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•	grow through acquisition of long-life, high quality properties;

•	efficiently operate and develop acquired properties; and

•	reduce cash flow volatility through hedging.

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•	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.

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(1)	Does not include optimization projects.

(1)	The Company had 12 operated wells with multiple completions at December 31, 2012.

(2)	The Company had no nonoperated wells with multiple completions at December 31, 2012.

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

(2)	General and administrative expenses for the years ended December 31, 2012, December 31, 2011, and December 31, 2010, include approximately $28 million, $21 million and $13 million, respectively, of noncash unit-based compensation expenses.

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(1)	This measure is not intended to represent the market value of estimated reserves.

(2)	In accordance with Securities and Exchange Commission (“SEC”) regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.

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•	require the acquisition of various permits before drilling commences;

•	require the installation of expensive pollution control equipment;

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•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

•	limit or prohibit drilling activities on lands lying within wilderness, wetlands, areas inhabited by endangered species and other protected areas;

•	require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

•	impose substantial liabilities for pollution resulting from operations; and

•	with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

•	Clean Air Act, and its amendments, which governs air emissions;

•	Clean Water Act, which governs discharges to and excavations within the waters of the U.S.;

•	Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), which imposes liability where hazardous releases have occurred or are threatened to occur (commonly known as “Superfund”);

•	Energy Independence and Security Act of 2007, which prescribes new fuel economy standards and other energy saving measures;

•	National Environmental Policy Act, which governs oil and natural gas production activities on federal lands;

•	Resource Conservation and Recovery Act (“RCRA”), which governs the management of solid waste;

•	Safe Drinking Water Act, which governs the underground injection and disposal of wastewater; and

•	U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages.

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•	business strategy;

•	acquisition strategy;

•	financial strategy;

•	ability to maintain or grow distributions;

•	drilling locations;

•	oil, natural gas and NGL reserves;

•	realized oil, natural gas and NGL prices;

•	production volumes;

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

•	future operating results; and

•	plans, objectives, expectations and intentions.

•	produced volumes of oil, natural gas and NGL;

•	prices at which oil, natural gas and NGL production is sold;

•	level of our operating costs;

•	payment of interest, which depends on the amount of our indebtedness and the interest payable thereon; and

•	level of our capital expenditures.

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•	availability of borrowings on acceptable terms under our Credit Facility to pay distributions;

•	the costs of acquisitions, if any;

•	fluctuations in our working capital needs;

•	timing and collectability of receivables;

•	restrictions on distributions contained in our Credit Facility and the indentures governing our November 2019 Senior Notes, May 2019 Senior Notes, 2010 Issued Senior Notes, and our Original Senior Notes, as defined in Note 6;

•	prevailing economic conditions;

•	access to credit or capital markets; and

•	the amount of cash reserves established by our Board of Directors for the proper conduct of our business.

•	Production from existing assets: Our revenues are dependent on how much oil, natural gas and NGLs we produce. If our existing assets under-perform for a prolonged period of time with respect to expected production volumes, our revenues may be lower than expected, and net cash provided by operating activities could be insufficient to pay our current distribution to unitholders.

•

NGL commodity prices: We have been and continue to be limited in our ability to effectively hedge our NGL production. As a result, we are subject to the current depressed price environment for NGLs, and in particular, ethane prices. If current price levels for NGLs continue into the future, our revenues and results of operations will be affected, and net cash provided by operating activities could be insufficient to pay our current distribution to unitholders.

•

Access to and cost of capital: Accretive acquisitions are an integral component of our business strategy. When revenues are expected to be lower as a result of under-performance of assets, weakening commodity prices on unhedged volumes or declining contract prices on hedged volumes, we seek to make accretive acquisitions of oil and natural gas properties to cover potential shortfalls in net cash provided by operating activities in order to maintain our distribution level. As a result of the pending SEC inquiry, we may be limited in our ability to access the capital markets at an acceptable cost or at all; thus our ability to make accretive acquisitions may be limited.

•	the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

•	the risk of title defects discovered after closing;

•	inaccurate assumptions about revenues and costs, including synergies;

•	significant increases in our indebtedness and working capital requirements;

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•	an inability to transition and integrate successfully or timely the businesses we acquire;

•	the cost of transition and integration of data systems and processes;

•	the potential environmental problems and costs;

•	the assumption of unknown liabilities;

•	limitations on rights to indemnity from the seller;

•	the diversion of management’s attention from other business concerns;

•	increased demands on existing personnel and on our corporate structure;

•	disputes arising out of acquisitions;

•	customer or key employee losses of the acquired businesses; and

•	the failure to realize expected growth or profitability.

•	unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

•	unable to obtain financing for these acquisitions on economically acceptable terms; or

•	outbid by competitors.

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•	the domestic and foreign supply of and demand for oil, natural gas and NGL;

•	the price and level of foreign imports;

•	the level of consumer product demand;

•	weather conditions;

•	overall domestic and global economic conditions;

•	political and economic conditions in oil and natural gas producing countries;

•	the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain price and production controls;

•	the impact of the U.S. dollar exchange rates on oil, natural gas and NGL prices;

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•	technological advances affecting energy consumption;

•	domestic and foreign governmental regulations and taxation;

•	the impact of energy conservation efforts;

•	the proximity and capacity of pipelines and other transportation facilities; and

•	the price and availability of alternative fuels.

