10-Q

 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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Table of Contents

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.

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Table of Contents

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.

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Table of Contents

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.

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Table of Contents

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.

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Table of Contents

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.

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Table of Contents

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.

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Table of Contents
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

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Table of Contents
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.

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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.

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Table of Contents
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

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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

Table of Contents
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.

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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

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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

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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

Table of Contents
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

Table of Contents

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

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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

Table of Contents
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

Table of Contents
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

Table of Contents
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

Table of Contents
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

Table of Contents
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

Table of Contents
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

Table of Contents
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

Table of Contents
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

Table of Contents
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

Table of Contents
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

Table of Contents
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

Table of Contents
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

Table of Contents
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.

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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.

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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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