Q2 2015 Form 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 June 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
600 Travis, Suite 4900
Houston, Texas 77002
(Former address of principal executive offices)
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 a 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)
 
June 30,
2015
 
December 31, 2014
 
(in thousands)
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
2,664

 
$
1,586

Accounts receivable – trade, net
83,314

 
100,359

Derivative instruments
15,534

 
43,694

Other current assets
43,238

 
59,259

Total current assets
144,750

 
204,898

 
 
 
 
Noncurrent assets:
 
 
 
Oil and natural gas properties (successful efforts method)
4,967,722

 
4,872,059

Less accumulated depletion and amortization
(923,731
)
 
(525,007
)
 
4,043,991

 
4,347,052

 
 
 
 
Other property and equipment
121,511

 
115,999

Less accumulated depreciation
(13,749
)
 
(8,452
)
 
107,762

 
107,547

 
 
 
 
Derivative instruments
976

 
—

Advance to affiliate
171,044

 
293,627

Restricted cash
250,162

 
125

Other noncurrent assets
11,587

 
14,159

 
433,769

 
307,911

Total noncurrent assets
4,585,522

 
4,762,510

Total assets
$
4,730,272

 
$
4,967,408

 
 
 
 
LIABILITIES AND MEMBER’S EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
218,534

 
$
242,350

Derivative instruments
3,333

 
—

Other accrued liabilities
17,798

 
19,087

Total current liabilities
239,665

 
261,437

 
 
 
 
Noncurrent liabilities:
 
 
 
Credit facility
1,173,175

 
1,173,175

Senior notes, net
860,680

 
913,777

Derivative instruments
588

 
—

Other noncurrent liabilities
195,940

 
200,015

Total noncurrent liabilities
2,230,383

 
2,286,967

 
 
 
 
Commitments and contingencies (Note 7)

 

 
 
 
 
Member’s equity:
 
 
 
Additional paid-in capital
2,609,158

 
2,416,381

Accumulated income (deficit)
(348,934
)
 
2,623

 
2,260,224

 
2,419,004

Total liabilities and member’s equity
$
4,730,272

 
$
4,967,408

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

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BERRY PETROLEUM COMPANY, LLC
CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$
173,381

 
$
360,380

 
$
329,967

 
$
693,496

Electricity sales
6,609

 
10,192

 
11,760

 
20,161

Losses on oil and natural gas derivatives
(4,474
)
 
(25,562
)
 
(1,207
)
 
(22,097
)
Marketing revenues
839

 
2,242

 
3,220

 
7,088

Other revenues
1,535

 
9

 
3,431

 
(7
)
 
177,890

 
347,261

 
347,171

 
698,641

Expenses:
 
 
 
 
 
 
 
Lease operating expenses
49,896

 
93,354

 
117,085

 
183,385

Electricity generation expenses
4,993

 
7,629

 
9,563

 
16,012

Transportation expenses
12,978

 
7,483

 
25,584

 
15,476

Marketing expenses
1,005

 
2,096

 
2,080

 
4,694

General and administrative expenses
37,102

 
28,322

 
58,289

 
71,813

Depreciation, depletion and amortization
63,052

 
77,753

 
136,031

 
146,384

Impairment of long-lived assets
—

 
—

 
272,000

 
—

Taxes, other than income taxes
22,196

 
23,479

 
45,528

 
46,508

(Gains) losses on sale of assets and other, net
(811
)
 
4,257

 
(5,284
)
 
7,624

 
190,411

 
244,373

 
660,876

 
491,896

Other income and (expenses):
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(22,690
)
 
(23,486
)
 
(44,111
)
 
(47,487
)
Gain on extinguishment of debt
6,831

 
—

 
6,831

 
—

Other, net
(463
)
 
(445
)
 
(633
)
 
(634
)
 
(16,322
)
 
(23,931
)
 
(37,913
)
 
(48,121
)
Income (loss) before income taxes
(28,843
)
 
78,957

 
(351,618
)
 
158,624

Income tax benefit
(11
)
 
(51
)
 
(61
)
 
(82
)
Net income (loss)
$
(28,832
)
 
$
79,008

 
$
(351,557
)
 
$
158,706

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

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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 contribution from affiliate
250,000

 
—

 
250,000

Distributions to affiliate
(57,223
)
 
—

 
(57,223
)
Net loss
—

 
(351,557
)
 
(351,557
)
June 30, 2015
$
2,609,158

 
$
(348,934
)
 
$
2,260,224

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

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BERRY PETROLEUM COMPANY, LLC
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
June 30,
 
2015
 
2014
 
(in thousands)
Cash flow from operating activities:
 
 
 
Net income (loss)
$
(351,557
)
 
$
158,706

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
136,031

 
146,384

Impairment of long-lived assets
272,000

 
—

Gain on extinguishment of debt
(6,831
)
 
—

Amortization and write-off of deferred financing fees
854

 
(5,492
)
Gains on sale of assets and other, net
(2,991
)
 
—

Deferred income taxes
(61
)
 
(82
)
Derivatives activities:
 
 
 
Total (gains) losses
(1,853
)
 
22,097

Cash settlements
32,943

 
(10,472
)
Changes in assets and liabilities:
 
 
 
(Increase) decrease in accounts receivable – trade, net
15,281

 
(34,294
)
Decrease in other assets
3,515

 
1,486

Increase in accounts payable and accrued expenses
11,378

 
11,869

Decrease in other liabilities
(10,310
)
 
(25,473
)
Net cash provided by operating activities
98,399


264,729

 
 
 
 
Cash flow from investing activities:
 
 
 
Development of oil and natural gas properties
(3,076
)
 
(269,129
)
Purchases of other property and equipment
(2,982
)
 
(5,625
)
Proceeds from sale of properties and equipment and other
11,302

 
—

Net cash provided by (used in) investing activities
5,244


(274,754
)
 
 
 
 
Cash flow from financing activities:
 
 
 
Repayments of debt
(45,353
)
 