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•	actual prices we receive for oil, natural gas and NGL;

•	the amount and timing of actual production;

•	the timing and success of development activities;

•	supply of and demand for oil, natural gas and NGL; and

•	changes in governmental regulations or taxation.

•	our proved reserves;

•	the level of oil, natural gas and NGL we are able to produce from existing wells;

•	the prices at which we are able to sell our oil, natural gas and NGL; and

•	our ability to acquire, locate and produce new reserves.

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•	the high cost, shortages or delivery delays of equipment and services;

•	unexpected operational events;

•	adverse weather conditions;

•	facility or equipment malfunctions;

•	title problems;

•	pipeline ruptures or spills;

•	compliance with environmental and other governmental requirements;

•	unusual or unexpected geological formations;

•	loss of drilling fluid circulation;

•	formations with abnormal pressures;

•	fires;

•	blowouts, craterings and explosions; and

•	uncontrollable flows of oil, natural gas and NGL or well fluids.

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•	an individual unitholder’s proportionate ownership interest in us may decrease;

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•	the relative voting strength of each previously outstanding unit may be reduced;

•	the amount of cash available for distribution per unit may decrease; and

•	the market price of the units may decline.

•	our limited liability company agreement gives our Board of Directors broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our management will use its reasonable discretion to establish and maintain cash reserves sufficient to fund our drilling program;

•	our management team, subject to oversight from our Board of Directors, determines the timing and extent of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuances of additional units and reserve adjustments, all of which will affect the amount of cash that we distribute to our unitholders; and

•	affiliates of our directors are not prohibited from investing or engaging in other businesses or activities that compete with the Company.

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•	the current trading price of our units may reflect a market assumption that the merger will be completed and a failure to complete or delays in completing the merger could result in a further decline in the price of our units;

•	we may not realize the benefits expected from the merger, including cost savings, increased production, enhanced financial and competitive position and diversification of operating locations and assets;

•	we will be required to pay certain costs relating to the merger, including certain investment banking, financing, legal and accounting fees and expenses, whether or not the merger is completed; and

•	we may be responsible, under certain circumstances, for the net losses resulting from the termination of the derivatives transactions entered into by Berry at our request on or after the date of the merger agreement, which net losses could be significant.

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•	market reaction to the announcement of the merger and the prospects of the combined company;

•	changes in our, Berry’s and LinnCo’s respective businesses, operations, assets, liabilities and prospects;

•	changes in market assessments of our, Berry’s or LinnCo’s business, operations, financial position and prospects;

•	market assessments of the likelihood that the merger will be completed;

•	interest rates, general market and economic conditions and other factors generally affecting the price of LinnCo common shares and Berry common stock;

•	the status of our SEC inquiry and litigation;

•	federal, state and local legislation, governmental regulation and legal developments in the businesses in which we, Berry and LinnCo operate; and

•	other factors beyond our, Berry’s and LinnCo’s control, including those described or referred to elsewhere in this “Risk Factors” section.

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If the price of LinnCo common shares increases between the date the merger agreement was signed or the date of the LinnCo annual meeting and the effective time of the merger, Berry stockholders will receive LinnCo common shares that have a market value upon completion of the merger that is greater than the market value of such shares calculated pursuant to the exchange ratio when the merger agreement was signed or the date of the LinnCo annual meeting, respectively. Therefore, while the number of LinnCo common shares to be issued per share of Berry common stock is fixed, the LinnCo common shareholders cannot be sure of the market value of the consideration that will be paid to Berry stockholders upon completion of the merger.

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If the price of LinnCo common shares declines between the date the merger agreement was signed or the date of the Berry special meeting and the effective time of the merger, including for any of the reasons described above, Berry stockholders will receive LinnCo common shares that have a market value upon completion of the merger that is less than the market value of such shares calculated pursuant to the exchange ratio on the date the merger agreement was signed or on the date of the Berry special meeting, respectively. Therefore, while the number of LinnCo common shares to be issued per share of Berry common stock is fixed, Berry stockholders cannot be sure of the market value of the LinnCo common shares they will receive upon completion of the merger or the market value of LinnCo common shares at any time after the completion of the merger.

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•	under the merger agreement, Berry may be required, under certain circumstances, to pay LinnCo a termination fee of $83.7 million or $25.7 million in respect of LinnCo’s expenses;

•	under the merger agreement, LinnCo may be required, under certain circumstances, to pay Berry a termination fee of $83.7 million or $25.7 million in respect of Berry’s expenses;

•	We, Berry and LinnCo will be required to pay certain costs relating to the merger, whether or not the merger is completed, such as legal, accounting, financial advisor and printing fees;

•	We, Berry and LinnCo would not realize the expected benefits of the merger;

•	under the merger agreement, we and each of Berry and LinnCo are subject to certain restrictions on the conduct of its business prior to completing the merger which may adversely affect its ability to execute certain of its business strategies;

•	matters relating to the merger may require substantial commitments of time and resources by Berry, LinnCo and our management, which could otherwise have been devoted to other opportunities that may have been beneficial to Berry, LinnCo and us as independent companies; and

•	We, Berry or LinnCo may be responsible for the net losses resulting from the termination of the derivative transactions entered into by Berry on or after the date of the merger agreement, which net losses could be significant.

