Q2-2014 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, 2014
OR
¨
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the transition period from_______________ to _______________
Commission file number 1-9735
BERRY PETROLEUM COMPANY, LLC
(Successor in interest to Berry Petroleum Company)
(Exact name of registrant as specified in its charter)
Delaware
(State of incorporation or organization)
 
77-0079387
(I.R.S. Employer Identification Number)

600 Travis, Suite 5100
Houston, Texas 77002
(Address of principal executive offices, including zip code)

Registrant’s telephone number, including area code:
(281) 840-4000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨    No x
Pursuant to the terms of its senior note indentures, the registrant is a voluntary filer of reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934, and has filed all such reports as required by its senior note indentures during the preceding 12 months.
The registrant meets the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q as it is an indirect wholly owned subsidiary of Linn Energy, LLC, which is a reporting company under the Securities Exchange Act of 1934 and which has filed with the SEC all materials required to be filed pursuant to Section 13, 14 or 15(d) thereof, and the registrant is therefore filing this Form 10-Q with a reduced disclosure format.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x    No ¨



Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
 
Accelerated filer ¨
 
Non-accelerated filer x
 
Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨    No x
On December 16, 2013, the registrant was acquired (see Note 1 of Notes to the 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 thousands 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)
(in thousands)
 
June 30, 2014
 
December 31, 2013
 
 
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
2,489

 
$
51,041

Accounts receivable – trade, net
156,577

 
122,855

Derivative instruments
2,070

 
5,596

Other current assets
30,235

 
30,833

Total current assets
191,371

 
210,325

 
 
 
 
Noncurrent assets:
 
 
 
Oil and natural gas properties (successful efforts method)
5,126,125

 
4,813,659

Less accumulated depletion and amortization
(150,631
)
 
(10,394
)
 
4,975,494

 
4,803,265

 
 
 
 
Other property and equipment
89,856

 
83,126

Less accumulated depreciation
(3,790
)
 
(233
)
 
86,066

 
82,893

 
 
 
 
Derivative instruments
1,210

 
2,511

Other noncurrent assets
16,204

 
8,051

 
17,414

 
10,562

Total noncurrent assets
5,078,974

 
4,896,720

Total assets
$
5,270,345

 
$
5,107,045

 
 
 
 
LIABILITIES AND MEMBER'S EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
314,108

 
$
264,271

Derivative instruments
31,575

 
20,393

Other accrued liabilities
19,560

 
28,993

Current portion of long-term debt

 
211,558

Total current liabilities
365,243

 
525,215

 
 
 
 
Noncurrent liabilities:
 
 
 
Credit facility
1,173,175

 
1,173,175

Senior notes, net
914,680

 
916,428

Derivative instruments

 
4,649

Other noncurrent liabilities
184,591

 
192,091

Total noncurrent liabilities
2,272,446

 
2,286,343

 
 
 
 
Commitments and contingencies (Note 10)

 

 
 
 
 
Member’s equity:
 
 
 
Additional paid-in capital
2,493,923

 
2,315,460

Accumulated income (deficit)
138,733

 
(19,973
)
 
2,632,656

 
2,295,487

Total liabilities and member’s equity
$
5,270,345

 
$
5,107,045

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

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Table of Contents

BERRY PETROLEUM COMPANY, LLC
CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
(in thousands)
 
Successor
 
 
Predecessor
 
Successor
 
 
Predecessor
 
Three Months Ended
June 30, 2014
 
 
Three Months Ended
June 30, 2013
 
Six Months Ended
June 30, 2014
 
 
Six Months Ended
June 30, 2013
 
 
 
 
 
 
 
 
 
 
Revenues and other:
 
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$
360,380

 
 
$
274,715

 
$
693,496

 
 
$
541,487

Electricity sales
10,192

 
 
9,513

 
20,161

 
 
17,102

Gains (losses) on oil and natural gas derivatives
(25,562
)
 
 
35,622

 
(22,097
)
 
 
34,885

Marketing revenues
2,242

 
 
2,255

 
7,088

 
 
4,282

Other revenues
9

 
 
233

 
(7
)
 
 
705

 
347,261

 
 
322,338

 
698,641

 
 
598,461

Expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
93,354

 
 
79,759

 
183,385

 
 
155,027

Electricity generation expenses
7,629

 
 
6,337

 
16,012

 
 
11,633

Transportation expenses
7,483

 
 
8,293

 
15,476

 
 
15,987

Marketing expenses
2,096

 
 
2,198

 
4,694

 
 
4,076

General and administrative expenses
28,322

 
 
19,371

 
71,813

 
 
41,597

Exploration costs

 
 
872

 

 
 
4,301

Depreciation, depletion and amortization
77,753

 
 
70,272

 
146,384

 
 
138,750

Taxes, other than income taxes
23,479

 
 
14,229

 
46,508

 
 
28,199

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

 
 

 
7,624

 
 
(23
)
 
244,373

 
 
201,331

 
491,896

 
 
399,547

Other income and (expenses):
 
 
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(23,486
)
 
 
(24,879
)
 
(47,487
)
 
 
(49,566
)
Other, net
(445
)
 
 
82

 
(634
)
 
 
33

 
(23,931
)
 
 
(24,797
)
 
(48,121
)
 
 
(49,533
)
Income before income taxes
78,957

 
 
96,210

 
158,624

 
 
149,381

Income tax expense (benefit)
(51
)
 
 
34,846

 
(82
)
 
 
55,583

Net income
$
79,008

 
 
$
61,364

 
$
158,706

 
 
$
93,798

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

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Table of Contents

BERRY PETROLEUM COMPANY, LLC
CONDENSED STATEMENT OF MEMBER’S EQUITY
(Unaudited)
(in thousands)
 
Additional Paid-In Capital
 
Accumulated Income (Deficit)
 
Total Member’s Equity
 
 
 
 
 
 
December 31, 2013
$
2,315,460

 
$
(19,973
)
 
$
2,295,487

Capital contribution from affiliate
220,000

 

 
220,000

Distribution to affiliate
(41,537
)
 

 
(41,537
)
Net income

 
158,706

 
158,706

June 30, 2014
$
2,493,923

 
$
138,733

 
$
2,632,656

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)
(in thousands)
 
Successor
 
 
Predecessor
 
Six Months Ended
June 30, 2014
 
 
Six Months Ended
June 30, 2013
 
 
 
 
 
Cash flow from operating activities:
 
 
 
 
Net income
$
158,706

 
 
$
93,798

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation, depletion and amortization
146,384

 
 
138,750

Stock-based compensation expense

 
 
5,903

Amortization and write-off of deferred financing fees
(5,492
)
 
 
3,438

Change in book overdraft

 
 
(14,885
)
Deferred income taxes
(82
)
 
 
61,639

Other, net

 
 
5,382

Derivatives activities:
 
 
 
 
Total (gains) losses
22,097

 
 
(34,885
)
Cash settlements
(10,472
)
 
 
4,844

Changes in assets and liabilities:
 
 
 
 
Increase in accounts receivable – trade, net
(34,294
)
 
 
(16,518
)
Decrease in other assets
1,486

 
 
242

Increase (decrease) in accounts payable and accrued expenses
11,869

 
 
(11,470
)
Decrease in other liabilities
(25,473
)
 
