LINE 3.31.2015 10Q


 
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 March 31, 2015
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the transition period from _______________ to _______________
Commission File Number: 000-51719
LINN ENERGY, LLC
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
65-1177591
(IRS Employer
Identification No.)
600 Travis, Suite 4900
Houston, Texas
(Address of principal executive offices)
77002
(Zip Code)
(281) 840-4000
(Registrant’s telephone number, including area code)
600 Travis, Suite 5100
Houston, Texas 77002
(Former address of principal executive offices)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨
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 the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  x     Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company ¨
Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
As of March 31, 2015, there were 336,887,489 units outstanding.
 



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.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
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.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMBbls. One million barrels of oil or other liquid hydrocarbons.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMcf/d. MMcf per day.
MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMcfe/d. MMcfe per day.
MMMBtu. One billion British thermal units.
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
LINN ENERGY, LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
March 31,
2015
 
December 31,
2014
 
(in thousands,
except unit amounts)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
48,312

 
$
1,809

Accounts receivable – trade, net
340,838

 
471,684

Derivative instruments
1,119,332

 
1,077,142

Other current assets
147,969

 
155,955

Total current assets
1,656,451

 
1,706,590

 
 
 
 
Noncurrent assets:
 
 
 
Oil and natural gas properties (successful efforts method)
18,246,897

 
18,068,900

Less accumulated depletion and amortization
(5,592,674
)
 
(4,867,682
)
 
12,654,223

 
13,201,218

 
 
 
 
Other property and equipment
682,772

 
669,149

Less accumulated depreciation
(158,409
)
 
(144,282
)
 
524,363

 
524,867

 
 
 
 
Derivative instruments
949,879

 
848,097

Other noncurrent assets
135,259

 
142,737

 
1,085,138

 
990,834

Total noncurrent assets
14,263,724

 
14,716,919

Total assets
$
15,920,175

 
$
16,423,509

 
 
 
 
LIABILITIES AND UNITHOLDERS’ CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
608,926

 
$
814,809

Derivative instruments
899

 

Other accrued liabilities
184,430

 
167,736

Total current liabilities
794,255

 
982,545

 
 
 
 
Noncurrent liabilities:
 
 
 
Credit facilities
3,148,175

 
2,968,175

Term loan
500,000

 
500,000

Senior notes, net
6,750,313

 
6,827,634

Derivative instruments
1,999

 
684

Other noncurrent liabilities
598,930

 
600,866

Total noncurrent liabilities
10,999,417

 
10,897,359

 
 
 
 
Commitments and contingencies (Note 10)


 


 
 
 
 
Unitholders’ capital:
 
 
 
336,887,489 units and 331,974,913 units issued and outstanding at March 31, 2015, and December 31, 2014, respectively
5,317,869

 
5,395,811

Accumulated deficit
(1,191,366
)
 
(852,206
)
 
4,126,503

 
4,543,605

Total liabilities and unitholders’ capital
$
15,920,175

 
$
16,423,509

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

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Table of Contents

LINN ENERGY, LLC
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
Three Months Ended
March 31,
 
2015
 
2014
 
(in thousands, except per unit amounts)
Revenues and other:
 
 
 
Oil, natural gas and natural gas liquids sales
$
450,569

 
$
938,877

Gains (losses) on oil and natural gas derivatives
424,781

 
(241,493
)
Marketing revenues
33,744

 
30,546

Other revenues
7,453

 
5,657

 
916,547

 
733,587

Expenses:
 
 
 
Lease operating expenses
173,021

 
194,033

Transportation expenses
53,540

 
45,630

Marketing expenses
28,841

 
21,072

General and administrative expenses
78,968

 
79,228

Exploration costs
396

 
1,091

Depreciation, depletion and amortization
215,014

 
267,801

Impairment of long-lived assets
532,617

 

Taxes, other than income taxes
54,045

 
65,713

(Gains) losses on sale of assets and other, net
(12,287
)
 
2,586

 
1,124,155

 
677,154

Other income and (expenses):
 
 
 
Interest expense, net of amounts capitalized
(143,101
)
 
(133,813
)
Gain on extinguishment of debt
6,635

 

Other, net
(2,213
)
 
(2,303
)
 
(138,679
)
 
(136,116
)
Loss before income taxes
(346,287
)
 
(79,683
)
Income tax expense (benefit)
(7,127
)
 
5,654

Net loss
$
(339,160
)
 
$
(85,337
)
 
 
 
 
Net loss per unit:
 
 
 
Basic
$
(1.03
)
 
$
(0.27
)
Diluted
$
(1.03
)
 
$
(0.27
)
Weighted average units outstanding:
 
 
 
Basic
330,642

 
328,329

Diluted
330,642

 
328,329

 
 
 
 
Distributions declared per unit
$
0.313

 
$
0.725

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

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Table of Contents

LINN ENERGY, LLC
CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL
(Unaudited)
 
Units
 
Unitholders’ Capital
 
Accumulated Deficit
 
Total Unitholders’ Capital
 
(in thousands)
 
 
 
 
 
 
 
 
December 31, 2014
331,975

 
$
5,395,811

 
$
(852,206
)
 
$
4,543,605

Sale of units, net of offering costs of $594
1,328

 
15,306

 

 
15,306

Issuance of units
3,584

 

 

 

Distributions to unitholders
 
 
(104,815
)
 

 
(104,815
)
Unit-based compensation expenses
 
 
20,510

 

 
20,510

Excess tax benefit from unit-based compensation and other
 
 
(8,943
)
 

 
(8,943
)
Net loss
 
 

 
(339,160
)
 
(339,160
)
March 31, 2015
336,887

 
$
5,317,869

 
$
(1,191,366
)
 
$
4,126,503

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

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LINN ENERGY, LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Three Months Ended
March 31,
 
2015
 
2014
 
(in thousands)
Cash flow from operating activities:
 
 
 
Net loss
$
(339,160
)
 
$
(85,337
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
215,014

 
267,801

Impairment of long-lived assets
532,617

 

Unit-based compensation expenses
20,510

 
21,500

Gain on extinguishment of debt
(6,635
)
 

Amortization and write-off of deferred financing fees
6,712

 
2,313

(Gains) losses on sale of assets and other, net
(7,100
)
 
1,327

Deferred income taxes
(7,158
)
 
5,584

Derivatives activities:
 
 
 
Total (gains) losses
(423,855
)
 
241,493

Cash settlements
282,082

 
(14,511
)
Changes in assets and liabilities:
 
 
 
(Increase) decrease in accounts receivable – trade, net
135,230

 
(34,337
)
Increase in other assets
(12,399
)
 
(4,176
)
Increase (decrease) in accounts payable and accrued expenses
(29,868
)
 
16,105

Increase in other liabilities
8,713

 
16,720

Net cash provided by operating activities
374,703

 
434,482

 
 
 
 
Cash flow from investing activities:
 
 
 
Acquisition of oil and natural gas properties and joint-venture funding

 
(25,345
)
Development of oil and natural gas properties
(264,818
)
 
(394,843
)
Purchases of other property and equipment
(12,401
)
 
(10,151
)
Proceeds from sale of properties and equipment and other
27,500

 
(10,686
)
Net cash used in investing activities
(249,719
)
 
(441,025
)
 
 
 
 
Cash flow from financing activities:
 
 
 
Proceeds from sale of units
15,900

 

Proceeds from borrowings
395,000

 
540,000

Repayments of debt
(280,287
)
 
(241,188
)
Distributions to unitholders
(104,815
)
 
(240,073
)
Financing fees and offering costs
(453
)
 
(2,662
)
Excess tax benefit from unit-based compensation
(8,867
)
 
1,457

Other
(94,959
)
 
(34,848
)
Net cash provided by (used in) financing activities
(78,481
)
 
22,686

 
 
 
 
Net increase in cash and cash equivalents
46,503

 
16,143

Cash and cash equivalents:
 
 
 
Beginning
1,809

 
52,171

Ending
$
48,312

 
$
68,314

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

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Table of Contents

LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 – Basis of Presentation
Nature of Business
Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company. LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. The Company’s properties are located in eight operating regions in the United States (“U.S.”), in the Rockies, the Hugoton Basin, California, the Mid-Continent, the Permian Basin, TexLa, South Texas and Michigan/Illinois.
Principles of Consolidation and Reporting
The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.
The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.
The condensed consolidated 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), unitholders’ capital or cash flows.
Use of Estimates
The preparation of the accompanying condensed consolidated 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 April 2015, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2015, and interim periods within those years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its condensed consolidated financial statements and related disclosures.

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Table of Contents
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU will be applied either retrospectively or as a cumulative-effect adjustment as of the date of adoption and is effective for fiscal years beginning after December 15, 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 condensed consolidated financial statements and related disclosures.
Note 2 – Acquisitions and Joint-Venture Funding
The revenues and expenses related to certain oil and natural gas properties acquired in 2014 from subsidiaries of Devon Energy Corporation (“Devon” and the acquisition, the “Devon Assets Acquisition”) are included in the condensed consolidated results of operations of the Company as of August 29, 2014. The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the three months ended March 31, 2014, assuming the Devon Assets Acquisition had been completed as of January 1, 2014, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information has been prepared for informational purposes only and does not purport to represent what the actual results of operations would have been had the transaction been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The pro forma financial information does not give effect to the costs of any integration activities or benefits that may result from the realization of future cost savings from operating efficiencies, or any other synergies that may result from the transaction.
 
Three Months Ended
March 31, 2014
 
(in thousands, except per unit amounts)
 
 
Total revenues and other
$
879,115

Total operating expenses
$
765,491

Net loss
$
(62,305
)
 
 
Net loss per unit:
 
Basic
$
(0.20
)
Diluted
$
(0.20
)
The pro forma condensed combined statement of operations includes adjustments to:
Reflect the results of the Devon Assets Acquisition.
Reflect incremental depreciation, depletion and amortization expense, using the unit-of-production method related to oil and natural gas properties acquired and an estimated useful life of 10 years for other property and equipment.
Reflect incremental accretion expense related to asset retirement obligations on oil and natural gas properties acquired.
Reflect an increase in interest expense related to incremental debt of $2.3 billion incurred to fund the purchase price.
Reflect incremental amortization of deferred financing fees associated with debt incurred to fund the purchase price.
Joint-Venture Funding – 2014
For the three months ended March 31, 2014, the Company paid approximately $25 million, including interest, to fund the commitment related to the joint-venture agreement it entered into with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) in April 2012. As of February 2014, the Company had fully funded the total commitment of $400 million.

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Table of Contents
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

Note 3 – Unitholders’ Capital
At-the-Market Offering Program
The Company has the authority to sell up to $500 million of units under an at-the-market offering program. Sales of units, if any, will be made under an equity distribution agreement by means of ordinary brokers’ transactions, through the facilities of the NASDAQ Global Select Market, any other national securities exchange or facility thereof, a trading facility of a national securities association or an alternate trading system, to or through a market maker or directly on or through an electronic communication network, a “dark pool” or any similar market venue, at market prices, in block transactions, or as otherwise agreed with a sales agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.
During the three months ended March 31, 2015, the Company, under its equity distribution agreement, issued and sold 1,328,192 units representing limited liability company interests at an average unit price of $11.97 for net proceeds of approximately $16 million (net of approximately $159,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional service expenses of approximately $435,000. The Company used the net proceeds for general corporate purposes including the open market repurchases of a portion of its 8.625% senior notes due April 2020 (see Note 6). At March 31, 2015, units totaling approximately $484 million in aggregate offering price remained available to be issued and sold under the agreement.
Distributions
Under the Company’s limited liability company agreement, unitholders are entitled to receive a distribution of available cash, which includes cash on hand plus borrowings less any reserves established by the Company’s Board of Directors to provide for the proper conduct of the Company’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions over the next four quarters. Distributions paid by the Company are presented on the condensed consolidated statement of unitholders’ capital and the condensed consolidated statements of cash flows. On April 1, 2015, the Company’s Board of Directors declared a cash distribution of $0.3125 per unit with respect to the first quarter of 2015, to be paid in three equal installments of $0.1042 per unit. The first monthly distribution with respect to the first quarter of 2015, totaling approximately $35 million, was paid on April 16, 2015, to unitholders of record as of the close of business on April 13, 2015.
Note 4 – 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:
 
March 31,
2015
 
December 31,
2014
 
(in thousands)
Proved properties:
 
 
 
Leasehold acquisition
$
13,368,818

 
$
13,362,642

Development
3,012,467

 
2,830,841

Unproved properties
1,865,612

 
1,875,417

 
18,246,897

 
18,068,900

Less accumulated depletion and amortization
(5,592,674
)
 
(4,867,682
)
 
$
12,654,223

 
$
13,201,218


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Table of Contents
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

