Berry Petroleum 10-Q 2015 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended September 30, 2015

OR

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

for the transition period from_______________ to _______________

Commission file number 1-9735

BERRY PETROLEUM COMPANY, LLC

(Successor in interest to Berry Petroleum Company)

(Exact name of registrant as specified in its charter)

Delaware (State of incorporation or organization) 77-0079387 (I.R.S. Employer Identification Number)

600 Travis, Suite 5100

Houston, Texas 77002

(Address of principal executive offices, including zip code)

Registrant’s telephone number, including area code:

(281) 840-4000

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

Pursuant to the terms of its senior note indentures, the registrant is a voluntary filer of reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934, and has filed all such reports as required by its senior note indentures during the preceding 12 months.

The registrant meets the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q as it is an indirect wholly owned subsidiary of Linn Energy, LLC, which is a reporting company under the Securities Exchange Act of 1934 and which has filed with the SEC all materials required to be filed pursuant to Section 13, 14 or 15(d) thereof, and the registrant is therefore filing this Form 10-Q with a reduced disclosure format.

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

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

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x Smaller reporting company ¨

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

On December 16, 2013, the registrant was acquired (see Note 1 of Notes to Condensed Financial Statements), as a result of which 100% of its membership interest is currently held by a single member and the registrant deregistered its equity under the Securities Exchange Act of 1934.

TABLE OF CONTENTS

		Page
	Glossary of Terms	ii
	Part I – Financial Information
Item 1.	Financial Statements
	Condensed Balance Sheets as of September 30, 2015, and December 31, 2014	1
	Condensed Statements of Operations for the three months and nine months ended September 30, 2015, and September 30, 2014	2
	Condensed Statement of Member’s Equity for the nine months ended September 30, 2015	3
	Condensed Statements of Cash Flows for the nine months ended September 30, 2015, and September 30, 2014	4
	Notes to Condensed Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	37
	Part II – Other Information
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	40
Item 4.	Mine Safety Disclosures	40
Item 5.	Other Information	40
Item 6.	Exhibits	41
	Signatures	42

i

GLOSSARY OF TERMS

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

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

Bbls/d. Bbls per day.

Bcf. One billion cubic feet.

BOE. Barrel of oil equivalent, determined using the ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas.

BOE/d. BOE per day.

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

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

MBbls/d. MBbls per day.

Mcf. One thousand cubic feet.

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

MBOE. One thousand barrels of oil equivalent.

MBOE/d. MBOE per day.

MMBOE. One million barrels of oil equivalent.

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcf/d. MMcf per day.

Mwh. One thousand kilowatts of electricity used continuously for one hour.

Mwh/d. Mwh per day.

NGL. Natural gas liquids, which are the hydrocarbon liquids contained within natural gas.

ii

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

BERRY PETROLEUM COMPANY, LLC

CONDENSED BALANCE SHEETS

(Unaudited)

	September 30, 2015			December 31, 2014
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	282,805		$	1,586
Accounts receivable – trade, net	55,530			100,359
Derivative instruments	26,529			43,694
Other current assets	43,420			59,259
Total current assets	408,284			204,898
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	5,000,233			4,872,059
Less accumulated depletion and amortization	(1,493,749		)	(525,007		)
	3,506,484			4,347,052
Other property and equipment	128,891			115,999
Less accumulated depreciation	(16,288		)	(8,452		)
	112,603			107,547
Derivative instruments	336			—
Advance to affiliate	—			293,627
Restricted cash	250,245			125
Other noncurrent assets	10,747			14,159
	261,328			307,911
Total noncurrent assets	3,880,415			4,762,510
Total assets	$	4,288,699		$	4,967,408
LIABILITIES AND MEMBER’S EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	182,453		$	242,350
Derivative instruments	1,462			—
Other accrued liabilities	12,707			19,087
Total current liabilities	196,622			261,437
Noncurrent liabilities:
Credit facility	1,173,175			1,173,175
Senior notes, net	845,804			913,777
Derivative instruments	423			—
Other noncurrent liabilities	200,931			200,015
Total noncurrent liabilities	2,220,333			2,286,967
Commitments and contingencies (Note 8)
Member’s equity:
Additional paid-in capital	2,757,836			2,416,381
Accumulated income (deficit)	(886,092		)	2,623
	1,871,744			2,419,004
Total liabilities and member’s equity	$	4,288,699		$	4,967,408

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

1

BERRY PETROLEUM COMPANY, LLC

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	140,252		$	350,863		$	470,219		$	1,044,359
Electricity sales	8,610			11,300			20,370			31,461
Gains on oil and natural gas derivatives	27,664			44,990			26,457			22,893
Marketing revenues	1,109			2,018			4,329			9,106
Other revenues	1,672			245			5,103			238
	179,307			409,416			526,478			1,108,057
Expenses:
Lease operating expenses	67,341			83,684			184,426			267,069
Electricity generation expenses	4,759			5,892			14,322			21,904
Transportation expenses	13,794			13,326			39,378			28,802
Marketing expenses	967			1,811			3,047			6,505
General and administrative expenses	21,564			16,566			79,853			88,379
Depreciation, depletion and amortization	63,057			79,725			199,088			226,109
Impairment of long-lived assets	510,631			—			782,631			—
Taxes, other than income taxes	14,520			24,830			60,048			71,338
(Gains) losses on sale of assets and other, net	2,633			49,011			(2,651		)	56,635
	699,266			274,845			1,360,142			766,741
Other income and (expenses):
Interest expense, net of amounts capitalized	(21,484		)	(19,068		)	(65,595		)	(66,555		)
Gain on extinguishment of debt	4,378			—			11,209			—
Other, net	(90		)	(179		)	(723		)	(813		)
	(17,196		)	(19,247		)	(55,109		)	(67,368		)
Income (loss) before income taxes	(537,155		)	115,324			(888,773		)	273,948
Income tax expense (benefit)	3			159			(58		)	77
Net income (loss)	$	(537,158	)	$	115,165		$	(888,715	)	$	273,871

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

2

BERRY PETROLEUM COMPANY, LLC

CONDENSED STATEMENT OF MEMBER’S EQUITY

(Unaudited)

	Additional Paid-In Capital			Accumulated Income (Deficit)			Total Member’s Equity
	(in thousands)
December 31, 2014	$	2,416,381		$	2,623		$	2,419,004
Capital contributions from affiliate	398,678			—			398,678
Distributions to affiliate	(57,223		)	—			(57,223		)
Net loss	—			(888,715		)	(888,715		)
September 30, 2015	$	2,757,836		$	(886,092	)	$	1,871,744

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

3

BERRY PETROLEUM COMPANY, LLC

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2015			2014
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(888,715	)	$	273,871
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	199,088			226,109
Impairment of long-lived assets	782,631			—
Gain on extinguishment of debt	(11,209		)	—
Amortization and write-off of deferred financing fees	1,121			(5,174		)
(Gains) losses on sale of assets and other, net	(1,521		)	48,357
Deferred income taxes	(58		)	77
Derivatives activities:
Total gains	(29,355		)	(22,893		)
Cash settlements	48,054			(18,130		)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	43,709			(10,611		)
Decrease in other assets	1,519			4,551
Decrease in accounts payable and accrued expenses	(15,171		)	(16,341		)
Decrease in other liabilities	(20,789		)	(36,626		)
Net cash provided by operating activities	109,304			443,190
Cash flow from investing activities:
Development of oil and natural gas properties	(3,076		)	(429,940		)
Purchases of other property and equipment	(12,760		)	(8,316		)
Settlement of advance to affiliate	129,217			—
Proceeds from sale of properties and equipment and other	22,486			256
Net cash provided by (used in) investing activities	135,867			(438,000		)
Cash flow from financing activities:
Repayments of debt	(55,418		)	(206,124		)
Financing fees and other, net	11			(11,252		)
Capital contributions from affiliate	148,678			220,000
Distributions to affiliate	(57,223		)	(52,279		)
Net cash provided by (used in) financing activities	36,048			(49,655		)
Net increase (decrease) in cash and cash equivalents	281,219			(44,465		)
Cash and cash equivalents:
Beginning	1,586			51,041
Ending	$	282,805		$	6,576

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

4

BERRY PETROLEUM COMPANY, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation

Nature of Business

Berry Petroleum Company, LLC (“Berry” or the “Company”) was formed as a Delaware limited liability company on December 16, 2013, and is an indirect wholly owned subsidiary of Linn Energy, LLC (“LINN Energy”) engaged in the production and development of oil and natural gas. The Company’s predecessor, Berry Petroleum Company, was publicly traded from 1987 until December 2013. On December 16, 2013, the Company completed the transactions contemplated by the merger agreement between LINN Energy, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and LINN Energy, under which LinnCo contributed Berry to LINN Energy in exchange for LINN Energy units. Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, is the Company’s sole member.

The Company’s properties are located in the United States (“U.S.”), in California (San Joaquin Valley and Los Angeles basins), Kansas and the Oklahoma Panhandle (Hugoton Basin), Utah (Uinta Basin), Colorado (Piceance Basin) and east Texas. In August and November of 2014, the Company divested all of its properties located in the Permian Basin.

Principles of Reporting

The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The results reported in these unaudited condensed financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.

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

Use of Estimates

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

5

BERRY PETROLEUM COMPANY, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued

(Unaudited)

Recently Issued Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2015, and interim periods within those years (early adoption permitted). The Company does not expect the adoption of this ASU to have a material impact on its financial statements.

In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU will be applied either retrospectively or as a cumulative-effect adjustment as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those years (early adoption permitted for fiscal years beginning after December 15, 2016, including interim periods within that year). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its financial statements and related disclosures.