 
(4,278
)
Net cash provided by operating activities
264,729


 
231,960

Cash flow from investing activities:
 
 
 
 
Property acquisitions

 
 
(3,080
)
Development of oil and natural gas properties
(269,129
)
 
 
(302,724
)
Purchases of other property and equipment
(5,625
)
 
 
(3,954
)
Proceeds from sale of properties and equipment and other

 
 
11,511

Net cash used in investing activities
(274,754
)

 
(298,247
)
Cash flow from financing activities:
 
 
 
 
Proceeds from borrowings

 
 
490,700

Repayments of debt
(206,124
)
 
 
(407,600
)
Dividends paid

 
 
(8,803
)
Financing fees and other, net
(10,866
)
 
 
(223
)
Proceeds from stock option exercises

 
 
65

Capital contribution from affiliate
220,000

 
 

Distribution to affiliate
(41,537
)
 
 

Excess tax benefit from stock-based compensation

 
 
750

Net cash provided by (used in) financing activities
(38,527
)

 
74,889

Net increase (decrease) in cash and cash equivalents
(48,552
)
 
 
8,602

Cash and cash equivalents:
 
 
 
 
Beginning
51,041

 
 
312

Ending
$
2,489

 
 
$
8,914

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 (see Note 2). 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, which includes California (South Midway-Sunset (“SMWSS”)—Steam Floods, North Midway-Sunset (“NMWSS”)—Diatomite and NMWSS—New Steam Floods (“NSF”)), Texas (Permian Basin and east Texas), Utah (Uinta Basin) and Colorado (Piceance 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, 2013. 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 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.
Predecessor and Successor Reporting
The LINN Energy transaction was accounted for under the acquisition method of accounting. Under the acquisition method of accounting, LinnCo initially, and LINN Energy upon the contribution was treated as the accounting acquirer and the Company was treated as the acquired company for financial reporting purposes. As such, the assets and liabilities of the Company were provisionally recorded at their respective fair values as of the acquisition date. Fair value adjustments related to the transaction have been pushed down to the Company, resulting in assets and liabilities of the Company being recorded at their fair values at December 16, 2013. See Note 2 for additional information.
The Company’s statements of operations subsequent to the transaction includes depreciation, depletion and amortization expense on the Company’s oil and natural gas properties, and other property and equipment balances resulting from the fair value adjustments made under the new basis of accounting. Certain other items of income and expense were also impacted. Therefore, the Company’s financial information prior to the transaction is not comparable to its financial information subsequent to the transaction.
As a result of the impact of pushdown accounting, the financial statements and certain note presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the transaction (labeled predecessor) and the period after that date (labeled successor), to indicate the application of different basis of accounting between the periods presented.

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Table of Contents
BERRY PETROLEUM COMPANY
NOTES TO THE CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)


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.
Recently Issued Accounting Standards
In May 2014, the Financial Accounting Standards Board issued an Accounting Standards Update (“ASU”) that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. The 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, 2016, and interim periods within those years (early adoption prohibited). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its financial statements and related disclosures.
Note 2 – Properties Exchange and LINN Energy Transaction
Properties Exchange – Pending
On May 20, 2014, the Company, along with a subsidiary of its indirect parent LINN Energy, entered into a definitive agreement to trade a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., for operating interests in the Hugoton Basin. The Company anticipates the transaction will close in the third quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
LINN Energy Transaction
On December 16, 2013, the Company completed the transactions contemplated by the merger agreement between LINN Energy, 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. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy. The transaction has a value of approximately $4.6 billion, including the assumption of approximately $2.3 billion of Berry’s debt and net of cash acquired of approximately $451 million.
On the Berry acquisition date, LinnCo contributed Berry to its affiliate, LINN Energy. As a result, the assets, liabilities and results of operations of Berry are not included in LinnCo’s financial statements.
The acquisition was accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition date, while transaction and integration costs associated with the acquisition were expensed as incurred. The initial accounting for the business combination is not complete and adjustments to provisional

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Table of Contents
BERRY PETROLEUM COMPANY
NOTES TO THE CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)


amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date.
As a result of being formed as a limited liability company on December 16, 2013, the date of the LINN Energy transaction, the Company ceased to be subject to federal and state income taxes, with the exception of the state of Texas. The Company’s net deferred income tax liabilities were assumed by LinnCo in the merger and were not transferred to LINN Energy in the contribution.
Note 3 – Oil and Natural Gas Properties
Oil and Natural Gas Capitalized Costs
Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:
 
June 30, 2014
 
December 31, 2013
 
(in thousands)
Oil and natural gas:
 
 
 
Proved properties
$
3,755,393

 
$
3,397,785

Unproved properties
1,370,732

 
1,415,874

 
5,126,125

 
4,813,659

Less accumulated depletion and amortization
(150,631
)
 
(10,394
)
 
$
4,975,494

 
$
4,803,265


Note 4 – Debt
The following summarizes the Company’s outstanding debt:
 
June 30, 2014
 
December 31, 2013
 
(in thousands, except percentages)
 
 
 
 
Credit facility (1)
$
1,173,175

 
$
1,173,175

10.25% senior notes due June 2014

 
205,257

6.75% senior notes due November 2020
299,970

 
300,000

6.375% senior notes due September 2022
599,163

 
600,000

Net unamortized premiums
15,547

 
22,729

Total debt, net
2,087,855

 
2,301,161

Less current maturities

 
(211,558
)
Total long-term debt, net
$
2,087,855

 
$
2,089,603

(1) 
Variable interest rates of 2.66% and 2.67% at June 30, 2014, and December 31, 2013, respectively.
Fair Value
The Company’s debt is recorded at the carrying amount in the condensed balance sheets. The carrying amount of the Company’s Credit Facility, as defined below, approximates fair value because the interest rate is variable and reflective of market rates. The Company uses a market approach to determine the fair value of its senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement.

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


 
June 30, 2014
 
December 31, 2013
 
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
914,680

 
948,212

 
1,127,986

 
1,128,527

Total debt, net
$
2,087,855

 
$
2,121,387

 
$
2,301,161

 
$
2,301,702

Credit Facility
The Company’s Second Amended and Restated Credit Agreement (“Credit Facility”) has a borrowing base of $1.4 billion, subject to lender commitments. At June 30, 2014, lender commitments under the facility were $1.2 billion but the Company had less than $1 million of available borrowing capacity, including outstanding letters of credit. In February 2014, the Company entered into an amendment to the Credit Facility to amend the terms of certain financial and reporting covenants, and in April 2014, the Company entered into an amendment to the Credit Facility to extend the maturity from May 2016 to April 2019 and to amend the terms of certain financial covenants and definitions, among other items.
Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October. The lenders under the Credit Facility and Berry also have the right to request interim borrowing base redeterminations once between scheduled redeterminations. Significant declines in commodity prices may result in a decrease in the borrowing base. 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 currently in compliance with all financial and other covenants of the Credit Facility. If an event of default would occur and were continuing, the Company would be unable to make borrowings and its financial condition and liquidity would be adversely affected.
At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the 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 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.
Senior Notes Due November 2020
The Company has $300 million in aggregate principal amount of 6.75% senior notes due November 2020 (the “November 2020 Senior Notes”). The November 2020 Senior Notes were recorded at their fair value of $310 million on the acquisition date including a $10 million premium which is being amortized to interest expense over the life of the related notes.
Senior Notes Due September 2022
The Company has $599 million aggregate principal amount of 6.375% senior notes due September 2022 (the “September 2022 Senior Notes”). The September 2022 Senior Notes were recorded at their fair value of $607 million on the acquisition date including a $7 million premium which is being amortized to interest expense over the life of the related notes.
Repurchases of Senior Notes
In February 2014, in accordance with the indentures related to the senior notes, the Company repurchased through cash tender offers $321,000, $30,000 and $837,000 of its 10.25% senior notes due June 2014 (the “June 2014 Senior Notes”), November 2020 Senior Notes and September 2022 Senior Notes, respectively.