Impairment of Proved Properties
The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.
Based on the analysis described above, for the three months ended March 31, 2015, the Company recorded noncash impairment charges, before and after tax, of approximately $533 million associated with proved oil and natural gas properties. The impairment was due to a decline in commodity prices. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the condensed consolidated statement of operations. Following are the impairment charges recorded:
Shallow Texas Panhandle Brown Dolomite formation – $278 million;
California region – $207 million;
TexLa region – $33 million;
South Texas region – $9 million; and
Mid-Continent region – $6 million.
The Company recorded no impairment charges for the three months ended March 31, 2014.
Note 5 – Unit-Based Compensation
During the three months ended March 31, 2015, the Company granted 3,468,245 restricted units and 697,120 phantom units to employees, primarily as part of its annual review of its employees’ compensation, including executives, with an aggregate fair value of approximately $42 million. The restricted units and phantom units vest over three years. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:
 
Three Months Ended
March 31,
 
2015
 
2014
 
(in thousands)
 
 
 
 
General and administrative expenses
$
16,633

 
$
18,223

Lease operating expenses
3,877

 
3,277

Total unit-based compensation expenses
$
20,510

 
$
21,500

Income tax benefit
$
7,579

 
$
7,944

Cash-Based Performance Unit Awards
The Company also granted 567,320 performance units (the maximum number of units available to be earned) to certain executive officers. The 2015 performance unit awards vest three years from the award date. The vesting of these units is determined based on the Company’s performance compared to the performance of a predetermined group of peer companies over a specified performance period, and the value of vested units is to be paid in cash. To date, no performance units have vested and no amounts have been paid to settle any such awards. Performance unit awards that are settled in cash are recorded as a liability with the changes in fair value recognized over the vesting period. For the three months ended March 31, 2015, the Company recognized expense for cash-based performance unit awards of approximately $266,000, included in “general and

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Table of Contents
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

administrative expenses” on the condensed consolidated statement of operations. At March 31, 2015, the Company’s liability related to these performance unit awards was also approximately $266,000.
Note 6 – Debt
The following summarizes the Company’s outstanding debt:
 
March 31,
2015
 
December 31, 2014
 
(in thousands, except percentages)
 
 
 
 
LINN credit facility (1)
$
1,975,000

 
$
1,795,000

Berry credit facility (2)
1,173,175

 
1,173,175

Term loan (3)
500,000

 
500,000

6.50% senior notes due May 2019
1,200,000

 
1,200,000

6.25% senior notes due November 2019
1,800,000

 
1,800,000

8.625% senior notes due April 2020
1,220,800

 
1,300,000

6.75% Berry senior notes due November 2020
299,970

 
299,970

7.75% senior notes due February 2021
1,000,000

 
1,000,000

6.50% senior notes due September 2021
650,000

 
650,000

6.375% Berry senior notes due September 2022
599,163

 
599,163

Net unamortized discounts and premiums
(19,620
)
 
(21,499
)
Total debt, net
10,398,488

 
10,295,809

Less current maturities

 

Total long-term debt, net
$
10,398,488

 
$
10,295,809

(1) 
Variable interest rates of 1.93% and 1.92% at March 31, 2015, and December 31, 2014, respectively.
(2) 
Variable interest rates of 2.68% and 2.67% at March 31, 2015, and December 31, 2014, respectively.
(3) 
Variable interest rates of 2.68% and 2.66% at March 31, 2015, and December 31, 2014, respectively.
Fair Value
The Company’s debt is recorded at the carrying amount in the condensed consolidated balance sheets. The carrying amounts of the Company’s credit facilities and term loan approximate fair value because the interest rates are 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.
 
March 31, 2015
 
December 31, 2014
 
Carrying Value
 
Fair Value
 
Carrying Value
 
Fair Value
 
(in thousands)
 
 
 
 
 
 
 
 
Credit facilities
$
3,148,175

 
$
3,148,175

 
$
2,968,175

 
$
2,968,175

Term loan
500,000

 
500,000

 
500,000

 
500,000

Senior notes, net
6,750,313

 
5,454,065

 
6,827,634

 
5,703,649

Total debt, net
$
10,398,488

 
$
9,102,240

 
$
10,295,809

 
$
9,171,824


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LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

Credit Facilities
LINN Credit Facility
The Company’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) provides for (1) a senior secured revolving credit facility and (2) a $500 million senior secured term loan, in aggregate subject to the then-effective borrowing base. Borrowing capacity under the revolving credit facility is limited to the lesser of (i) the then-effective borrowing base reduced by the $500 million term loan and (ii) the maximum commitment amount of $4.0 billion, and is currently $4.0 billion. The maturity date is April 2019. At March 31, 2015, the borrowing base under the LINN Credit Facility was $4.5 billion and availability under the revolving credit facility was approximately $2.0 billion, which includes a $6 million reduction for outstanding letters of credit.
Redetermination of the borrowing base under the LINN Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. The administrative agent, at the direction of a super-majority of certain of the lenders, has the right to request one interim borrowing base redetermination per year. The Company also has the right to request one interim borrowing base redetermination per year, as well as the right to an additional interim redetermination each year in connection with certain acquisitions. Significant declines in commodity prices may result in a decrease in the borrowing base. The spring 2015 semi-annual redetermination is scheduled for May 2015, and the Company anticipates its lenders will recommend a decrease in the borrowing base under the LINN Credit Facility.
The Company’s obligations under the LINN Credit Facility are secured by mortgages on certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in the Company’s direct and indirect material subsidiaries. The Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report, or 2) a Collateral Coverage Ratio of at least 2.5 to 1. Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount. Additionally, the obligations under the LINN Credit Facility are guaranteed by all of the Company’s material subsidiaries, other than Berry Petroleum Company, LLC (“Berry”), and are required to be guaranteed by any future material subsidiaries. The Company is in compliance with all financial and other covenants of the LINN Credit Facility.
At the Company’s election, interest on borrowings under the LINN Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.5% and 2.5% per annum (depending on the then-current level of borrowings under the LINN Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.5% and 1.5% per annum (depending on the then-current level of borrowings under the LINN Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR. The Company is required to pay a commitment fee to the lenders under the LINN Credit Facility, which accrues at a rate per annum between 0.375% and 0.5% (depending on the then-current level of borrowings under the LINN Credit Facility) on the average daily unused amount of the maximum commitment amount of the lenders.
The $500 million term loan has a maturity date of April 2019 and incurs interest based on either the LIBOR plus a margin of 2.5% per annum or the ABR plus a margin of 1.5% per annum, at the Company’s election. Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR. The term loan may be repaid at the option of the Company without premium or penalty, subject to breakage costs. While the term loan is outstanding, the Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report, or 2) a Term Loan Collateral Coverage Ratio of at least 2.5 to 1. The Term Loan Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount and the aggregate amount of the term loan outstanding. The other terms and conditions of the LINN Credit Facility, including the financial and other restrictive covenants set forth therein, are applicable to the term loan.

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LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

Berry Credit Facility
Berry’s Second Amended and Restated Credit Agreement (“Berry Credit Facility”) currently has a borrowing base of $1.4 billion, subject to lender commitments. The maturity date is April 2019. At March 31, 2015, lender commitments under the facility were $1.2 billion but there was less than $1 million of available borrowing capacity, including outstanding letters of credit.
Redetermination of the borrowing base under the Berry Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. A super-majority of the lenders under the Berry 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 spring 2015 semi-annual redetermination is scheduled for May 2015, and the Company anticipates its lenders will recommend a decrease in the borrowing base under the Berry Credit Facility.
Berry’s obligations under the Berry Credit Facility are secured by mortgages on its oil and natural gas properties and other personal property. Berry is required to maintain mortgages on properties representing at least 80% of the present value of its oil and natural gas proved reserves. Berry is in compliance with all financial and other covenants of the Berry Credit Facility.
At Berry’s election, interest on borrowings under the Berry 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 Berry Credit Facility) or a Base Rate (as defined in the Berry Credit Facility) plus an applicable margin between 0.5% and 1.5% per annum (depending on the then-current level of borrowings under the Berry Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the Base Rate and at the end of the applicable interest period for loans bearing interest at the LIBOR. Berry is required to pay a commitment fee to the lenders under the Berry 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 Berry Credit Facility) on the average daily unused amount of the maximum commitment amount of the lenders.
The Company refers to the LINN Credit Facility and the Berry Credit Facility, collectively, as the “Credit Facilities.”
Repurchases of Senior Notes
During the three months ended March 31, 2015, the Company repurchased on the open market approximately $79 million of its 8.625% senior notes due April 2020. In connection with the repurchases, the Company recorded a gain on extinguishment of debt of approximately $7 million for the three months ended March 31, 2015.
Senior Notes Covenants
The Company’s senior notes contain covenants that, among other things, may limit its ability to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. The Company is in compliance with all financial and other covenants of its senior notes.
Berry’s senior notes contain covenants that, among other things, may limit its ability to: (i) incur or guarantee additional indebtedness; (ii) pay distributions or dividends on Berry’s equity or redeem its subordinated debt; (iii) create certain liens; (iv) enter into agreements that restrict distributions or other payments from Berry’s restricted subsidiaries to Berry; (v) sell assets; (vi) engage in transactions with affiliates; and (vii) consolidate, merge or transfer all or substantially all of Berry’s assets. Berry is in compliance with all financial and other covenants of its senior notes.
In addition, any cash generated by Berry is currently being used by Berry to fund its activities. To the extent that Berry generates cash in excess of its needs, the indentures governing Berry’s senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and Berry 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 Berry

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LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

indentures. Berry’s restricted payments basket may be increased in accordance with the terms of the Berry indentures by, among other things, 50% of Berry’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions.
Note 7 – Derivatives
Commodity Derivatives
The Company hedges a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions. 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 directly hedges only its oil and natural gas production. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials.
The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. In connection with the 2013 acquisition of Berry, the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.
The following table summarizes derivative positions for the periods indicated as of March 31, 2015:
 
April 1 - December 31, 2015
 
2016
 
2017
 
2018
Natural gas positions:
 
 
 
 
 
 
 
Fixed price swaps (NYMEX Henry Hub):
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
88,935

 
121,841

 
120,122

 
36,500

Average price ($/MMBtu)
$
5.19

 
$
4.20

 
$
4.26

 
$
5.00

Put options (NYMEX Henry Hub):
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
54,137

 
76,269

 
66,886

 

Average price ($/MMBtu)
$
5.00

 
$
5.00

 
$
4.88

 
$

Oil positions:
 
 
 
 
 
 
 
Fixed price swaps (NYMEX WTI): (1)
 
 
 
 
 
 
 
Hedged volume (MBbls)
9,426

 
11,465

 
4,755

 

Average price ($/Bbl)
$
93.33

 
$
90.56

 
$
89.02

 
$

Three-way collars (NYMEX WTI):
 
 
 
 
 
 
 
Hedged volume (MBbls)
825

 

 

 

Short put ($/Bbl)
$
70.00

 
$

 
$

 
$

Long put ($/Bbl)
$
90.00

 
$

 
$

 
$

Short call ($/Bbl)
$
101.62

 
$

 
$

 
$

Put options (NYMEX WTI):
 
 
 
 
 
 
 
Hedged volume (MBbls)
2,581

 
3,271

 
384

 

Average price ($/Bbl)
$
90.00

 
$
90.00

 
$
90.00

 
$

 
 
 
 
 
 
 
 

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LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

 
April 1 - December 31, 2015
 
2016
 
2017
 
2018
Natural gas basis differential positions: (2)
 
 
 
 
 
 
 
Panhandle basis swaps: (3)
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
65,670

 
59,954

 
59,138

 
16,425

Hedged differential ($/MMBtu)
$
(0.33
)
 
$
(0.32
)
 
$
(0.33
)
 
$
(0.33
)
NWPL Rockies basis swaps: (3)
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
43,707

 
65,794

 
38,880

 
10,804

Hedged differential ($/MMBtu)
$
(0.23
)
 
$
(0.24
)
 
$
(0.19
)
 
$
(0.19
)
MichCon basis swaps: (3)
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
7,040

 
7,768

 
7,437

 
2,044

Hedged differential ($/MMBtu)
$
0.06

 
$
0.05

 
$
0.05

 
$
0.05

Houston Ship Channel basis swaps: (3)
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
19,351

 
34,364

 
36,730

 
986

Hedged differential ($/MMBtu)
$
(0.03
)
 
$
(0.02
)
 
$
(0.02
)
 
$
(0.08
)
Permian basis swaps: (3)
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
3,823

 
4,219

 
4,819

 
1,314

Hedged differential ($/MMBtu)
$
(0.21
)
 
$
(0.20
)
 
$
(0.20
)
 
$
(0.20
)
SoCal basis swaps: (4)
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
22,050

 
32,940

 

 

Hedged differential ($/MMBtu)
$
(0.03
)
 
$
(0.03
)
 
$

 
$

Oil timing differential positions:
 
 
 
 
 
 
 
Trade month roll swaps (NYMEX WTI): (5)
 
 
 
 
 
 
 
Hedged volume (MBbls)
5,463

 
7,446

 
6,486

 

Hedged differential ($/Bbl)
$
0.24

 
$
0.25

 
$
0.25

 
$

(1) 
Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, at counterparty election on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.
(2) 
Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.
(3) 
For positions which hedge exposure to differentials in producing areas, the Company receives the NYMEX Henry Hub natural gas price plus the respective spread and pays the specified index price. Cash settlements are made on a net basis.
(4) 
For positions which hedge exposure to differentials in consuming areas, the Company pays the NYMEX Henry Hub natural gas price plus the respective spread and receives the specified index price. Cash settlements are made on a net basis.
(5) 
The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).
During the three months ended March 31, 2015, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for May 2015 through December 2017, to hedge exposure to differentials in certain producing areas, and oil swaps for April 2015 through December 2015. In addition, the Company entered into natural gas basis swaps for May 2015 through December 2016 to hedge exposure to the differential in California, where it consumes natural gas in its heavy oil development operations.

