LinnCo, LLC - FORM 10-Q - EX-99.1 - LINN ENERGY, LLC'S FORM 10-Q Q3 2015 - November 6, 2015

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10-Q - FORM 10-Q Q3 2015 - LinnCo, LLClinnco930201510q.htm
EX-32.2 - CERTIFICATION OF CFO SECTION 906 - LinnCo, LLCq32015exhibit322lnco.htm
EX-31.2 - CERTIFICATION OF CFO SECTION 302 - LinnCo, LLCq32015exhibit312lnco.htm
EX-31.1 - CERTIFICATION OF CEO SECTION 302 - LinnCo, LLCq32015exhibit311lnco.htm
EX-32.1 - CERTIFICATION OF CEO SECTION 906 - LinnCo, LLCq32015exhibit321lnco.htm

Exhibit 99.1

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2015
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the transition period from _______________ to _______________
Commission File Number: 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 5100
Houston, Texas
(Address of principal executive offices)
77002
(Zip Code)
(281) 840-4000
(Registrant’s telephone number, including area code)
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 the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
As of October 31, 2015, there were 355,039,816 units outstanding.
 


TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

i

GLOSSARY OF TERMS
As commonly used in the oil and natural gas industry and as used in this Quarterly Report on Form 10-Q, the following terms have the following meanings:
Bbl. One stock tank barrel or 42 United States gallons liquid volume.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet equivalent, determined using the 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 the 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.

ii

PART I – FINANCIAL INFORMATION
Item 1.
Financial Statements
LINN ENERGY, LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
September 30,
2015
 
December 31,
2014
 
(in thousands,
except unit amounts)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
344,806

 
$
1,809

Accounts receivable – trade, net
271,156

 
471,684

Derivative instruments
1,132,164

 
1,077,142

Other current assets
112,222

 
155,955

Total current assets
1,860,348

 
1,706,590

 
 
 
 
Noncurrent assets:
 
 
 
Oil and natural gas properties (successful efforts method)
18,061,991

 
18,068,900

Less accumulated depletion and amortization
(7,953,397
)
 
(4,867,682
)
 
10,108,594

 
13,201,218

 
 
 
 
Other property and equipment
713,783

 
669,149

Less accumulated depreciation
(187,383
)
 
(144,282
)
 
526,400

 
524,867

 
 
 
 
Derivative instruments
721,733

 
848,097

Restricted cash
257,043

 
6,225

Other noncurrent assets
104,351

 
136,512

 
1,083,127

 
990,834

Total noncurrent assets
11,718,121

 
14,716,919

Total assets
$
13,578,469

 
$
16,423,509

 
 
 
 
LIABILITIES AND UNITHOLDERS’ CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
568,349

 
$
814,809

Derivative instruments
1,462

 
—

Other accrued liabilities
182,178

 
167,736

Total current liabilities
751,989

 
982,545

 
 
 
 
Noncurrent liabilities:
 
 
 
Credit facilities
3,478,175

 
2,968,175

Term loan
500,000

 
500,000

Senior notes, net
6,050,101

 
6,827,634

Derivative instruments
743

 
684

Other noncurrent liabilities
603,156

 
600,866

Total noncurrent liabilities
10,632,175

 
10,897,359

 
 
 
 
Commitments and contingencies (Note 10)


 


 
 
 
 
Unitholders’ capital:
 
 
 
355,050,314 units and 331,974,913 units issued and outstanding at September 30, 2015, and December 31, 2014, respectively
5,334,115

 
5,395,811

Accumulated deficit
(3,139,810
)
 
(852,206
)
 
2,194,305

 
4,543,605

Total liabilities and unitholders’ capital
$
13,578,469

 
$
16,423,509

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

1

LINN ENERGY, LLC
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands, except per unit amounts)
Revenues and other:
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$
427,245

 
$
937,458

 
$
1,374,233

 
$
2,844,185

Gains (losses) on oil and natural gas derivatives
549,029

 
451,702

 
782,622

 
(198,579
)
Marketing revenues
15,723

 
39,836

 
60,200

 
100,655

Other revenues
6,307

 
6,119

 
19,624

 
19,392

 
998,304

 
1,435,115

 
2,236,679

 
2,765,653

Expenses:
 
 
 
 
 
 
 
Lease operating expenses
154,086

 
191,630

 
467,759

 
570,564

Transportation expenses
54,915

 
53,412

 
164,250

 
143,896

Marketing expenses
9,359

 
31,574

 
47,359

 
75,920

General and administrative expenses
60,113

 
75,384

 
237,731

 
221,518

Exploration costs
3,072

 
7,850

 
4,032

 
10,492

Depreciation, depletion and amortization
207,218

 
290,287

 
637,964

 
832,523

Impairment of long-lived assets
2,255,080

 
603,250

 
2,787,697

 
603,250

Taxes, other than income taxes
46,238

 
66,770

 
158,317

 
201,014

Gains on sale of assets and other, net
(166,980
)
 