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


Payment of Senior Notes Due June 2014
On May 30, 2014, in accordance with the provisions of the indenture related to its June 2014 Senior Notes, the Company paid in full the remaining outstanding principal amount of approximately $205 million using a cash capital contribution from LINN Energy (see Note 11).
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 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.
Note 5 – Derivative Instruments
The Company hedges a significant portion of its forecasted oil production to reduce exposure to commodity price fluctuations and provide long-term cash flow predictability to manage its business. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, currently, the Company does not directly hedge its NGL production. The Company also, from time to time, enters into derivative contracts for a portion of its natural gas consumption.
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 to provide an economic hedge of the risk related to the future commodity prices received. The Company does not enter into derivative contracts for trading purposes. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 6 for fair value disclosures about oil and natural gas commodity derivatives.

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Table of Contents
BERRY PETROLEUM COMPANY
NOTES TO THE CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)


The following table summarizes derivative positions for the periods indicated as of June 30, 2014:
 
July 1 - December 31, 2014
 
2015
 
 
 
 
Oil positions:
 
 
 
Fixed price swaps (NYMEX WTI):
 
 
 
Hedged volume (MBbls)
2,484

 

Average price ($/Bbl)
$
91.26

 
$

Collars (NYMEX WTI):
 
 
 
Hedged volume (MBbls)
368

 

Average floor price ($/Bbl)
$
90.00

 
$

Average ceiling price ($/Bbl)
$
102.87

 
$

Three-way collars (NYMEX WTI):
 
 
 
Hedged volume (MBbls)
1,564

 
1,095

Short put ($/Bbl)
$
72.11

 
$
70.00

Long put ($/Bbl)
$
93.76

 
$
90.00

Short call ($/Bbl)
$
109.79

 
$
101.62

Three-way collars (ICE Brent):
 
 
 
Hedged volume (MBbls)
184

 

Short put ($/Bbl)
$
80.00

 
$

Long put ($/Bbl)
$
100.00

 
$

Short call ($/Bbl)
$
114.05

 
$

Oil basis differential positions:
 
 
 
ICE Brent - NYMEX WTI basis swaps:
 
 
 
Hedged volume (MBbls)
1,840

 
2,920

Hedged differential ($/Bbl)
$
11.60

 
$
11.60

Oil timing differential positions:
 
 
 
Trade month roll swaps (NYMEX WTI): (1)
 
 
 
Hedged volume (MBbls)
920

 

Hedged differential ($/Bbl)
$
0.32

 
$

(1) 
The Company hedges the timing risk associated with the sales price of oil in the Permian Basin. In this operating area, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).
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 light crude oil for each day of the delivery month.

10

Table of Contents
BERRY PETROLEUM COMPANY
NOTES TO THE CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)


Balance Sheet Presentation
The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis:
 
June 30, 2014
 
December 31, 2013
 
(in thousands)
Assets:
 
 
 
Commodity derivatives
$
17,004

 
$
28,291

Liabilities:
 
 
 
Commodity derivatives
$
45,299

 
$
45,226

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 $17 million at June 30, 2014. 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
Gains and losses on oil and natural gas derivatives were net losses of approximately $26 million and $22 million for the three months and six months ended June 30, 2014, respectively. Net losses for the three months and six months ended June 30, 2014, include cash settlement payments of approximately $8 million and $11 million, respectively. Gains and losses on oil and natural gas derivatives were net gains of approximately $36 million and $35 million for the three months and six months ended June 30, 2013, respectively. Net gains for the three months and six months ended June 30, 2013, include cash settlement receipts of approximately $3 million and $5 million, respectively. These amounts are reported on the condensed statements of operations in “gains (losses) on oil and natural gas derivatives.”
Note 6 – Fair Value Measurements on a Recurring Basis
The Company accounts for its commodity derivatives at fair value (see Note 5) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives.
Fair Value Hierarchy
In accordance with applicable accounting standards, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

11

Table of Contents
BERRY PETROLEUM COMPANY
NOTES TO THE CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)


The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
 
June 30, 2014
 
Level 2
 
Netting (1)
 
Total
 
(in thousands)
Assets:
 
 
 
 
 
Commodity derivatives
$
17,004

 
$
(13,724
)
 
$
3,280

Liabilities:
 
 
 
 
 
Commodity derivatives
$
45,299

 
$
(13,724
)
 
$
31,575

 
December 31, 2013
 
Level 2
 
Netting (1)
 
Total
 
(in thousands)
Assets:
 
 
 
 
 
Commodity derivatives
$
28,291

 
$
(20,184
)
 
$
8,107

Liabilities:
 
 
 
 
 
Commodity derivatives
$
45,226

 
$
(20,184
)
 
$
25,042

(1) 
Represents counterparty netting under agreements governing such derivatives.
Note 7 – Asset Retirement Obligations
Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other accrued liabilities” and “other noncurrent liabilities” on the 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 (2.0% for the six months ended June 30, 2014); and (iv) a credit-adjusted risk-free interest rate (average of 5.4% for the six months ended June 30, 2014). 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, 2013
$
94,830

Liabilities added from drilling
2,842

Current year accretion expense
2,649

Settlements
(3,266
)
Asset retirement obligations at June 30, 2014
$
97,055

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 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. Prior to the LINN Energy transaction, the Company was a Subchapter C-corporation subject to federal and state income taxes. Amounts recognized for income taxes purposes are reported in “income tax expense (benefit)” on the condensed statements of operations.

12

Table of Contents
BERRY PETROLEUM COMPANY
NOTES TO THE CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)