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LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

Settled derivatives on natural gas production for the three months ended March 31, 2015, included volumes of 46,823 MMMBtu at an average contract price of $5.12 per MMBtu. Settled derivatives on oil production for the three months ended March 31, 2015, included volumes of 3,975 MBbls at an average contract price of $94.29 per Bbl. Settled derivatives on natural gas production for the three months ended March 31, 2014, included volumes of 43,651 MMMBtu at an average contract price of $5.14 per MMBtu. Settled derivatives on oil production for the three months ended March 31, 2014, included volumes of 6,161 MBbls at an average contract price of $92.39 per Bbl.
The natural gas derivatives are settled based on the closing price of NYMEX Henry Hub natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX WTI crude oil for each day of the delivery month.
Balance Sheet Presentation
The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis:
 
March 31, 2015
 
December 31,
2014
 
(in thousands)
Assets:
 
 
 
Commodity derivatives
$
2,106,710

 
$
2,014,815

Liabilities:
 
 
 
Commodity derivatives
$
40,397

 
$
90,260

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 Facilities or were participants or affiliates of participants in its Credit Facilities at the time it originally entered into the derivatives. The Credit Facilities are 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 $2.1 billion at March 31, 2015. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
Gains (Losses) on Derivatives
Gains and losses on derivatives used to hedge production were net gains of approximately $425 million for the three months March 31, 2015, and net losses of approximately $241 million for the three months ended March 31, 2014, and are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.” Gains and losses on derivatives used to hedge natural gas consumption, entered into in March 2015, were net losses of approximately $1 million for the three months ended March 31, 2015, and are reported on the condensed consolidated statement of operations in “lease operating expenses.” For the three months ended March 31, 2015, and March 31, 2014, the Company received net cash settlements of approximately $282 million and paid net cash settlements of approximately $15 million, respectively.

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LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

Note 8 – Fair Value Measurements on a Recurring Basis
The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives.
Fair Value Hierarchy
In accordance with applicable accounting standards, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
 
March 31, 2015
 
Level 2
 
Netting (1)
 
Total
 
(in thousands)
Assets:
 
 
 
 
 
Commodity derivatives
$
2,106,710

 
$
(37,499
)
 
$
2,069,211

Liabilities:
 
 
 
 
 
Commodity derivatives
$
40,397

 
$
(37,499
)
 
$
2,898

 
December 31, 2014
 
Level 2
 
Netting (1)
 
Total
 
(in thousands)
Assets:
 
 
 
 
 
Commodity derivatives
$
2,014,815

 
$
(89,576
)
 
$
1,925,239

Liabilities:
 
 
 
 
 
Commodity derivatives
$
90,260

 
$
(89,576
)
 
$
684

(1) 
Represents counterparty netting under agreements governing such derivatives.
Note 9 – Asset Retirement Obligations
The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “other noncurrent liabilities” on the condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2% for the three months ended March 31, 2015); and (iv) a credit-adjusted risk-free interest rate (average of 5.6% for the three months ended March 31, 2015). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

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Table of Contents
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

The following presents a reconciliation of the Company’s asset retirement obligations (in thousands):
Asset retirement obligations at December 31, 2014
$
497,570

Liabilities added from drilling
1,390

Current year accretion expense
7,399

Settlements
(1,783
)
Revision of estimates
(1,345
)
Asset retirement obligations at March 31, 2015
$
503,231


Note 10 – Commitments and Contingencies
The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. With respect to a certain statewide class action case, the Company’s motion to dismiss was denied by the Court, and the parties have agreed on a scheduling order, which provides for briefing on the class certification issues in late 2015 and the first part of 2016. The Company has denied that it has liability on the claims asserted in the case and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. For another statewide class action royalty payment dispute, briefing on class certification issues is expected to be completed during the summer of 2015. The Company has denied that it has any liability on the claims and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. The Company is unable to estimate a possible loss, or range of possible loss, if any, in these cases. In addition, the Company is involved in various other disputes arising in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
During the three months ended March 31, 2015, and March 31, 2014, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Note 11 – Earnings Per Unit
Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect.

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LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net loss:
 
Three Months Ended
March 31,
 
2015
 
2014
 
(in thousands,
except per unit data)
 
 
 
 
Net loss
$
(339,160
)
 
$
(85,337
)
Allocated to participating securities
(1,781
)
 
(2,199
)
 
$
(340,941
)
 
$
(87,536
)
 
 
 
 
Basic net loss per unit
$
(1.03
)
 
$
(0.27
)
Diluted net loss per unit
$
(1.03
)
 
$
(0.27
)
 
 
 
 
Basic weighted average units outstanding
330,642

 
328,329

Dilutive effect of unit equivalents

 

Diluted weighted average units outstanding
330,642

 
328,329

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 5 million and 6 million unit options and warrants for the three months ended March 31, 2015, and March 31, 2014, respectively. All equivalent units were antidilutive for both the three months ended March 31, 2015, and March 31, 2014.
Note 12 – Income Taxes
The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, 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. Amounts recognized for income taxes are reported in “income tax expense (benefit)” on the condensed consolidated statements of operations.
Note 13 – Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows
“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:
 
March 31,
2015
 
December 31,
2014
 
(in thousands)
 
 
 
 
Accrued interest
$
143,088

 
$
105,310

Accrued compensation
22,854

 
44,875

Asset retirement obligations
16,187

 
16,187

Other
2,301

 
1,364

 
$
184,430

 
$
167,736


17

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LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
 
Three Months Ended
March 31,
 
2015
 
2014
 
(in thousands)
 
 
 
 
Cash payments for interest, net of amounts capitalized
$
98,541

 
$
77,512

Cash payments for income taxes
$
57

 
$

 
 
 
 
Noncash investing activities:
 
 
 
Accrued capital expenditures
$
161,247

 
$
338,323

Included in “acquisition of oil and natural gas properties and joint-venture funding” on the condensed consolidated statement of cash flows for the three months ended March 31, 2014, is approximately $25 million paid by the Company to fund the commitment related to the joint-venture agreement entered into with Anadarko in April 2012 (see Note 2).
For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $6 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at both March 31, 2015, and December 31, 2014, and primarily represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.
The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facilities. At December 31, 2014, net outstanding checks of approximately $95 million were reclassified and included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet. At March 31, 2015, no net outstanding checks were reclassified. Net outstanding checks are presented as cash flows from financing activities and included in “other” on the condensed consolidated statements of cash flows.
Note 14 – Related Party Transactions
LinnCo
LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, was formed on April 30, 2012. LinnCo’s initial sole purpose was to own units in LINN Energy. In connection with the 2013 acquisition of Berry, LinnCo amended its limited liability company agreement to permit, among other things, the acquisition and subsequent contribution of assets to LINN Energy. All of LinnCo’s common shares are held by the public. As of March 31, 2015, LinnCo had no significant assets or operations other than those related to its interest in LINN Energy and owned approximately 39% of LINN Energy’s outstanding units.
LINN Energy has agreed to provide to LinnCo, or to pay on LinnCo’s behalf, any financial, legal, accounting, tax advisory, financial advisory and engineering fees, and other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with any public offering of shares in LinnCo or incurred as a result of being a publicly traded entity. These expenses include costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, printing costs, independent auditor fees and expenses, legal counsel fees and expenses, limited liability company governance and compliance expenses and registrar and transfer agent fees. In addition, the Company has agreed to indemnify LinnCo and its officers and directors for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities. All expenses and costs paid by LINN Energy on LinnCo’s behalf are expensed by LINN Energy.
For the three months ended March 31, 2015, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $1.4 million, of which approximately $1.1 million had been paid by LINN Energy on LinnCo’s behalf as of March 31, 2015. The expenses for the three months ended March 31, 2015, include approximately $491,000 related to

18

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LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses.
For the three months ended March 31, 2014, LinnCo incurred total general and administrative expenses of approximately $734,000, of which approximately $83,000 had been paid by LINN Energy on LinnCo’s behalf as of March 31, 2014. The expenses for the three months ended March 31, 2014, include approximately $470,000 related to services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses. In addition, during the three months ended March 31, 2014, LINN Energy paid approximately $11 million on LinnCo’s behalf for general and administrative expenses incurred by LinnCo in 2013.
During the three months ended March 31, 2015, and March 31, 2014, the Company paid approximately $40 million and $93 million, respectively, in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy.
Other
One of the Company’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 ended March 31, 2015, and March 31, 2014, the Company incurred expenditures of approximately $3 million and $4 million, respectively, related to services rendered by Superior and its subsidiaries.
Note 15 – Subsidiary Guarantors
LINN Energy, LLC’s May 2019 senior notes, November 2019 senior notes, April 2020 senior notes, February 2021 senior notes and September 2021 senior notes are guaranteed by all of the Company’s material subsidiaries, other than Berry Petroleum Company, LLC, which is an indirect 100% wholly owned subsidiary of the Company.
The following condensed consolidating financial information presents the financial information of LINN Energy, LLC, the guarantor subsidiaries and the non-guarantor subsidiary in accordance with SEC Regulation S-X Rule 3‑10. The condensed consolidating financial information for the co-issuer, Linn Energy Finance Corp., is not presented as it has no assets, operations or cash flows. The financial information may not necessarily be indicative of the financial position or results of operations had the guarantor subsidiaries or non-guarantor subsidiary operated as independent entities. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.

19

Table of Contents
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS
March 31, 2015
 
LINN Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
(in thousands)
ASSETS
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
3,864

 
$
43,024

 
$
1,424

 
$

 
$
48,312

Accounts receivable – trade, net

 
251,957

 
88,881

 

 
340,838

Accounts receivable – affiliates
4,011,808

 
33,061

 

 
(4,044,869
)
 

Derivative instruments

 
1,099,777

 
19,555

 

 
1,119,332

Other current assets
18

 
94,722

 
53,229

 

 
147,969

Total current assets
4,015,690

 
1,522,541

 
163,089

 
(4,044,869
)
 
1,656,451

 
 
 
 
 
 
 
 
 
 
Noncurrent assets:
 
 
 
 
 
 
 
 
 
Oil and natural gas properties (successful efforts method)

 
13,318,736

 
4,928,161

 

 
18,246,897

Less accumulated depletion and amortization

 
(4,790,872
)
 
(865,266
)
 
63,464

 
(5,592,674
)
 

 
8,527,864

 
4,062,895

 
63,464

 
12,654,223

 
 
 
 
 
 
 
 
 
 
Other property and equipment

 
564,928

 
117,844

 

 
682,772

Less accumulated depreciation

 
(147,307
)
 
(11,102
)
 

 
(158,409
)
 

 
417,621

 
106,742

 

 
524,363

 
 
 
 
 
 
 
 
 
 
Derivative instruments

 
949,798

 
81

 

 
949,879

Notes receivable – affiliates
146,900

 

 

 
(146,900
)
 

Advance to affiliate

 

 
220,571

 
(220,571
)
 

Investments in consolidated subsidiaries
8,296,020

 

 

 
(8,296,020
)
 

Other noncurrent assets, net
110,256

 
11,660

 
13,343

 

 
135,259

 
8,553,176

 
961,458

 
233,995

 
(8,663,491
)
 
1,085,138

Total noncurrent assets
8,553,176

 
9,906,943

 
4,403,632

 
(8,600,027
)
 
14,263,724

Total assets
$
12,568,866

 
$
11,429,484

 
$
4,566,721

 
$
(12,644,896
)
 
$
15,920,175

 
 
 
 
 
 
 
 
 
 
LIABILITIES AND UNITHOLDERS’ CAPITAL
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable and accrued expenses
$
5,150

 
$
422,042

 
$
181,734

 
$

 
$
608,926

Accounts payable – affiliates

 
4,011,808

 
33,061

 
(4,044,869
)
 

Advance from affiliate

 
220,571

 

 
(220,571
)
 

Derivative instruments

 

 
899

 

 
899

Other accrued liabilities
132,202

 
37,872

 
14,356

 

 
184,430

Total current liabilities
137,352

 
4,692,293

 
230,050

 
(4,265,440
)
 
794,255

 
 
 
 
 
 
 
 
 
 
Noncurrent liabilities:
 

 
 

 
 

 
 

 
 