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Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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(1)	Includes gains (losses) on sale of assets, net of taxes.

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(2)	Net of payments made for commodity derivative premiums of approximately $583 million, $134 million, $120 million, $94 million and $130 million for the years ended December 31, 2012, December 31, 2011, December 31, 2010, December 31, 2009, and December 31, 2008, respectively.

(1)

In accordance with Securities and Exchange Commission (“SEC”) regulations, reserves at December 31, 2012, December 31, 2011, December 31, 2010, and December 31, 2009, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. In accordance with SEC regulations, reserves at December 31, 2008, were estimated using year-end prices. The price used to estimate reserves is held constant over the life of the reserves.

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•	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.

•	oil, natural gas and NGL sales of approximately $1.6 billion compared to $1.2 billion in 2011;

•	average daily production of 671 MMcfe/d compared to 369 MMcfe/d in 2011;

•	net loss of approximately $387 million compared to net income of $438 million in 2011;

•	net cash provided by operating activities of approximately $351 million compared to $519 million in 2011;

•	capital expenditures, excluding acquisitions, of approximately $1.1 billion compared to $697 million in 2011; and

•	440 wells drilled (436 successful) compared to 294 wells drilled (292 successful) in 2011.

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(1)	During the year ended December 31, 2011, the Company canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in gains of approximately $27 million. The proceeds from the cancellation of the derivative contracts were reallocated within the Company’s derivatives portfolio.

(2)	General and administrative expenses for the years ended December 31, 2012, and December 31, 2011, include approximately $28 million and $21 million, respectively, of noncash unit-based compensation expenses.

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

(2)	General and administrative expenses for the years ended December 31, 2012, and December 31, 2011, include approximately $28 million and $21 million, respectively, of noncash unit-based compensation expenses.

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(1)	During the year ended December 31, 2011, the Company canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in gains of approximately $27 million. The proceeds from the cancellation of the derivative contracts were reallocated within the Company’s derivatives portfolio.

(2)	General and administrative expenses for the years ended December 31, 2011, and December 31, 2010, include approximately $21 million and $13 million, respectively, of noncash unit-based compensation expenses.

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

(2)	General and administrative expenses for the years ended December 31, 2011, and December 31, 2010, include approximately $21 million and $13 million, respectively, of noncash unit-based compensation expenses.

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(1)

Oil and natural gas capital costs expended include the costs of property acquisition, exploration and development activities conducted to add reserves and exclude asset retirement costs. The Company expects to incur development costs in the future for proved undeveloped reserves; such future costs are excluded from costs expended and are not considered in the reserve replacement metrics presented herein.

(2)	Reserve additions include proved reserves (developed and undeveloped) and reflect reserve revisions for prices and performance, extensions, discoveries and other additions and acquisitions, and do not include unproved reserve quantities.

(1)	Not meaningful due to the impact of a significant decrease in year-end natural gas prices at December 31, 2012, compared to December 31, 2011.

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(1)	The years ended December 31, 2012, December 31, 2011, and December 31, 2010, are net of payments made for commodity derivative premiums of approximately $583 million, $134 million and $120 million, respectively.

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(1)

Represents interest on the Credit Facility computed at the weighted average LIBOR of 1.97% through maturity in April 2017 and interest on the Original Senior Notes, May 2019 Senior Notes, November 2019 Senior Notes, and the 2010 Issued Senior Notes, as defined in Note 6, computed at fixed rates of 11.75%, 9.875%, 6.50%, 6.25%, 8.625% and 7.75% through maturities in May 2017, July 2018, May 2019, November 2019, April 2020 and February 2021, respectively.

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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

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(2)	Represent derivatives canceled prior to the contract settlement date. In 2011, commodity derivatives were canceled and the proceeds were reallocated within the Company’s derivatives portfolio. In 2010, interest rate swaps were canceled in connection with the issuances of certain fixed-rate senior notes.

(3)	Represent the recoveries of a bankruptcy claim against Lehman Brothers which was not a transaction occurring in the ordinary course of the Company’s business.

(4)

Represents adjustments to the purchase price of acquisitions, 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.

(5)

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 “Risk Factors - If we are unable to fully offset declines in production and proved developed producing reserves from discretionary reductions for a portion of our oil and natural gas development costs, our net cash provided by operating activities could be reduced, which could adversely affect our ability to pay a distribution at the current level or at all.”

(a)

Represents the estimated costs to convert non-producing reserves to producing status on the Company’s most efficient projects, with the intent to fully offset declines in production and proved developed producing reserves through drilling and development activities. Includes not only the conversion of reserves from proved undeveloped to producing status but also includes converting reserves that are non-proved to producing status and converting reserves from activities such as recompletions and workovers to

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(b)

Represents the reserves estimated to be converted from the Company’s most efficient projects, with the intent to fully offset declines in production and proved developed producing reserves through drilling and development activities. Includes not only the conversion of reserves from proved undeveloped to producing status but also includes converting reserves that are non-proved to producing status and converting reserves from activities such as recompletions and workovers to producing status.