Note 2 – Exchange of Properties

On August 15, 2014, the Company, along with a subsidiary of its indirect parent LINN Energy, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., in exchange for properties in the Hugoton Basin. The noncash exchange was accounted for at fair value and the Company recognized a net loss of approximately $49 million, equal to the difference between the carrying value and the fair value of the assets exchanged, which is included in “(gains) losses on sale of assets and other, net” on the condensed statements of operations. The fair value measurements were based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy.

Note 3 – Oil and Natural Gas Properties

Oil and Natural Gas Capitalized Costs

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

	September 30, 2015			December 31, 2014
	(in thousands)
Oil and natural gas:
Proved properties	$	4,161,155		$	4,025,595
Unproved properties	839,078			846,464
	5,000,233			4,872,059
Less accumulated depletion and amortization	(1,493,749		)	(525,007		)
	$	3,506,484		$	4,347,052

Impairment of Proved Properties

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future

6

BERRY PETROLEUM COMPANY, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued

(Unaudited)

commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

Based on the analysis described above, the Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties:

	Three Months Ended September 30, 2015		Nine Months Ended September 30, 2015
	(in thousands)
California operating area	$	330,311	$	537,511
Uinta Basin operating area	111,339		111,339
East Texas operating area	13,637		78,437
Piceance Basin operating area	55,344		55,344
	$	510,631	$	782,631

The impairment charges in 2015 were due to a decline in commodity prices and the Company’s estimates of proved reserves. The Company recorded no impairment charges for the three months or nine months ended September 30, 2014.

The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the condensed statements of operations.

Note 4 – Debt

The following summarizes the Company’s outstanding debt:

	September 30, 2015		December 31, 2014
	(in thousands, except percentages)
Credit facility (1)	$	1,173,175	$	1,173,175
6.75% senior notes due November 2020	261,100		299,970
6.375% senior notes due September 2022	572,700		599,163
Net unamortized premiums	12,004		14,644
Total debt, net	2,018,979		2,086,952
Less current maturities	—		—
Total long-term debt, net	$	2,018,979	$	2,086,952

⁽¹⁾  Variable interest rates of 2.71% and 2.67% at September 30, 2015, and December 31, 2014, respectively.

Fair Value

The Company’s debt is recorded at the carrying amount in the condensed balance sheets. The carrying amount of the Company’s Credit Facility, as defined below, approximates fair value because the interest rate is variable and reflective of market rates. The Company uses a market approach to determine the fair value of its senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement.

7

BERRY PETROLEUM COMPANY, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued

(Unaudited)

	September 30, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Credit facility	$	1,173,175	$	1,173,175	$	1,173,175	$	1,173,175
Senior notes, net	845,804		269,564		913,777		699,462
Total debt, net	$	2,018,979	$	1,442,739	$	2,086,952	$	1,872,637

Credit Facility

The Company’s Second Amended and Restated Credit Agreement (“Credit Facility”) had a borrowing base of $1.2 billion, subject to lender commitments, as of September 30, 2015. The maturity date is April 2019. At September 30, 2015, lender commitments under the facility were $1.2 billion but there was less than $1 million of available borrowing capacity, including outstanding letters of credit.

In October 2015, the Company entered into an amendment to the Credit Facility to provide for, among other things: (i) a springing maturity based on the maturity of any outstanding junior lien debt; (ii) the ability of the Company to incur junior lien debt to refinance its senior notes or as additional indebtedness, but such additional indebtedness issued may not exceed $500 million outstanding at any one time and is subject to a borrowing base reduction; (iii) a decrease in the Company’s covenant requiring the maintenance of an EBITDA to Interest Expense ratio of 2.5 to 1.0, such that the permissible ratio is decreased to 2.0 to 1.0 from December 31, 2015 through December 31, 2016, to 2.25 to 1.0 from March 31, 2017 through June 30, 2017 and returning to 2.5 to 1.0 thereafter; (iv) an increase in the mortgage requirement on the total value of the oil and natural gas properties included in the Company’s most recent reserve report from 80% to 90%; (v) an increase to the applicable margin charged on borrowings under the Credit Facility by 0.25% and increase the commitment fee under the Credit Facility to 0.5% per annum; and (vi) permission to prepay or exchange the Company’s senior notes with notes issued by LINN Energy.

Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. A super-majority of the lenders under the Credit Facility and Berry also have the right to request interim borrowing base redeterminations once between scheduled redeterminations. The spring 2015 semi-annual borrowing base redetermination was completed in May 2015, and, as a result of lower commodity prices, the borrowing base under the Credit Facility decreased from $1.4 billion to $1.2 billion. The fall 2015 semi-annual redetermination was completed in October 2015 and the borrowing base under the Credit Facility decreased from $1.2 billion to $900 million. Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs may impact future redeterminations.

In connection with the reduction in Berry’s borrowing base in October 2015, Berry repaid $300 million of borrowings outstanding under the Credit Facility. In connection with the reduction in Berry’s borrowing base in May 2015, LINN Energy borrowed $250 million under the LINN Credit Facility, which it contributed to Berry to post as restricted cash with Berry’s lenders. As directed by LINN Energy, the $250 million was deposited on Berry’s behalf in a security account with the administrative agent subject to a security control agreement. Berry’s ability to withdraw funds from this account is subject to a concurrent reduction of the borrowing base under the Credit Facility or lender’s consent in connection with a redetermination of such borrowing base. The $250 million may be used to satisfy obligations under the Credit Facility or, subject to restrictions in the indentures governing Berry’s senior notes, may be returned to LINN Energy in the future. The amount is included in “restricted cash” on the condensed consolidated balance sheet.

The Company’s obligations under the Credit Facility, as amended, are secured by mortgages on its oil and natural gas properties and other personal property. The Company is required to maintain mortgages on properties representing at least 90% of the present value of its oil and natural gas proved reserves. The Company is in compliance with all financial and other covenants of the Credit Facility.

8

BERRY PETROLEUM COMPANY, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued

(Unaudited)

At the Company’s election, interest on borrowings under the Credit Facility, as amended, is determined by reference to either the LIBOR plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the Credit Facility) or a Base Rate (as defined in the Credit Facility) plus an applicable margin between 0.75% and 1.75% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the Base Rate and at the end of the applicable interest period for loans bearing interest at the LIBOR. The Company is required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the maximum commitment amount of the lenders.

Repurchases of Senior Notes

During the nine months ended September 30, 2015, the Company repurchased, on the open market and through a privately negotiated transaction, approximately $65 million of its outstanding senior notes including approximately $39 million of its 6.75% senior notes due November 2020 and approximately $26 million of its 6.375% senior notes due September 2022. In connection with the repurchases, the Company paid approximately $55 million in cash and recorded a gain on extinguishment of debt of approximately $11 million for the nine months ended September 30, 2015.

Senior Notes Covenants

The Company’s senior notes contain covenants that, among other things, may limit its ability to: (i) incur or guarantee additional indebtedness; (ii) pay distributions or dividends on its equity or redeem its subordinated debt; (iii) create certain liens; (iv) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (v) sell assets; (vi) engage in transactions with affiliates; and (vii) consolidate, merge or transfer all or substantially all of the Company’s assets. The Company is in compliance with all financial and other covenants of its senior notes.

In addition, any cash generated by the Company is currently being used by the Company to fund its activities. To the extent that the Company generates cash in excess of its needs and determines to distribute such amounts to LINN Energy, the indentures governing the Company’s senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and the Company may not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Company’s indentures. The Company’s restricted payments basket may be increased in accordance with the terms of the Company’s indentures by, among other things, 50% of the Company’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions.

The Company may from time to time seek to repurchase its outstanding debt through open market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, may be material and will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors.

Note 5 – Derivative Instruments

The Company seeks to hedge a portion of its forecasted production to reduce exposure to commodity price fluctuations and provide long-term cash flow predictability to manage its business. The Company also, from time to time, enters into derivative contracts for a portion of its natural gas consumption. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials.

The Company enters into commodity hedging transactions primarily in the form of swap contracts, collars and three-way collars. Swap contracts are designed to provide a fixed price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price.

9

BERRY PETROLEUM COMPANY, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued

(Unaudited)

The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 6 for fair value disclosures about oil and natural gas commodity derivatives.

The following table summarizes derivative positions for the periods indicated as of September 30, 2015:

	October 1 - December 31, 2015			2016
Oil positions:
Fixed price swaps (NYMEX WTI):
Hedged volume (MBbls)	966			—
Average price ($/Bbl)	$	59.94		$	—
Three-way collars (NYMEX WTI):
Hedged volume (MBbls)	276			—
Short put ($/Bbl)	$	70.00		$	—
Long put ($/Bbl)	$	90.00		$	—
Short call ($/Bbl)	$	101.62		$	—
Natural gas basis differential positions: (1)
NWPL Rockies basis swaps: (2)
Hedged volume (MMMBtu)	2,576			11,712
Hedged differential ($/MMBtu)	$	(0.34	)	$	(0.34	)
SoCal basis swaps: (3)
Hedged volume (MMMBtu)	8,280			32,940
Hedged differential ($/MMBtu)	$	(0.03	)	$	(0.03	)

⁽¹⁾  Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.

⁽²⁾  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.

⁽³⁾  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.

During the nine months ended September 30, 2015, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for May 2015 through December 2016 to hedge exposure to differentials in certain producing areas, and oil swaps for April 2015 through December 2015. In addition, the Company entered into natural gas basis swaps for May 2015 through December 2016 to hedge exposure to the differential in California, where it consumes natural gas in its heavy oil development operations.