Credit facilities
1,975,000

 

 
1,173,175

 

 
3,148,175

Term loan
500,000

 

 

 

 
500,000

Senior notes, net
5,836,998

 

 
913,315

 

 
6,750,313

Notes payable – affiliates

 
146,900

 

 
(146,900
)
 

Derivative instruments

 
1,770

 
229

 

 
1,999

Other noncurrent liabilities

 
401,479

 
197,451

 

 
598,930

Total noncurrent liabilities
8,311,998

 
550,149

 
2,284,170

 
(146,900
)
 
10,999,417

 
 
 
 
 
 
 
 
 
 
Unitholders’ capital:
 
 
 
 
 
 
 
 
 
Units issued and outstanding
5,310,882

 
4,831,265

 
2,372,603

 
(7,196,881
)
 
5,317,869

Accumulated income (deficit)
(1,191,366
)
 
1,355,777

 
(320,102
)
 
(1,035,675
)
 
(1,191,366
)
 
4,119,516

 
6,187,042

 
2,052,501

 
(8,232,556
)
 
4,126,503

Total liabilities and unitholders’ capital
$
12,568,866

 
$
11,429,484

 
$
4,566,721

 
$
(12,644,896
)
 
$
15,920,175


20

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LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2014
 
LINN Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
(in thousands)
ASSETS
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
38

 
$
185

 
$
1,586

 
$

 
$
1,809

Accounts receivable – trade, net

 
371,325

 
100,359

 

 
471,684

Accounts receivable – affiliates
4,028,890

 
13,205

 

 
(4,042,095
)
 

Derivative instruments

 
1,033,448

 
43,694

 

 
1,077,142

Other current assets
18

 
96,678

 
59,259

 

 
155,955

Total current assets
4,028,946

 
1,514,841

 
204,898

 
(4,042,095
)
 
1,706,590

 
 
 
 
 
 
 
 
 
 
Noncurrent assets:
 
 
 
 
 
 
 
 
 
Oil and natural gas properties (successful efforts method)

 
13,196,841

 
4,872,059

 

 
18,068,900

Less accumulated depletion and amortization

 
(4,342,675
)
 
(525,007
)
 

 
(4,867,682
)
 

 
8,854,166

 
4,347,052

 

 
13,201,218

 
 
 
 
 
 
 
 
 
 
Other property and equipment

 
553,150

 
115,999

 

 
669,149

Less accumulated depreciation

 
(135,830
)
 
(8,452
)
 

 
(144,282
)
 

 
417,320

 
107,547

 

 
524,867

 
 
 
 
 
 
 
 
 
 
Derivative instruments

 
848,097

 

 

 
848,097

Notes receivable – affiliates
130,500

 

 

 
(130,500
)
 

Advance to affiliate

 

 
293,627

 
(293,627
)
 

Investments in consolidated subsidiaries
8,562,608

 

 

 
(8,562,608
)
 

Other noncurrent assets, net
116,637

 
11,816

 
14,284

 

 
142,737

 
8,809,745

 
859,913

 
307,911

 
(8,986,735
)
 
990,834

Total noncurrent assets
8,809,745

 
10,131,399

 
4,762,510

 
(8,986,735
)
 
14,716,919

Total assets
$
12,838,691

 
$
11,646,240

 
$
4,967,408

 
$
(13,028,830
)
 
$
16,423,509

 
 
 
 
 
 
 
 
 
 
LIABILITIES AND UNITHOLDERS’ CAPITAL
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable and accrued expenses
$
3,784

 
$
581,880

 
$
229,145

 
$

 
$
814,809

Accounts payable – affiliates

 
4,028,890

 
13,205

 
(4,042,095
)
 

Advance from affiliate

 
293,627

 

 
(293,627
)
 

Derivative instruments

 

 

 

 

Other accrued liabilities
89,507

 
59,142

 
19,087

 

 
167,736

Total current liabilities
93,291

 
4,963,539

 
261,437

 
(4,335,722
)
 
982,545

 
 
 
 
 
 
 
 
 
 
Noncurrent liabilities:
 

 
 

 
 

 
 

 
 

Credit facilities
1,795,000

 

 
1,173,175

 

 
2,968,175

Term loan
500,000

 

 

 

 
500,000

Senior notes, net
5,913,857

 

 
913,777

 

 
6,827,634

Notes payable – affiliates

 
130,500

 

 
(130,500
)
 

Derivative instruments

 
684

 

 

 
684

Other noncurrent liabilities

 
400,851

 
200,015

 

 
600,866

Total noncurrent liabilities
8,208,857

 
532,035

 
2,286,967

 
(130,500
)
 
10,897,359

 
 
 
 
 
 
 
 
 
 
Unitholders’ capital:
 
 
 
 
 
 
 
 
 
Units issued and outstanding
5,388,749

 
4,831,339

 
2,416,381

 
(7,240,658
)
 
5,395,811

Accumulated income (deficit)
(852,206
)
 
1,319,327

 
2,623

 
(1,321,950
)
 
(852,206
)
 
4,536,543

 
6,150,666

 
2,419,004

 
(8,562,608
)
 
4,543,605

Total liabilities and unitholders’ capital
$
12,838,691

 
$
11,646,240

 
$
4,967,408

 
$
(13,028,830
)
 
$
16,423,509


21

Table of Contents
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2015
 
LINN Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$

 
$
293,983

 
$
156,586

 
$

 
$
450,569

Gains on oil and natural gas derivatives

 
421,514

 
3,267

 

 
424,781

Marketing revenues

 
26,212

 
7,532

 

 
33,744

Other revenues

 
5,557

 
1,896

 

 
7,453

 

 
747,266

 
169,281

 

 
916,547

Expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses

 
105,832

 
67,189

 

 
173,021

Transportation expenses

 
40,934

 
12,606

 

 
53,540

Marketing expenses

 
23,196

 
5,645

 

 
28,841

General and administrative expenses

 
57,781

 
21,187

 

 
78,968

Exploration costs

 
396

 

 

 
396

Depreciation, depletion and amortization

 
140,699

 
72,979

 
1,336

 
215,014

Impairment of long-lived assets

 
325,417

 
272,000

 
(64,800
)
 
532,617

Taxes, other than income taxes
2

 
30,711

 
23,332

 

 
54,045

Gains on sale of assets and other, net

 
(7,814
)
 
(4,473
)
 

 
(12,287
)
 
2

 
717,152

 
470,465

 
(63,464
)
 
1,124,155

Other income and (expenses):
 
 
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(123,386
)
 
1,706

 
(21,421
)
 

 
(143,101
)
Interest expense – affiliates

 
(2,382
)
 

 
2,382

 

Interest income – affiliates
2,382

 

 

 
(2,382
)
 

Gain on extinguishment of debt
6,635

 

 

 

 
6,635

Equity in losses from consolidated subsidiaries
(222,811
)
 

 

 
222,811

 

Other, net
(1,978
)
 
(65
)
 
(170
)
 

 
(2,213
)
 
(339,158
)
 
(741
)
 
(21,591
)
 
222,811

 
(138,679
)
Income (loss) before income taxes
(339,160
)
 
29,373

 
(322,775
)
 
286,275

 
(346,287
)
Income tax benefit

 
(7,077
)
 
(50
)
 

 
(7,127
)
Net income (loss)
$
(339,160
)
 
$
36,450

 
$
(322,725
)
 
$
286,275

 
$
(339,160
)

22

Table of Contents
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2014
 
LINN Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$

 
$
605,761

 
$
333,116

 
$

 
$
938,877

Gains (losses) on oil and natural gas derivatives

 
(244,958
)
 
3,465

 

 
(241,493
)
Marketing revenues

 
15,731

 
14,815

 

 
30,546

Other revenues

 
5,673

 
(16
)
 

 
5,657

 

 
382,207

 
351,380

 

 
733,587

Expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses

 
104,002

 
90,031

 

 
194,033

Transportation expenses

 
37,637

 
7,993

 

 
45,630

Marketing expenses

 
10,091

 
10,981

 

 
21,072

General and administrative expenses

 
35,737

 
43,491

 

 
79,228

Exploration costs

 
1,091

 

 

 
1,091

Depreciation, depletion and amortization

 
199,170

 
68,631

 

 
267,801

Taxes, other than income taxes

 
42,684

 
23,029

 

 
65,713

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

 
(781
)
 
3,367

 

 
2,586

 

 
429,631

 
247,523

 

 
677,154

Other income and (expenses):
 
 
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(109,650
)
 
(162
)
 
(24,001
)
 

 
(133,813
)
Interest expense – affiliates

 
(1,550
)
 

 
1,550

 

Interest income – affiliates
1,550

 

 

 
(1,550
)
 

Equity in earnings from consolidated subsidiaries
24,893

 

 

 
(24,893
)
 

Other, net
(2,130
)
 
16

 
(189
)
 

 
(2,303
)
 
(85,337
)
 
(1,696
)
 
(24,190
)
 
(24,893
)
 
(136,116
)
Income (loss) before income taxes
(85,337
)
 
(49,120
)
 
79,667

 
(24,893
)
 
(79,683
)
Income tax expense (benefit)

 
5,685

 
(31
)
 

 
5,654

Net income (loss)
$
(85,337
)
 
$
(54,805
)
 
$
79,698

 
$
(24,893
)
 
$
(85,337
)


23

Table of Contents
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2015
 
LINN Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
(in thousands)
Cash flow from operating activities:
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(339,160
)
 
$
36,450

 
$
(322,725
)
 
$
286,275

 
$
(339,160
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
 
 
 
 
 
 
Depreciation, depletion and amortization

 
140,699

 
72,979

 
1,336

 
215,014

Impairment of long-lived assets

 
325,417

 
272,000

 
(64,800
)
 
532,617

Unit-based compensation expenses

 
20,510

 

 

 
20,510

Gain on extinguishment of debt
(6,635
)
 

 

 

 
(6,635
)
Amortization and write-off of deferred financing fees
6,453

 

 
259

 

 
6,712

Gains on sale of assets and other, net

 
(5,243
)
 
(1,857
)
 

 
(7,100
)
Equity in losses from consolidated subsidiaries
222,811

 

 

 
(222,811
)
 

Deferred income taxes

 
(7,108
)
 
(50
)
 

 
(7,158
)
Derivatives activities:
 
 
 
 
 
 
 
 
 
Total gains

 
(421,514
)
 
(2,341
)
 

 
(423,855
)
Cash settlements

 
254,569

 
27,513

 

 
282,082

Changes in assets and liabilities:
 
 
 
 
 
 
 
 
 
Decrease in accounts receivable – trade, net
21,921

 
96,917

 
16,392

 

 
135,230

(Increase) decrease in accounts receivable – affiliates
17,082

 
(19,856
)
 

 
2,774

 

Increase in other assets

 
(8,521
)
 
(3,878
)
 

 
(12,399
)
Decrease in accounts payable and accrued expenses
(290
)
 
(3,844
)
 
(25,734
)
 

 
(29,868
)
Increase (decrease) in accounts payable and accrued expenses – affiliates

 
(17,082
)
 
19,856

 
(2,774
)
 

Increase (decrease) in other liabilities
42,695

 
(24,057
)
 
(9,925
)
 

 
8,713

Net cash provided by (used in) operating activities
(35,123
)
 
367,337

 
42,489

 

 
374,703

 
 
 
 
 
 
 
 
 
 
Cash flow from investing activities:
 
 
 
 
 
 
 
 
 
Acquisition of oil and natural gas properties and joint-venture funding

 

 

 

 

Development of oil and natural gas properties

 
(263,209
)
 
(1,609
)
 

 
(264,818
)
Purchases of other property and equipment

 
(11,309
)
 
(1,092
)
 

 
(12,401
)
Investment in affiliates
43,778

 

 

 
(43,778
)
 

Change in notes receivable with affiliate
(16,400
)
 

 

 
16,400

 

Proceeds from sale of properties and equipment and other
(1,121
)
 
24,808

 
3,813

 

 
27,500

Net cash provided by (used in) investing activities
26,257

 
(249,710
)
 
1,112

 
(27,378
)
 
(249,719
)
 
 
 
 
 
 
 
 
 
 

24

Table of Contents
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

 
LINN Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
(in thousands)
Cash flow from financing activities:
 
 
 
 
 
 
 
 
 
Proceeds from sale of units
15,900

 

 

 

 
15,900

Proceeds from borrowings
395,000

 

 

 

 
395,000

Repayments of debt
(280,287
)
 

 

 

 
(280,287
)
Distributions to unitholders
(104,815
)
 

 

 

 
(104,815
)
Financing fees and offering costs
(453
)
 

 

 

 
(453
)
Change in notes payable with affiliate

 
16,400

 

 
(16,400
)
 

Distribution to affiliate

 

 
(43,778
)
 
43,778

 

Excess tax benefit from unit-based compensation
(8,867
)
 

 

 

 
(8,867
)
Other
(3,786
)
 
(91,188
)
 
15

 