(35,803
)
 
(197,263
)
 
(27,750
)
 
2,623,101

 
1,284,354

 
4,307,846

 
2,631,427

Other income and (expenses):
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(138,383
)
 
(154,047
)
 
(427,584
)
 
(422,160
)
Gain on extinguishment of debt
197,741

 
—

 
213,527

 
—

Other, net
(1,701
)
 
(1,847
)
 
(10,060
)
 
(6,699
)
 
57,657

 
(155,894
)
 
(224,117
)
 
(428,859
)
Loss before income taxes
(1,567,140
)
 
(5,133
)
 
(2,295,284
)
 
(294,633
)
Income tax expense (benefit)
2,177

 
(1,033
)
 
(7,680
)
 
2,674

Net loss
$
(1,569,317
)
 
$
(4,100
)
 
$
(2,287,604
)
 
$
(297,307
)
 
 
 
 
 
 
 
 
Net loss per unit:
 
 
 
 
 
 
 
Basic
$
(4.47
)
 
$
(0.02
)
 
$
(6.72
)
 
$
(0.92
)
Diluted
$
(4.47
)
 
$
(0.02
)
 
$
(6.72
)
 
$
(0.92
)
Weighted average units outstanding:
 
 
 
 
 
 
 
Basic
350,695

 
329,168

 
340,831

 
328,783

Diluted
350,695

 
329,168

 
340,831

 
328,783

 
 
 
 
 
 
 
 
Distributions declared per unit
$
0.313

 
$
0.725

 
$
0.938

 
$
2.175

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

2

LINN ENERGY, LLC
CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL
(Unaudited)
 
Units
 
Unitholders’ Capital
 
Accumulated Deficit
 
Treasury Units
(at Cost)
 
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 $8,762
19,622

 
224,665

 
—

 
—

 
224,665

Issuance of units
3,644

 
—

 
—

 
—

 
—

Cancellation of units
(191
)
 
(672
)
 
—

 
672

 
—

Purchase of units
 
 
—

 
—

 
(672
)
 
(672
)
Distributions to unitholders
 
 
(323,878
)
 
—

 
—

 
(323,878
)
Unit-based compensation expenses
 
 
47,918

 
—

 
—

 
47,918

Excess tax benefit from unit-based compensation and other
 
 
(9,729
)
 
—

 
—

 
(9,729
)
Net loss
 
 
—

 
(2,287,604
)
 
—

 
(2,287,604
)
September 30, 2015
355,050

 
$
5,334,115

 
$
(3,139,810
)
 
$
—

 
$
2,194,305

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

3

LINN ENERGY, LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Nine Months Ended
September 30,
 
2015
 
2014
 
(in thousands)
Cash flow from operating activities:
 
 
 
Net loss
$
(2,287,604
)
 
$
(297,307
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
637,964

 
832,523

Impairment of long-lived assets
2,787,697

 
603,250

Unit-based compensation expenses
47,918

 
43,692

Gain on extinguishment of debt
(213,527
)
 
—

Amortization and write-off of deferred financing fees
23,798

 
29,236

Gains on sale of assets and other, net
(193,768
)
 
(33,135
)
Deferred income taxes
(8,263
)
 
2,619

Derivatives activities:
 
 
 
Total (gains) losses
(785,520
)
 
198,579

Cash settlements
858,368

 
(12,507
)
Changes in assets and liabilities:
 
 
 
(Increase) decrease in accounts receivable – trade, net
207,062

 
(56,014
)
Decrease in other assets
2,683

 
3,284

Increase (decrease) in accounts payable and accrued expenses
(36,626
)
 
112,235

Increase (decrease) in other liabilities
(5,413
)
 
9,355

Net cash provided by operating activities
1,034,769

 
1,435,810

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

 
(2,601,932
)
Development of oil and natural gas properties
(503,206
)
 
(1,176,478
)
Purchases of other property and equipment
(51,529
)
 
(50,138
)
Proceeds from sale of properties and equipment and other
364,195

 
(7,485
)
Net cash used in investing activities
(190,540
)
 
(3,836,033
)
 
 
 
 
Cash flow from financing activities:
 
 
 
Proceeds from sale of units
233,427

 
—

Proceeds from borrowings
1,405,000

 
5,300,024

Repayments of debt
(1,701,909
)
 
(2,156,124
)
Distributions to unitholders
(323,878
)
 