Settled derivatives on oil production for the three months and nine months ended September 30, 2015, included volumes of 1,273 MBbls and 2,617 MBbls, respectively, at average contract prices of $65.89 per Bbl and $68.44 per Bbl. Settled derivatives on oil production for the three months and nine months ended September 30, 2014, included volumes of 2,300 MBbls and 6,825 MBbls, respectively, at an average contract price of $92.16 per Bbl. The oil derivatives are settled based on the average closing price of NYMEX WTI crude oil for each day of the delivery month.

10

BERRY PETROLEUM COMPANY, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued

(Unaudited)

Balance Sheet Presentation

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

	September 30, 2015		December 31, 2014
	(in thousands)
Assets:
Commodity derivatives	$	34,416	$	60,843
Liabilities:
Commodity derivatives	$	9,436	$	17,149

By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $34 million at September 30, 2015. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Gains (Losses) on Derivatives

A summary of gains and losses on derivatives included on the condensed statements of operations is presented below:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015			2014		2015		2014
	(in thousands)
Gains on oil and natural gas derivatives	$	27,664		$	44,990	$	26,457	$	22,893
Lease operating expenses (1)	(162		)	—		2,898		—
Total gains on oil and natural gas derivatives	$	27,502		$	44,990	$	29,355	$	22,893

⁽¹⁾  Consists of gains and (losses) on derivatives used to hedge exposure to differentials in consuming areas, which were entered into in March 2015.

For the three months and nine months ended September 30, 2015, the Company received net cash settlements of approximately $15 million and $48 million, respectively. For the three months and nine months ended September 30, 2014, the Company paid net cash settlements of approximately $8 million and $19 million, respectively.

11

BERRY PETROLEUM COMPANY, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued

(Unaudited)

Note 6 – Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity derivatives at fair value (see Note 5) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads are applied to the Company’s commodity derivatives.

Fair Value Hierarchy

In accordance with applicable accounting standards, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

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

	September 30, 2015
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	34,416	$	(7,551	)	$	26,865
Liabilities:
Commodity derivatives	$	9,436	$	(7,551	)	$	1,885

	December 31, 2014
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	60,843	$	(17,149	)	$	43,694
Liabilities:
Commodity derivatives	$	17,149	$	(17,149	)	$	—

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

Note 7 – Asset Retirement Obligations

The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “other noncurrent liabilities” on the condensed balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2% for the nine months ended September 30, 2015); and (iv) a credit-adjusted risk-free interest rate (average of 5.5% for the nine months ended September 30, 2015). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

12

BERRY PETROLEUM COMPANY, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

Asset retirement obligations at December 31, 2014	$	121,760
Liabilities added from drilling	1,185
Current year accretion expense	5,051
Settlements	(447		)
Revision of estimates	8,319
Asset retirement obligations at September 30, 2015	$	135,868

Note 8 – Commitments and Contingencies

East Texas Gathering System

The Company is party to certain long-term natural gas gathering agreements for its East Texas production. The agreements contain embedded leases and the transaction was accounted for as a financing obligation. The asset is being depreciated over the remaining useful life and has a net book value of approximately $12 million at September 30, 2015. There are no minimum payments required under these agreements.

Carry and Earning Agreement

In January 2011, the Company entered into an amendment relating to certain contractual obligations to a third-party co-owner of certain Piceance Basin assets in Colorado. The amendment waives a $200,000 penalty for each well not spud by February 2011 and requires the Company to reassign to such third party, by January 31, 2020, all of the interest acquired by the Company from the third party in each 160-acre tract in which the Company has not drilled and completed a well that is producing or capable of producing from a designated formation, or deeper formation, on January 1, 2020. The amendment also requires the Company to pay the first $9 million of costs incurred in connection with the construction of either an extension of the existing access road or a new access road, including the third party’s 50% share. Pursuant to the terms of a further amendment effective September 30, 2015, if by September 30, 2017, the Company does not expend $9 million on the construction of either the extension of the existing access road or a new access road, the Company is obligated to pay the third party 50% of the difference between $12 million and the actual amount expended on road construction as of such date. Under the terms of the 2015 amendment, this deadline is subject to further extension to no later than December 31, 2017. Due to the need to obtain regulatory approvals, among other reasons, the Company has not yet commenced construction of either an extension of the existing access road or a new access road and may be unable to do so by the extended deadline, thus triggering the payment of the obligation to the third party.

Legal Matters

The Company is involved in various lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of management, the resolution of these matters will not have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

During the nine months ended September 30, 2015, and September 30, 2014, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Note 9 – Income Taxes

The Company is a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does

13

BERRY PETROLEUM COMPANY, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued

(Unaudited)

not directly pay federal and state income taxes, and therefore, recognition has not been given to federal and state income taxes for the operations of the Company. Amounts recognized for income taxes are reported in “income tax expense (benefit)” on the condensed statements of operations.

Note 10 – Supplemental Disclosures to the Condensed Balance Sheets and Condensed Statements of Cash Flows

“Other current assets” reported on the condensed balance sheets primarily consist of inventories. “Other accrued liabilities” reported on the condensed balance sheets include the following:

	September 30, 2015		December 31, 2014
	(in thousands)
Accrued interest	$	9,548	$	15,803
Asset retirement obligations	3,101		3,101
Other	58		183
	$	12,707	$	19,087

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

	Nine Months Ended September 30,
	2015		2014
	(in thousands)
Cash payments for interest, net of amounts capitalized	$	70,853	$	79,090
Cash payments for income taxes	$	—	$	—
Noncash investing activities:
Accrued capital expenditures	$	20,959	$	79,425

For the nine months ended September 30, 2015, LINN Energy spent approximately $165 million of capital expenditures in respect of Berry’s operations. Berry recorded the $165 million to oil and natural gas properties with an offset to the advance due from LINN Energy. On September 30, 2015, LINN Energy repaid in full the remaining advance of approximately $129 million.

In addition, in May 2015, LINN Energy made a capital contribution of $250 million to Berry which was deposited on Berry’s behalf and posted as restricted cash with Berry’s lenders in connection with the reduction in its borrowing base (see Note 4).

Note 11 – Related Party Transactions

LINN Energy

The Company has no employees. The employees of Linn Operating, Inc. (“LOI”), a subsidiary of LINN Energy, provide services and support to the Company in accordance with an agency agreement and power of attorney between the Company and LOI. For the three months and nine months ended September 30, 2015, the Company incurred management fee expenses of approximately $20 million and $73 million, respectively, for services provided by LOI. For the three months and nine months ended September 30, 2014, the Company incurred management fee expenses of approximately $14 million and $74 million, respectively, for services provided by LOI. The Company also had affiliated accounts payable due to LINN Energy of approximately $6 million and $13 million at September 30, 2015, and December 31, 2014, respectively, included in “accounts payable and accrued expenses” on the condensed balance sheets.

14

BERRY PETROLEUM COMPANY, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued

(Unaudited)

During the nine months ended September 30, 2015, the Company made cash distributions of approximately $57 million to LINN Energy. During the nine months ended September 30, 2014, the Company made cash distributions of approximately $52 million to LINN Energy.

In 2014, the Company advanced approximately $352 million, to a subsidiary of LINN Energy, of net cash proceeds from the sale of certain of the Company’s Wolfberry properties in Ector and Midland counties in the Permian Basin to Fleur de Lis Energy, LLC. These proceeds must be used by LINN Energy on capital expenditures in respect of Berry’s operations, to repay Berry’s indebtedness or as otherwise permitted under the terms of Berry’s indentures and Credit Facility. During the twelve months ended September 30, 2015, LINN Energy spent approximately $223 million, including approximately $58 million in 2014, of capital expenditures in respect of Berry’s operations. On September 30, 2015, LINN Energy repaid in full the remaining advance of approximately $129 million. In October 2015, Berry used that cash to repay borrowings under its Credit Facility.

During the nine months ended September 30, 2015, Linn Energy made capital contributions of approximately $399 million to Berry including $250 million which was deposited on Berry’s behalf and posted as restricted cash with Berry’s lenders in connection with the reduction in its borrowing base in May 2015 (see Note 4). The $250 million may be used to satisfy obligations under the Credit Facility or may be returned to LINN Energy in the future if commodity prices improve. During the second quarter of 2014, LINN Energy made a cash capital contribution of $220 million to the Company which was used to pay in full the remaining outstanding principal amount of its approximate $205 million 10.25% senior notes due June 2014 plus accrued interest.

Other

One of LINN Energy’s directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. For the three months and nine months ended September 30, 2015, the Company incurred expenditures of approximately $24,000 and $342,000, respectively, and for the nine months ended September 30, 2014, the Company incurred expenditures of approximately $176,000 related to services rendered by Superior and its subsidiaries. No expenditures were incurred for the three months ended September 30, 2014.

15

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

The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control. The Company’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement Regarding Forward-Looking Statements” 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, 2014, 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, 2014. The reference to a “Note” herein refers to the accompanying Notes to Condensed Financial Statements contained in Item 1. “Financial Statements.”

Executive Overview

Berry Petroleum Company, LLC (“Berry” or the “Company”) was formed as a Delaware limited liability company on December 16, 2013, and is an indirect wholly owned subsidiary of Linn Energy, LLC (“LINN Energy”) engaged in the production and development of oil and natural gas. The Company’s predecessor, Berry Petroleum Company, was publicly traded from 1987 until being acquired by LINN Energy in December 2013. On December 16, 2013, the Company completed the transactions contemplated by the merger agreement between LINN Energy, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and LINN Energy, under which LinnCo contributed Berry to LINN Energy in exchange for LINN Energy units. Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, is currently the Company’s sole member.

The Company currently has five operating areas in the United States (“U.S.”): California, Hugoton Basin, Uinta Basin, Piceance Basin and East Texas. In August and November of 2014, the Company divested all of its properties located in the Permian Basin.

