ended September 30, 2012, from approximately $1 million for the three months ended September 30, 2011, primarily due to the acquisition of the Jayhawk natural gas processing plant from BP in March 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 $15 million or 51% to approximately $45 million for the three months ended September 30, 2012, from approximately $30 million for the three months ended September 30, 2011. 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 $6 million. General and administrative expenses per Mcfe decreased to $0.63 per Mcfe for the three months ended September 30, 2012, from $0.86 per Mcfe for the three months ended September 30, 2011, due to higher production volumes.

Depreciation, Depletion and Amortization Depreciation, depletion and amortization increased by approximately $80 million or 90% to approximately $168 million for the three months ended September 30, 2012, from approximately $88 million for the three months ended September 30, 2011. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per Mcfe decreased to $2.33 per Mcfe for the three months ended September 30, 2012, from $2.53 per Mcfe for the three months ended September 30, 2011, primarily due to higher production volumes associated with newly acquired properties with lower depletion rates.

Taxes, Other Than Income Taxes
Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, increased by approximately $17 million or 82% to approximately $38 million for the three months ended September 30, 2012, from approximately $21 million for the three months ended September 30, 2011. Severance taxes, which are a function of revenues generated from production, increased approximately $6 million compared to the three months ended September 30, 2011, primarily due to higher production volumes partially offset by lower natural gas and NGL prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased by approximately $11 million compared to the three months ended September 30, 2011, primarily due to property acquisitions in 2011 and 2012 and higher rates on the Company's base properties.

. . .