(206,124
)
Financing fees and other, net
11

 
(10,866
)
Capital contribution from affiliate
—

 
220,000

Distributions to affiliate
(57,223
)
 
(41,537
)
Net cash used in financing activities
(102,565
)

(38,527
)
 
 
 
 
Net increase (decrease) in cash and cash equivalents
1,078

 
(48,552
)
Cash and cash equivalents:
 
 
 
Beginning
1,586

 
51,041

Ending
$
2,664

 
$
2,489

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

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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 currently 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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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 – 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:
 
June 30,
2015
 
December 31, 2014
 
(in thousands)
Oil and natural gas:
 
 
 
Proved properties
$
4,128,644

 
$
4,025,595

Unproved properties
839,078

 
846,464

 
4,967,722

 
4,872,059

Less accumulated depletion and amortization
(923,731
)
 
(525,007
)
 
$
4,043,991

 
$
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 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 no impairment charges for the three months ended June 30, 2015, or the six months ended June 30, 2014. During the first quarter of 2015, the Company recorded noncash impairment charges, before and after tax, of approximately $272 million associated with proved oil and natural gas properties. The impairment was due to a decline in commodity prices. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. For the six months ended June 30, 2015, the following impairment charges are included in “impairment of long-lived assets” on the condensed statement of operations:
•
California operating area – $207 million; and
•
East Texas operating area – $65 million.

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BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)

Note 3 – Debt
The following summarizes the Company’s outstanding debt:
 
June 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
275,177

 
299,970

6.375% senior notes due September 2022
572,700

 
599,163

Net unamortized premiums
12,803

 
14,644

Total debt, net
2,033,855

 
2,086,952

Less current maturities
—

 
—

Total long-term debt, net
$
2,033,855

 
$
2,086,952

(1) 
Variable interest rates of 2.69% and 2.67% at June 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.
 
June 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
860,680

 
664,672

 
913,777

 
699,462

Total debt, net
$
2,033,855

 
$
1,837,847

 
$
2,086,952

 
$
1,872,637

Credit Facility
The Company’s Second Amended and Restated Credit Agreement (“Credit Facility”) currently has a borrowing base of $1.2 billion, subject to lender commitments. The maturity date is April 2019. At June 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.
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 the borrowing base under the Credit Facility decreased from $1.4 billion to $1.2 billion as a result of lower commodity prices. Continued low or further declining commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs are expected to result in further decreases in the borrowing base at the October 2015 redetermination and may also impact future redeterminations.
In connection with the reduction in Berry’s borrowing base, 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

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BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)

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 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 balance sheet.
The Company’s obligations under the Credit Facility 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 80% 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.
At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.5% and 2.5% 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 0.5% and 1.5% 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 between 0.375% and 0.5% (depending on the then-current level of utilization under the Credit Facility) on the average daily unused amount of the maximum commitment amount of the lenders.
Repurchases of Senior Notes
During the six months ended June 30, 2015, the Company repurchased on the open market approximately $51 million of its outstanding senior notes. The Company repurchased approximately $25 million and $26 million of its 6.75% senior notes due November 2020 and 6.375% senior notes due September 2022, respectively. In connection with the repurchases, the Company recorded a gain on extinguishment of debt of approximately $7 million for the six months ended June 30, 2015.
Repurchases of Senior Notes – Subsequent Event
In July 2015, the Company repurchased through a privately negotiated transaction approximately $14 million of its 6.75% senior notes due November 2020.
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, the indentures governing its 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 4 – Derivative Instruments
The Company hedges 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 direct NGL hedging market has been constrained in terms of price,

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BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)

volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, the Company has not directly hedged 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.
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 5 for fair value disclosures about oil and natural gas commodity derivatives.
The following table summarizes derivative positions for the periods indicated as of June 30, 2015:
 
July 1 - December 31, 2015
 
2016
Oil positions:
 
 
 
Fixed price swaps (NYMEX WTI):
 
 
 
Hedged volume (MBbls)
1,963

 
—

Average price ($/Bbl)
$
59.97

 
$
—

Three-way collars (NYMEX WTI):
 
 
 
Hedged volume (MBbls)
552

 
—

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)
5,152

 
11,712

Hedged differential ($/MMBtu)
$
(0.34
)
 
$
(0.34
)
SoCal basis swaps: (3)
 
 
 
Hedged volume (MMMBtu)
16,560

 
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 six months ended June 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.

9
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BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)

Settled derivatives on oil production for the three months and six months ended June 30, 2015, included volumes of 1,074 MBbls and 1,344 MBbls, respectively, at average contract prices of $66.75 per Bbl and $70.86 per Bbl. Settled derivatives on oil production for the three months and six months ended June 30, 2014, included volumes of 2,275 MBbls and 4,525 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.
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:
 
June 30,
2015
 
December 31, 2014
 
(in thousands)
Assets:
 
 
 
Commodity derivatives
$
23,636

 
$
60,843

Liabilities:
 
 
 
Commodity derivatives
$
11,047

 
$
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 $24 million at June 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
June 30,
 
Six Months Ended
June 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
 
 
 
 
 
 
 
 
Losses on oil and natural gas derivatives
$
(4,474
)
 
$
(25,562
)
 
$
(1,207
)
 
$
(22,097
)
Lease operating expenses (1)
3,986

 
—

 
3,060

 
—

Total gains (losses) on oil and natural gas derivatives
$
(488
)
 
$
(25,562
)
 
$
1,853

 
$
(22,097
)
(1) 
Consists of gains and losses on derivatives used to hedge natural gas consumption which were entered into in March 2015.