Results for the three months ended September 30, 2015, included the following:

• oil, natural gas and NGL sales of approximately $140 million compared to $351 million for the third quarter of 2014;

• average daily production of approximately 48.3 MBOE/d compared to 54.7 MBOE/d for the third quarter of 2014;

• net loss of approximately $537 million compared to net income of $115 million for the third quarter of 2014;

• capital expenditures, excluding acquisitions, of approximately $34 million compared to $163 million for the third quarter of 2014; and

• 19 wells drilled (all successful) compared to 129 wells drilled (all successful) for the third quarter of 2014.

Results for the nine months ended September 30, 2015, included the following:

• oil, natural gas and NGL sales of approximately $470 million compared to $1.0 billion for the nine months ended September 30, 2014;

• average daily production of approximately 49.1 MBOE/d compared to 50.7 MBOE/d for the nine months ended September 30, 2014;

• net loss of approximately $889 million compared to net income of $274 million for the nine months ended September 30, 2014;

• net cash provided by operating activities of approximately $109 million compared to $443 million for the nine months ended September 30, 2014;

• capital expenditures, excluding acquisitions, of approximately $135 million compared to $438 million for the nine months ended September 30, 2014; and

• 119 wells drilled (all successful) compared to 317 wells drilled (all successful) for the nine months ended September 30, 2014.

16

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

Financing Activities

In October 2015, the Company entered into an amendment to its Second Amended and Restated Credit Agreement (“Credit Facility”). See Note 4 for additional details.

The spring 2015 semi-annual borrowing base redetermination of the Company’s Credit Facility was completed in May 2015, and, as a result of lower commodity prices, the borrowing base under the Credit Facility decreased from $1.4 billion to $1.2 billion. The fall 2015 semi-annual redetermination was completed in October 2015, and the borrowing base under the Credit Facility decreased from $1.2 billion to $900 million. Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs may impact future redeterminations.

In connection with the reduction in Berry’s borrowing base in October 2015, Berry repaid $300 million of borrowings outstanding under the Credit Facility. In connection with the reduction in Berry’s borrowing base in May 2015, LINN Energy contributed $250 million to Berry to post as restricted cash with Berry’s lenders. As directed by LINN Energy, the $250 million was deposited on Berry’s behalf in a security account with the administrative agent subject to a security control agreement. Berry’s ability to withdraw funds from this account is subject to a concurrent reduction of the borrowing base under the Credit Facility or lender’s consent in connection with a redetermination of such borrowing base. The $250 million may be used to satisfy obligations under the Credit Facility or, subject to restrictions in the indentures governing Berry’s senior notes, may be returned to LINN Energy in the future.

During the nine months ended September 30, 2015, the Company repurchased, on the open market and through a privately negotiated transaction, approximately $65 million of its outstanding senior notes. See Note 4 for additional details.

Commodity Derivatives

During the nine months ended September 30, 2015, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for May 2015 through December 2016 to hedge exposure to differentials in certain producing areas, and oil swaps for April 2015 through December 2015. In addition, the Company entered into natural gas basis swaps for May 2015 through December 2016 to hedge exposure to the differential in California, where it consumes natural gas in its heavy oil development operations.

17

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

Results of Operations

Three Months Ended September 30, 2015, Compared to Three Months Ended September 30, 2014

	Three Months Ended September 30,
	2015			2014			Variance
	(in thousands)
Revenues and other:
Oil sales	$	113,155		$	310,742		$	(197,587	)
Natural gas sales	23,190			34,950			(11,760		)
NGL sales	3,907			5,171			(1,264		)
Total oil, natural gas and NGL sales	140,252			350,863			(210,611		)
Electricity sales	8,610			11,300			(2,690		)
Gains on oil and natural gas derivatives	27,664			44,990			(17,326		)
Marketing and other revenues	2,781			2,263			518
	179,307			409,416			(230,109		)
Expenses:
Lease operating expenses	67,341			83,684			(16,343		)
Electricity generation expenses	4,759			5,892			(1,133		)
Transportation expenses	13,794			13,326			468
Marketing expenses	967			1,811			(844		)
General and administrative expenses	21,564			16,566			4,998
Depreciation, depletion and amortization	63,057			79,725			(16,668		)
Impairment of long-lived assets	510,631			—			510,631
Taxes, other than income taxes	14,520			24,830			(10,310		)
Losses on sale of assets and other, net	2,633			49,011			(46,378		)
	699,266			274,845			424,421
Other income and (expenses)	(17,196		)	(19,247		)	2,051
Income (loss) before income taxes	(537,155		)	115,324			(652,479		)
Income tax expense	3			159			(156		)
Net income (loss)	$	(537,158	)	$	115,165		$	(652,323	)

18

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

	Three Months Ended September 30,
	2015		2014		Variance
Average daily production:
Oil (MBbls/d)	29.8		37.8		(21	)%
Natural gas (MMcf/d)	93.8		93.5		—
NGL (MBbls/d)	2.9		1.2		142	%
Total (MBOE/d)	48.3		54.7		(12	)%
Weighted average prices:(1)
Oil (Bbl)	$	41.32	$	89.24	(54	)%
Natural gas (Mcf)	$	2.69	$	4.06	(34	)%
NGL (Bbl)	$	14.43	$	45.56	(68	)%
Average NYMEX prices:
Oil (Bbl)	$	46.43	$	97.17	(52	)%
Natural gas (MMBtu)	$	2.77	$	4.06	(32	)%
Costs per BOE of production:
Lease operating expenses	$	15.14	$	16.64	(9	)%
Transportation expenses	$	3.10	$	2.65	17	%
General and administrative expenses	$	4.85	$	3.29	47	%
Depreciation, depletion and amortization	$	14.18	$	15.85	(11	)%
Taxes, other than income taxes	$	3.26	$	4.94	(34	)%

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

19

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

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales decreased by approximately $211 million or 60% to approximately $140 million for the three months ended September 30, 2015, from approximately $351 million for the three months ended September 30, 2014, due to lower oil, natural gas and NGL prices and lower production volumes. Lower oil, natural gas and NGL prices resulted in a decrease in revenues of approximately $132 million, $12 million and $8 million, respectively.

Average daily production volumes decreased to approximately 48.3 MBOE/d for the three months ended September 30, 2015, from 54.7 MBOE/d for the three months ended September 30, 2014. Lower oil production volumes resulted in a decrease in revenues of approximately $66 million. Higher NGL production volumes resulted in an increase in revenues of approximately $7 million. Natural gas production volumes were virtually unchanged.

The following table sets forth average daily production by operating area:

	Three Months Ended September 30,
	2015	2014	Variance
Average daily production (MBOE/d):
California	25.5	26.6	(1.1	)	(4	)%
Hugoton Basin	9.5	5.6	3.9		70	%
Uinta Basin	7.9	11.2	(3.3	)	(29	)%
Piceance Basin	3.8	1.9	1.9		100	%
East Texas	1.6	1.8	(0.2	)	(11	)%
Permian Basin	—	7.6	(7.6	)	(100	)%
	48.3	54.7	(6.4	)	(12	)%

The decrease in average daily production volumes in California primarily reflects reduced development capital spending, partially offset by the impact of the properties received in the exchange with Exxon Mobil Corporation (“ExxonMobil”) on November 21, 2014. Average daily production volumes in the Hugoton Basin operating area reflect the impact of the properties received in the exchange with Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc. (“Exxon XTO”) on August 15, 2014. The decrease in average daily production volumes in the Uinta Basin and East Texas operating areas primarily reflects the effects of production declines due to reduced development capital spending. The increase in average daily production volumes in the Piceance Basin operating area primarily reflects development capital spending. The decrease in average daily production volumes in the Permian Basin operating area reflects the properties relinquished in the two exchanges with ExxonMobil and Exxon XTO and the properties sold to Fleur de Lis Energy, LLC on November 14, 2014. The Company had no Permian Basin properties remaining as of December 31, 2014.

Electricity Sales

The following table sets forth selected electricity data:

	Three Months Ended September 30,
	2015		2014		Variance
Electricity sales (in thousands)	$	8,610	$	11,300	(24	)%
Electricity generation expenses (in thousands)	$	4,759	$	5,892	(19	)%
Electric power produced (Mwh/d)	2,159		2,119		2	%
Electric power sold (Mwh/d)	1,934		1,933		—
Average sales price per Mwh	$	48.35	$	71.18	(32	)%
Fuel gas cost per MMBtu (including transportation)	$	2.83	$	4.17	(32	)%
Estimated natural gas volumes consumed to produce electricity (MMBtu/d) (1)	14,764		14,557		1	%

⁽¹⁾  Estimate is based on the historical allocation of fuel costs to electricity.

20

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

Electricity sales represent sales to utilities and decreased by approximately $2 million or 24% to approximately $9 million for the three months ended September 30, 2015, from approximately $11 million for the three months ended September 30, 2014, primarily due to a decrease in the average sales price of electricity during the period.

Gains (Losses) on Oil and Natural Gas Derivatives

Gains on oil and natural gas derivatives were approximately $28 million and $45 million for the three months ended September 30, 2015, and September 30, 2014, respectively, representing a decrease of approximately $17 million. Gains on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts. The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.

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” and Note 5 and Note 6 for additional information about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.

Marketing and Other Revenues

Marketing revenues primarily represent third-party activities associated with the Company’s long-term firm transportation contracts. The Company’s current production is insufficient to fully utilize this capacity. To optimize its remaining capacity, the Company utilizes asset management agreements and various other marketing arrangements. Sales of third-party natural gas are recorded as marketing revenues. Marketing and other revenues increased by approximately $1 million or 23% to approximately $3 million for the three months ended September 30, 2015, from approximately $2 million for the three months ended September 30, 2014. The increase was primarily due to higher helium sales revenue in the Hugoton Basin partially offset by lower marketing revenues principally due to a decrease in natural gas prices.