Note 9 – Equity Incentive Compensation Plans
The successor Company does not have any equity incentive compensation (“EIC”) plans under which it grants stock awards and, therefore, recognized no direct stock compensation expense for the six months ended June 30, 2014. Prior to the LINN Energy transaction, the Company granted equity awards to its employees under its EIC plans. The total compensation expense recognized by the predecessor Company in the condensed statements of operations for grants under the Company’s EIC plans was approximately $3 million and $6 million for the three months and six months ended June 30, 2013, respectively. In connection with the LINN Energy transaction, effective December 16, 2013, the predecessor Company’s equity awards were exchanged for LinnCo common shares or LINN Energy equity awards.
Note 10 – Commitments and Contingencies
East Texas Gathering System
The Company has entered into certain long-term natural gas gathering agreements for its east Texas production. The agreements contain embedded leases and the transaction has been accounted for as a financing obligation. The fair value of the property associated with this transaction was recorded in the amount of approximately $13 million and is being depreciated over the remaining useful life of the asset. Under the agreements, portions of the payments are recorded as gathering expense and interest expense with the balance recorded as a reduction to the financing obligation. 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
Department of the Interior Notice of Proposed Debarment
On June 14, 2012, the Company received a Notice of Proposed Debarment issued by the United States Department of the Interior (“DOI”). Pursuant to the notice, the DOI’s Office of the Inspector General proposed to debar the Company from participation in certain federal contracts and assistance activities, including oil and natural gas leases, for a period of three years. The basis for the proposed debarment relates to the Company’s purported noncompliance with Bureau of Land Management (“BLM”) regulations relating to the operation of certain equipment, and the submission of related site facility diagrams, in its Uinta operations. In 2011, the Company entered into a settlement agreement with the BLM and paid a $2 million civil penalty relating to the matter. The Company contested the proposed debarment and believes the matter is without merit; nevertheless, in June 2013, the Company entered into an agreement with the DOI to resolve the matter administratively through an independent compliance review. The independent compliance review has concluded and the final compliance review reports have been submitted to the DOI. The Company has been informed that the DOI intends to make follow-up inquiries to the Company in the near future, but has not received any further communications to date.

13

Table of Contents
BERRY PETROLEUM COMPANY
NOTES TO THE CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)


Royalty Class Action
The Company is a defendant in a certain statewide royalty class action case in which the parties have entered into a settlement agreement to settle past claims for approximately $2.4 million. Subject to approval of the settlement agreement by the court, the Company anticipates distribution of settlement funds to begin late in the third quarter or early fourth quarter of 2014.
Other
The Company is involved in various other 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 business, financial condition, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
During the three months and six months ended June 30, 2014, and June 30, 2013, 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 11 – Related Party Transactions
LINN Energy
All former employees of the Company that were retained after the LINN Energy transaction are now employed by Linn Operating, Inc. (“LOI”), a subsidiary of LINN Energy, and along with other LOI personnel, 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, 2014, the Company incurred management fee expenses of approximately $24 million and $60 million, respectively, for services provided by LOI.
During the second quarter of 2014, LINN Energy made a cash capital contribution of $220 million to the Company which was used to pay in full the remaining outstanding principal amount of its approximately $205 million June 2014 Senior Notes plus accrued interest. During the same period, the Company made a cash distribution of approximately $42 million to LINN Energy. The Company also has affiliated accounts payable due to LOI of approximately $26 million and $17 million at June 30, 2014, and December 31, 2013, respectively, included in “accounts payable and accrued expenses” on the condensed balance sheets.
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, 2014, the Company paid approximately $98,000 and $176,000, respectively, to Superior or its subsidiaries for services rendered to the Company. The transactions associated with these payments were consummated on terms equivalent to those that prevail in arm’s-length transactions.

14

Table of Contents
BERRY PETROLEUM COMPANY
NOTES TO THE CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)


Note 12 – 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, 2014
 
December 31, 2013
 
(in thousands)
 
 
 
 
Accrued interest
$
16,232

 
$
18,926

Accrued compensation

 
6,749

Asset retirement obligations (current portion)
3,318

 
3,318

Other
10

 

 
$
19,560

 
$
28,993

Supplemental disclosures to the condensed statements of cash flows are presented below:
 
Successor
 
 
Predecessor
 
Six Months Ended
June 30, 2014
 
 
Six Months Ended
June 30, 2013
(in thousands)
 
 
 
 
Cash payments for interest, net of amounts capitalized
$
55,751

 
 
$
43,197

Cash payments for income taxes
$

 
 
$
600

 
 
 
 
 
Noncash investing activities:
 
 
 
 
Accrued capital expenditures
$
38,969

 
 
$
40,607

Asset retirement obligations
$
2,842

 
 
$
10,607


15

Table of Contents

Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control. The Company’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement” 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, 2013, 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, 2013. 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 (see “LINN Energy Transaction” below and Note 2). Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, is currently the Company’s sole member.
The Company’s principal reserves and producing properties are located in California (South Midway-Sunset (“SMWSS”)—Steam Floods, North Midway-Sunset (“NMWSS”)—Diatomite, NMWSS—New Steam Floods (“NSF”)), Texas (Permian Basin and east Texas), Utah (Uinta Basin) and Colorado (Piceance Basin).
Results for the three months ended June 30, 2014, included the following:
oil, natural gas and NGL sales of approximately $360 million compared to $275 million for the second quarter of 2013;
average daily production of 49.9 MBOE/d compared to 39.5 MBOE/d for the second quarter of 2013;
net income of approximately $79 million compared to $61 million for the second quarter of 2013;
capital expenditures, excluding acquisitions, of approximately $138 million compared to $130 million for the second quarter of 2013; and
117 wells drilled (all successful) compared to 78 wells drilled (all successful) for the second quarter of 2013.
Results for the six months ended June 30, 2014, included the following:
oil, natural gas and NGL sales of approximately $693 million compared to $541 million for the six months ended June 30, 2013;
average daily production of 48.7 MBOE/d compared to 39.6 MBOE/d for the six months ended June 30, 2013;
net income of approximately $159 million compared to $94 million for the six months ended June 30, 2013;
net cash provided by operating activities of approximately $265 million compared to $232 million for the six months ended June 30, 2013;
capital expenditures, excluding acquisitions, of approximately $275 million compared to $307 million for the six months ended June 30, 2013; and
188 wells drilled (all successful) compared to 158 wells drilled (all successful) for the six months ended June 30, 2013.
LINN Energy Transaction
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. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares.

16

Table of Contents

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

Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy. The transaction had a preliminary value of approximately $4.6 billion, including the assumption of approximately $2.3 billion of Berry’s debt and net of cash acquired of approximately $451 million.
Predecessor and Successor Reporting
As a result of the impact of pushdown accounting on the acquisition date (see Note 1), the Company’s financial statements and certain note presentations are separated into two distinct periods, the period before the consummation of the LINN Energy transaction (labeled predecessor) and the period after that date (labeled successor), to indicate the application of different basis of accounting between the periods presented. Despite this separate GAAP presentation, the successor had no independent oil and natural gas operations prior to the acquisition, and, accordingly, there were no operational activities that changed as a result of the acquisition of the predecessor.
Properties Exchange – Pending
On May 20, 2014, the Company, along with a subsidiary of its indirect parent LINN Energy, entered into a definitive agreement to trade a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., for operating interests in the Hugoton Basin. The Company anticipates the transaction will close in the third quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
Financing and Liquidity
On May 30, 2014, in accordance with the provisions of the indenture related to its 10.25% senior notes due June 2014 (the “June 2014 Senior Notes”), the Company paid in full the remaining outstanding principal amount of approximately $205 million using a cash capital contribution from LINN Energy.