(6)	Represents reserves and settlements related to legal matters.

(7)

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.

(8)	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.

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Item 7A.	Quantitative and Qualitative Disclosures About Market Risk

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•	On December 15, 2011, the Company completed the acquisition of certain oil and natural gas properties located primarily in the Granite Wash of Texas and Oklahoma from Plains Exploration & Production Company for approximately $542 million.

•	On November 1, 2011, and November 18, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Permian Basin for approximately $110 million.

•	On June 1, 2011, the Company completed the acquisition of certain oil and natural gas properties in the Cleveland play, located in the Texas Panhandle, from Panther Energy Company, LLC and Red Willow Mid-Continent, LLC for approximately $224 million.

•	On May 2, 2011, and May 11, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Williston Basin for approximately $153 million.

•	On April 1, 2011, and April 5, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Permian Basin, including properties from SandRidge Exploration and Production, LLC for approximately $239 million.

•	On March 31, 2011, the Company completed the acquisition of certain oil and natural gas properties located in the Williston Basin from an affiliate of Concho Resources Inc. for approximately $192 million.

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•	On November 16, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin from Element Petroleum, LP for approximately $118 million.

•	On October 14, 2010, the Company completed two acquisitions of certain oil and natural gas properties located in the Wolfberry trend of the Permian Basin from Crownrock, LP and Patriot Resources Partners LLC for approximately $260 million.

•	On August 16, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin from Crownrock, LP and Element Petroleum, LP for approximately $95 million.

•	On May 27, 2010, the Company completed the acquisition of interests in Henry Savings LP and Henry Savings Management LLC that primarily hold oil and natural gas properties located in the Permian Basin for approximately $323 million.

•	On April 30, 2010, the Company completed the acquisition of interests in two wholly owned subsidiaries of HighMount Exploration & Production LLC that hold oil and natural gas properties in the Antrim Shale located in northern Michigan for approximately $327 million.

•	On January 29, 2010, the Company completed the acquisition of certain oil and natural gas properties located in the Anadarko Basin in Oklahoma and Kansas and the Permian Basin in Texas and New Mexico from certain affiliates of Merit Energy Company for approximately $151 million.

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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.

(2)	Variable interest rates of 1.97% and 2.57% at December 31, 2012, and December 31, 2011, respectively.

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(1)	Includes certain outstanding natural gas puts of approximately 10,570 MMMBtu for each of the years ending December 31, 2013, December 31, 2014, and December 31, 2015, and 10,599 MMMBtu 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 approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per 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 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”).

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Level 1	Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.

Level 2	Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives and interest rate swaps).

Level 3	Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

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

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(1)	See Note 2 for details about the Company’s acquisitions.

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(1)

In accordance with SEC regulations, reserves at December 31, 2012, December 31, 2011, and December 31, 2010, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The price used to estimate reserves is held constant over the life of the reserves.

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(1)	Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, bad debt, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.

(1)	Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, bad debt, depreciation, depletion and amortization and taxes, other than income taxes.

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1.	personal and professional integrity and high ethical standards;

2.	good business judgment;

3.	an excellent reputation in the industry in which the nominee or director is or has been primarily employed;

4.	a sophisticated understanding of our business or similar businesses;

5.	curiosity and a willingness to ask probing questions of management;

6.	the ability and willingness to work cooperatively with other members of the board of directors and with our Chairman, President and Chief Executive Officer and our other members of senior management; and

7.	the ability and willingness to support us with his preparation for, attendance at and participation in board of directors meetings.

1.	George A. Alcorn

•	As President of Alcorn Exploration, Inc., brings significant knowledge of our business.

•	Brings significant experience in the oil and natural gas industry, including as former chairman of the IPAA.

•	As member of the board of directors and committees of EOG Resources, Inc., brings experience and expertise serving on public company boards and as nominating committee chair.

2.	David D. Dunlap

•	As current President, CEO and director of Superior, brings significant knowledge of public company governance and process.

•	Brings significant experience in the oil and natural gas industry.

•	Brings over 25 years of experience in the well services business.

3.	Mark E. Ellis

•	As our current Chairman, President and Chief Executive Officer, is well suited to inform the board of directors of significant strategic matters and to lead the board of directors as Chairman.

•	Brings significant experience in the oil and natural gas industry, including membership in the Society of Petroleum Engineers.

•	As an engineer, brings technical expertise.

4.	Michael C. Linn

•	As our founder, brings historical knowledge and strategic experience and is well suited to serve as a link between the board of directors and management.

•	Brings significant experience in the oil and natural gas industry, including as former chairman of the IPAA.

•	As an attorney, brings legal expertise.

5.	Joseph P. McCoy

•	As former Chief Financial Officer of Burlington Resources Inc., brings significant knowledge of our business.

•	As former director of Rancher Energy, Inc. and BPI Energy Corp. and current director of Global Geophysical Services, Inc. and Scientific Drilling International brings experience serving on public company boards.

•	As former Chief Financial Officer and Chief Accounting Officer of Burlington Resources Inc., brings

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6.	Jeffrey C. Swoveland

•	As former Vice President and Treasurer and Interim Chief Financial Officer of Equitable Resources, Inc., brings significant financial expertise and experience in the preparation and review of financial statements and disclosure documents.