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 decreased by approximately $17 million or 20% to approximately $67 million for the three months ended September 30, 2015, from approximately $84 million for the three months ended September 30, 2014. The decrease was primarily due to a decrease in steam costs caused by lower prices for natural gas used in steam generation, cost savings initiatives and lower costs as a result of the properties sold and exchanged during the third and fourth quarters of 2014. Lease operating expenses per BOE also decreased to $15.14 per BOE for the three months ended September 30, 2015, from $16.64 per BOE for the three months ended September 30, 2014.

The following table sets forth steam information:

	Three Months Ended September 30,
	2015		2014		Variance
Average net volume of steam injected (Bbls/d)	283,093		252,006		12	%
Fuel gas cost per MMBtu (including transportation)	$	2.83	$	4.17	(32	)%
Estimated natural gas volumes consumed to produce steam (MMBtu/d)	99,874		90,348		11	%

Electricity Generation Expenses

Electricity generation expenses decreased by approximately $1 million or 19% to approximately $5 million for the three months ended September 30, 2015, from approximately $6 million for the three months ended September 30, 2014, primarily due to a decrease in fuel gas cost partially offset by an increase in fuel gas volumes purchased.

21

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

Transportation Expenses

Transportation expenses increased by approximately $1 million or 4% to approximately $14 million for the three months ended September 30, 2015, from approximately $13 million for the three months ended September 30, 2014, primarily due to costs associated with Hugoton Basin properties acquired in the exchange with Exxon XTO on August 15, 2014.

Marketing Expenses

Marketing expenses primarily represent third-party activities associated with the Company’s long-term firm transportation contracts. The Company’s current production is insufficient to fully utilize its capacity. To optimize its remaining capacity, the Company utilizes asset management agreements and various other marketing arrangements. Purchases of third-party natural gas are recorded as marketing expenses. Marketing expenses decreased by approximately $1 million or 47% to approximately $1 million for the three months ended September 30, 2015, from approximately $2 million for the three months ended September 30, 2014, primarily due to a decrease in natural gas prices.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations. General and administrative expenses increased by approximately $5 million or 30% to approximately $22 million for the three months ended September 30, 2015, from approximately $17 million for the three months ended September 30, 2014. The increase was primarily due to higher costs allocated to the Company by Linn Operating, Inc. General and administrative expenses per BOE also increased to $4.85 per BOE for the three months ended September 30, 2015, from $3.29 per BOE for the three months ended September 30, 2014.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization decreased by approximately $17 million or 21% to approximately $63 million for the three months ended September 30, 2015, from approximately $80 million for the three months ended September 30, 2014. The decrease was primarily due to lower rates as a result of the impairments recorded in the prior year and the first quarter of 2015 as well as lower total production volumes. Depreciation, depletion and amortization per BOE also decreased to $14.18 per BOE for the three months ended September 30, 2015, from $15.85 per BOE for the three months ended September 30, 2014.

Impairment of Long-Lived Assets

The Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties:

	Three Months Ended September 30, 2015
	(in thousands)
California operating area	$	330,311
Uinta Basin operating region	111,339
East Texas operating area	13,637
Piceance Basin operating region	55,344
	$	510,631

The impairment charges in 2015 were due to a decline in commodity prices and the Company’s estimates of proved reserves. The Company recorded no impairment charges for the three months ended September 30, 2014.

22

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

Taxes, Other Than Income Taxes

	Three Months Ended September 30,
	2015			2014		Variance
	(in thousands)
Severance taxes	$	(809	)	$	8,187	$	(8,996	)
Ad valorem taxes	9,966			12,529		(2,563		)
California carbon allowances	5,366			4,114		1,252
Other	(3		)	—		(3		)
	$	14,520		$	24,830	$	(10,310	)

Taxes, other than income taxes decreased by approximately $10 million or 42% for the three months ended September 30, 2015, compared to the three months ended September 30, 2014. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower oil, natural gas and NGL prices and lower production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, decreased primarily due to a lower estimated valuation on certain of the Company’s California properties. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed and higher costs for acquired allowances.

Losses on Sale of Assets and Other, Net

During the three months ended September 30, 2014, the Company recorded a net loss of approximately $49 million on the noncash exchange of a portion of its Permian Basin properties to Exxon XTO for properties in the Hugoton Basin (see Note 2).

Other Income and (Expenses)

	Three Months Ended September 30,
	2015			2014			Variance
	(in thousands)
Interest expense, net of amounts capitalized	$	(21,484	)	$	(19,068	)	$	(2,416	)
Gain on extinguishment of debt	4,378			—			4,378
Other, net	(90		)	(179		)	89
	$	(17,196	)	$	(19,247	)	$	2,051

Other income and (expenses) decreased by approximately $2 million for the three months ended September 30, 2015, compared to the three months ended September 30, 2014. Interest expense increased primarily due to a decrease in capitalized interest, partially offset by lower outstanding debt during the period. In addition, for the three months ended September 30, 2015, the Company recorded a gain on extinguishment of debt of approximately $4 million as a result of the repurchases of a portion of its senior notes. See “Debt” under “Liquidity and Capital Resources” below for additional details.

Income Tax Expense (Benefit)

The Company is a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income taxes, and therefore, recognition has not been given to federal and state income taxes for the operations of the Company. The Company recognized income tax expense of approximately $3,000 and $159,000 for the three months ended September 30, 2015, and September 30, 2014, respectively. The decrease was primarily due to a decrease in state income tax expense resulting from changes in the Company’s operations during the three months ended September 30, 2015, compared to the same period in 2014.

23

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

Net Income (Loss)

Net income decreased by approximately $652 million or 566% to a net loss of approximately $537 million for the three months ended September 30, 2015, from net income of approximately $115 million for the three months ended September 30, 2014. The decrease was primarily due to higher impairment charges and lower production revenues, partially offset by lower expenses. See discussions above for explanations of variances.

24

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

Results of Operations

Nine Months Ended September 30, 2015, Compared to Nine Months Ended September 30, 2014

	Nine Months Ended September 30,
	2015			2014			Variance
	(in thousands)
Revenues and other:
Oil sales	$	381,813		$	936,463		$	(554,650	)
Natural gas sales	71,694			88,339			(16,645		)
NGL sales	16,712			19,557			(2,845		)
Total oil, natural gas and NGL sales	470,219			1,044,359			(574,140		)
Electricity sales	20,370			31,461			(11,091		)
Gains on oil and natural gas derivatives	26,457			22,893			3,564
Marketing and other revenues	9,432			9,344			88
	526,478			1,108,057			(581,579		)
Expenses:
Lease operating expenses	184,426			267,069			(82,643		)
Electricity generation expenses	14,322			21,904			(7,582		)
Transportation expenses	39,378			28,802			10,576
Marketing expenses	3,047			6,505			(3,458		)
General and administrative expenses	79,853			88,379			(8,526		)
Depreciation, depletion and amortization	199,088			226,109			(27,021		)
Impairment of long-lived assets	782,631			—			782,631
Taxes, other than income taxes	60,048			71,338			(11,290		)
(Gains) losses on sale of assets and other, net	(2,651		)	56,635			(59,286		)
	1,360,142			766,741			593,401
Other income and (expenses)	(55,109		)	(67,368		)	12,259
Income (loss) before income taxes	(888,773		)	273,948			(1,162,721		)
Income tax expense (benefit)	(58		)	77			(135		)
Net income (loss)	$	(888,715	)	$	273,871		$	(1,162,586	)

25

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

	Nine Months Ended September 30,
	2015		2014		Variance
Average daily production:
Oil (MBbls/d)	30.8		37.2		(17	)%
Natural gas (MMcf/d)	93.7		71.0		32	%
NGL (MBbls/d)	2.7		1.6		69	%
Total (MBOE/d)	49.1		50.7		(3	)%
Weighted average prices:(1)
Oil (Bbl)	$	45.36	$	92.19	(51	)%
Natural gas (Mcf)	$	2.80	$	4.56	(39	)%
NGL (Bbl)	$	23.03	$	43.68	(47	)%
Average NYMEX prices:
Oil (Bbl)	$	51.00	$	99.61	(49	)%
Natural gas (MMBtu)	$	2.80	$	4.55	(38	)%
Costs per BOE of production:
Lease operating expenses	$	13.76	$	19.30	(29	)%
Transportation expenses	$	2.94	$	2.08	41	%
General and administrative expenses	$	5.96	$	6.39	(7	)%
Depreciation, depletion and amortization	$	14.85	$	16.34	(9	)%
Taxes, other than income taxes	$	4.48	$	5.16	(13	)%

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

26

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

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales decreased by approximately $574 million or 55% to approximately $470 million for the nine months ended September 30, 2015, from approximately $1.0 billion for the nine months ended September 30, 2014, due to lower oil, natural gas and NGL prices and lower production volumes. Lower oil, natural gas and NGL prices resulted in a decrease in revenues of approximately $394 million, $45 million and $15 million, respectively.

Average daily production volumes decreased to approximately 49.1 MBOE/d for the nine months ended September 30, 2015, from 50.7 MBOE/d for the nine months ended September 30, 2014. Lower oil production volumes resulted in a decrease in revenues of approximately $160 million. Higher natural gas and NGL production volumes resulted in an increase in revenues of approximately $28 million and $12 million, respectively.