17

Table of Contents

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

Results of Operations
Three Months Ended June 30, 2014, Compared to Three Months Ended June 30, 2013
 
Successor
 
 
Predecessor
 
 
 
Three Months Ended
June 30, 2014
 
 
Three Months Ended
June 30, 2013
 
Variance
(in thousands)
 
 
 
 
 
 
Revenues and other:
 
 
 
 
 
 
Oil sales
$
330,820

 
 
$
250,106

 
$
80,714

Natural gas sales
24,444

 
 
18,033

 
6,411

NGL sales
5,116

 
 
6,576

 
(1,460
)
Total oil, natural gas and NGL sales
360,380

 
 
274,715

 
85,665

Electricity sales
10,192

 
 
9,513

 
679

Gains (losses) on oil and natural gas derivatives
(25,562
)
 
 
35,622

 
(61,184
)
Marketing and other revenues
2,251

 
 
2,488

 
(237
)
 
347,261

 
 
322,338

 
24,923

Expenses:
 
 
 
 
 
 
Lease operating expenses
93,354

 
 
79,759

 
13,595

Electricity generation expenses
7,629

 
 
6,337

 
1,292

Transportation expenses
7,483

 
 
8,293

 
(810
)
Marketing expenses
2,096

 
 
2,198

 
(102
)
General and administrative expenses
28,322

 
 
19,371

 
8,951

Exploration costs

 
 
872

 
(872
)
Depreciation, depletion and amortization
77,753

 
 
70,272

 
7,481

Taxes, other than income taxes
23,479

 
 
14,229

 
9,250

Losses on sale of assets and other, net
4,257

 
 

 
4,257

 
244,373

 
 
201,331

 
43,042

Other income and (expenses)
(23,931
)
 
 
(24,797
)
 
866

Income before income taxes
78,957

 
 
96,210

 
(17,253
)
Income tax expense (benefit)
(51
)
 
 
34,846

 
(34,897
)
Net income
$
79,008

 
 
$
61,364

 
$
17,644



18

Table of Contents

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

 
Successor
 
 
Predecessor
 
 
 
Three Months Ended
June 30, 2014
 
 
Three Months Ended
June 30, 2013
 
Variance
 
 
 
 
 
 
 
Average daily production:
 
 
 
 
 
 
Oil (MBbls/d)
38.2

 
 
29.4

 
30
 %
Natural gas (MMcf/d)
61.8

 
 
48.4

 
28
 %
NGL (MBbls/d)
1.3

 
 
2.1

 
(38
)%
Total (MBOE/d)
49.9

 
 
39.5

 
26
 %
 
 
 
 
 
 
 
Weighted average price: (1)
 
 
 
 
 
 
Oil (Bbl)
$
95.06

 
 
$
93.54

 
2
 %
Natural gas (Mcf)
$
4.34

 
 
$
4.09

 
6
 %
NGL (Bbl)
$
43.03

 
 
$
34.87

 
23
 %
 
 
 
 
 
 
 
Average NYMEX prices:
 
 
 
 
 
 
Oil (Bbl)
$
102.99

 
 
$
94.22

 
9
 %
Natural gas (MMBtu)
$
4.67

 
 
$
4.09

 
14
 %
 
 
 
 
 
 
 
Costs per BOE of production:
 
 
 
 
 
 
Lease operating expenses
$
20.58

 
 
$
22.17

 
(7
)%
Transportation expenses
$
1.65

 
 
$
2.31

 
(29
)%
General and administrative expenses
$
6.24

 
 
$
5.39

 
16
 %
Depreciation, depletion and amortization
$
17.14

 
 
$
19.54

 
(12
)%
Taxes, other than income taxes
$
5.18

 
 
$
3.96

 
31
 %
(1) 
Does not include the effect of gains (losses) on derivatives.

19

Table of Contents

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

Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales increased by approximately $85 million or 31% to approximately $360 million for the three months ended June 30, 2014, from approximately $275 million for the three months ended June 30, 2013, due to higher production volumes and higher oil, natural gas and NGL prices. Higher oil, natural gas and NGL prices resulted in an increase in revenues of approximately $5 million, $1 million and $1 million, respectively.
Average daily production volumes increased to approximately 49.9 MBOE/d for the three months ended June 30, 2014, from 39.5 MBOE/d for the three months ended June 30, 2013. Higher oil and natural gas production volumes resulted in an increase in revenues of approximately $75 million and $5 million, respectively. Lower NGL production volumes resulted in a decrease in revenues of approximately $2 million.
The following table sets forth average daily production by operating area:
 
Successor
 
 
Predecessor
 
 
 
 
 
Three Months Ended
June 30, 2014
 
 
Three Months Ended
June 30, 2013
 
Variance
 
 
 
 
 
 
 
 
 
Average daily production (MBOE/d):
 
 
 
 
 
 
 
 
California
26.5

 
 
19.8

 
6.7

 
34
 %
Uinta Basin
11.0

 
 
7.3

 
3.7

 
51
 %
Permian Basin
8.8

 
 
8.0

 
0.8

 
10
 %
Piceance Basin
1.9

 
 
2.3

 
(0.4
)
 
(17
)%
East Texas
1.7

 
 
2.1

 
(0.4
)
 
(19
)%
 
49.9

 
 
39.5

 
10.4

 
26
 %
The increase in average daily production volumes in California, the Uinta Basin and Permian Basin operating areas primarily reflect development capital spending. The decrease in average daily production volumes in the Piceance Basin and East Texas operating areas primarily reflect the effects of production declines due to reduced development capital spending.
Electricity Sales
The following table sets forth selected electricity data:
 
Successor
 
 
Predecessor
 
 
 
Three Months Ended
June 30, 2014
 
 
Three Months Ended
June 30, 2013
 
Variance
 
 
 
 
 
 
 
Electricity sales (in thousands)
$
10,192

 
 
$
9,513

 
7
%
Electricity generation expenses (in thousands)
$
7,629

 
 
$
6,337

 
20
%
Electric power produced (Mwh/d)
2,002

 
 
1,957

 
2
%
Electric power sold (Mwh/d)
1,820

 
 
1,772

 
3
%
Average sales price per Mwh
$
61.47

 
 
$
58.98

 
4
%
Fuel gas cost per MMBtu (including transportation)
$
4.62

 
 
$
3.95

 
17
%
Estimated natural gas volumes consumed to produce electricity (MMBtu/d) (1)
14,921

 
 
14,612

 
2
%
(1) 
Estimate is based on the historical allocation of fuel costs to electricity.
Electricity sales increased by approximately $679,000 or 7% to approximately $10 million for the three months ended June 30, 2014, primarily due to an increase 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 $26 million for the three months ended June 30, 2014, compared to gains of approximately $36 million for the three months ended June 30, 2013, representing a variance of approximately $62

20

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

million. Losses on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts and lower cash settlements during the period. The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Note 5 and Note 6 for additional information about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” in “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 its capacity. To optimize its remaining capacity, the Company purchases third-party natural gas at the market rate in its producing areas and utilizes asset management agreements. Sales of third-party natural gas are recorded as marketing revenues. Marketing and other revenues decreased by approximately $237,000 or 10% to approximately $2 million for the three months ended 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 increased by approximately $13 million or 17% to approximately $93 million for the three months ended June 30, 2014, from approximately $80 million for the three months ended June 30, 2013. Lease operating expenses increased primarily due to an increase in steam costs caused by an increase in the price and volume of natural gas used in steam generation. Lease operating expenses per BOE decreased to $20.58 per BOE for the three months ended June 30, 2014, from $22.17 per BOE for the three months ended June 30, 2013, primarily due to higher production volumes.
The following table sets forth steam information:
 
Successor
 
 
Predecessor
 
 
 
Three Months Ended
June 30, 2014
 
 
Three Months Ended
June 30, 2013
 
Variance
 
 
 