 
(94,959
)
Net cash provided by (used in) financing activities
12,692

 
(74,788
)
 
(43,763
)
 
27,378

 
(78,481
)
 
 
 
 
 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents
3,826

 
42,839

 
(162
)
 

 
46,503

Cash and cash equivalents:
 
 
 
 
 
 
 
 
 
Beginning
38

 
185

 
1,586

 

 
1,809

Ending
$
3,864

 
$
43,024

 
$
1,424

 
$

 
$
48,312


25

Table of Contents
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2014
 
LINN Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
(in thousands)
Cash flow from operating activities:
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(85,337
)
 
$
(54,805
)
 
$
79,698

 
$
(24,893
)
 
$
(85,337
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
 
 
 
 
 
 
Depreciation, depletion and amortization

 
199,170

 
68,631

 

 
267,801

Unit-based compensation expenses

 
21,500

 

 

 
21,500

Amortization and write-off of deferred financing fees
5,791

 

 
(3,478
)
 

 
2,313

Losses on sale of assets and other, net

 
1,327

 

 

 
1,327

Equity in earnings from consolidated subsidiaries
(24,893
)
 

 

 
24,893

 

Deferred income taxes

 
5,615

 
(31
)
 

 
5,584

Derivatives activities:
 
 
 
 
 
 
 
 
 
Total (gains) losses

 
244,958

 
(3,465
)
 

 
241,493

Cash settlements

 
(11,856
)
 
(2,655
)
 

 
(14,511
)
Changes in assets and liabilities:
 
 
 
 
 
 
 
 
 
Increase in accounts receivable – trade, net

 
(18,964
)
 
(15,373
)
 

 
(34,337
)
Decrease in accounts receivable – affiliates
10,513

 
16,950

 

 
(27,463
)
 

Increase in other assets

 
(3,136
)
 
(1,040
)
 

 
(4,176
)
Increase (decrease) in accounts payable and accrued expenses
30

 
20,252

 
(4,177
)
 

 
16,105

Decrease in accounts payable and accrued expenses – affiliates

 
(10,513
)
 
(16,950
)
 
27,463

 

Increase (decrease) in other liabilities
53,698

 
(30,648
)
 
(6,330
)
 

 
16,720

Net cash provided by (used in) operating activities
(40,198
)
 
379,850

 
94,830

 

 
434,482

 
 
 
 
 
 
 
 
 
 
Cash flow from investing activities:
 
 
 
 
 
 
 
 
 
Acquisition of oil and natural gas properties and joint-venture funding

 
(25,345
)
 

 

 
(25,345
)
Development of oil and natural gas properties

 
(260,093
)
 
(134,750
)
 

 
(394,843
)
Purchases of other property and equipment

 
(8,318
)
 
(1,833
)
 

 
(10,151
)
Change in notes receivable with affiliate
(9,200
)
 

 

 
9,200

 

Proceeds from sale of properties and equipment and other
(11,230
)
 
544

 

 

 
(10,686
)
Net cash used in investing activities
(20,430
)
 
(293,212
)
 
(136,583
)
 
9,200

 
(441,025
)

26

Table of Contents
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

 
LINN Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
(in thousands)
Cash flow from financing activities:
 
 
 
 
 
 
 
 
 
Proceeds from borrowings
540,000

 

 

 

 
540,000

Repayments of debt
(240,000
)
 

 
(1,188
)
 

 
(241,188
)
Distributions to unitholders
(240,073
)
 

 

 

 
(240,073
)
Financing fees and offering costs
(81
)
 

 
(2,581
)
 

 
(2,662
)
Change in notes payable with affiliate

 
9,200

 

 
(9,200
)
 

Excess tax benefit from unit-based compensation

 
1,457

 

 

 
1,457

Other
763

 
(35,611
)
 

 

 
(34,848
)
Net cash provided by (used in) financing activities
60,609

 
(24,954
)
 
(3,769
)
 
(9,200
)
 
22,686

 
 
 
 
 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents
(19
)
 
61,684

 
(45,522
)
 

 
16,143

Cash and cash equivalents:
 
 
 
 
 
 
 
 
 
Beginning
52

 
1,078

 
51,041

 

 
52,171

Ending
$
33

 
$
62,762

 
$
5,519

 
$

 
$
68,314


27

Table of Contents

Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control. The Company’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement Regarding Forward-Looking Statements” below and in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2014, and elsewhere in the Annual Report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
The following discussion and analysis should be read in conjunction with the financial statements and related notes included in this Quarterly Report on Form 10-Q and in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”
Executive Overview
LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. LINN Energy is an independent oil and natural gas company that began operations in March 2003 and completed its initial public offering in January 2006. The Company’s properties are located in eight operating regions in the United States (“U.S.”):
Rockies, which includes properties located in Wyoming (Green River, Washakie and Powder River basins), Utah (Uinta Basin), North Dakota (Williston Basin) and Colorado (Piceance Basin);
Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle;
California, which includes properties located in the San Joaquin Valley and Los Angeles basins;
Mid-Continent, which includes Oklahoma properties located in the Anadarko and Arkoma basins, as well as waterfloods in the Central Oklahoma Platform;
Permian Basin, which includes properties located in west Texas and southeast New Mexico;
TexLa, which includes properties located in east Texas and north Louisiana;
South Texas; and
Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois.
Results for the three months ended March 31, 2015, included the following:
oil, natural gas and NGL sales of approximately $451 million compared to $939 million for the first quarter of 2014;
average daily production of approximately 1,201 MMcfe/d compared to 1,104 MMcfe/d for the first quarter of 2014;
net loss of approximately $339 million compared to $85 million for the first quarter of 2014;
net cash provided by operating activities of approximately $375 million compared to $434 million for the first quarter of 2014;
capital expenditures, excluding acquisitions, of approximately $197 million compared to $409 million for the first quarter of 2014; and
196 wells drilled (all successful) compared to 200 wells drilled (199 successful) for the first quarter of 2014.
Reduction of 2015 Oil and Natural Gas Capital Budget and Distribution
In February 2015, the Company’s Board of Directors approved a revised 2015 budget which includes a 61% reduction in total capital expenditures to approximately $600 million, from approximately $1.6 billion spent in 2014, and includes approximately $520 million related to its oil and natural gas capital program. The 2015 budget contemplates significantly lower commodity prices as compared to 2014. In January 2015, the Company reduced its distribution to $1.25 per unit, from the previous level of $2.90 per unit, on an annualized basis. The reduction of the 2015 budget and the distribution was intended to solidify the Company’s financial position and allow it to regain a useful cost of capital.

28

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

Alliance with GSO Capital Partners
In January 2015, the Company announced that it signed a non-binding letter of intent with private capital investor GSO Capital Partners LP (“GSO”) to fund oil and natural gas development (“DrillCo”). Subject to final documentation, funds managed by GSO and its affiliates have agreed to commit up to $500 million with 5-year availability to fund drilling programs on locations provided by LINN Energy. Subject to certain conditions, GSO will fund 100% of the costs associated with new wells drilled under the DrillCo agreement and is expected to receive an 85% working interest in these wells until it achieves a 15% internal rate of return on annual groupings of wells, while LINN Energy is expected to receive a 15% carried working interest during this period. Upon reaching the internal rate of return target, GSO’s interest will be reduced to 5%, while LINN Energy’s interest will increase to 95%.
The DrillCo agreement is subject to final negotiations and approval by the Company and GSO, and as such there can be no assurance that an agreement will be reached on the terms set forth in the letter of intent or at all.
Alliance with Quantum Energy Partners
In March 2015, the Company announced that it signed a non-binding letter of intent with private capital investor Quantum Energy Partners (“Quantum”) to fund selected future oil and natural gas acquisitions and development of those acquired assets (“AcqCo”). Subject to final documentation, Quantum has agreed to initially commit up to $1 billion of equity capital to fund acquisitions and development of oil and natural gas assets. LINN Energy will have the ability to participate in all acquisition opportunities with a direct working interest ranging from 15% to 50%. AcqCo assets will be managed by LINN Energy in exchange for a reimbursement of general and administrative expenses. Additionally, after certain investor return hurdles are met, LINN Energy will have the ability to earn a promoted interest in AcqCo. Upon the sale of any assets within AcqCo, LINN Energy will be given right of first offer to acquire those assets.
The AcqCo agreement is subject to final negotiations and approval by the Company and Quantum, and as such there can be no assurance that an agreement will be reached on the terms set forth in the letter of intent or at all.
Financing Activities
The spring 2015 semi-annual borrowing base redetermination of the Company’s Credit Facilities, as defined in Note 6, is scheduled for May 2015. Pending final approval from its bank group, the Company expects the borrowing base under the LINN Credit Facility to decrease from $4.5 billion to approximately $4.05 billion and the borrowing base under the Berry Credit Facility to decrease from $1.4 billion to approximately $1.2 billion at the upcoming redetermination as a result of lower commodity prices. In connection with the reduction in Berry’s borrowing base, LINN Energy intends to make a contribution to Berry of approximately $250 million, which will be posted as restricted cash with Berry’s lenders and may be returned to LINN Energy in the future if commodity prices improve.
During the three months ended March 31, 2015, the Company, under its equity distribution agreement, issued and sold 1,328,192 units representing limited liability company interests at an average unit price of $11.97 for net proceeds of approximately $16 million (net of approximately $159,000 in commissions). The Company used the net proceeds for general corporate purposes including the open market repurchases of a portion of its 8.625% senior notes due April 2020 (see Note 6). At March 31, 2015, units totaling approximately $484 million in aggregate offering price remained available to be issued and sold under the agreement.
In addition, during the three months ended March 31, 2015, the Company repurchased on the open market approximately $79 million of its 8.625% senior notes due April 2020.
Commodity Derivatives
During the three months ended March 31, 2015, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for May 2015 through December 2017, to hedge exposure to differentials in certain producing areas, and oil swaps for April 2015 through December 2015. In addition, the Company entered into natural gas basis swaps for May 2015 through December 2016 to hedge exposure to the differential in California, where it consumes natural gas in its heavy oil development operations.
In April 2015, the Company entered into oil swaps for May 2015 through December 2015. Including these new hedges, as of April 1, 2015, the Company had oil swaps of approximately 10,039 MBbls at an average price of approximately $91.29 for the remainder of 2015.

29

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

Results of Operations
Three Months Ended March 31, 2015, Compared to Three Months Ended March 31, 2014
 
Three Months Ended
March 31,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
Revenues and other:
 
 
 
 
 
Natural gas sales
$
172,096

 
$
226,689

 
$
(54,593
)
Oil sales
235,237

 
595,645

 
(360,408
)
NGL sales
43,236

 
116,543

 
(73,307
)
Total oil, natural gas and NGL sales
450,569

 
938,877

 
(488,308
)
Gains (losses) on oil and natural gas derivatives
424,781

 
(241,493
)
 
666,274

Marketing and other revenues
41,197

 
36,203

 
4,994

 
916,547

 
733,587

 
182,960

Expenses:
 
 
 
 
 
Lease operating expenses
173,021

 
194,033

 
(21,012
)
Transportation expenses
53,540

 
45,630

 
7,910

Marketing expenses
28,841

 
21,072

 
7,769

General and administrative expenses (1)
78,968

 
79,228

 
(260
)
Exploration costs
396

 
1,091

 
(695
)
Depreciation, depletion and amortization
215,014

 
267,801

 
(52,787
)
Impairment of long-lived assets
532,617

 

 
532,617

Taxes, other than income taxes
54,045

 
65,713

 
(11,668
)
(Gains) losses on sale of assets and other, net
(12,287
)
 
2,586

 
(14,873
)
 
1,124,155

 
677,154

 
447,001

Other income and (expenses)
(138,679
)
 
(136,116
)
 
(2,563
)
Loss before income taxes
(346,287
)
 
(79,683
)
 
(266,604
)
Income tax expense (benefit)
(7,127
)
 
5,654

 
(12,781
)
Net loss
$
(339,160
)
 
$
(85,337
)
 
$
(253,823
)
(1) 
General and administrative expenses for the three months ended March 31, 2015, and March 31, 2014, include approximately $17 million and $18 million, respectively, of noncash unit-based compensation expenses.