The following table sets forth average daily production by operating area:

	Nine Months Ended September 30,
	2015	2014	Variance
Average daily production (MBOE/d):
California	26.3	25.7	0.6		2	%
Hugoton Basin	9.9	1.9	8.0		421	%
Uinta Basin	8.6	11.0	(2.4	)	(22	)%
Piceance Basin	2.7	2.0	0.7		35	%
East Texas	1.6	1.7	(0.1	)	(6	)%
Permian Basin	—	8.4	(8.4	)	(100	)%
	49.1	50.7	(1.6	)	(3	)%

The increase in average daily production volumes in California primarily reflects the impact of the properties received in the exchange with ExxonMobil on November 21, 2014, partially offset by reduced development capital spending. Average daily production volumes in the Hugoton Basin operating area reflect the impact of the properties received in the exchange with Exxon XTO on August 15, 2014. The decrease in average daily production volumes in the Uinta Basin and East Texas operating areas primarily reflects the effects of production declines due to reduced development capital spending. The increase in average daily production volumes in the Piceance Basin operating area primarily reflects development capital spending. The decrease in average daily production volumes in the Permian Basin operating area reflects the properties relinquished in the two exchanges with ExxonMobil and Exxon XTO and the properties sold to Fleur de Lis Energy, LLC on November 14, 2014. The Company had no Permian Basin properties remaining as of December 31, 2014.

Electricity Sales

The following table sets forth selected electricity data:

	Nine Months Ended September 30,
	2015		2014		Variance
Electricity sales (in thousands)	$	20,370	$	31,461	(35	)%
Electricity generation expenses (in thousands)	$	14,322	$	21,904	(35	)%
Electric power produced (Mwh/d)	2,021		2,076		(3	)%
Electric power sold (Mwh/d)	1,790		1,889		(5	)%
Average sales price per Mwh	$	41.68	$	63.61	(34	)%
Fuel gas cost per MMBtu (including transportation)	$	2.73	$	4.77	(43	)%
Estimated natural gas volumes consumed to produce electricity (MMBtu/d) (1)	14,019		15,098		(7	)%

⁽¹⁾  Estimate is based on the historical allocation of fuel costs to electricity.

27

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

Electricity sales represent sales to utilities and decreased by approximately $11 million or 35% to approximately $20 million for the nine months ended September 30, 2015, from approximately $31 million for the nine months ended September 30, 2014, primarily due to decreases in the average sales price of electricity and electric power sold during the period.

Gains (Losses) on Oil and Natural Gas Derivatives

Gains on oil and natural gas derivatives were approximately $26 million and $23 million for the nine months ended September 30, 2015, and September 30, 2014, respectively, representing an increase of approximately $3 million. Gains on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts. The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.

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” and Note 5 and Note 6 for additional information about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.

Marketing and Other Revenues

Marketing revenues primarily represent third-party activities associated with the Company’s long-term firm transportation contracts. The Company’s current production is insufficient to fully utilize this capacity. To optimize its remaining capacity, the Company utilizes asset management agreements and various other marketing arrangements. Sales of third-party natural gas are recorded as marketing revenues. Marketing and other revenues remained virtually unchanged at approximately $9 million for both the nine months ended September 30, 2015, and September 30, 2014. For the nine months ended September 30, 2015, higher helium sales revenue in the Hugoton Basin was offset by lower marketing revenues principally due to a decrease in natural gas prices.

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 decreased by approximately $83 million or 31% to approximately $184 million for the nine months ended September 30, 2015, from approximately $267 million for the nine months ended September 30, 2014. The decrease was primarily due to a decrease in steam costs caused by lower prices for natural gas used in steam generation, cost savings initiatives and lower costs as a result of the properties sold and exchanged during the third and fourth quarters of 2014. Lease operating expenses per BOE also decreased to $13.76 per BOE for the nine months ended September 30, 2015, from $19.30 per BOE for the nine months ended September 30, 2014.

The following table sets forth steam information:

	Nine Months Ended September 30,
	2015		2014		Variance
Average net volume of steam injected (Bbls/d)	282,809		245,329		15	%
Fuel gas cost per MMBtu (including transportation)	$	2.73	$	4.77	(43	)%
Estimated natural gas volumes consumed to produce steam (MMBtu/d)	100,472		87,742		15	%

Electricity Generation Expenses

Electricity generation expenses decreased by approximately $8 million or 35% to approximately $14 million for the nine months ended September 30, 2015, from approximately $22 million for the nine months ended September 30, 2014, primarily due to a decrease in fuel gas cost partially offset by an increase in fuel gas volumes purchased.

28

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

Transportation Expenses

Transportation expenses increased by approximately $10 million or 37% to approximately $39 million for the nine months ended September 30, 2015, from approximately $29 million for the nine months ended September 30, 2014, primarily due to costs associated with Hugoton Basin properties acquired in the exchange with Exxon XTO on August 15, 2014.

Marketing Expenses

Marketing expenses primarily represent third-party activities associated with the Company’s long-term firm transportation contracts. The Company’s current production is insufficient to fully utilize its capacity. To optimize its remaining capacity, the Company utilizes asset management agreements and various other marketing arrangements. Purchases of third-party natural gas are recorded as marketing expenses. Marketing expenses decreased by approximately $4 million or 53% to approximately $3 million for the nine months ended September 30, 2015, from approximately $7 million for the nine months ended September 30, 2014, primarily due to a decrease in natural gas prices.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations. General and administrative expenses decreased by approximately $8 million or 10% to approximately $80 million for the nine months ended September 30, 2015, from approximately $88 million for the nine months ended September 30, 2014. The decrease was primarily due to lower costs allocated to the Company by Linn Operating, Inc., as well as lower transition expenses and professional services expenses. General and administrative expenses per BOE also decreased to $5.96 per BOE for the nine months ended September 30, 2015, from $6.39 per BOE for the nine months ended September 30, 2014.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization decreased by approximately $27 million or 12% to approximately $199 million for the nine months ended September 30, 2015, from approximately $226 million for the nine months ended September 30, 2014. The decrease was primarily due to lower rates as a result of the impairments recorded in the prior year and the first quarter of 2015 as well as lower total production volumes. Depreciation, depletion and amortization per BOE also decreased to $14.85 per BOE for the nine months ended September 30, 2015, from $16.34 per BOE for the nine months ended September 30, 2014.

Impairment of Long-Lived Assets

The Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties:

	Nine Months Ended September 30, 2015
	(in thousands)
California operating area	$	537,511
Uinta Basin operating region	111,339
East Texas operating area	78,437
Piceance Basin operating region	55,344
	$	782,631

The impairment charges in 2015 were due to a decline in commodity prices and the Company’s estimates of proved reserves. The Company recorded no impairment charges for the nine months ended September 30, 2014.

29

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

Taxes, Other Than Income Taxes

	Nine Months Ended September 30,
	2015		2014		Variance
	(in thousands)
Severance taxes	$	4,967	$	19,429	$	(14,462	)
Ad valorem taxes	38,238		38,882		(644		)
California carbon allowances	16,834		13,002		3,832
Other	9		25		(16		)
	$	60,048	$	71,338	$	(11,290	)

Taxes, other than income taxes decreased by approximately $11 million or 16% for the nine months ended September 30, 2015, compared to the nine months ended September 30, 2014. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower oil, natural gas and NGL prices and lower production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, decreased primarily due to a lower estimated valuation on certain of the Company’s California properties. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed and higher costs for acquired allowances.

(Gains) Losses on Sale of Assets and Other, Net

During the nine months ended September 30, 2014, the Company recorded a net loss of approximately $49 million on the noncash exchange of a portion of its Permian Basin properties to Exxon XTO for properties in the Hugoton Basin (see Note 2).

Other Income and (Expenses)

	Nine Months Ended September 30,
	2015			2014			Variance
	(in thousands)
Interest expense, net of amounts capitalized	$	(65,595	)	$	(66,555	)	$	960
Gain on extinguishment of debt	11,209			—			11,209
Other, net	(723		)	(813		)	90
	$	(55,109	)	$	(67,368	)	$	12,259

Other income and (expenses) decreased by approximately $12 million for the nine months ended September 30, 2015, compared to the nine months ended September 30, 2014. Interest expense decreased primarily due to lower outstanding debt during the period, partially offset by lower premium amortization related to the repayment of the June 2014 senior notes in May 2014 and a decrease in capitalized interest. In addition, for the nine months ended September 30, 2015, the Company recorded a gain on extinguishment of debt of approximately $11 million as a result of the repurchases of a portion its senior notes. See “Debt” under “Liquidity and Capital Resources” below for additional details.

Income Tax Expense (Benefit)

The Company is a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income taxes, and therefore, recognition has not been given to federal and state income taxes for the operations of the Company. The Company recognized an income tax benefit of approximately $58,000 for the nine months ended September 30, 2015, compared to income tax expense of approximately $77,000 for the nine months ended September 30, 2014. The income tax benefit was primarily due to a decrease in state income tax expense resulting from changes in the Company’s operations during the nine months ended September 30, 2015, compared to the same period in 2014.

30

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

Net Income (Loss)

Net income decreased by approximately $1.2 billion or 425% to a net loss of approximately $889 million for the nine months ended September 30, 2015, from net income of approximately $274 million for the nine months ended September 30, 2014. The decrease was primarily due to higher impairment charges and lower production revenues, partially offset by lower expenses. See discussions above for explanations of variances.