(721,235
)
Financing fees and offering costs
(8,774
)
 
(68,614
)
Excess tax benefit from unit-based compensation
(9,467
)
 
4,031

Other
(95,631
)
 
49,131

Net cash provided by (used in) financing activities
(501,232
)
 
2,407,213

 
 
 
 
Net increase in cash and cash equivalents
342,997

 
6,990

Cash and cash equivalents:
 
 
 
Beginning
1,809

 
52,171

Ending
$
344,806

 
$
59,161

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

4

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). Adoption of this ASU is expected

5
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

to result in a decrease to the Company’s assets and liabilities in its consolidated balance sheets, with no impact to the consolidated statements of operations.
In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU will be applied either retrospectively or as a cumulative-effect adjustment as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those years (early adoption permitted for fiscal years beginning after December 15, 2016, including interim periods within that year). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.
Note 2 – Divestiture, Acquisitions, Exchange of Properties and Joint-Venture Funding
Divestiture – 2015
On August 31, 2015, the Company, through certain of its wholly owned subsidiaries, completed the sale of its remaining position in Howard County in the Permian Basin. Cash proceeds received from the sale of these properties were approximately $276 million, net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $174 million. The gain is included in “gains on sale of assets and other, net” on the condensed consolidated statements of operations. The Company used the net proceeds from the sale to repay a portion of the outstanding indebtedness under the LINN Credit Facility, which included debt initially incurred to fund the repurchase of a portion of its senior notes during 2015 (see Note 6).
Acquisitions – 2014
On September 11, 2014, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin from Pioneer Natural Resources Company (“Pioneer” and the acquisition, the “Pioneer Assets Acquisition”) for total consideration of approximately $328 million, which was initially financed with borrowings under the LINN Credit Facility.
On August 29, 2014, the Company completed the acquisition of certain oil and natural gas properties located in five operating regions in the U.S. from subsidiaries of Devon Energy Corporation (“Devon” and the acquisition, the “Devon Assets Acquisition”) for total consideration of approximately $2.1 billion, which was initially financed with proceeds from a bridge loan and borrowings under a short-period term loan.
During the third quarter of 2014, the Company used the net proceeds from the issuance of its 6.50% senior notes due May 2019 and 6.50% senior notes due September 2021 to repay the bridge loan in full, and during the fourth quarter of 2014, the Company used the net proceeds from the sales of its Granite Wash properties as well as certain of its Wolfberry properties to repay the short-period term loan in full.
The revenues and expenses related to the Devon Assets Acquisition are included on the Company’s condensed consolidated statements of operations as of August 29, 2014. The following unaudited pro forma financial information presents a summary of the Company’s condensed combined results of operations for the three months and nine months ended September 30, 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.

6
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

 
Three Months Ended
September 30, 2014
 
Nine Months Ended
September 30, 2014
 
(in thousands, except per unit amounts)
 
 
 
 
Total revenues and other
$
1,509,498

 
$
3,117,792

Total operating expenses
$
(1,330,384
)
 
$
(2,846,361
)
Net income (loss)
$
1,480

 
$
(251,192
)
 
 
 
 
Net income (loss) per unit:
 
 
 
Basic
$
—

 
$
(0.78
)
Diluted
$
—

 
$
(0.78
)
The pro forma condensed combined results 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.
•
Exclude transaction costs related to the Devon Assets Acquisition included in the historical statements of operations as they reflect nonrecurring charges not expected to have a continuing impact on the combined results.
Exchange of Properties – 2014
On August 15, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., in exchange for properties in the Hugoton Basin. The noncash exchange was accounted for at fair value and the Company recognized a net gain of approximately $45 million, including costs to sell of approximately $3 million. The gain is equal to the difference between the carrying value and the fair value of the assets exchanged less costs to sell, and is included in “gains on sale of assets and other, net” on the condensed consolidated statements of operations. The fair value measurements were based on inputs that are not observable and therefore represent Level 3 inputs under the fair value hierarchy.
Joint-Venture Funding – 2014
During the first quarter of 2014, the Company paid approximately $25 million, including interest, to complete the total funding commitment of $400 million related to the joint-venture agreement it entered into with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) in April 2012.
Note 3 – Unitholders’ Capital
At-the-Market Offering Program
The Company’s Board of Directors has authorized the sale of 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