10
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BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)

For the three months and six months ended June 30, 2015, the Company received net cash settlements of approximately $5 million and $33 million, respectively. For the three months and six months ended June 30, 2014, the Company paid net cash settlements of approximately $8 million and $11 million, respectively.
Note 5 – Fair Value Measurements on a Recurring Basis
The Company accounts for its commodity derivatives at fair value (see Note 4) 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:
 
June 30, 2015
 
Level 2
 
Netting (1)
 
Total
 
(in thousands)
Assets:
 
 
 
 
 
Commodity derivatives
$
23,636

 
$
(7,126
)
 
$
16,510

Liabilities:
 
 
 
 
 
Commodity derivatives
$
11,047

 
$
(7,126
)
 
$
3,921


 
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 6 – 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 six months ended June 30, 2015); and (iv) a credit-adjusted risk-free interest rate

11
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BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)

(average of 5.5% for the six months ended June 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.
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
1,030

Current year accretion expense
3,340

Settlements
(284
)
Asset retirement obligations at June 30, 2015
$
125,846

Note 7 – 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 June 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 entered into in April 2014, if by September 30, 2015, the Company does not expend $9 million on the construction of either the extension of the road or a new 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 2014 amendment, this deadline is subject to further extension to no later than December 31, 2015. 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 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 six months ended June 30, 2015, and June 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 8 – 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

12
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BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)

not directly pay federal and state income taxes and 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 benefit” on the condensed statements of operations.
Note 9 – 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:
 
June 30,
2015
 
December 31, 2014
 
(in thousands)
 
 
 
 
Accrued interest
$
14,643

 
$
15,803

Asset retirement obligations
3,101

 
3,101

Other
54

 
183

 
$
17,798

 
$
19,087

Supplemental disclosures to the condensed statements of cash flows are presented below:
 
Six Months Ended
June 30,
 
2015
 
2014
 
(in thousands)
 
 
 
 
Cash payments for interest, net of amounts capitalized
$
44,608

 
$
55,751

Cash payments for income taxes
$
—

 
$
—

 
 
 
 
Noncash investing activities:
 
 
 
Accrued capital expenditures
$
28,468

 
$
114,145

For the six months ended June 30, 2015, LINN Energy spent approximately $123 million of capital expenditures in respect of Berry’s operations. The Company recorded the $123 million to oil and natural gas properties with an offset to the advance due from LINN Energy. 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 3).
Note 10 – 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 six months ended June 30, 2015, the Company incurred management fee expenses of approximately $33 million and $53 million, respectively, for services provided by LOI. For the three months and six months ended June 30, 2014, the Company incurred management fee expenses of approximately $24 million and $60 million, respectively, for services provided by LOI. The Company also had affiliated accounts payable due to LINN Energy of approximately $29 million and $13 million at June 30, 2015, and December 31, 2014, respectively, included in “accounts payable and accrued expenses” on the condensed balance sheets.
During the three months and six months ended June 30, 2015, the Company made cash distributions of approximately $13 million and $57 million, respectively, to LINN Energy. In 2014, the Company advanced approximately $352 million, to a

13
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BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)

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 six months ended June 30, 2015, and three months ended December 31, 2014, LINN Energy spent approximately $123 million and $58 million, respectively, of capital expenditures in respect of Berry’s operations. At June 30, 2015, the remaining advance balance was approximately $171 million.
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 3).  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.
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 six months ended June 30, 2015, the Company incurred expenditures of approximately $218,000 and $318,000, respectively, and for the three months and six months ended June 30, 2014, the Company incurred expenditures of approximately $98,000 and $176,000, respectively, related to services rendered by Superior and its subsidiaries.

14
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 June 30, 2015, included the following:
•
oil, natural gas and NGL sales of approximately $173 million compared to $360 million for the second quarter of 2014;
•
average daily production of approximately 48.7 MBOE/d compared to 49.9 MBOE/d for the second quarter of 2014;
•
net loss of approximately $29 million compared to net income of $79 million for the second quarter of 2014;
•
capital expenditures, excluding acquisitions, of approximately $44 million compared to $138 million for the second quarter of 2014; and
•
34 wells drilled (all successful) compared to 117 wells drilled (all successful) for the second quarter of 2014.
Results for the six months ended June 30, 2015, included the following:
•
oil, natural gas and NGL sales of approximately $330 million compared to $693 million for the six months ended June 30, 2014;
•
average daily production of approximately 49.5 MBOE/d compared to 48.7 MBOE/d for the six months ended June 30, 2014;
•
net loss of approximately $352 million compared to net income of $159 million for the six months ended June 30, 2014;
•
net cash provided by operating activities of approximately $98 million compared to $265 million for the six months ended June 30, 2014;
•
capital expenditures, excluding acquisitions, of approximately $101 million compared to $275 million for the six months ended June 30, 2014; and
•
119 wells drilled (all successful) compared to 188 wells drilled (all successful) for the six months ended June 30, 2014.

15
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Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Financing Activities
The spring 2015 semi-annual borrowing base redetermination of the Company’s Second Amended and Restated Credit Agreement (“Credit Facility”) was completed in May 2015, and the borrowing base under the Credit Facility decreased from $1.4 billion to $1.2 billion as a result of lower commodity prices. Continued low or further declining commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs are expected to result in further decreases in the borrowing base at the October 2015 redetermination and may also impact future redeterminations.
In connection with the reduction in Berry’s borrowing base, 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 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 six months ended June 30, 2015, the Company repurchased on the open market approximately $51 million of its outstanding senior notes. In addition, in July 2015, the Company repurchased through a privately negotiated transaction approximately $14 million of its outstanding senior notes. See Note 3 for additional details.
Commodity Derivatives
During the six months ended June 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.