Liquidity and Capital Resources

The Company has utilized funds from debt offerings, borrowings under its Credit Facility and net cash provided by operating activities for capital resources and liquidity. Historically, the primary use of capital has been for the development of oil and natural gas properties. For the nine months ended September 30, 2015, the Company’s total capital expenditures were approximately $135 million. LINN Energy continually evaluates the capital needs of the Company along with those of its other operating areas. LINN Energy establishes a capital plan each calendar year for all of its operations based on development opportunities and the expected cash flow from operations for that year. The capital plan may be revised during the year as a result of drilling outcomes or significant changes in cash flows. To the extent net cash provided by operating activities is higher or lower than currently anticipated, LINN Energy may adjust the Company’s capital plan accordingly or adjust borrowings under the Company’s Credit Facility, as needed. However, at September 30, 2015, the Company had less than $1 million of available borrowing capacity under its Credit Facility.

In October 2015, the Company entered into an amendment to the Credit Facility. See Note 4 for additional details.

The spring 2015 semi-annual borrowing base redetermination of the Company’s Credit Facility was completed in May 2015, and, as a result of lower commodity prices, the borrowing base under the Credit Facility decreased from $1.4 billion to $1.2 billion. The fall 2015 semi-annual redetermination was completed in October 2015, and the borrowing base under the Credit Facility decreased from $1.2 billion to $900 million. Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs may impact future redeterminations.

In connection with the reduction in Berry’s borrowing base in October 2015, Berry repaid $300 million of borrowings outstanding under the Credit Facility using the cash received from the settlement of its advance and capital contributions made by LINN Energy. In connection with the reduction in Berry’s borrowing base in May 2015, LINN Energy contributed $250 million to Berry to post as restricted cash with Berry’s lenders. As directed by LINN Energy, the $250 million was deposited on Berry’s behalf in a security account with the administrative agent subject to a security control agreement. Berry’s ability to withdraw funds from this account is subject to a concurrent reduction of the borrowing base under the Credit Facility or lender’s consent in connection with a redetermination of such borrowing base. The $250 million may be used to satisfy obligations under the Credit Facility or, subject to restrictions in the indentures governing Berry’s senior notes, may be returned to LINN Energy in the future.

LINN Energy continually monitors the capital resources available to meet future financial obligations and planned capital expenditures. The Company’s future success in growing reserves and production volumes will be highly dependent on the capital resources available and its success in adding reserves from its drilling program. The Company’s Credit Facility and indentures governing its senior notes impose certain restrictions on the Company’s ability to obtain additional debt financing. The Company does not intend to obtain additional borrowing capacity under its Credit Facility or access the capital markets separately from LINN Energy. The Company intends to finance its operations, including its future capital expenditures, with net cash provided by operating activities and funding from LINN Energy. The Company believes such resources will be sufficient to conduct the Company’s business and operations.

Any cash generated by the Company is currently being used by the Company to fund its activities. To the extent that the Company generates cash in excess of its needs and determines to distribute such amounts to LINN Energy, the indentures governing the Company’s senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and the Company may not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Company’s indentures. The Company’s restricted payments basket was approximately $563 million at September 30, 2015, and may be increased in accordance with the terms of the Company’s indentures by, among other things, 50% of the Company’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions.

31

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

Statements of Cash Flows

The following is a comparative cash flow summary:

	Nine Months Ended September 30,
	2015		2014			Variance
	(in thousands)
Net cash:
Provided by operating activities	$	109,304	$	443,190		$	(333,886	)
Provided by (used in) investing activities	135,867		(438,000		)	573,867
Provided by (used in) financing activities	36,048		(49,655		)	85,703
Net increase (decrease) in cash and cash equivalents	$	281,219	$	(44,465	)	$	325,684

Operating Activities

Cash provided by operating activities for the nine months ended September 30, 2015, was approximately $109 million, compared to approximately $443 million for the nine months ended September 30, 2014. The decrease was primarily due to lower production related revenues principally due to lower commodity prices partially offset by higher cash settlements on derivatives.

Investing Activities

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

	Nine Months Ended September 30,
	2015			2014
	(in thousands)
Cash flow from investing activities:
Capital expenditures	$	(15,836	)	$	(438,256	)
Settlement of advance to affiliate	129,217			—
Proceeds from sale of properties and equipment and other	22,486			256
	$	135,867		$	(438,000	)

The primary use of cash in investing activities is for the development of the Company’s oil and natural gas properties. Capital expenditures decreased primarily due to lower spending on development activities during 2015. For the nine months ended September 30, 2015, LINN Energy spent approximately $165 million of capital expenditures in respect of Berry’s operations (see Note 10 and Note 11). In addition, on September 30, 2015, LINN Energy repaid in full its remaining advance of approximately $129 million.

Financing Activities

Cash provided by financing activities of approximately $36 million for the nine months ended September 30, 2015, was primarily related to capital contributions made by LINN Energy, partially offset by cash distributions to LINN Energy and repurchases of senior notes. Cash used in financing activities of approximately $50 million for the nine months ended September 30, 2014, was primarily related to cash distributions of approximately $52 million made to LINN Energy. In October 2015, Berry used the cash received from its remaining advance of approximately $129 million to repay borrowings outstanding under its Credit Facility. In addition, in May 2015, LINN Energy made a capital contribution of $250 million to Berry which was deposited on Berry’s behalf and posted as restricted cash with Berry’s lenders in connection with the reduction in its borrowing base (see Note 4).

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

Debt

During the nine months ended September 30, 2015, the Company repurchased, on the open market and through a privately negotiated transaction, approximately $65 million of its outstanding senior notes including approximately $39 million of its 6.75% senior notes due November 2020 and approximately $26 million of its 6.375% senior notes due September 2022.

The Company’s Credit Facility had a borrowing base of $1.2 billion, subject to lender commitments, as of September 30, 2015. At September 30, 2015, lender commitments under the facility were $1.2 billion but there was less than $1 million of available borrowing capacity, including outstanding letters of credit. For additional information related to the Company’s outstanding debt, see Note 4.

Financial Covenants

The Credit Facility, as amended in October 2015, contains requirements and financial covenants, among others, to maintain: 1) a ratio of Adjusted EBITDAX to Interest Expense (as each term is defined in the Credit Facility) (“Interest Coverage Ratio”) for the preceding four quarters of greater than 2.5 to 1.0 currently, 2.0 to 1.0 from December 31, 2015 through December 31, 2016, 2.25 to 1.0 from March 31, 2017 through June 30, 2017, and returning to 2.5 to 1.0 thereafter, and 2) a ratio of Current Assets to Current Liabilities (as each term is defined in the Credit Facility) (“Current Ratio”) as of the last day of any fiscal quarter of greater than 1.0 to 1.0. The Interest Coverage Ratio is intended as a measure of the Company’s ability to make interest payments on its outstanding indebtedness and the Current Ratio is intended as a measure of the Company’s solvency. The Company is required to demonstrate compliance with each of these ratios on a quarterly basis. The following represents the calculations of the Interest Coverage Ratio and the Current Ratio as presented to the lenders under the Credit Facility:

	At or for the Quarter Ended
	December 31, 2014	March 31, 2015	June 30, 2015	September 30, 2015	Twelve Months Ended September 30, 2015
Interest Coverage Ratio	6.5	1.7	2.6	2.2	3.3
Current Ratio (1)	0.6	0.6	0.5	2.0	2.0
Current Ratio (consolidated) (1)	2.9	3.2	2.9	2.6	2.6

⁽¹⁾  The 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.

The Company has included disclosure of the Interest Coverage Ratio for the twelve months ended September 30, 2015, and the Current Ratio as of September 30, 2015, to demonstrate its compliance for the quarter ended September 30, 2015, as well as the Interest Coverage Ratio for each of the preceding four quarters on an individual basis (rather than on a last twelve months basis) and the Current Ratio as of the end of each of the preceding four quarters to provide investors with trend information about the Company’s ongoing compliance with these financial covenants. If the Company fails to demonstrate compliance with either or both of the Interest Coverage Ratio or the Current Ratio as of the end of the quarter and such failure continues beyond applicable cure periods, an event of default would occur and the Company would be unable to make additional borrowings and outstanding indebtedness may be accelerated.

The Company is in compliance with all financial and other covenants of its Credit Facility and senior notes.

Counterparty Credit Risk

The Company accounts for its commodity derivatives at fair value. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or

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

have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Off-Balance Sheet Arrangements

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

Contingencies

See Part II. Item 1. “Legal Proceedings” for information regarding legal proceedings that the Company is party to and any contingencies related to these legal proceedings.

Commitments and Contractual Obligations

The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in the table of contractual obligations in the 2014 Annual Report on Form 10-K. With the exception of the repurchases of approximately $65 million of its outstanding senior notes, there have been no significant changes to the Company’s contractual obligations since December 31, 2014. See Note 4 for additional information about the Company’s debt instruments.

Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations is based on the condensed financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires management of the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors that are believed to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. Actual results may differ from these estimates and assumptions used in the preparation of the financial statements.

Recently Issued Accounting Standards

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

Cautionary Statement Regarding Forward-Looking Statements

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

• business strategy;

• financial strategy;

• ability to obtain additional funding from LINN Energy;

• effects of legal proceedings;

• 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;

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

• future operating results;

• plans, objectives, expectations and intentions; and

• integration of the assets and operations acquired in the exchanges of properties and commencement of activities in LINN Energy’s strategic alliances with GSO and Quantum, 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.

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

The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on Company expectations, which reflect estimates and assumptions made by Company management. These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors. Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control. In addition, management’s assumptions may prove to be inaccurate. The Company cautions that the forward-looking statements contained in this Quarterly Report on Form 10-Q are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors set forth in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2014, and elsewhere in the Annual Report. The forward-looking statements speak only as of the date made and, other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

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

The following should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Company’s 2014 Annual Report on Form 10-K. The reference to a “Note” herein refers to the accompanying Notes to Condensed Financial Statements contained in Item 1. “Financial Statements.”