•	Brings expertise and experience in banking, including credit/financial analysis.

•	As director and former chair of the audit and compensation committees of PDC Energy, Inc. brings experience serving on public company boards and as compensation committee chair.

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•	We increased the per-unit distribution to unitholders by 5%;

•	We closed approximately $2.9 billion in acquisitions;

•	We increased proved reserves by 42% from 3.4 Tcfe in 2011 to 4.8 Tcfe in 2012;

•	We created and successfully took public LinnCo to broaden our access to capital and provide investors who may not want the tax reporting obligations of a master limited partnership a vehicle to invest in us;

•	We increased average daily production by 82% year over year from 2011;

•	We increased adjusted EBITDA (defined below) to $1.4 billion compared to $998 million for 2011; and

•	We shifted the focus of the Granite Wash drilling program to the oil-producing Hogshooter zone.

•	Our performance described above demonstrated continued successful and profitable growth for our unitholders;

•	We met or exceeded most of our goals and expectations for the year;

•	Although we fell short of our quantitative volume targets in some areas, the impact was somewhat offset by the quick shift of the Granite Wash drilling program to the oil-producing Hogshooter zone;

•	The Compensation Committee intends to continue its performance-oriented pay philosophy to reflect demonstrated performance in both EICP and LTIP awards;

•	The Compensation Committee compared performance in 2012 to that in 2011 and approved EICP awards equal to 185% of target versus 125% of target awarded in 2011 to reflect our extraordinary achievements outside our quantitative performance targets, including the acquisition and integration of approximately $2.9 billion of assets and the successful IPO of LinnCo; and

•	The Compensation Committee granted an award of special incentive options to recognize and reward the creativity and effort involved in the success of the IPO of LinnCo.

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•	the role of the Compensation Committee in establishing executive compensation;

•	our process for setting executive compensation;

•	our compensation philosophy and policies regarding executive compensation; and

•	our compensation decisions with respect to our Named Officers.

•	considers and approves changes in base salary and EICP targets for the upcoming year;

•	reviews actual results compared to the pre-established performance measures for the previous year to determine annual cash incentive awards for our executive officers under its Employee Incentive Compensation Plan, or EICP;

•	grants equity awards under the LTIP based on past performance of the Company and forward looking retention;

•	approves the performance measures under the EICP for the upcoming year, which may include both quantitative financial and operational measures and qualitative performance measures intended to focus on and reward activities that create unitholder value;

•	evaluates the compensation paid to our independent directors and, to the extent it deems appropriate, approves any adjustments; and

•	reviews the summary results of our board of directors’ written evaluations of our Chief Executive Officer, as well as the Chief Executive Officer’s self-evaluation.

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•	evaluating performance;

•	recommending EICP award targets and quantitative and qualitative performance measures under the EICP;

•	recommending base salary levels, actual EICP awards and LTIP awards; and

•	advising the Compensation Committee with respect to achievement of performance measures under the EICP.

•	attract and retain talented executive officers by providing total compensation levels competitive with that of executives holding comparable positions in similarly situated organizations;

•	provide total compensation that is supported by individual performance;

•	provide a performance-based compensation component that balances rewards for short-term and long-term results and is tied to company performance; and

•	encourage the long-term commitment of our executive officers to us and to our unitholders’ long-term interests.

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•	short term compensation:

•	base salary

•	employee incentive compensation plan

•	long-term equity compensation in the form of restricted units

•	other benefits

•	survey and published peer data provided by the Compensation Committee’s independent compensation consultant;

•	internal review of the executive’s compensation, both individually and relative to other executive officers; and

•	recommendations by our Chairman, President and Chief Executive Officer.

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a)	Operations - measured by actual production volumes, total cash costs (including lease operating expenses and general and administrative expenses) and cash costs on a per-unit basis, each as compared to our budget;

b)	Ability to Pay Distribution - measured by:

1.	Our cash flow per unit (defined as adjusted EBITDA less interest expense divided by the number of units outstanding) compared to our budget for 2012; and

2.	Our Distribution Coverage Ratio as compared to our budget. Distribution Coverage Ratio was defined as Distributable Cash Flow for 2012 divided by total cash distributions. Distributable Cash Flow was defined as adjusted EBITDA (defined below) less cash interest expense and maintenance capital.

c)

Relative Unitholder Return - measured by our total return for fiscal year 2012 compared to that of a peer group of energy master limited partnerships, selected due to management’s and the Compensation Committee’s view that these companies most closely align with the peer group considered by analysts and investors when comparing our total return. The Compensation Committee selected the following peer group for comparison of total return: EV Energy Partners, L.P., Inergy, L.P., Buckeye Partners, L.P., El Paso Pipeline Partners, L.P., BreitBurn Energy Partners L.P., Magellan Midstream Partners, L.P. and NuStar Energy L.P.

•	Net operating cash flow from acquisitions and divestitures, effective date through closing date;

•	Interest expense;

•	Depreciation, depletion and amortization;

•	Impairment of long-lived assets;

•	Write off of deferred financing fees;

•	(Gains) losses on sale of assets and other, net;

•	Provision for legal matters;

•	Loss on extinguishment of debt;

•	Unrealized (gains) losses on commodity derivatives;

•	Unrealized (gains) losses on interest rate derivatives;

•	Realized (gains) losses on interest rate derivatives;

•	Realized (gains) losses on canceled derivatives;

•	Realized gains on recovery of bankruptcy claim;

•	Unit-based compensation expenses;

•	Exploration costs; and

•	Income tax expense (benefit).