16
Table of Contents
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Results of Operations
Three Months Ended June 30, 2015, Compared to Three Months Ended June 30, 2014
 
Three Months Ended
June 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
Revenues and other:
 
 
 
 
 
Oil sales
$
144,678

 
$
330,820

 
$
(186,142
)
Natural gas sales
22,528

 
24,444

 
(1,916
)
NGL sales
6,175

 
5,116

 
1,059

Total oil, natural gas and NGL sales
173,381

 
360,380

 
(186,999
)
Electricity sales
6,609

 
10,192

 
(3,583
)
Losses on oil and natural gas derivatives
(4,474
)
 
(25,562
)
 
21,088

Marketing and other revenues
2,374

 
2,251

 
123

 
177,890

 
347,261

 
(169,371
)
Expenses:
 
 
 
 
 
Lease operating expenses
49,896

 
93,354

 
(43,458
)
Electricity generation expenses
4,993

 
7,629

 
(2,636
)
Transportation expenses
12,978

 
7,483

 
5,495

Marketing expenses
1,005

 
2,096

 
(1,091
)
General and administrative expenses
37,102

 
28,322

 
8,780

Depreciation, depletion and amortization
63,052

 
77,753

 
(14,701
)
Taxes, other than income taxes
22,196

 
23,479

 
(1,283
)
(Gains) losses on sale of assets and other, net
(811
)
 
4,257

 
(5,068
)
 
190,411

 
244,373

 
(53,962
)
Other income and (expenses)
(16,322
)
 
(23,931
)
 
7,609

Income (loss) before income taxes
(28,843
)
 
78,957

 
(107,800
)
Income tax benefit
(11
)
 
(51
)
 
40

Net income (loss)
$
(28,832
)
 
$
79,008

 
$
(107,840
)


17
Table of Contents
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

 
Three Months Ended
June 30,
 
 
 
2015
 
2014
 
Variance
Average daily production:
 
 
 
 
 
Oil (MBbls/d)
30.5

 
38.2

 
(20
)%
Natural gas (MMcf/d)
93.6

 
61.8

 
51
 %
NGL (MBbls/d)
2.6

 
1.3

 
100
 %
Total (MBOE/d)
48.7

 
49.9

 
(2
)%
 
 
 
 
 
 
Weighted average prices: (1)
 
 
 
 
 
Oil (Bbl)
$
52.15

 
$
95.06

 
(45
)%
Natural gas (Mcf)
$
2.64

 
$
4.34

 
(39
)%
NGL (Bbl)
$
25.72

 
$
43.03

 
(40
)%
 
 
 
 
 
 
Average NYMEX prices:
 
 
 
 
 
Oil (Bbl)
$
57.94

 
$
102.99

 
(44
)%
Natural gas (MMBtu)
$
2.64

 
$
4.67

 
(43
)%
 
 
 
 
 
 
Costs per BOE of production:
 
 
 
 
 
Lease operating expenses
$
11.25

 
$
20.58

 
(45
)%
Transportation expenses
$
2.93

 
$
1.65

 
78
 %
General and administrative expenses
$
8.37

 
$
6.24

 
34
 %
Depreciation, depletion and amortization
$
14.22

 
$
17.14

 
(17
)%
Taxes, other than income taxes
$
5.01

 
$
5.18

 
(3
)%
(1) 
Does not include the effect of gains (losses) on derivatives.

18
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 $187 million or 52% to approximately $173 million for the three months ended June 30, 2015, from approximately $360 million for the three months ended June 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 $119 million, $15 million and $4 million, respectively.
Average daily production volumes decreased to approximately 48.7 MBOE/d for the three months ended June 30, 2015, from 49.9 MBOE/d for the three months ended June 30, 2014. Higher natural gas and NGL production volumes resulted in an increase in revenues of approximately $13 million and $5 million, respectively. Lower oil production volumes resulted in a decrease in revenues of approximately $67 million.
The following table sets forth average daily production by operating area:
 
Three Months Ended
June 30,
 
 
 
 
 
2015
 
2014
 
Variance
Average daily production (MBOE/d):
 
 
 
 
 
 
 
California
26.0

 
26.5

 
(0.5
)
 
(2
)%
Hugoton Basin
10.3

 
—

 
10.3

 
—

Uinta Basin
8.4

 
11.0

 
(2.6
)
 
(24
)%
Piceance Basin
2.5

 
1.9

 
0.6

 
32
 %
East Texas
1.5

 
1.7

 
(0.2
)
 
(12
)%
Permian Basin
—

 
8.8

 
(8.8
)
 
(100
)%
 
48.7

 
49.9

 
(1.2
)
 
(2
)%
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.

19
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Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Electricity Sales
The following table sets forth selected electricity data:
 
Three Months Ended
June 30,
 
 
 
2015
 
2014
 
Variance
 
 
 
 
 
 
Electricity sales (in thousands)
$
6,609

 
$
10,192

 
(35
)%
Electricity generation expenses (in thousands)
$
4,993

 
$
7,629

 
(35
)%
Electric power produced (Mwh/d)
2,106

 
2,002

 
5
 %
Electric power sold (Mwh/d)
1,876

 
1,820

 
3
 %
Average sales price per Mwh
$
38.96

 
$
61.47

 
(37
)%
Fuel gas cost per MMBtu (including transportation)
$
2.62

 
$
4.62

 
(43
)%
Estimated natural gas volumes consumed to produce electricity (MMBtu/d) (1)
14,654

 
14,921

 
(2
)%
(1) 
Estimate is based on the historical allocation of fuel costs to electricity.
Electricity sales represent sales to utilities and decreased by approximately $3 million or 35% to approximately $7 million for the three months ended June 30, 2015, from approximately $10 million for the three months ended June 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
Losses on oil and natural gas derivatives were approximately $4 million for the three months ended June 30, 2015, compared to losses of approximately $26 million for the three months ended June 30, 2014, representing a variance of approximately $22 million. Losses 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 4 and Note 5 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 consistent at approximately $2 million for both the three months ended June 30, 2015, and June 30, 2014.
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 $43 million or 47% to approximately $50 million for the three months ended June 30, 2015, from approximately $93 million for the three months ended June 30, 2014. The decrease was primarily due to a decrease in steam costs caused by a lower price of 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 $11.25 per BOE for the three months ended June 30, 2015, from $20.58 per BOE for the three months ended June 30, 2014.