 
 
 
 
Average net volume of steam injected (Bbls/d)
252,001

 
 
190,085

 
33
%
Fuel gas cost per MMBtu (including transportation)
$
4.62

 
 
$
3.95

 
17
%
Estimated natural gas volumes consumed to produce steam (MMBtu/d)
89,498

 
 
65,313

 
37
%
Electricity Generation Expenses
Electricity generation expenses increased by approximately $2 million or 20% to approximately $8 million for the three months ended June 30, 2014, from approximately $6 million for the three months ended June 30, 2013, primarily due to increases in fuel gas cost and fuel gas volumes purchased.
Transportation Expenses
Transportation expenses decreased by approximately $1 million or 10% to approximately $7 million for the three months ended June 30, 2014, from approximately $8 million for the three months ended June 30, 2013, primarily due to favorable marketing contract adjustments partially offset by higher expenses due to increased production volumes in the Uinta Basin.
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 purchases third-party natural gas at the market rate in its producing areas and utilizes asset management agreements. Purchases of third-party natural gas are recorded as marketing expenses. Marketing expenses decreased by approximately $102,000 or 5% to approximately $2 million for the three months ended June 30, 2014.

21

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

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 46% to approximately $28 million for the three months ended June 30, 2014, from approximately $19 million for the three months ended June 30, 2013. The increase was primarily due to higher personnel expenses, transition expenses, professional services expenses and various other administrative expenses. General and administrative expenses per BOE also increased to $6.24 per BOE for the three months ended June 30, 2014, from $5.39 per BOE for the three months ended June 30, 2013.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased by approximately $8 million or 11% to approximately $78 million for the three months ended June 30, 2014, from approximately $70 million for the three months ended June 30, 2013. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per BOE decreased to $17.14 per BOE for the three months ended June 30, 2014, from $19.54 per BOE for the three months ended June 30, 2013, primarily due to a lower oil and natural gas properties basis as a result of the adjustment made to record the properties at fair value on December 16, 2013, the acquisition date.
Taxes, Other Than Income Taxes
 
Successor
 
 
Predecessor
 
 
 
Three Months Ended
June 30, 2014
 
 
Three Months Ended
June 30, 2013
 
Variance
(in thousands)
 
 
 
 
 
 
Severance taxes
$
5,823

 
 
$
4,317

 
$
1,506

Ad valorem taxes
13,112

 
 
6,687

 
6,425

California carbon allowances
4,520

 
 
3,225

 
1,295

Other
24

 
 

 
24

 
$
23,479

 
 
$
14,229

 
$
9,250

Taxes, other than income taxes increased by approximately $9 million or 65% for the three months ended June 30, 2014, compared to the three months ended June 30, 2013. Severance taxes, which are a function of revenues generated from production, increased primarily due to higher production volumes and higher oil, natural gas and NGL prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to an adjustment to the taxable property basis in California in connection with the LINN Energy transaction. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed.
Other Income and (Expenses)
 
Successor
 
 
Predecessor
 
 
 
Three Months Ended
June 30, 2014
 
 
Three Months Ended
June 30, 2013
 
Variance
(in thousands)
 
 
 
 
 
 
Interest expense, net of amounts capitalized
$
(23,486
)
 
 
$
(24,879
)
 
$
1,393

Other, net
(445
)
 
 
82

 
(527
)
 
$
(23,931
)
 
 
$
(24,797
)
 
$
866

Other income and (expenses) decreased by approximately $1 million for the three months ended June 30, 2014, compared to the three months ended June 30, 2013. Interest expense decreased primarily due to the amortization of premiums related to the Company’s debt being recorded at fair value on December 16, 2013, the acquisition date, partially offset by higher outstanding debt during the period. See “Debt” in “Liquidity and Capital Resources” below for additional details.
Income Tax Expense (Benefit)
Effective December 16, 2013, the Company became 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. Prior to the LINN Energy transaction, the Company

22

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

was a Subchapter C-corporation subject to federal and state income taxes. The Company recognized an income tax benefit of approximately $51,000 for the three months ended June 30, 2014, compared to income tax expense of approximately $35 million for the three months ended June 30, 2013. The decrease was primarily due to the Company’s conversion from a Subchapter C-corporation to a limited liability company in connection with the LINN Energy transaction.
Net Income
Net income increased by approximately $18 million or 29% to approximately $79 million for the three months ended June 30, 2014, from approximately $61 million for the three months ended June 30, 2013. The increase was primarily due to higher production revenues, partially offset by higher expenses and higher losses on oil and natural gas derivatives. See discussions above for explanations of variances.


23

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

Results of Operations
Six Months Ended June 30, 2014, Compared to Six Months Ended June 30, 2013
 
Successor
 
 
Predecessor
 
 
 
Six Months Ended
June 30, 2014
 
 
Six Months Ended
June 30, 2013
 
Variance
(in thousands)
 
 
 
 
 
 
Revenues and other:
 
 
 
 
 
 
Oil sales
$
625,721

 
 
$
494,561

 
$
131,160

Natural gas sales
53,389

 
 
34,028

 
19,361

NGL sales
14,386

 
 
12,898

 
1,488

Total oil, natural gas and NGL sales
693,496

 
 
541,487

 
152,009

Electricity sales
20,161

 
 
17,102

 
3,059

Gains (losses) on oil and natural gas derivatives
(22,097
)
 
 
34,885

 
(56,982
)
Marketing and other revenues
7,081

 
 
4,987

 
2,094

 
698,641

 
 
598,461

 
100,180

Expenses:
 
 
 
 
 
 
Lease operating expenses
183,385

 
 
155,027

 
28,358

Electricity generation expenses
16,012

 
 
11,633

 
4,379

Transportation expenses
15,476

 
 
15,987

 
(511
)
Marketing expenses
4,694

 
 
4,076

 
618

General and administrative expenses
71,813

 
 
41,597

 
30,216

Exploration costs

 
 
4,301

 
(4,301
)
Depreciation, depletion and amortization
146,384

 
 
138,750

 
7,634

Taxes, other than income taxes
46,508

 
 
28,199

 
18,309

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

 
 
(23
)
 
7,647

 
491,896

 
 
399,547

 
92,349

Other income and (expenses)
(48,121
)
 
 
(49,533
)
 
1,412

Income before income taxes
158,624

 
 
149,381

 
9,243

Income tax expense (benefit)
(82
)
 
 
55,583

 
(55,665
)
Net income
$
158,706

 
 
$
93,798

 
$
64,908



24

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

 
Successor
 
 
Predecessor
 
 
 
Six Months Ended
June 30, 2014
 
 
Six Months Ended
June 30, 2013
 
Variance
 
 
 
 
 
 
 
Average daily production:
 
 
 
 
 
 
Oil (MBbls/d)
36.9

 
 
29.3

 
26
 %
Natural gas (MMcf/d)
59.5

 
 
49.8

 
19
 %
NGL (MBbls/d)
1.8

 
 
2.0

 
(10
)%
Total (MBOE/d)
48.7

 
 
39.6

 
23
 %
 
 
 
 
 
 
 
Weighted average price: (1)
 
 
 
 
 
 
Oil (Bbl)
$
93.72

 
 
$
93.27

 
1
 %
Natural gas (Mcf)
$
4.95

 
 
$
3.78

 
31
 %
NGL (Bbl)
$
43.04

 
 
$
35.47

 
21
 %
 
 
 
 
 
 
 
Average NYMEX prices:
 
 
 
 
 
 
Oil (Bbl)
$
100.84

 
 
$
94.30

 
7
 %
Natural gas (MMBtu)
$
4.80

 
 
$
3.71

 
29
 %
 
 
 
 
 
 
 
Costs per BOE of production:
 
 
 
 
 
 
Lease operating expenses
$
20.82

 
 
$
21.63

 
(4
)%
Transportation expenses
$
1.76

 
 
$
2.23

 
(21
)%
General and administrative expenses
$
8.15

 
 
$
5.80

 
41
 %
Depreciation, depletion and amortization
$
16.62

 
 
$
19.36

 
(14
)%
Taxes, other than income taxes
$
5.28

 
 
$
3.93

 
34
 %
(1) 
Does not include the effect of gains (losses) on derivatives.