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•	Consistent Operational Results and Execution;

•	Acquisitions Excellence;

•	Culture-People Development and Growth; and

•	Access to Capital/Optimizing Capital Structure.

*	Budget targets and ranges were updated throughout the year to reflect acquisition activity.

(1)	The Compensation Committee based its decisions on estimates of 2012 performance available at the January 2013 Compensation Committee meeting. Actual final results were released in our Annual Report on Form 10-K for the year ended December 31, 2012 and our Earnings Release, filed on Current Report on Form 8-K, each filed on February 21, 2013.

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(1)	the Company significantly exceeding budget targets in cash flow per unit and distribution coverage ratio demonstrating profitable growth in 2012;

(2)	our overall significant increase in volumes despite the Company falling short of targets that were revised to account for acquisitions;

(3)	our decrease in costs on a per-unit basis which will continue to enhance our profitability; and

(4)	given that unit price can fluctuate substantially, our positive total unitholder return relative to our peer group over the past five years as opposed to a return measured at one point in time.

(1)	our ability to source, execute, close and integrate accretive acquisition opportunities which resulted in a total of approximately $2.9 billion in asset acquisitions closed throughout 2012;

(2)	our innovative approach to accessing new sources of capital through the creation and successful IPO of LinnCo;

(3)	our focus on maintaining a strong corporate culture while rapidly growing the Company, thereby allowing us to continue to attract and retain key employees;

(4)	our focus on growing new leaders from within the Company through extensive leadership training and development for key personnel;

(5)	our success in capital program execution and our maintenance of safe and environmentally sound operations; and

(6)	our expanded involvement with our community commensurate with our underlying growth.

•	enhancing the link between the creation of unitholder value and long-term executive incentive compensation;

•	maintaining significant forfeitable equity stakes among executives thereby fostering retention; and

•	maintaining competitive levels of total compensation.

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•	Chairman, President and Chief Executive Officer: 5 times base salary

•	Executive Vice Presidents: 4 times base salary

•	Senior Vice Presidents: 3 times base salary

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Change of Control. In certain scenarios, a merger or acquisition of us by another person may be in the best interests of our unitholders. We provide severance compensation to the Named Officers if such officer’s employment terminates following a change of control transaction to promote the ability of the officer to act in the best interests of our unitholders even though his or her employment could be terminated as a result of the transaction.

•

Termination without Cause. If we terminate the employment of certain executive officers “without cause” as defined in the applicable agreement, we are obligated to pay the officer certain compensation and other benefits as described in greater detail in “-Potential Payments Upon Termination or Change of Control” below. We believe these payments are appropriate because the terminated officer is generally bound by confidentiality obligations for five years, and nonsolicitation and non-compete provisions for one year after termination. Both parties have mutually agreed to severance terms that would be in place prior to any termination event. This provides us with more flexibility to make a change in senior management if such a change is in our best interests of us and that of our unitholders.

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(1)	Represents the total amount of the grant date fair value for awards in accordance with valuation methodology in FASB ASC Topic 718.

(1)	Includes all unit options granted as of December 31, 2012, less all that have been exercised or canceled as of December 31, 2012.

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(1)	Effective February 27, 2013, Ms. Ripley resigned her position as Senior Vice President and General Counsel.

(2)	The amounts in columns (e) and (f) reflect the aggregate grant date fair value of awards granted under our LTIP, computed in accordance with FASB ASC Topic 718. Assumptions used in the calculation of these amounts are included in Note 5 to our audited consolidated financial statements for the fiscal year ended December 31, 2012, included in our Form 10-K.

(3)	The amounts in column (g) reflect the cash awards approved by the Compensation Committee under our EICP for performance in 2010, 2011 and 2012. The 2010 amounts were not actually paid until February 2011, the 2011 amounts were not actually paid until February 2012 and the 2012 amounts were not actually paid until February 2013.

(4)

For each Named Officer, the amount shown in column (h) reflects (1) matching contributions allocated by us to each of our Named Officers pursuant to the Retirement Savings Plan (which is more fully described under the heading “-Other Benefits”) and (2) $10,000 paid by us for reimbursement of certain tax preparation expenses. Mr. Ellis’s 2012 amount also includes $100,000 paid by us for personal usage of company-leased aircraft.

(5)	Distributions paid during 2012 on issued, but unvested units pursuant to the equity awards are not shown in column (i) because the fair value shown in column (e) reflects the value of distributions. Distributions are paid to our Named

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(1)	In each case, the grant date is the same as the date of Compensation Committee approval.

(2)

In January 2012, the Compensation Committee set EICP targets for 2012 as a percentage of base salary. There is no threshold or maximum payout; the Compensation Committee has discretion to adjust the actual award above or below the target. The amount shown represents the payout at target; the actual awards for 2012 (awarded on January 23, 2013) are shown in column (g) of the Summary Compensation Table.