20
Table of Contents
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following table sets forth steam information:
 
Three Months Ended
June 30,
 
 
 
2015
 
2014
 
Variance
 
 
 
 
 
 
Average net volume of steam injected (Bbls/d)
288,569

 
252,001

 
15
 %
Fuel gas cost per MMBtu (including transportation)
$
2.62

 
$
4.62

 
(43
)%
Estimated natural gas volumes consumed to produce steam (MMBtu/d)
102,498

 
89,498

 
15
 %
Electricity Generation Expenses
Electricity generation expenses decreased by approximately $3 million or 35% to approximately $5 million for the three months ended June 30, 2015, from approximately $8 million for the three months ended June 30, 2014, primarily due to a decrease in fuel gas cost partially offset by an increase in fuel gas volumes purchased.
Transportation Expenses
Transportation expenses increased by approximately $6 million or 73% to approximately $13 million for the three months ended June 30, 2015, from approximately $7 million for the three months ended June 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 52% to approximately $1 million for the three months ended June 30, 2015, from approximately $2 million for the three months ended June 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 $9 million or 31% to approximately $37 million for the three months ended June 30, 2015, from approximately $28 million for the three months ended June 30, 2014. The increase was primarily due to higher costs allocated to the Company by Linn Operating, Inc., primarily driven by higher salaries and benefits related expenses, principally driven by severance costs. General and administrative expenses per BOE also increased to $8.37 per BOE for the three months ended June 30, 2015, from $6.24 per BOE for the three months ended June 30, 2014.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $15 million or 19% to approximately $63 million for the three months ended June 30, 2015, from approximately $78 million for the three months ended June 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 $14.22 per BOE for the three months ended June 30, 2015, from $17.14 per BOE for the three months ended June 30, 2014.

21
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
June 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
 
 
 
 
 
 
Severance taxes
$
2,671

 
$
5,823

 
$
(3,152
)
Ad valorem taxes
14,148

 
13,112

 
1,036

California carbon allowances
5,365

 
4,520

 
845

Other
12

 
24

 
(12
)
 
$
22,196

 
$
23,479

 
$
(1,283
)
Taxes, other than income taxes decreased by approximately $1 million or 5% for the three months ended June 30, 2015, compared to the three months ended June 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, increased primarily due to the properties received in the two exchanges with ExxonMobil and Exxon XTO. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed and higher costs for acquired allowances.
Other Income and (Expenses)
 
Three Months Ended
June 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
 
 
 
 
 
 
Interest expense, net of amounts capitalized
$
(22,690
)
 
$
(23,486
)
 
$
796

Gain on extinguishment of debt
6,831

 
—

 
6,831

Other, net
(463
)
 
(445
)
 
(18
)
 
$
(16,322
)
 
$
(23,931
)
 
$
7,609

Other income and (expenses) decreased by approximately $8 million for the three months ended June 30, 2015, compared to the three months ended June 30, 2014, primarily due to reduced interest expense resulting from lower outstanding debt during the period. In addition, for the three months ended June 30, 2015, the Company recorded a gain on extinguishment of debt of approximately $7 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 $11,000 for the three months ended June 30, 2015, compared to approximately $51,000 for the three months ended June 30, 2014. The decrease was primarily due to an increase in state tax expense resulting from changes in the Company’s operations during the three months ended June 30, 2015, compared to the same period in 2014.
Net Income (Loss)
Net income decreased by approximately $108 million or 136% to a net loss of approximately $29 million for the three months ended June 30, 2015, from net income of approximately $79 million for the three months ended June 30, 2014. The decrease was primarily due to lower production revenues, partially offset by lower expenses. See discussions above for explanations of variances.

22
Table of Contents
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Results of Operations
Six Months Ended June 30, 2015, Compared to Six Months Ended June 30, 2014
 
Six Months Ended
June 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
Revenues and other:
 
 
 
 
 
Oil sales
$
268,658

 
$
625,721

 
$
(357,063
)
Natural gas sales
48,504

 
53,389

 
(4,885
)
NGL sales
12,805

 
14,386

 
(1,581
)
Total oil, natural gas and NGL sales
329,967

 
693,496

 
(363,529
)
Electricity sales
11,760

 
20,161

 
(8,401
)
Losses on oil and natural gas derivatives
(1,207
)
 
(22,097
)
 
20,890

Marketing and other revenues
6,651

 
7,081

 
(430
)
 
347,171

 
698,641

 
(351,470
)
Expenses:
 
 
 
 
 
Lease operating expenses
117,085

 
183,385

 
(66,300
)
Electricity generation expenses
9,563

 
16,012

 
(6,449
)
Transportation expenses
25,584

 
15,476

 
10,108

Marketing expenses
2,080

 
4,694

 
(2,614
)
General and administrative expenses
58,289

 
71,813

 
(13,524
)
Depreciation, depletion and amortization
136,031

 
146,384

 
(10,353
)
Impairment of long-lived assets
272,000

 
—

 
272,000

Taxes, other than income taxes
45,528

 
46,508

 
(980
)
(Gains) losses on sale of assets and other, net
(5,284
)
 
7,624

 
(12,908
)
 
660,876

 
491,896

 
168,980

Other income and (expenses)
(37,913
)
 
(48,121
)
 
10,208

Income (loss) before income taxes
(351,618
)
 
158,624

 
(510,242
)
Income tax benefit
(61
)
 
(82
)
 
21

Net income (loss)
$
(351,557
)
 
$
158,706

 
$
(510,263
)


23
Table of Contents
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

 
Six Months Ended
June 30,
 
 
 
2015
 
2014
 
Variance
Average daily production:
 
 
 
 
 
Oil (MBbls/d)
31.4

 
36.9

 
(15
)%
Natural gas (MMcf/d)
93.7

 
59.5

 
57
 %
NGL (MBbls/d)
2.5

 
1.8

 
39
 %
Total (MBOE/d)
49.5

 
48.7

 
2
 %
 
 
 
 
 
 
Weighted average prices: (1)
 
 
 
 
 
Oil (Bbl)
$
47.31

 
$
93.72

 
(50
)%
Natural gas (Mcf)
$
2.86

 
$
4.95

 
(42
)%
NGL (Bbl)
$
28.15

 
$
43.04

 
(35
)%
 
 
 
 
 
 
Average NYMEX prices:
 
 
 
 
 
Oil (Bbl)
$
53.29

 
$
100.84

 
(47
)%
Natural gas (MMBtu)
$
2.81

 
$
4.80

 
(41
)%
 
 
 
 
 
 
Costs per BOE of production:
 
 
 
 
 
Lease operating expenses
$
13.07

 
$
20.82

 
(37
)%
Transportation expenses
$
2.86

 
$
1.76

 
63
 %
General and administrative expenses
$
6.51

 
$
8.15

 
(20
)%
Depreciation, depletion and amortization
$
15.18

 
$
16.62

 
(9
)%
Taxes, other than income taxes
$
5.08

 
$
5.28

 
(4
)%
(1) 
Does not include the effect of gains (losses) on derivatives.