30

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

 
Three Months Ended
March 31,
 
 
 
2015
 
2014
 
Variance
Average daily production:
 
 
 
 
 
Natural gas (MMcf/d)
651

 
481

 
35
 %
Oil (MBbls/d)
62.8

 
71.2

 
(12
)%
NGL (MBbls/d)
28.8

 
32.5

 
(11
)%
Total (MMcfe/d)
1,201

 
1,104

 
9
 %
 
 
 
 
 
 
Weighted average prices: (1)
 
 
 
 
 
Natural gas (Mcf)
$
2.94

 
$
5.23

 
(44
)%
Oil (Bbl)
$
41.65

 
$
92.95

 
(55
)%
NGL (Bbl)
$
16.69

 
$
39.85

 
(58
)%
 
 
 
 
 
 
Average NYMEX prices:
 
 
 
 
 
Natural gas (MMBtu)
$
2.98

 
$
4.94

 
(40
)%
Oil (Bbl)
$
48.64

 
$
98.68

 
(51
)%
 
 
 
 
 
 
Costs per Mcfe of production:
 
 
 
 
 
Lease operating expenses
$
1.60

 
$
1.95

 
(18
)%
Transportation expenses
$
0.50

 
$
0.46

 
9
 %
General and administrative expenses (2)
$
0.73

 
$
0.80

 
(9
)%
Depreciation, depletion and amortization
$
1.99

 
$
2.70

 
(26
)%
Taxes, other than income taxes
$
0.50

 
$
0.66

 
(24
)%
(1) 
Does not include the effect of gains (losses) on derivatives.
(2) 
General and administrative expenses for the three months ended March 31, 2015, and March 31, 2014, include approximately $17 million and $18 million, respectively, of noncash unit-based compensation expenses.


31

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

Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales decreased by approximately $488 million or 52% to approximately $451 million for the three months ended March 31, 2015, from approximately $939 million for the three months ended March 31, 2014, due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Lower oil, natural gas and NGL prices resulted in a decrease in revenues of approximately $289 million, $135 million and $60 million, respectively.
Average daily production volumes increased to approximately 1,201 MMcfe/d for the three months ended March 31, 2015, from 1,104 MMcfe/d for the three months ended March 31, 2014. Higher natural gas production volumes resulted in an increase in revenues of approximately $80 million. Lower oil and NGL production volumes resulted in a decrease in revenues of approximately $71 million and $13 million, respectively.
The following table sets forth average daily production by region:
 
Three Months Ended
March 31,
 
 
 
 
 
2015
 
2014
 
Variance
Average daily production (MMcfe/d):
 
 
 
 
 
 
 
Rockies
424

 
273

 
151

 
55
 %
Hugoton Basin
247

 
144

 
103

 
72
 %
California
191

 
157

 
34

 
22
 %
Mid-Continent
102

 
300

 
(198
)
 
(66
)%
Permian Basin
94

 
166

 
(72
)
 
(43
)%
TexLa
78

 
31

 
47

 
149
 %
South Texas
34

 

 
34

 

Michigan/Illinois
31

 
33

 
(2
)
 
(6
)%
 
1,201

 
1,104

 
97

 
9
 %
The increase in average daily production volumes in the Rockies region primarily reflects the impact of the acquisition of properties from subsidiaries of Devon Energy Corporation (the “Devon Assets Acquisition”) on August 29, 2014, and development capital spending. The increase in average daily production volumes in the Hugoton Basin region primarily reflects the impact of the properties received in the exchange with Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., on August 15, 2014, the acquisition of properties from Pioneer Natural Resources Company (the “Pioneer Assets Acquisition”) on September 11, 2014, and development capital spending. The increase in average daily production volumes in the California region primarily reflects the impact of the properties received in the exchange with Exxon Mobil Corporation on November 21, 2014, and development capital spending. The decrease in average daily production volumes in the Mid-Continent region primarily reflects lower production volumes as a result of the properties sold to privately held institutional affiliates of EnerVest, Ltd. and its joint venture partner FourPoint Energy, LLC (the “Granite Wash Assets Sale”) on December 15, 2014, partially offset by the impact of the Devon Assets Acquisition. The decrease in average daily production volumes in the Permian Basin region primarily reflects lower production volumes as a result of the properties relinquished in the two exchanges with ExxonMobil and the properties sold to Fleur de Lis Energy, LLC (the “Permian Basin Assets Sale”) on November 14, 2014. The increase in average daily production volumes in the TexLa region primarily reflects the impact of the Devon Assets Acquisition. Average daily production volumes in the South Texas region reflect the impact of the Devon Assets Acquisition. The decrease in average daily production volumes in the Michigan/Illinois region primarily reflects a low-decline asset base and minimal development capital spending.

32

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

See below for details regarding capital expenditures for the periods presented:
 
Three Months Ended
March 31,
 
2015
 
2014
 
(in thousands)
 
 
 
 
Oil and natural gas
$
182,973

 
$
397,200

Plant and pipeline
2,253

 
5,395

Other
11,561

 
6,845

Capital expenditures, excluding acquisitions
$
196,787

 
$
409,440

Gains (Losses) on Oil and Natural Gas Derivatives
Gains on oil and natural gas derivatives were approximately $425 million for the three months ended March 31, 2015, compared to losses of approximately $241 million for the three months ended March 31, 2014, representing a variance of approximately $666 million. Gains on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts. The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.
During the three months ended March 31, 2015, the Company had commodity derivative contracts for approximately 80% of its natural gas production and 70% of its oil production. During the three months ended March 31, 2014, the Company had commodity derivative contracts for approximately 101% of its natural gas production and 96% of its oil production. The Company does not hedge the portion of natural gas production used to economically offset natural gas consumption related to its heavy oil development operations in California.
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 7 and Note 8 for additional information about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.
Marketing and Other Revenues
Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing and other revenues increased by approximately $5 million or 14% to approximately $41 million for the three months ended March 31, 2015, from approximately $36 million for the three months ended March 31, 2014. The increase was primarily due to higher revenues generated by the Jayhawk natural gas processing plant in Kansas and higher helium sales revenues, partially offset by lower electricity sales revenues generated by the Company’s California cogeneration facilities.
Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $21 million or 11% to approximately $173 million for the three months ended March 31, 2015, from approximately $194 million for the three months ended March 31, 2014. The decrease was primarily due to lower costs as a result of the properties sold during the fourth quarter of 2014, a decrease in steam costs caused by a lower price of natural gas used in steam generation and cost savings initiatives, partially offset by costs associated with properties acquired during the third quarter of 2014. Lease operating expenses per Mcfe also decreased to $1.60 per Mcfe for the three months ended March 31, 2015, from $1.95 per Mcfe for the three months ended March 31, 2014.
Transportation Expenses
Transportation expenses increased by approximately $8 million or 17% to approximately $54 million for the three months ended March 31, 2015, from approximately $46 million for the three months ended March 31, 2014. The increase was primarily due to costs associated with properties acquired during the third quarter of 2014 partially offset by lower costs as a

33

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

result of the properties sold during the fourth quarter of 2014. Transportation expenses per Mcfe also increased to $0.50 per Mcfe for the three months ended March 31, 2015, from $0.46 per Mcfe for the three months ended March 31, 2014.
Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses increased by approximately $8 million or 37% to approximately $29 million for the three months ended March 31, 2015, from approximately $21 million for the three months ended March 31, 2014. The increase was primarily due to higher expenses associated with the Jayhawk natural gas processing plant in Kansas partially offset by lower electricity generation expenses incurred by the Company’s California cogeneration facilities.
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. General and administrative expenses remained consistent at approximately $79 million for both the three months ended March 31, 2015, and March 31, 2014. For the three months ended March 31, 2015, higher acquisition expenses and higher professional services expenses were offset by lower salaries and benefits related expenses, primarily driven by reduced unit-based compensation, and lower various other administrative expenses. General and administrative expenses per Mcfe decreased to $0.73 per Mcfe for the three months ended March 31, 2015, from $0.80 per Mcfe for the three months ended March 31, 2014.
Exploration Costs
Exploration costs decreased by approximately $695,000 or 64% to approximately $396,000 for the three months ended March 31, 2015, from approximately $1 million for the three months ended March 31, 2014. The decrease was primarily due to lower leasehold impairment expenses on unproved properties.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $53 million or 20% to approximately $215 million for the three months ended March 31, 2015, from approximately $268 million for the three months ended March 31, 2014. The decrease was primarily due to the 2014 divestitures of properties with higher rates compared to the rates of properties acquired in 2014, as well as lower rates as a result of the impairments recorded in the prior year, partially offset by higher total production volumes. Depreciation, depletion and amortization per Mcfe decreased to $1.99 per Mcfe for the three months ended March 31, 2015, from $2.70 per Mcfe for the three months ended March 31, 2014.
Impairment of Long-Lived Assets
During the three months ended March 31, 2015, the Company recorded noncash impairment charges, before and after tax, of approximately $533 million associated with proved oil and natural gas properties. The impairment was due to a decline in commodity prices. Following are the impairment charges recorded:
Shallow Texas Panhandle Brown Dolomite formation – $278 million;
California region – $207 million;
TexLa region – $33 million;
South Texas region – $9 million; and
Mid-Continent region – $6 million.
The Company recorded no impairment charges for the three months ended March 31, 2014.
Taxes, Other Than Income Taxes
 
Three Months Ended
March 31,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
 
 
 
 
 
 
Severance taxes
$
13,890

 
$
32,116

 
$
(18,226
)
Ad valorem taxes
34,116

 
29,076

 
5,040

California carbon allowances
6,151

 
4,519

 
1,632

Other
(112
)
 
2

 
(114
)
 
$
54,045

 
$
65,713

 
$
(11,668
)

34

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

Taxes, other than income taxes decreased by approximately $12 million or 18% for the three months ended March 31, 2015, compared to the three months ended March 31, 2014. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to acquisitions completed during the third quarter of 2014. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed, caused by production increases.
Other Income and (Expenses)
 
Three Months Ended
March 31,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
 
 
 
 
 
 
Interest expense, net of amounts capitalized
$
(143,101
)
 
$
(133,813
)
 
$
(9,288
)
Gain on extinguishment of debt
6,635

 

 
6,635

Other, net
(2,213
)
 
(2,303
)
 
90

 
$
(138,679
)
 
$
(136,116
)
 
$
(2,563
)
Other income and (expenses) increased by approximately $3 million for the three months ended March 31, 2015, compared to the three months ended March 31, 2014. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with the senior notes issued in September 2014 and amendments made to the Company’s Credit Facilities during 2014. In addition, for the three months ended March 31, 2015, the Company recorded a gain on extinguishment of debt of approximately $7 million as a result of the repurchases of a portion of the 8.625% senior notes due April 2020. See “Debt” under “Liquidity and Capital Resources” below for additional details.
Income Tax Expense (Benefit)
The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized an income tax benefit of approximately $7 million for the three months ended March 31, 2015, compared to income tax expense of approximately $6 million for the three months ended March 31, 2014. The income tax benefit was primarily due to lower income from the Company’s taxable subsidiaries during the three months ended March 31, 2015, compared to the same period in 2014.
Net Income (Loss)
Net loss increased by approximately $254 million or 297% to approximately $339 million for the three months ended March 31, 2015, from approximately $85 million for the three months ended March 31, 2014. The increase was primarily due to higher impairment charges and lower production revenues, partially offset by higher gains on oil and natural gas derivatives. See discussions above for explanations of variances.
Liquidity and Capital Resources
The Company utilizes funds from debt and equity offerings, borrowings under its Credit Facilities and net cash provided by operating activities for capital resources and liquidity. To date, the primary use of capital has been for acquisitions and the development of oil and natural gas properties. For the three months ended March 31, 2015, the Company’s total capital expenditures, excluding acquisitions, were approximately $197 million. For 2015, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $600 million, including approximately $520 million related to its oil and natural gas capital program and approximately $40 million related to its plant and pipeline capital. This estimate reflects amounts for the development of properties associated with acquisitions (see Note 2), is under continuous review and subject to ongoing adjustments. The Company expects to fund the capital expenditures primarily with net cash provided by

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

operating activities. At March 31, 2015, there was approximately $2.0 billion of available borrowing capacity under the LINN Credit Facility but less than $1 million available under the Berry Credit Facility, each as defined in Note 6.
The spring 2015 semi-annual borrowing base redetermination of the Company’s Credit Facilities is scheduled for May 2015. Pending final approval from its bank group, the Company expects the borrowing base under the LINN Credit Facility to decrease from $4.5 billion to approximately $4.05 billion and the borrowing base under the Berry Credit Facility to decrease from $1.4 billion to approximately $1.2 billion at the upcoming redetermination as a result of lower commodity prices. In connection with the reduction in Berry’s borrowing base, LINN Energy intends to make a contribution to Berry of approximately $250 million, which will be posted as restricted cash with Berry’s lenders and may be returned to LINN Energy in the future if commodity prices improve.
As the Company pursues growth, it 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 drilling for or acquiring additional reserves. The Company actively reviews acquisition opportunities on an ongoing basis. If the Company were to make significant additional acquisitions for cash, it would need to borrow additional amounts under its Credit Facilities, if available, or obtain additional debt or equity financing. The Company’s Credit Facilities and indentures governing its senior notes impose certain restrictions on the Company’s ability to obtain additional debt financing. Based upon current expectations, the Company believes its liquidity and capital resources will be sufficient to conduct its business and operations.
Statements of Cash Flows
The following is a comparative cash flow summary:
 
Three Months Ended
March 31,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
Net cash:
 
 
 
 
 
Provided by operating activities
$
374,703

 
$
434,482

 
$
(59,779
)
Used in investing activities
(249,719
)
 
(441,025
)
 
191,306

Provided by (used in) financing activities
(78,481
)
 