(3)	The amounts shown in column (j) represent the grant date fair value for each award under FASB ASC Topic 718. Assumptions used in the calculation of these amounts are included in Note 5 to our audited consolidated financial statements for the fiscal year ended December 31, 2012, included in our Form 10-K.

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(1)	Except as otherwise indicated, options expire ten years from date of grant.

(2)	Based on the closing sales price of our units on December 31, 2012 of $35.24.

(3)	These unit options are fully vested as of the date of this annual report.

(4)	These restricted unit awards vest in three equal installments on January 27, 2011, 2012, 2013.

(5)	These restricted unit awards vest in three equal installments on January 28, 2012, 2013 and 2014.

(6)	These restricted unit awards vest in three equal installments on January 26, 2013, 2014 and 2015.

(7)	These unit options vest in full on January 19, 2016, and expire seven years from the date of grant.

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(1)	The value realized represents the total fair market value of the units on the vesting date reported as earned compensation during 2012.

(2)	Mr. Ellis vested and sold 47,917 units to satisfy statutory federal payroll tax withholding requirements.

(3)	Mr. Rockov vested and sold 19,418 units to satisfy statutory federal payroll tax withholding requirements.

(4)	Mr. Walker vested and sold 13,474 units to satisfy statutory federal payroll tax withholding requirements.

(5)	Ms. Ripley vested and sold 11,994 units to satisfy statutory federal payroll tax withholding requirements.

(6)	Mr. Rottino vested and sold 9,742 units to satisfy statutory federal payroll tax withholding requirements.

•	earned, but unpaid base salary;

•	unused vacation pay;

•	amounts contributed and vested through our Retirement Savings Plan; and

•	any other amounts that may be reimbursable by us to the Named Officer under his or her employment agreement.

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•	a lump sum severance payment that ranges from two to three times the sum of the Named Officer’s base salary at the highest rate in effect at any time during the thirty-six (36) month period immediately preceding the termination date, plus the highest EICP award that the Employee was paid in the thirty-six (36) months immediately preceding the Change of Control;

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•	COBRA continuation coverage as described above upon a termination without “Cause” or for “Good Reason;”

•	his or her earned, but unpaid EICP award determined as described above upon a termination without “Cause” or for “Good Reason;”

•	an amount equal to the excise tax charged to the Named Officer as a result of the receipt of any change of control payments; and

•	all restricted unit and unit options awards held by the Named Officer will automatically vest and become exercisable.

(1)

The acquisition by any individual, entity or group (within the meaning of Section 13(d) (3) or 14(d) (2) of the Exchange Act) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of thirty-five percent (35%) or more of either (A) the then-outstanding equity interests of the Company (the “Outstanding Equity”) or (B) the combined voting power of the then-outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Voting Securities”); provided, however, that, for purposes of this Section 1 of this definition, the following acquisitions will not constitute a Change of Control: (i) any acquisition directly from us, (ii) any acquisition by us, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by us or any affiliated company, or (iv) any acquisition by any corporation or other entity pursuant to a transaction that complies with Section (3)(A), Section (3)(B) or Section (3)(C) below;

(2)

Any time at which individuals who, as of the date of such Named Officer’s employment agreement with us, constitute the board of directors (the “Incumbent Board”) cease for any reason to constitute at least a majority of the board of directors; provided, however, that any individual becoming a director subsequent to such date whose election, or nomination for election by our Unitholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board will be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a person other than the Incumbent Board;

(3)

Consummation of a reorganization, merger, statutory share exchange or consolidation or similar corporate transaction involving us or any of our subsidiaries, a sale or other disposition of all or substantially all of our assets, or the acquisition of assets or equity interests of another entity by us or any of our subsidiaries (each, a “Business Combination”), in each case unless, following such Business Combination, (A) all or substantially all of the individuals and entities that were the beneficial owners of the Outstanding Equity and the Outstanding Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than fifty percent (50%) of the then-outstanding equity interests and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation or other entity that, as a result of such transaction, owns us or all or substantially all of our assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership immediately prior to such Business Combination of the Outstanding Equity and the Outstanding Voting Securities, as the case may be, (B) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation or other entity resulting from such Business Combination) beneficially owns, directly or indirectly, thirty-five percent (35%) or more of, respectively, the then-outstanding equity interests of the corporation or other entity resulting from such Business Combination or the combined voting power of the then-outstanding voting securities of such corporation or other entity, except to the extent that such ownership existed prior to the Business Combination, and (C) at least a majority of the members of the board of directors of the corporation or equivalent body of any other entity resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement or of the action of the Board providing for such Business Combination; or

(4)	Consummation of a complete liquidation or dissolution of the Company.

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(a)	Closing price of our units on December 31, 2012 was $35.24. All awards under the LTIP fully vest upon termination without cause, good reason, death, disability or a change of control (as each is defined in the respective employment agreements). Upon retirement, unvested awards are canceled and an equivalent amount of immediately vested unit grants are made.