24
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 $363 million or 52% to approximately $330 million for the six months ended June 30, 2015, from approximately $693 million for the six months ended June 30, 2014, due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Lower oil, natural gas and NGL prices resulted in a decrease in revenues of approximately $263 million, $35 million and $7 million, respectively.
Average daily production volumes increased to approximately 49.5 MBOE/d for the six months ended June 30, 2015, from 48.7 MBOE/d for the six months ended June 30, 2014. Higher natural gas and NGL production volumes resulted in an increase in revenues of approximately $31 million and $5 million, respectively. Lower oil production volumes resulted in a decrease in revenues of approximately $94 million.
The following table sets forth average daily production by operating area:
 
Six Months Ended
June 30,
 
 
 
 
 
2015
 
2014
 
Variance
Average daily production (MBOE/d):
 
 
 
 
 
 
 
California
26.7

 
25.3

 
1.4

 
6
 %
Hugoton Basin
10.2

 
—

 
10.2

 
—

Uinta Basin
9.0

 
10.9

 
(1.9
)
 
(17
)%
Piceance Basin
2.1

 
2.0

 
0.1

 
5
 %
East Texas
1.5

 
1.7

 
(0.2
)
 
(12
)%
Permian Basin
—

 
8.8

 
(8.8
)
 
(100
)%
 
49.5

 
48.7

 
0.8

 
2
 %
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.

25
Table of Contents
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Electricity Sales
The following table sets forth selected electricity data:
 
Six Months Ended
June 30,
 
 
 
2015
 
2014
 
Variance
 
 
 
 
 
 
Electricity sales (in thousands)
$
11,760

 
$
20,161

 
(42
)%
Electricity generation expenses (in thousands)
$
9,563

 
$
16,012

 
(40
)%
Electric power produced (Mwh/d)
1,950

 
2,055

 
(5
)%
Electric power sold (Mwh/d)
1,717

 
1,867

 
(8
)%
Average sales price per Mwh
$
37.85

 
$
59.62

 
(37
)%
Fuel gas cost per MMBtu (including transportation)
$
2.67

 
$
5.09

 
(48
)%
Estimated natural gas volumes consumed to produce electricity (MMBtu/d) (1)
13,646

 
15,344

 
(11
)%
(1) 
Estimate is based on the historical allocation of fuel costs to electricity.
Electricity sales represent sales to utilities and decreased by approximately $8 million or 42% to approximately $12 million for the six months ended June 30, 2015, from approximately $20 million for the six months ended June 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
Losses on oil and natural gas derivatives were approximately $1 million for the six months ended June 30, 2015, compared to losses of approximately $22 million for the six months ended June 30, 2014, representing a variance of approximately $21 million. Losses 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 4 and Note 5 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 consistent at approximately $7 million for both the six months ended June 30, 2015, and June 30, 2014.
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 $66 million or 36% to approximately $117 million for the six months ended June 30, 2015, from approximately $183 million for the six months ended June 30, 2014. The decrease was primarily due to a decrease in steam costs caused by a lower price of 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 $13.07 per BOE for the six months ended June 30, 2015, from $20.82 per BOE for the six months ended June 30, 2014.

26
Table of Contents
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following table sets forth steam information:
 
Six Months Ended
June 30,
 
 
 
2015
 
2014
 
Variance
 
 
 
 
 
 
Average net volume of steam injected (Bbls/d)
282,664

 
241,934

 
17
 %
Fuel gas cost per MMBtu (including transportation)
$
2.67

 
$
5.09

 
(48
)%
Estimated natural gas volumes consumed to produce steam (MMBtu/d)
100,720

 
86,447

 
17
 %
Electricity Generation Expenses
Electricity generation expenses decreased by approximately $6 million or 40% to approximately $10 million for the six months ended June 30, 2015, from approximately $16 million for the six months ended June 30, 2014, primarily due to a decrease in fuel gas cost partially offset by an increase in fuel gas volumes purchased.
Transportation Expenses
Transportation expenses increased by approximately $11 million or 65% to approximately $26 million for the six months ended June 30, 2015, from approximately $15 million for the six months ended June 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 $3 million or 56% to approximately $2 million for the six months ended June 30, 2015, from approximately $5 million for the six months ended June 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 $14 million or 19% to approximately $58 million for the six months ended June 30, 2015, from approximately $72 million for the six months ended June 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 $6.51 per BOE for the six months ended June 30, 2015, from $8.15 per BOE for the six months ended June 30, 2014.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $10 million or 7% to approximately $136 million for the six months ended June 30, 2015, from approximately $146 million for the six months ended June 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, partially offset by higher total production volumes. Depreciation, depletion and amortization per BOE also decreased to $15.18 per BOE for the six months ended June 30, 2015, from $16.62 per BOE for the six months ended June 30, 2014.
Impairment of Long-Lived Assets
The Company recorded no impairment charges for the three months ended June 30, 2015, or the six months ended June 30, 2014. During the first quarter of 2015, the Company recorded noncash impairment charges, before and after tax, of approximately $272 million associated with proved oil and natural gas properties. The impairment was due to a decline in commodity prices. Following are the impairment charges recorded:
•
California operating area – $207 million; and
•
East Texas operating area – $65 million.

