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Item 1.	Financial Statements

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•	Reflect the results of the Devon Assets Acquisition.

•	Reflect incremental depreciation, depletion and amortization expense, using the unit-of-production method related to oil and natural gas properties acquired and an estimated useful life of 10 years for other property and equipment.

•	Reflect incremental accretion expense related to asset retirement obligations on oil and natural gas properties acquired.

•	Reflect an increase in interest expense related to incremental debt of $2.3 billion incurred to fund the purchase price.

•	Reflect incremental amortization of deferred financing fees associated with debt incurred to fund the purchase price.

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•	Shallow Texas Panhandle Brown Dolomite formation – $278 million;

•	California region – $207 million;

•	TexLa region – $33 million;

•	South Texas region – $9 million; and

•	Mid-Continent region – $6 million.

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(1)	Variable interest rates of 1.93% and 1.92% at March 31, 2015, and December 31, 2014, respectively.

(2)	Variable interest rates of 2.68% and 2.67% at March 31, 2015, and December 31, 2014, respectively.

(3)	Variable interest rates of 2.68% and 2.66% at March 31, 2015, and December 31, 2014, respectively.

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(1)

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, at counterparty election on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

(2)	Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.

(3)	For positions which hedge exposure to differentials in producing areas, the Company receives the NYMEX Henry Hub natural gas price plus the respective spread and pays the specified index price. Cash settlements are made on a net basis.

(4)	For positions which hedge exposure to differentials in consuming areas, the Company pays the NYMEX Henry Hub natural gas price plus the respective spread and receives the specified index price. Cash settlements are made on a net basis.

(5)

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

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

•	Rockies, which includes properties located in Wyoming (Green River, Washakie and Powder River basins), Utah (Uinta Basin), North Dakota (Williston Basin) and Colorado (Piceance Basin);

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

•	California, which includes properties located in the San Joaquin Valley and Los Angeles basins;

•	Mid-Continent, which includes Oklahoma properties located in the Anadarko and Arkoma basins, as well as waterfloods in the Central Oklahoma Platform;

•	Permian Basin, which includes properties located in west Texas and southeast New Mexico;

•	TexLa, which includes properties located in east Texas and north Louisiana;

•	South Texas; and

•	Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois.

•	oil, natural gas and NGL sales of approximately $451 million compared to $939 million for the first quarter of 2014;

•	average daily production of approximately 1,201 MMcfe/d compared to 1,104 MMcfe/d for the first quarter of 2014;

•	net loss of approximately $339 million compared to $85 million for the first quarter of 2014;

•	net cash provided by operating activities of approximately $375 million compared to $434 million for the first quarter of 2014;

•	capital expenditures, excluding acquisitions, of approximately $197 million compared to $409 million for the first quarter of 2014; and

•	196 wells drilled (all successful) compared to 200 wells drilled (199 successful) for the first quarter of 2014.

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(1)	General and administrative expenses for the three months ended March 31, 2015, and March 31, 2014, include approximately $17 million and $18 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 three months ended March 31, 2015, and March 31, 2014, include approximately $17 million and $18 million, respectively, of noncash unit-based compensation expenses.

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•	Shallow Texas Panhandle Brown Dolomite formation – $278 million;

•	California region – $207 million;

•	TexLa region – $33 million;

•	South Texas region – $9 million; and

•	Mid-Continent region – $6 million.

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(1)	The Berry Credit Facility allows Berry to demonstrate its compliance with the Current Ratio financial covenant on a consolidated basis with LINN Energy for up to three quarters of each calendar year.

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*	Not meaningful due to the 2015 change in presentation.

(1)

Represent discretionary reductions for a portion of oil and natural gas development costs, an estimated component of total development costs. The Board of Directors establishes the discretionary reductions with the objective of replacing proved developed producing reserves, current production and cash flow, taking into consideration the Company’s overall commodity mix. Management evaluates all of these objectives as part of the decision-making process to determine the discretionary reductions for a portion of oil and natural gas development costs for the year, although every objective may not be met in each year. Furthermore, there may be certain years in which commodity prices and other economic conditions do not merit capital spending at a level sufficient to accomplish any of these objectives. The 2014 amounts were established by the Board of Directors at the end of the previous year, allocated across four quarters, and were intended to fully offset declines in production and proved developed producing reserves during the year as compared to the prior year.

(2)

Represents total capital expenditures for the development of oil and natural gas properties as presented on an accrual basis. For 2015, the Company intends to fund its total oil and natural gas capital program, in addition to interest expense and distributions to unitholders, from net cash provided by operating activities. Previously, the Company intended to fund only a portion of its oil and natural gas capital program, in addition to interest expense and distributions to unitholders, from net cash provided by operating activities.

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(3)

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

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

(5)

Represents primarily working capital adjustments. These adjustments may or may not impact cash provided by (used in) 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.

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

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•	business strategy;

•	acquisition strategy;

•	financial strategy;

•	effects of legal proceedings;

•	ability to maintain or grow distributions;

•	drilling locations;

•	oil, natural gas and NGL reserves;

•	realized oil, natural gas and NGL prices;

•	production volumes;

•	capital expenditures;

•	economic and competitive advantages;

•	credit and capital market conditions;

•	regulatory changes;

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

•	future operating results, including results of acquired properties;

•	plans, objectives, expectations and intentions; and

•	integration of acquired businesses and operations, which may take longer than anticipated, may be more costly than anticipated as a result of unexpected factors or events and may have an unanticipated adverse effect on the Company’s business.

Item 3.	Quantitative and Qualitative Disclosures About Market Risk

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Item 1.	Legal Proceedings

Item 1A.	Risk Factors

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

Item 3.	Defaults Upon Senior Securities

Item 4.	Mine Safety Disclosures

Item 5.	Other Information

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Item 6.	Exhibits

*	Filed herewith.

**	Furnished herewith.

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