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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 increased by approximately $152 million or 28% to approximately $693 million for the six months ended June 30, 2014, from approximately $541 million for the six months ended June 30, 2013, due to higher production volumes and higher natural gas, oil and NGL prices. Higher natural gas, oil and NGL prices resulted in an increase in revenues of approximately $12 million, $3 million and $3 million, respectively.
Average daily production volumes increased to approximately 48.7 MBOE/d for the six months ended June 30, 2014, from 39.6 MBOE/d for the six months ended June 30, 2013. Higher oil and natural gas production volumes resulted in an increase in revenues of approximately $128 million and $7 million, respectively. Lower NGL production volumes resulted in a decrease in revenues of approximately $1 million.
The following table sets forth average daily production by operating area:
 
Successor
 
 
Predecessor
 
 
 
 
 
Six Months Ended
June 30, 2014
 
 
Six Months Ended
June 30, 2013
 
Variance
 
 
 
 
 
 
 
 
 
Average daily production (MBOE/d):
 
 
 
 
 
 
 
 
California
25.3

 
 
19.7

 
5.6

 
28
 %
Uinta Basin
10.9

 
 
7.3

 
3.6

 
49
 %
Permian Basin
8.8

 
 
8.1

 
0.7

 
9
 %
Piceance Basin
2.0

 
 
2.4

 
(0.4
)
 
(17
)%
East Texas
1.7

 
 
2.1

 
(0.4
)
 
(19
)%
 
48.7

 
 
39.6

 
9.1

 
23
 %
The increase in average daily production volumes in California, the Uinta Basin and Permian Basin operating areas primarily reflect development capital spending. The decrease in average daily production volumes in the Piceance Basin and East Texas operating areas primarily reflect the effects of production declines due to reduced development capital spending.
Electricity Sales
The following table sets forth selected electricity data:
 
Successor
 
 
Predecessor
 
 
 
Six Months Ended
June 30, 2014
 
 
Six Months Ended
June 30, 2013
 
Variance
 
 
 
 
 
 
 
Electricity sales (in thousands)
$
20,161

 
 
$
17,102

 
18
%
Electricity generation expenses (in thousands)
$
16,012

 
 
$
11,633

 
38
%
Electric power produced (Mwh/d)
2,055

 
 
1,996

 
3
%
Electric power sold (Mwh/d)
1,867

 
 
1,812

 
3
%
Average sales price per Mwh
$
59.62

 
 
$
51.76

 
15
%
Fuel gas cost per MMBtu (including transportation)
$
5.09

 
 
$
3.75

 
36
%
Estimated natural gas volumes consumed to produce electricity (MMBtu/d) (1)
15,344

 
 
14,684

 
4
%
(1) 
Estimate is based on the historical allocation of fuel costs to electricity.
Electricity sales increased by approximately $3 million or 18% to approximately $20 million for the six months ended June 30, 2014, from approximately $17 million for the six months ended June 30 2013, primarily due to an increase in the average sales price of electricity and electric power sold during the period.

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

Gains (Losses) on Oil and Natural Gas Derivatives
Losses on oil and natural gas derivatives were approximately $22 million for the six months ended June 30, 2014, compared to gains of approximately $35 million for the six months ended June 30, 2013, representing a variance of approximately $57 million. Losses on oil and natural gas derivatives were primarily due to the changes in fair value of the derivative contracts during the period and lower cash settlements during the period. The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Note 5 and Note 6 for additional information about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” in “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 its capacity. To optimize its remaining capacity, the Company purchases third-party natural gas at the market rate in its producing areas and utilizes asset management agreements. Sales of third-party natural gas are recorded as marketing revenues. Marketing and other revenues increased by approximately $2 million or 42% to approximately $7 million for the six months ended June 30, 2014, from approximately $5 million for the six months ended June 30, 2013, primarily due to an increase in natural gas prices during the first quarter of 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 increased by approximately $28 million or 18% to approximately $183 million for the six months ended June 30, 2014, from approximately $155 million for the six months ended June 30, 2013. Lease operating expenses increased primarily due to an increase in steam costs caused by an increase in the price and volume of natural gas used in steam generation. Lease operating expenses per BOE decreased to $20.82 per BOE for the six months ended June 30, 2014, from $21.63 per BOE for the six months ended June 30, 2013, primarily due to higher production volumes.
The following table sets forth steam information:
 
Successor
 
 
Predecessor
 
 
 
Six Months Ended
June 30, 2014
 
 
Six Months Ended
June 30, 2013
 
Variance
 
 
 
 
 
 
 
Average net volume of steam injected (Bbls/d)
241,934

 
 
193,936

 
25
%
Fuel gas cost per MMBtu (including transportation)
$
5.09

 
 
$
3.75

 
36
%
Estimated natural gas volumes consumed to produce steam
(MMBtu/d)
86,447

 
 
65,724

 
32
%
Electricity Generation Expenses
Electricity generation expenses increased by approximately $4 million or 38% to approximately $16 million for the six months ended June 30, 2014, from approximately $12 million for the six months ended June 30, 2013, primarily due to increases in fuel gas cost and fuel gas volumes purchased.
Transportation Expenses
Transportation expenses decreased by approximately $1 million or 3% to approximately $15 million for the six months ended June 30, 2014, from approximately $16 million for the six months ended June 30, 2013, primarily due to favorable marketing contract adjustments partially offset by higher expenses due to increased production volumes in the Uinta Basin.