Commodity Price Risk

The Company seeks to hedge a portion of its forecasted production to reduce exposure to commodity price fluctuations and provide long-term cash flow predictability to manage its business. The Company also, from time to time, enters into derivative contracts for a portion of its natural gas consumption. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials. By removing a portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices.

The appropriate level of production to be hedged is an ongoing consideration and is based on a variety of factors, including current and future expected commodity market prices, cost and availability of put option contracts, the level of LINN Energy’s acquisition activity and the Company’s overall risk profile, including leverage and size and scale considerations. In addition, when commodity prices are depressed and forward commodity price curves are flat or in backwardation, the Company may determine that the benefit of hedging its anticipated production at these levels is outweighed by its resultant inability to obtain

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Item 3.    Quantitative and Qualitative Disclosures About Market Risk - Continued

higher revenues for its production if commodity prices recover during the duration of the contracts. As a result, the appropriate percentage of production volumes to be hedged may change over time.

The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts, collars and three-way collars, and may enter into put option contracts in the future. The Company does not enter into derivative contracts for trading purposes.

At September 30, 2015, the fair value of fixed price swaps and three-way collars was a net asset of approximately $19 million. A 10% increase in the index oil and natural gas prices above the September 30, 2015, prices would result in a net asset of approximately $15 million, which represents a decrease in the fair value of approximately $4 million; conversely, a 10% decrease in the index oil and natural gas prices below the September 30, 2015, prices would result in a net asset of approximately $24 million, which represents an increase in the fair value of approximately $5 million.

At December 31, 2014, the fair value of three-way collars was a net asset of approximately $20 million. A 10% increase in the index oil price above the December 31, 2014, price would result in a net asset of approximately $18 million, which represents a decrease in the fair value of approximately $2 million; conversely, a 10% decrease in the index oil price below the December 31, 2014, price would result in a net asset of approximately $21 million, which represents an increase in the fair value of approximately $1 million. At December 31, 2014, the Company had no outstanding natural gas derivative instruments.

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.

The prices of oil, natural gas and NGL have been extremely volatile, and the Company expects this volatility to continue. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for such commodities, market uncertainty and a variety of additional factors that are beyond its control. Actual gains or losses recognized related to the Company’s derivative contracts will likely differ from those estimated at September 30, 2015, and December 31, 2014, and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.

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

Interest Rate Risk

At September 30, 2015, and December 31, 2014, the Company had long-term debt outstanding under its Credit Facility of approximately $1.2 billion which incurred interest at floating rates (see Note 4). A 1% increase in the London Interbank Offered Rate would result in an estimated $12 million increase in annual interest expense.

Counterparty Credit Risk

The Company accounts for its commodity derivatives at fair value on a recurring basis (see Note 6). The fair value of these derivative financial instruments includes the impact of assumed credit risk adjustments, which are based on the Company’s and counterparties’ published credit ratings, public bond yield spreads and credit default swap spreads, as applicable.

At September 30, 2015, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 1.85%. A 1% increase in the average public bond yield spread would result in an estimated $11,000 increase in net income for the nine months ended September 30, 2015. At September 30, 2015, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 0.71%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $41,000 decrease in net income for the nine months ended September 30, 2015.

At December 31, 2014, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 1.52%. A 1% increase in the average public bond yield spread would result in no

36

Item 3.    Quantitative and Qualitative Disclosures About Market Risk - Continued

significant increase or decrease in net income for the year ended December 31, 2014. At December 31, 2014, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0.20% and 0.27%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $102,000 decrease in net income for the year ended December 31, 2014.

Item 4.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2015.

Changes in the Company’s Internal Control Over Financial Reporting

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

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

There were no changes in the Company’s internal control over financial reporting during the third quarter of 2015 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Part II – Other Information

Item 1.    Legal Proceedings

The Company is involved in various lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of management, the resolution of these matters will not have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

Item 1A.    Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity are described in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014. Except as set forth below, as of the date of this report, these risk factors have not changed materially. This information should be considered carefully, together with other information in this report and other reports and materials we file with the United States Securities and Exchange Commission.

If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.

We cannot assure you that our business will generate sufficient cash flow from operations to service our outstanding indebtedness, or that future borrowings will be available to us or LINN Energy in an amount sufficient to enable us to pay our indebtedness or to fund our other capital needs. If we do not generate sufficient cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

• refinancing or restructuring all or a portion of our debt;

• obtaining alternative financing;

• selling assets;

• reducing or delaying capital investments;

• seeking to raise additional capital; or

• revising or delaying our strategic plans.

However, we cannot assure you that we would be able to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations and capital requirements or that these actions would be permitted under the terms of our various debt instruments.

Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our business, financial condition, results of operations, cash flows and prospects. Any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating.Further, if for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our Credit Facility, as defined in Note 4, could terminate their commitments to loan money, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. In addition, the lenders under our Credit Facility could compel us to apply all of our cash flow from operations to repay our borrowings or they could prevent us from making payments on our senior notes. If the amounts outstanding under our Credit Facility or any of our other indebtedness were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.

Any further reduction of the borrowing base under our Credit Facility may require us to repay indebtedness under our Credit Facility earlier than anticipated, which would adversely impact our liquidity.

We have not historically accumulated cash to preserve liquidity and have been dependent on LINN Energy for liquidity. Due to low commodity prices and other factors, LINN Energy’s ability to provide liquidity may be constrained. If these constraints continue, we will be primarily reliant on the excess of net cash provided by operating activities for liquidity.

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Item 1A.    Risk Factors - Continued

In October 2015, the borrowing base under the Credit Facility decreased from $1.2 billion to $900 million. Continued low commodity prices, reductions in our capital budget and the resulting reserve write-downs may impact future redeterminations.

To the extent our borrowing base is reduced to or below the amount of borrowings outstanding, any excess borrowings may become due within a short time span. For example, upon the most recent borrowing base redetermination, we repaid $300 million of borrowings outstanding under the Credit Facility to bring our borrowings outstanding to $900 million. We may not have the financial resources to make mandatory prepaymentsand our liquidity would be significantly impacted.

Restrictive covenants in the indentures governing our senior notes and in the Credit Facility could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

The indentures governing our senior notes impose significant operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:

• make distributions to our owner or make other restricted payments;

• incur or guarantee additional indebtedness;

• create or incur liens;

• engage in mergers or consolidations or sell or otherwise dispose of all or substantially all of our assets;

• make certain dispositions and transfers of assets;

• engage in transactions with affiliates;

• make investments; and

• refinance certain indebtedness.

In addition, the Credit Facility contains a number of significant covenants that, among other things, restrict our ability to:

• dispose of assets;

• incur or guarantee additional indebtedness;

• make distributions to our owner;

• create liens on our assets;

• make investments or acquisitions;

• repurchase, redeem or retire our senior notes;

• merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;

• engage in specified transactions with subsidiaries and affiliates; and

• pursue other corporate activities.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under the indentures governing our senior notes and under the Credit Facility. The restrictions contained in those indentures and the Credit Facility could:

• limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan; and

• adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest.

Also, the Credit Facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general or otherwise conduct necessary corporate activities. Further declines in oil, natural gas and NGL prices, or a prolonged period of oil, natural gas and NGL prices at current levels, could eventually result in our failing to meet one or more of the financial covenants under the indentures governing our senior notes or the Credit Facility, which could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.

39

Item 1A.    Risk Factors - Continued

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our senior notes or the Credit Facility. A default under the Credit Facility or the indentures governing our senior notes, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder. The accelerated debt would become immediately due and payable, which would in turn trigger cross-acceleration and cross-default rights under our other debt. If that should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. In addition, if an event of default under the Credit Facility occurred, the lenders could foreclose on the collateral and compel us to apply all of our cash flow from operations to repay our borrowings or they could prevent us from making payments on our senior notes. If the amounts outstanding under the Credit Facility, the senior notes or any of our other indebtedness were to be accelerated, our assets may not be sufficient to repay in full the money owed to the lenders or to our other debt holders.

Moreover, any new indebtedness we incur may impose financial restrictions and other covenants on us that may be more restrictive than the Credit Facility or the indentures governing our senior notes.

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

This item is intentionally omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10‑Q.

Item 3.    Defaults Upon Senior Securities

This item is intentionally omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10‑Q.

Item 4.    Mine Safety Disclosures

Not applicable

Item 5.    Other Information

None

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Item 6.    Exhibits

Exhibit Number	Description
3.1	Certificate of Formation of Berry Petroleum Company, LLC (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on December 20, 2013)
3.2	Limited Liability Company Agreement of Berry Petroleum Company, LLC dated December 16, 2013 (incorporated herein by reference to Exhibit 3.2 to the Company’s Current Report on Form 8‑K filed on December 20, 2013)
10.1	Eleventh Amendment and Borrowing Base Agreement, dated as of October 21, 2015, among Berry Petroleum Company, LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and each of the lenders party thereto (incorporated herein by reference to Exhibit 10.2 to Linn Energy, LLC’s Current Report on Form 8-K filed on October 22, 2015)
31.1*	Section 302 Certification of Chief Executive Officer
31.2*	Section 302 Certification of Chief Financial Officer
32.1*	Section 906 Certification of Chief Executive Officer
32.2*	Section 906 Certification of Chief Financial Officer
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Data Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith.

** Furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereto duly authorized.

	BERRY PETROLEUM COMPANY, LLC
	(Registrant)
Date: November 10, 2015	/s/ Darren R. Schluter
	Darren R. Schluter
	Vice President and Controller
	(Duly Authorized Officer and Principal Accounting Officer)
Date: November 10, 2015	/s/ David B. Rottino
	David B. Rottino
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)

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