(1)	If Mr. Ellis’ employment is terminated without cause or by employee for good reason, his employment agreement provides that, in addition to the amounts earned but unpaid, (1) he will receive a lump sum severance payment of two times his base salary at the highest rate in effect at any time during the thirty-six (36) month period

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(2)

If either of Mr. Rockov or Mr. Walker is terminated without cause or by him for good reason, his employment agreement provides for severance benefits substantially similar to Mr. Ellis. If Mr. Rockov or Mr. Walker is terminated without cause or by him for good reason during the COC Period, each will be entitled to substantially the same benefits as Mr. Ellis except that 1) his Severance Pay is 2.5 times the sum of his Highest Base Salary and Highest EICP Award and 2) the period for continued coverage of medical benefits will be up to twelve months after the expiration of the maximum required period under COBRA. Mr. Rockov’s and Mr. Walker’s employment agreements include the Excise Tax Gross Up but no gross up for penalties or interest under Section 409A.

(3)

If Mr. Rottino is terminated without cause or by him for good reason, the employment agreement provides for severance benefits substantially similar to Mr. Ellis. If Mr. Rottino is terminated without cause or by him for good reason during the COC Period, he will be entitled to substantially the same benefits as Mr. Ellis, except (1) Severance Pay shall be two times the sum of his Highest Base Salary and Highest EICP Award and (2) the period for continued coverage of medical benefits will remain up to six months after the expiration of the maximum required period under COBRA. Mr. Rottino’s employment agreement includes the Excise Tax Gross Up but no gross up for penalties or interest under Section 409A.

(4)

The amounts listed under Bonus represent each Named Officer’s target EICP award for 2012. As described above under “-Payments Made Upon Termination Without Cause or for Good Reason,” if the Named Officer was employed for the entire previous year but was terminated prior to the Compensation Committee finally determining his or her EICP award for the preceding year (in the hypothetical case presented in the table above, on December 31, 2012), he or she would have received his or her target EICP award. The Compensation Committee determined actual EICP awards for 2012 performance on January 23, 2013; the actual awards for each Named Officer are identified in column (g) of the Summary Compensation Table, but are not reflected in the table above.

(5)	Using a hypothetical termination date of December 31, 2012, we determined that none of our Named Officers would have “excess parachute payments” as defined in Section 280G of the Code; thus none would be entitled to a tax gross up.

•	An annual cash retainer of $50,000 paid in four installments quarterly;

•	A per meeting fee of $1,500, payable quarterly;

•	A per committee meeting fee of $1,000, payable quarterly; and

•	Committee chair fees (each payable quarterly) of:

•	$15,000 for the Audit Committee chair;

•	$7,500 for the Nominating and Governance Committee chair; and

•	$10,000 for the Compensation Committee chair.

•	Lead director fee of $10,000 per year, payable quarterly.

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(1)	Mark E. Ellis, our Chairman, President and Chief Executive Officer, is not included in this table as he was an employee in 2012 and thus received no additional compensation for his service as director. Mr. Ellis’s compensation is shown in the Summary Compensation Table above.

(2)	Reflects the aggregate grant date fair value of 2012 awards computed in accordance with FASB ASC Topic 718. The following represents outstanding unit grant awards as of December 31, 2012:

(3)	In addition, the Compensation Committee approved the following restricted unit grants to our directors on January 23, 2013:

(4)	Reflects the dollar amount of distributions paid in 2012 on the phantom and restricted units reported in (2) above.

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*	Less than 1% of class based on 235,178,498 units outstanding as of October 1, 2013.

(1)	To our knowledge after reviewing Schedule 13G/Ds filed with the SEC, LinnCo, LLC is the only holder of which we are aware that beneficially own more than 5% of our units.

(2)	The address of each beneficial owner, unless otherwise noted, is c/o Linn Energy, LLC, 600 Travis, Suite 5100, Houston, Texas 77002.

(3)	Includes unvested restricted unit awards that vest in equal installments, generally over approximately three years. Please see “–Outstanding Equity Awards at December 31, 2012” for vesting schedule of unvested awards.

(4)	Includes 310,765 units underlying options currently exercisable. Includes 494,664 units Mr. Ellis has pledged to secure certain personal accounts.

(5)	Includes 400 units as custodian under certain Uniform Gifts to Minors Accounts (UGMA) for immediate family members as to which Mr. Rockov disclaims beneficial ownership. Includes 240,127 units Mr. Rockov has pledged to secure certain personal accounts and 279,665 units underlying options currently exercisable.

(6)	Includes 103,550 units underlying options currently exercisable.

(7)	Includes 92,240 units underlying options currently exercisable.

(8)	Includes 2,000 units underlying options currently exercisable and 9,946 phantom units.

(9)	Includes 102,301 units underlying options currently exercisable.

(10)	Includes 6,946 phantom units.

(11)	Includes 10,000 units underlying options currently exercisable and 9,946 phantom units.

(12)	Percentage ownership of executive officers and directors is based on total units outstanding as of October 1, 2013.

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•	the nature of the related person’s interest in the transaction;

•	the material terms of the transaction, including, without limitation, the amount and type of transaction;

•	the importance of the transaction to the related person;

•	the importance of the transaction to us;

•	whether the transaction would impair the judgment of a director or executive officer to act in our best interest; and

•	any other matters deemed appropriate.

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*	Management Contract or Compensatory Plan or Arrangement required to be filed as an exhibit hereto pursuant to Item 601 of Regulation S-K.

**	Filed herewith.