27

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

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 purchases third-party natural gas at the market rate in its producing areas and utilizes asset management agreements. Purchases of third-party natural gas are recorded as marketing expenses. Marketing expenses increased by approximately $1 million or 15% to approximately $5 million for the six months ended June 30, 2014, from approximately $4 million for the six months ended June 30, 2013, primarily due to an increase in natural gas prices during the first quarter of 2014.
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations. General and administrative expenses increased by approximately $30 million or 73% to approximately $72 million for the six months ended June 30, 2014, from approximately $42 million for the six months ended June 30, 2013. The increase was primarily due to higher share-based compensation allocated to the Company by LOI during the first quarter of 2014, which is expected to decrease over the remainder of the year, as well as higher personnel expenses, transition expenses, professional services expenses and various other administrative expenses. General and administrative expenses per BOE also increased to $8.15 million per BOE for the six months ended June 30, 2014, from $5.80 per BOE for the six months ended June 30, 2013.
Exploration Costs
The Company recorded no exploration costs for the six months ended June 30, 2014. For the six months ended June 30, 2013, the Company recorded exploration costs of approximately $4 million primarily related to the expiration of certain undeveloped leases in the Permian Basin.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased by approximately $7 million or 6% to approximately $146 million for the six months ended June 30, 2014, from approximately $139 million for the six months ended June 30, 2013. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per BOE decreased to $16.62 per BOE for the six months ended June 30, 2014, from $19.36 per BOE for the six months ended June 30, 2013, primarily due to a lower oil and natural gas properties basis as a result of the adjustment made to record the properties at fair value on December 16, 2013, the acquisition date.
Taxes, Other Than Income Taxes
 
Successor
 
 
Predecessor
 
 
 
Six Months Ended
June 30, 2014
 
 
Six Months Ended
June 30, 2013
 
Variance
(in thousands)
 
 
 
 
 
 
Severance taxes
$
11,242

 
 
$
8,343

 
$
2,899

Ad valorem taxes
26,353

 
 
13,445

 
12,908

California carbon allowances
8,888

 
 
6,411

 
2,477

Other
25

 
 

 
25

 
$
46,508

 
 
$
28,199

 
$
18,309

Taxes, other than income taxes increased by approximately $18 million or 65% for the six months ended June 30, 2014, compared to the six months ended June 30, 2013. Severance taxes, which are a function of revenues generated from production, increased primarily due to higher production volumes and higher natural gas, oil and NGL prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to an adjustment to the taxable property basis in California in connection with the LINN Energy transaction. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed.

28

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

Other Income and (Expenses)
 
Successor
 
 
Predecessor
 
 
 
Six Months Ended
June 30, 2014
 
 
Six Months Ended
June 30, 2013
 
Variance
(in thousands)
 
 
 
 
 
 
Interest expense, net of amounts capitalized
$
(47,487
)
 
 
$
(49,566
)
 
$
2,079

Other, net
(634
)
 
 
33

 
(667
)
 
$
(48,121
)
 
 
$
(49,533
)
 
$
1,412

Other income and (expenses) decreased by approximately $1 million for the six months ended June 30, 2014, compared to the six months ended June 30, 2013. Interest expense decreased primarily due to the amortization of premiums related to the Company’s debt being recorded at fair value on December 16, 2013, the acquisition date, partially offset by higher outstanding debt during the period. See “Debt” in “Liquidity and Capital Resources” below for additional details.
Income Tax Expense (Benefit)
Effective December 16, 2013, the Company became 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. Prior to the LINN Energy transaction, the Company was a Subchapter C-corporation subject to federal and state income taxes. The Company recognized an income tax benefit of approximately $82,000 for the six months ended June 30, 2014, compared to income tax expense of approximately $56 million for the six months ended June 30, 2013. The decrease was primarily due to the Company’s conversion from a Subchapter C-corporation to a limited liability company in connection with the LINN Energy transaction.
Net Income
Net income increased by approximately $65 million or 69% to approximately $159 million for the six months ended June 30, 2014, from approximately $94 million for the six months ended June 30, 2013. The increase was primarily due to higher production revenues, partially offset by higher expenses and higher losses on oil and natural gas derivatives. See discussions above for explanations of variances.
Liquidity and Capital Resources
The Company has utilized funds from debt offerings, borrowings under its Credit Facility and net cash provided by operating activities for capital resources and liquidity. Historically, the primary use of capital has been for acquisitions and the development of oil and natural gas properties. For the six months ended June 30, 2014, the Company’s total capital expenditures were approximately $275 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, 2014, the Company had less than $1 million of available borrowing capacity under its Credit Facility.
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. Following the LINN Energy transaction, 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 and is not currently being distributed to LINN Energy for further distribution to its unitholders. To the extent that the Company generates cash in excess

29

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

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 was approximately $266 million at June 30, 2014, 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.
On May 30, 2014, in accordance with the provisions of the indenture related to its June 2014 Senior Notes, the Company paid in full the remaining outstanding principal amount of approximately $205 million using a cash capital contribution from LINN Energy (see Note 11).
Statements of Cash Flows
The following is a comparative cash flow summary:
 
Successor
 
 
Predecessor
 
 
 
Six Months Ended
June 30, 2014
 
 
Six Months Ended
June 30, 2013
 
Variance
(in thousands)
 
 
 
 
 
 
Net cash:
 
 
 
 
 
 
Provided by operating activities
$
264,729

 
 
$
231,960

 
$
32,769

Used in investing activities
(274,754
)
 
 
(298,247
)
 
23,493

Provided by (used in) financing activities
(38,527
)
 
 
74,889

 
(113,416
)
Net increase (decrease) in cash and cash equivalents
$
(48,552
)
 
 
$
8,602

 
$
(57,154
)
Operating Activities
Cash provided by operating activities for the six months ended June 30, 2014, was approximately $265 million, compared to approximately $232 million for the six months ended June 30, 2013. The increase was primarily due to higher production related revenues principally due to increased oil and natural gas production volumes and higher commodity prices, partially offset by higher expenses and lower cash settlements on derivatives.
Investing Activities
The following provides a comparative summary of cash flow from investing activities:
 
Successor
 
 
Predecessor
 
Six Months Ended
June 30, 2014
 
 
Six Months Ended
June 30, 2013
(in thousands)
 
 
 
 
Cash flow from investing activities:
 
 
 
 
Property acquisitions
$

 
 
$
(3,080
)
Capital expenditures
(274,754
)
 
 
(306,678
)
Proceeds from sale of properties and equipment and other

 
 
11,511

 
$
(274,754
)
 
 
$
(298,247
)
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 2014.
Financing Activities
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. Cash provided by financing activities for the six months ended June 30, 2013, included net borrowings of approximately $83 million under the Company’s Credit Facility.

30

Table of Contents

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

Debt
The Company’s Second Amended and Restated Credit Agreement (“Credit Facility”) has a borrowing base of $1.4 billion, subject to lender commitments. At June 30, 2014, lender commitments under the facility were $1.2 billion but the Company had less than $1 million of available borrowing capacity, including outstanding letters of credit. In February 2014, the Company entered into an amendment to the Credit Facility to amend the terms of certain financial and reporting covenants, and in April 2014, the Company entered into an amendment to the Credit Facility to extend the maturity from May 2016 to April 2019 and to amend the terms of certain financial covenants and definitions, among other items.
As of June 30, 2014, the Company was in compliance with all financial and other covenants of its Credit Facility. If an event of default would occur and were continuing, the Company would be unable to make borrowings and its financial condition and liquidity would be adversely affected. For information related to the Credit Facility, see Note 4.
In February 2014, in accordance with the indentures related to the senior notes, the Company repurchased through cash tender offers $321,000, $30,000 and $837,000 of its June 2014 Senior Notes, November 2020 Senior Notes and September 2022 Senior Notes, respectively.
On May 30, 2014, in accordance with the provisions of the indenture related to its June 2014 Senior Notes, the Company paid in full the remaining outstanding principal amount of approximately $205 million using a cash capital contribution from LINN Energy (see Note 11).
Counterparty Credit Risk