22,686

 
(101,167
)
Net increase in cash and cash equivalents
$
46,503

 
$
16,143

 
$
30,360

Operating Activities
Cash provided by operating activities for the three months ended March 31, 2015, was approximately $375 million, compared to approximately $434 million for the three months ended March 31, 2014. The decrease was primarily due to lower production related revenues principally due to lower commodity prices partially offset by higher cash settlements on derivatives.
Investing Activities
The following provides a comparative summary of cash flow from investing activities:
 
Three Months Ended
March 31,
 
2015
 
2014
 
(in thousands)
Cash flow from investing activities:
 
 
 
Acquisition of oil and natural gas properties and joint-venture funding
$

 
$
(25,345
)
Capital expenditures
(277,219
)
 
(404,994
)
Proceeds from sale of properties and equipment and other
27,500

 
(10,686
)
 
$
(249,719
)
 
$
(441,025
)

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

The primary use of cash in investing activities is for capital spending, including acquisitions and the development of the Company’s oil and natural gas properties. Capital expenditures decreased primarily due to lower spending on development activities throughout the Company’s various operating regions as a result of the Company’s reduced 2015 capital budget.
Financing Activities
Cash used in financing activities for the three months ended March 31, 2015, was approximately $78 million, compared to cash provided by financing activities of approximately $23 million for the three months ended March 31, 2014. The decrease in financing cash flow needs was primarily attributable to decreased capital expenditures during the three months ended March 31, 2015, as compared to the three months ended March 31, 2014. The following provides a comparative summary of proceeds from borrowings and repayments of debt:
 
Three Months Ended
March 31,
 
2015
 
2014
 
(in thousands)
Proceeds from borrowings:
 
 
 
LINN Credit Facility
$
395,000

 
$
540,000

Repayments of debt:
 
 
 
LINN Credit Facility
$
(215,000
)
 
$
(240,000
)
Senior notes
(65,287
)
 
(1,188
)
 
$
(280,287
)
 
$
(241,188
)
Debt
The following summarizes the Company’s outstanding debt:
 
March 31, 2015
 
December 31, 2014
 
(in thousands, except percentages)
 
 
 
 
LINN credit facility
$
1,975,000

 
$
1,795,000

Berry credit facility
1,173,175

 
1,173,175

Term loan
500,000

 
500,000

6.50% senior notes due May 2019
1,200,000

 
1,200,000

6.25% senior notes due November 2019
1,800,000

 
1,800,000

8.625% senior notes due April 2020
1,220,800

 
1,300,000

6.75% Berry senior notes due November 2020
299,970

 
299,970

7.75% senior notes due February 2021
1,000,000

 
1,000,000

6.50% senior notes due September 2021
650,000

 
650,000

6.375% Berry senior notes due September 2022
599,163

 
599,163

Net unamortized discounts and premiums
(19,620
)
 
(21,499
)
Total debt, net
$
10,398,488

 
$
10,295,809

At March 31, 2015, there was approximately $2.0 billion of available borrowing capacity under the LINN Credit Facility but less than $1 million available under the Berry Credit Facility. During the three months ended March 31, 2015, the Company repurchased on the open market approximately $79 million of its 8.625% senior notes due April 2020.
For additional information related to the Company’s outstanding debt, see Note 6. The Company plans to file Berry’s stand-alone financial statements with the Securities and Exchange Commission at a later date.

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

Financial Covenants
The Credit Facilities contain requirements and financial covenants, among others, to maintain: 1) a ratio of EBITDA to Interest Expense (as each term is defined in the LINN Credit Facility) and Adjusted EBITDAX to Interest Expense (as each term is defined in the Berry Credit Facility) (“Interest Coverage Ratio”) for the preceding four quarters of greater than 2.5 to 1.0, and 2) a ratio of adjusted current assets to adjusted current liabilities (as described in the LINN Credit Facility) and Current Assets to Current Liabilities (as each term is defined in the Berry Credit Facility) (“Current Ratio”) as of the last day of any fiscal quarter of greater than 1.0 to 1.0. The Interest Coverage Ratio is intended as a measure of the Company’s ability to make interest payments on its outstanding indebtedness and the Current Ratio is intended as a measure of the Company’s solvency. The Company is required to demonstrate compliance with each of these ratios on a quarterly basis. The following represents the calculations of the Interest Coverage Ratio and the Current Ratio as presented to the lenders under the Credit Facilities:
 
At or for the Quarter Ended
 
 
 
June 30,
2014
 
September 30, 2014
 
December 31, 2014
 
March 31, 2015
 
Twelve Months Ended March 31, 2015
LINN Credit Facility:
 
 
 
 
 
 
 
 
 
Interest Coverage Ratio
3.7

 
3.4

 
2.7

 
2.9

 
3.2

Current Ratio
3.4

 
3.7

 
2.6

 
3.0

 
3.0

Berry Credit Facility:
 
 
 
 
 
 
 
 
 
Interest Coverage Ratio
8.1

 
9.4

 
6.7

 
1.9

 
6.6

Current Ratio (1)
0.6

 
2.0

 
0.6

 
0.6

 
0.6

Current Ratio (consolidated) (1)
2.5

 
3.3

 
2.9

 
3.2

 
3.2

(1) 
The Berry Credit Facility allows Berry to demonstrate its compliance with the Current Ratio financial covenant on a consolidated basis with LINN Energy for up to three quarters of each calendar year.
The Company has included disclosure of the Interest Coverage Ratio for the twelve months ended March 31, 2015, and the Current Ratio as of March 31, 2015, to demonstrate its compliance for the three months ended March 31, 2015, as well as the Interest Coverage Ratio for each of the preceding four quarters on an individual basis (rather than on a last twelve months basis) and the Current Ratio as of the end of each of the preceding four quarters to provide investors with trend information about the Company’s ongoing compliance with these financial covenants. If the Company fails to demonstrate compliance with either or both of the Interest Coverage Ratio or the Current Ratio as of the end of the quarter and such failure continues beyond applicable cure periods, an event of default would occur and the Company would be unable to make additional borrowings and outstanding indebtedness may be accelerated. The Company depends, in part, on its Credit Facilities for future capital needs. In addition, the Company has drawn on the LINN Credit Facility to fund or partially fund cash distribution payments. Absent such borrowings, the Company would have at times experienced a shortfall in cash available to pay the declared cash distribution amount. For additional information, see “Distribution Practices” below.
The Company is in compliance with all financial and other covenants of its Credit Facilities and senior notes.
Counterparty Credit Risk
The Company accounts for its commodity derivatives at fair value. The Company’s counterparties are current participants or affiliates of participants in its Credit Facilities or were participants or affiliates of participants in its Credit Facilities at the time it originally entered into the derivatives. The LINN Credit Facility is secured by LINN Energy’s oil, natural gas and NGL reserves and the Berry Credit Facility is secured by Berry’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

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

At-the-Market Offering Program
The Company has the authority to sell up to $500 million of units under an at-the-market offering program. Sales of units, if any, will be made under an equity distribution agreement by means of ordinary brokers’ transactions, through the facilities of the NASDAQ Global Select Market, any other national securities exchange or facility thereof, a trading facility of a national securities association or an alternate trading system, to or through a market maker or directly on or through an electronic communication network, a “dark pool” or any similar market venue, at market prices, in block transactions, or as otherwise agreed with a sales agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.
During the three months ended March 31, 2015, the Company, under its equity distribution agreement, issued and sold 1,328,192 units representing limited liability company interests at an average unit price of $11.97 for net proceeds of approximately $16 million (net of approximately $159,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional service expenses of approximately $435,000. The Company used the net proceeds for general corporate purposes including the open market repurchases of a portion of its 8.625% senior notes due April 2020 (see Note 6). At March 31, 2015, units totaling approximately $484 million in aggregate offering price remained available to be issued and sold under the agreement.
Distributions
Under the Company’s limited liability company agreement, unitholders are entitled to receive a distribution of available cash, which includes cash on hand plus borrowings less any reserves established by the Company’s Board of Directors to provide for the proper conduct of the Company’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions over the next four quarters. The following provides a summary of distributions paid by the Company during the three months ended March 31, 2015:
Date Paid
 
Distributions
Per Unit
 
Total
Distributions
 
 
 
 
(in millions)
 
 
 
 
 
March 2015
 
$
0.1042

 
$
35

February 2015
 
$
0.1042

 
$
35

January 2015
 
$
0.1042

 
$
35

On April 1, 2015, the Company’s Board of Directors declared a cash distribution of $0.3125 per unit with respect to the first quarter of 2015, to be paid in three equal monthly installments of $0.1042 per unit. The first monthly distribution with respect to the first quarter of 2015, totaling approximately $35 million, was paid on April 16, 2015, to unitholders of record as of the close of business on April 13, 2015.
Off-Balance Sheet Arrangements
The Company does not currently have any off-balance sheet arrangements.
Contingencies
See Part II. Item 1. “Legal Proceedings” for information regarding legal proceedings that the Company is party to and any contingencies related to these legal proceedings.
Commitments and Contractual Obligations
The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in the table of contractual obligations in the 2014 Annual Report on Form 10-K. There have been no significant changes to the Company’s contractual obligations since December 31, 2014. See Note 6 for additional information about the Company’s debt instruments.

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

Distribution Practices
The Company’s Board of Directors determines the appropriate level of distributions on a periodic basis in accordance with the provisions of the Company’s limited liability company agreement. Management considers the timing and size of planned capital expenditures and long-term views about expected results in determining the amount of its distributions. Capital spending and resulting production and net cash provided by operating activities do not typically occur evenly throughout the year due to a variety of factors which are difficult to predict, including rig availability, weather, well performance, the timing of completions and the commodity price environment. Consistent with practices common to publicly traded partnerships, the Company’s Board of Directors historically has not varied the distribution it declares from period to period based on uneven net cash provided by operating activities. The Company’s Board of Directors reviews historical financial results and forecasts for future periods, including development activities, as well as considers the impact of significant acquisitions in making a determination to increase, decrease or maintain the current level of distribution. If shortfalls are sustained over time and forecasts demonstrate expectations for continued future shortfalls, the Company’s Board of Directors may determine to reduce, suspend or discontinue paying distributions.
In January 2015, the Company’s Board of Directors approved a reduction of the Company’s distribution to $1.25 per unit, from the previous level of $2.90 per unit, on an annualized basis. The reduction of the distribution was intended to solidify the Company’s financial position and allow it to regain a useful cost of capital, and was primarily driven by the contemplation of significantly lower commodity prices and a reduced capital budget in 2015 as compared to 2014.
For 2015, the Company’s Board of Directors approved an oil and natural gas capital budget of approximately $520 million. At this level of capital investment, the Company forecasts a modest decline in production during 2015 while it focuses only on projects that generate an acceptable rate of return in the current low commodity price environment, and plans to balance cash flow and spending. As a result, for 2015, the Company intends to fund interest expense, its total oil and natural gas development costs and distributions to unitholders from net cash provided by operating activities, and will present “excess (shortfall) of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors” after deducting total oil and natural gas development costs. Previously, the Company intended to fund interest expense, a portion of its oil and natural gas development costs and distributions to unitholders from net cash provided by operating activities and presented “excess (shortfall) of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors” after deducting only a portion of oil and natural gas development costs.
The Company funds acquisitions and premiums paid for derivatives, if any, primarily with proceeds from debt or equity offerings, borrowings under the LINN Credit Facility or other external sources of funding. Although it is the Company’s practice to acquire or modify derivative instruments with external sources of funding, any cash settlements on derivatives are reported as net cash provided by operating activities and may be used to fund distributions.