27
Table of Contents
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Taxes, Other Than Income Taxes
 
Six Months Ended
June 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
 
 
 
 
 
 
Severance taxes
$
5,776

 
$
11,242

 
$
(5,466
)
Ad valorem taxes
28,272

 
26,353

 
1,919

California carbon allowances
11,468

 
8,888

 
2,580

Other
12

 
25

 
(13
)
 
$
45,528

 
$
46,508

 
$
(980
)
Taxes, other than income taxes decreased by approximately $1 million or 2% for the six months ended June 30, 2015, compared to the six months ended June 30, 2014. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to the properties received in the two exchanges with ExxonMobil and Exxon XTO. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed and higher costs for acquired allowances.
Other Income and (Expenses)
 
Six Months Ended
June 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
 
 
 
 
 
 
Interest expense, net of amounts capitalized
$
(44,111
)
 
$
(47,487
)
 
$
3,376

Gain on extinguishment of debt
6,831

 
—

 
6,831

Other, net
(633
)
 
(634
)
 
1

 
$
(37,913
)
 
$
(48,121
)
 
$
10,208

Other income and (expenses) decreased by approximately $10 million for the six months ended June 30, 2015, compared to the six months ended June 30, 2014, primarily due to reduced interest expense resulting from lower outstanding debt during the period. In addition, for the six months ended June 30, 2015, the Company recorded a gain on extinguishment of debt of approximately $7 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 $61,000 for the six months ended June 30, 2015, compared to approximately $82,000 for the six months ended June 30, 2014. The decrease was primarily due to an increase in state tax expense resulting from changes in the Company’s operations during the six months ended June 30, 2015, compared to the same period in 2014.
Net Income (Loss)
Net income decreased by approximately $511 million or 322% to a net loss of approximately $352 million for the six months ended June 30, 2015, from net income of approximately $159 million for the six months ended June 30, 2014. The decrease was primarily due to lower production revenues and higher impairment charges, partially offset by lower other expenses. See discussions above for explanations of variances.

28
Table of Contents
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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 six months ended June 30, 2015, the Company’s total capital expenditures were approximately $101 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 June 30, 2015, the Company had less than $1 million of available borrowing capacity under its Credit Facility.
The spring 2015 semi-annual borrowing base redetermination of the Company’s Credit Facility was completed in May 2015, and the borrowing base under the Credit Facility decreased from $1.4 billion to $1.2 billion as a result of lower commodity prices. In connection with the reduction in Berry’s borrowing base, 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 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 its senior notes limit the amount the Company 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 $431 million at June 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.
Statements of Cash Flows
The following is a comparative cash flow summary:
 
Six Months Ended
June 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
Net cash:
 
 
 
 
 
Provided by operating activities
$
98,399

 
$
264,729

 
$
(166,330
)
Provided by (used in) investing activities
5,244

 
(274,754
)
 
279,998

Used in financing activities
(102,565
)
 
(38,527
)
 
(64,038
)
Net increase (decrease) in cash and cash equivalents
$
1,078

 
$
(48,552
)
 
$
49,630


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

Operating Activities
Cash provided by operating activities for the six months ended June 30, 2015, was approximately $98 million, compared to approximately $265 million for the six months ended June 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:
 
Six Months Ended
June 30,
 
2015
 
2014
 
(in thousands)
Cash flow from investing activities:
 
 
 
Capital expenditures
$
(6,058
)
 
$
(274,754
)
Proceeds from sale of properties and equipment and other
11,302

 
—

 
$
5,244

 
$
(274,754
)
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 six months ended June 30, 2015, LINN Energy spent approximately $123 million of capital expenditures in respect of Berry’s operations (see Note 9 and Note 10).
Financing Activities
Cash used in financing activities of approximately $103 million for the six months ended June 30, 2015, was primarily related to cash distributions to LINN Energy and repurchases of senior notes. 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 3). Cash used in financing activities of approximately $39 million for the six months ended June 30, 2014, was primarily related to a cash distribution of approximately $42 million made to LINN Energy during the second quarter of 2014.
Debt
During the six months ended June 30, 2015, the Company repurchased on the open market approximately $51 million of its outstanding senior notes. The Company repurchased approximately $25 million and $26 million of its 6.75% senior notes due November 2020 and 6.375% senior notes due September 2022, respectively.
The Company’s Credit Facility currently has a borrowing base of $1.2 billion, subject to lender commitments. At June 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 3.
Financial Covenants
The Credit Facility 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, 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

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

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
 
 
 
September 30, 2014
 
December 31, 2014
 
March 31, 2015
 
June 30,
2015
 
Twelve Months Ended June 30, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Coverage Ratio
9.4

 
 
6.7

 
 
1.9

 
 
2.7
 
 
5.2
 
Current Ratio (1)
2.0

 
 
0.6

 
 
0.6

 
 
0.5
 
 
0.5
 
Current Ratio (consolidated) (1)
3.3

 
 
2.9

 
 
3.2

 
 
2.9
 
 
2.9
 
(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 June 30, 2015, and the Current Ratio as of June 30, 2015, to demonstrate its compliance for the three months ended June 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 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 open market repurchases of approximately $51 million of its outstanding senior notes, there have been no significant changes to the Company’s contractual obligations since December 31, 2014. See Note 3 for additional information about the Company’s debt instruments.