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

See below for details regarding the discretionary adjustments considered by the Company’s Board of Directors in assessing the appropriate distribution amount for each period, as well as the extent to which sources of funding have been sufficient for the periods presented:
 
Three Months Ended
March 31,
 
2015
 
2014
 
(in thousands)
 
 
 
 
Net cash provided by operating activities
$
374,703

 
$
434,482

Distributions to unitholders
(104,815
)
 
(240,073
)
Excess of net cash provided by operating activities after distributions to unitholders
269,888

 
194,409

Discretionary adjustments considered by the Board of Directors:
 
 
 
Discretionary reductions for a portion of oil and natural gas development costs (1)
NM*

 
(193,420
)
Development of oil and natural gas properties (2)
(182,973
)
 
NM*

Cash received (paid) for acquisitions or divestitures – revenues less operating expenses (3)
(2,712
)
 

Provision for legal matters (4)
(1,000
)
 

Changes in operating assets and liabilities and other, net (5)
(120,337
)
 
(3,982
)
Shortfall of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors, including a portion of oil and natural gas development costs (6)
NM*

 
$
(2,993
)
Shortfall of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors, including total development of oil and natural gas properties (6)
$
(37,134
)
 
NM*

* 
Not meaningful due to the 2015 change in presentation.
(1) 
Represent discretionary reductions for a portion of oil and natural gas development costs, an estimated component of total development costs. The Board of Directors establishes the discretionary reductions with the objective of replacing proved developed producing reserves, current production and cash flow, taking into consideration the Company’s overall commodity mix. Management evaluates all of these objectives as part of the decision-making process to determine the discretionary reductions for a portion of oil and natural gas development costs for the year, although every objective may not be met in each year. Furthermore, there may be certain years in which commodity prices and other economic conditions do not merit capital spending at a level sufficient to accomplish any of these objectives. The 2014 amounts were established by the Board of Directors at the end of the previous year, allocated across four quarters, and were intended to fully offset declines in production and proved developed producing reserves during the year as compared to the prior year.
The portion of oil and natural gas development costs includes estimated drilling and development costs associated with projects to convert a portion of non-producing reserves to producing status. However, the amounts do not include the historical cost of acquired properties as those amounts have already been spent in prior periods, were financed primarily with external sources of funding and do not affect the Company’s ability to pay distributions in the current period. The Company’s existing reserves, inventory of drilling locations and production levels will decline over time as a result of development and production activities. Consequently, if the Company were to limit its total capital expenditures to this portion of oil and natural gas development costs and not acquire new reserves, total reserves would decrease over time, resulting in an inability to maintain production at current levels, which could adversely affect the Company’s ability to pay a distribution at the current level or at all. However, the Company’s current total reserves do not include reserve additions that may result from converting existing probable and possible resources to additional proved reserves, potential additional discoveries or technological advancements on the Company’s existing acreage position.
(2) 
Represents total capital expenditures for the development of oil and natural gas properties as presented on an accrual basis. For 2015, the Company intends to fund its total oil and natural gas capital program, in addition to interest expense and distributions to unitholders, from net cash provided by operating activities. Previously, the Company intended to fund only a portion of its oil and natural gas capital program, in addition to interest expense and distributions to unitholders, from net cash provided by operating activities.

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

(3) 
Represents adjustments to the purchase price of acquisitions and divestitures, based on the Company’s contractual right to revenues less operating expenses for periods from the effective date of a transaction to the closing date of a transaction. When the Company is the buyer, it is legally entitled to revenues less operating expenses generated during this period, and the Company’s Board of Directors has historically made a discretionary adjustment to include this cash in the amount available for distribution. Conversely, when the Company is the seller, the Company’s Board of Directors has historically made a discretionary adjustment to reduce this cash from the amount available for distribution during the period.
(4) 
Represents reserves and settlements related to legal matters.
(5) 
Represents primarily working capital adjustments. These adjustments may or may not impact cash provided by (used in) operating activities during the respective period, but are included as discretionary adjustments considered by the Company’s Board of Directors as the Board historically has not varied the distribution it declares period to period based on uneven cash flows. The Company’s Board of Directors, when determining the appropriate level of cash distributions, excluded the impact of the timing of cash receipts and payments; as such, this adjustment is necessary to show the historical amounts considered by the Company’s Board of Directors in assessing the appropriate distribution amount for each period.
(6) 
Represents the excess (shortfall) of net operating cash flow after distributions to unitholders and discretionary adjustments. Any excess was retained by the Company for future operations, future capital expenditures, future debt service or other future obligations. Any shortfall was funded with cash on hand and/or borrowings under the LINN Credit Facility.
Any cash generated by Berry is currently being used by Berry to fund its activities. To the extent that Berry generates cash in excess of its needs, the indentures governing Berry’s senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and Berry 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 Berry indentures. Berry’s restricted payments basket was approximately $206 million at March 31, 2015, and may be increased in accordance with the terms of the Berry indentures by, among other things, 50% of Berry’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions.
A summary of the significant sources and uses of funding for the respective periods is presented below:
 
Three Months Ended
March 31,
 
2015
 
2014
 
(in thousands)
 
 
 
 
Net cash provided by operating activities
$
374,703

 
$
434,482

Distributions to unitholders
(104,815
)
 
(240,073
)
Excess of net cash provided by operating activities after distributions to unitholders
269,888

 
194,409

Plus (less):
 
 
 
Net cash provided by financing activities (excluding distributions to unitholders)
26,334

 
262,759

Acquisition of oil and natural gas properties and joint-venture funding

 
(25,345
)
Development of oil and natural gas properties
(264,818
)
 
(394,843
)
Purchases of other property and equipment
(12,401
)
 
(10,151
)
Proceeds from sale of properties and equipment and other
27,500

 
(10,686
)
Net increase in cash and cash equivalents
$
46,503

 
$
16,143

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

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

Recently Issued Accounting Standards
For a discussion of recently issued accounting standards, see Note 1 of Notes to Condensed Consolidated Financial Statements.
Cautionary Statement Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond the Company’s control. These statements may include discussions about the Company’s:
business strategy;
acquisition strategy;
financial strategy;
effects of legal proceedings;
ability to maintain or grow distributions;
drilling locations;
oil, natural gas and NGL reserves;
realized oil, natural gas and NGL prices;
production volumes;
capital expenditures;
economic and competitive advantages;
credit and capital market conditions;
regulatory changes;
lease operating expenses, general and administrative expenses and development costs;
future operating results, including results of acquired properties;
plans, objectives, expectations and intentions; and
integration of acquired businesses and operations, which may take longer than anticipated, may be more costly than anticipated as a result of unexpected factors or events and may have an unanticipated adverse effect on the Company’s business.
All of these types of statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, are forward-looking statements. These forward-looking statements may be found in Item 2. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.
The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on Company expectations, which reflect estimates and assumptions made by Company management. These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors. Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control. In addition, management’s assumptions may prove to be inaccurate. The Company cautions that the forward-looking statements contained in this Quarterly Report on Form 10-Q are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors set forth in Item 1A. “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2014, and elsewhere in the Annual Report. The forward-looking statements speak only as of the date made and, other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures. All of the Company’s market risk sensitive instruments were entered into for purposes other than trading.

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

The following should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Company’s 2014 Annual Report on Form 10-K. The reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”
Commodity Price Risk
An important part of the Company’s business strategy includes hedging a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions. 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 directly hedges only its oil and natural gas production. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices.
Commodity hedging transactions are entered into with respect to a portion of the Company’s projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date.
In addition, as part of the 2013 acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. 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 maintains a substantial portion of its hedges in the form of swap contracts. From time to time, the Company has chosen to purchase put option contracts primarily in connection with acquisition activity to hedge volumes in excess of those already hedged with swap contracts. The appropriate level of production to be hedged is an ongoing consideration and is based on a variety of factors, including current and future expected commodity market prices, cost and availability of put option contracts, the level of acquisition activity and the Company’s overall risk profile, including leverage and size and scale considerations. As a result, the appropriate percentage of production volumes to be hedged may change over time. There have been no significant changes to the Company’s objectives, general strategies or instruments used to manage the Company’s commodity price risk exposures from the year ended December 31, 2014.
In certain historical periods, the Company paid an incremental premium to increase the fixed price floors on existing put options because the Company typically hedges multiple years in advance and in some cases commodity prices had increased significantly beyond the initial hedge prices. As a result, the Company determined that the existing put option strike prices did not provide reasonable downside protection in the context of the current market.
At March 31, 2015, the fair value of fixed price swaps, put option contracts and three-way collars was a net asset of approximately $1.9 billion. A 10% increase in the index oil and natural gas prices above the March 31, 2015, prices would result in a net asset of approximately $1.6 billion, which represents a decrease in the fair value of approximately $347 million; conversely, a 10% decrease in the index oil and natural gas prices below the March 31, 2015, prices would result in a net asset of approximately $2.3 billion, which represents an increase in the fair value of approximately $347 million.

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

At December 31, 2014, the fair value of fixed price swaps, put option contracts and three-way collars was a net asset of approximately $1.8 billion. A 10% increase in the index oil and natural gas prices above the December 31, 2014, prices would result in a net asset of approximately $1.4 billion, which represents a decrease in the fair value of approximately $423 million; conversely, a 10% decrease in the index oil and natural gas prices below the December 31, 2014, prices would result in a net asset of approximately $2.2 billion, which represents an increase in the fair value of approximately $421 million.
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.
The prices of oil, natural gas and NGL have been extremely volatile, and the Company expects this volatility to continue. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for such commodities, market uncertainty and a variety of additional factors that are beyond its control. Actual gains or losses recognized related to the Company’s derivative contracts will likely differ from those estimated at March 31, 2015, and December 31, 2014, and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.
The Company cannot be assured that its counterparties will be able to perform under its derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, the Company’s cash flows and ability to pay distributions could be impacted.
Interest Rate Risk
At March 31, 2015, the Company had long-term debt outstanding under its credit facilities and term loan of approximately $3.6 billion which incurred interest at floating rates (see Note 6). A 1% increase in the LIBOR would result in an estimated $36 million increase in annual interest expense.
At December 31, 2014, the Company had long-term debt outstanding under its credit facilities and term loan of approximately $3.5 billion which incurred interest at floating rates. A 1% increase in the LIBOR would result in an estimated $35 million increase in annual interest expense.
Counterparty Credit Risk
The Company accounts for its commodity derivatives at fair value on a recurring basis (see Note 8). The fair value of these derivative financial instruments includes the impact of assumed credit risk adjustments, which are based on the Company’s and counterparties’ published credit ratings, public bond yield spreads and credit default swap spreads, as applicable.
At March 31, 2015, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 2.15%. A 1% increase in the average public bond yield spread would result in an estimated $45,000 increase in net income for the three months ended March 31, 2015. At March 31, 2015, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 2.01%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $22 million decrease in net income for the three months ended March 31, 2015.
At December 31, 2014, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 1.85%. A 1% increase in the average public bond yield spread would result in an estimated $18,000 increase in net income for the year ended December 31, 2014. At December 31, 2014, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 2.15%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $20 million decrease in net income for the year ended December 31, 2014.

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Item 4.    Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, and the Company’s Audit Committee of the Board of Directors, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2015.
Changes in the Company’s Internal Control Over Financial Reporting
The Company’s management is also responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. The Company’s internal controls were designed to provide reasonable assurance as to the reliability of its financial reporting and the preparation and presentation of the condensed consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
There were no changes in the Company’s internal control over financial reporting during the first quarter of 2015 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Part II - Other Information

Item 1.
Legal Proceedings
The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. With respect to a certain statewide class action case, the Company’s motion to dismiss was denied by the Court, and the parties have agreed on a scheduling order, which provides for briefing on the class certification issues in late 2015 and the first part of 2016. The Company has denied that it has liability on the claims asserted in the case and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. For another statewide class action royalty payment dispute, briefing on class certification issues is expected to be completed during the summer of 2015. The Company has denied that it has any liability on the claims and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. The Company is unable to estimate a possible loss, or range of possible loss, if any, in these cases. In addition, the Company is involved in various other disputes arising in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
Item 1A.
Risk Factors
Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our units are described in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014. As of the date of this report, these risk factors have not changed materially. This information should be considered carefully, together with other information in this report and other reports and materials we file with the United States Securities and Exchange Commission.

Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
The Company has the authority to repurchase up to $250 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. The timing and amounts of any such repurchases are at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. The Company did not repurchase any units during the quarter ended March 31, 2015, and as of March 31, 2015, the entire amount remained available for unit repurchase under the program.
Item 3.
Defaults Upon Senior Securities
None

Item 4.
Mine Safety Disclosures
Not applicable

Item 5.
Other Information
None


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Item 6.
Exhibits
Exhibit Number
 
Description
 
 
 
3.1
Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.1 to Registration Statement on Form S-1 (File No. 333-125501) filed on June 3, 2005)
3.2
Certificate of Amendment to Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.2 to Registration Statement on Form S‑1 (File No. 333-125501) filed on June 3, 2005)
3.3
Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC dated September 3, 2010 (incorporated herein by reference to Exhibit 3.1 to Current Report on Form 8-K filed on September 7, 2010)
3.4
Amendment No. 1, dated April 23, 2013, to Third Amended and Restated LLC Agreement of Linn Energy, LLC, dated September 3, 2010 (incorporated herein by reference to Exhibit 3.1 to Quarterly Report on Form 10-Q filed on April 25, 2013)
31.1*
Section 302 Certification of Mark E. Ellis, Chairman, President and Chief Executive Officer of Linn Energy, LLC
31.2*
Section 302 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
32.1*
Section 906 Certification of Mark E. Ellis, Chairman, President and Chief Executive Officer of Linn Energy, LLC
32.2*
Section 906 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
101.INS**
XBRL Instance Document
101.SCH**
XBRL Taxonomy Extension Schema Document
101.CAL**
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**
XBRL Taxonomy Extension Label Linkbase Document
101.PRE**
XBRL Taxonomy Extension Presentation Linkbase Document
*
Filed herewith.
**
Furnished herewith.

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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
LINN ENERGY, LLC
 
(Registrant)
 
 
Date: April 29, 2015
/s/ David B. Rottino
 
David B. Rottino
 
Executive Vice President, Business Development
and Chief Accounting Officer
 
(As Duly Authorized Officer and Chief Accounting Officer)


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