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

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;
•
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

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

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 uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and, from time to time, natural gas. 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 Company has historically entered into commodity hedging transactions primarily in the form of swap contracts, collars and three-way collars, and may enter into put option contracts in the future. 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. Put options are designed to provide a fixed price floor with the opportunity for upside.
The Company entered 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 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 derivatives contracts, the level of LINN Energy’s acquisition activity and overall risk profile, including leverage and size and scale considerations. As a result, the appropriate percentage of production volumes to be hedged may change over time.
At June 30, 2015, the fair value of fixed price swaps and three-way collars was a net asset of approximately $10 million. A 10% increase in the index oil and natural gas prices above the June 30, 2015, prices would result in a net liability of approximately $3 million, which represents a decrease in the fair value of approximately $13 million; conversely, a 10% decrease in the index oil and natural gas prices below the June 30, 2015, prices would result in a net asset of approximately $22 million, which represents an increase in the fair value of approximately $12 million.
At December 31, 2014, the fair value of three-way collars was a net asset of approximately $20 million. A 10% increase in the index oil price above the December 31, 2014, price would result in a net asset of approximately $18 million, which represents a decrease in the fair value of approximately $2 million; conversely, a 10% decrease in the index oil price below the December 31, 2014, price would result in a net asset of approximately $21 million, which represents an increase in the fair value of approximately $1 million. At December 31, 2014, the Company had no outstanding natural gas derivative instruments.
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the

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

data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.
The prices of oil, natural gas and NGL have been extremely volatile, and the Company expects this volatility to continue. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for such commodities, market uncertainty and a variety of additional factors that are beyond its control. Actual gains or losses recognized related to the Company’s derivative contracts will likely differ from those estimated at June 30, 2015, and December 31, 2014, and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.
The Company cannot be assured that its counterparties will be able to perform under its derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, the Company’s cash flows could be impacted.
Interest Rate Risk
At June 30, 2015, and December 31, 2014, the Company had long-term debt outstanding under its Credit Facility of approximately $1.2 billion which incurred interest at floating rates (see Note 3). A 1% increase in the London Interbank Offered Rate would result in an estimated $12 million increase in annual interest expense.
Counterparty Credit Risk
The Company accounts for its commodity derivatives at fair value on a recurring basis (see Note 5). The fair value of these derivative financial instruments includes the impact of assumed credit risk adjustments, which are based on the Company’s and counterparties’ published credit ratings, public bond yield spreads and credit default swap spreads, as applicable.
At June 30, 2015, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 1.55%. A 1% increase in the average public bond yield spread would result in an estimated $20,000 increase in net income for the six months ended June 30, 2015. At June 30, 2015, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 0.59%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $48,000 decrease in net income for the six months ended June 30, 2015.
At December 31, 2014, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 1.52%. A 1% increase in the average public bond yield spread would result in no significant increase or decrease in net income for the year ended December 31, 2014. At December 31, 2014, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0.20% and 0.27%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $102,000 decrease in net income for the year ended December 31, 2014.
Item 4.    Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, and LINN Energy’s Audit Committee of the Board of Directors, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the

34
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period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2015.
Changes in the Company’s Internal Control Over Financial Reporting
The Company’s management is also responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. The Company’s internal controls were designed to provide reasonable assurance as to the reliability of its financial reporting and the preparation and presentation of the condensed financial statements for external purposes in accordance with accounting principles generally accepted in the United States.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
There were no changes in the Company’s internal control over financial reporting during the second quarter of 2015 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Part II – Other Information
Item 1.    Legal Proceedings
The Company is involved in various lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of management, the resolution of these matters will not have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
Item 1A.    Risk Factors
Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity are described in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014. Except as set forth below, as of the date of this report, these risk factors have not changed materially. This information should be considered carefully, together with other information in this report and other reports and materials we file with the United States Securities and Exchange Commission.
Any further reduction of the borrowing base under our Credit Facility, as defined in Note 3, may require us to repay indebtedness under our Credit Facility earlier than anticipated, which would adversely impact our liquidity.
At June 30, 2015, there was less than $1 million available under the Credit Facility. Our Credit Facility is subject to scheduled redeterminations, semi-annually in April and October, of its borrowing base, based primarily on reserve reports using lender commodity price expectations at such time. As a result of lower commodity prices, in May 2015 the borrowing base under the Credit Facility decreased from $1.4 billion to $1.2 billion. Continued low or further declining commodity prices, reductions in our capital budget and the resulting reserve write-downs are expected to result in further decreases in the borrowing base at the October 2015 redetermination and may also impact future redeterminations.
To the extent our borrowing base is reduced to or below the amount of borrowings outstanding, any excess borrowings may become due within a short time span. We may not have the financial resources to make mandatory prepayments and our liquidity would be significantly impacted.
Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds
This item is intentionally omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10‑Q.
Item 3.    Defaults Upon Senior Securities
This item is intentionally omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10‑Q.
Item 4.    Mine Safety Disclosures
Not applicable
Item 5.    Other Information
None

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Item 6.    Exhibits
Exhibit Number
 
Description
 
 
 
3.1
 
Certificate of Formation of Berry Petroleum Company, LLC (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on December 20, 2013)
3.2
 
Limited Liability Company Agreement of Berry Petroleum Company, LLC dated December 16, 2013 (incorporated herein by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on December 20, 2013)
10.1
 
Tenth Amendment and Borrowing Base Agreement to Second Amended and Restated Credit Agreement of Berry Petroleum Company, LLC, dated as of May 12, 2015, among Berry Petroleum Company, LLC as Borrower, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders and agents party thereto (incorporated herein by reference to Exhibit 10.2 to Linn Energy, LLC’s Current Report on Form 8-K filed on May 15, 2015)
31.1*
 
Section 302 Certification of Chief Executive Officer
31.2*
 
Section 302 Certification of Chief Financial Officer
32.1*
 
Section 906 Certification of Chief Executive Officer
32.2*
 
Section 906 Certification of Chief Financial Officer
101.INS**
 
XBRL Instance Document
101.SCH**
 
XBRL Taxonomy Extension Schema Document
101.CAL**
 
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**
 
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**
 
XBRL Taxonomy Extension Label Linkbase Data Document
101.PRE**
 
XBRL Taxonomy Extension Presentation Linkbase Document
*
Filed herewith.
**
Furnished herewith.

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SIGNATURE

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

 
BERRY PETROLEUM COMPANY, LLC
 
(Registrant)
 
 
Date: August 7, 2015
/s/ David B. Rottino
 
David B. Rottino
Executive Vice President, Business Development and
Chief Accounting Officer
(As Duly Authorized Officer and Chief Accounting Officer)


38