7
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

otherwise agreed with a sales agent. The Company expects to use the net proceeds from any sale of units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.
During the nine months ended September 30, 2015, the Company, under its equity distribution agreement, sold 3,621,983 units representing limited liability company interests at an average unit price of $12.37 for net proceeds of approximately $44 million (net of approximately $448,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional services expenses of approximately $459,000. The Company used the net proceeds for general corporate purposes, including the open market repurchases of a portion of its senior notes (see Note 6). At September 30, 2015, units totaling approximately $455 million in aggregate offering price remained available to be sold under the agreement.
Public Offering of Units
In May 2015, the Company sold 16,000,000 units representing limited liability company interests in an underwritten public offering at $11.79 per unit ($11.32 per unit, net of underwriting discount) for net proceeds of approximately $181 million (after underwriting discount and offering costs of approximately $8 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under the LINN Credit Facility, which included debt initially incurred to fund the open market repurchases of a portion of its senior notes during 2015 (see Note 6).
Forfeiture of Units in Exchange for Cash
In August 2015, in accordance with terms of the separation agreement between the Company and Kolja Rockov dated August 31, 2015, Mr. Rockov agreed to forfeit 191,446 units issued to him under the Company’s equity compensation plan (see Note 5) in exchange for payment of approximately $672,000. These units will remain available for issuance under the Company’s equity compensation plan.
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. Monthly distributions were paid by the Company through September 2015. In October 2015, the Company’s Board of Directors determined to suspend payment of the Company’s distribution. The Company’s Board of Directors will continue to evaluate the Company’s ability to reinstate the distribution.
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:
 
September 30,
2015
 
December 31,
2014
 
(in thousands)
Proved properties:
 
 
 
Leasehold acquisition
$
13,296,925

 
$
13,362,642

Development
2,909,071

 
2,830,841

Unproved properties
1,855,995

 
1,875,417

 
18,061,991

 
18,068,900

Less accumulated depletion and amortization
(7,953,397
)
 
(4,867,682
)
 
$
10,108,594

 
$
13,201,218


8
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, the Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties:
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
 
 
 
 
 
 
 
 
Rockies region
$
1,182,337

 
$
—

 
$
1,182,337

 
$
—

California region
330,311

 
—

 
537,511

 
—

TexLa region
375,567

 
—

 
408,667

 
—

Mid-Continent region
366,865

 
—

 
372,568

 
—

Shallow Texas Panhandle Brown Dolomite formation
—

 
—

 
277,914

 
—

South Texas region
—

 
—

 
8,700

 
—

Permian Basin region
—

 
603,250

 
—

 
603,250

 
$
2,255,080

 
$
603,250

 
$
2,787,697

 
$
603,250

The impairment charges in 2015 were due to a decline in commodity prices and the Company’s estimates of proved reserves, and the impairment in 2014 was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for proved oil and natural gas properties.
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 statements of operations.
Note 5 – Unit-Based Compensation
During the nine months ended September 30, 2015, the Company granted 3,478,595 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. In addition, during the nine months ended September 30, 2015, the Company granted 400,502 unrestricted units, primarily as part of severance arrangements, with an aggregate fair value of approximately $4 million. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
 
 
 
 
 
 
 
 
General and administrative expenses
$
13,040

 
$
9,445

 
$
40,717

 
$
37,164

Lease operating expenses
1,167

 
1,664

 
7,201

 
6,528

Total unit-based compensation expenses
$
14,207

 
$
11,109

 
$
47,918

 
$
43,692

Income tax benefit
$
5,250

 
$
4,105

 
$
17,706

 
$
16,144


9
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)


Cash-Based Performance Unit Awards
In January 2015, 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. Based on the performance criteria, there was no liability recorded for these performance unit awards at September 30, 2015.
Note 6 – Debt
The following summarizes the Company’s outstanding debt:
 
September 30,
2015
 
December 31, 2014
 
(in thousands, except percentages)
 
 
 
 
LINN credit facility (1)
$
2,305,000

 
$
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
1,159,215

 
1,200,000

6.25% senior notes due November 2019
1,483,928

 
1,800,000

8.625% senior notes due April 2020
1,123,483

 
1,300,000

6.75% Berry senior notes due November 2020
261,100

 
299,970

7.75% senior notes due February 2021
963,774

 
1,000,000

6.50% senior notes due September 2021
502,010

 
650,000

6.375% Berry senior notes due September 2022
572,700

 
599,163

Net unamortized discounts and premiums
(16,109
)
 
(21,499
)
Total debt, net
10,028,276

 
10,295,809

Less current maturities
—

 
—

Total long-term debt, net
$
10,028,276

 
$
10,295,809

(1) 
Variable interest rates of 2.39% and 1.92% at September 30, 2015, and December 31, 2014, respectively.
(2) 
Variable interest rates of 2.71% and 2.67% at September 30, 2015, and December 31, 2014, respectively.
(3) 
Variable interest rates of 2.72% and 2.66% at September 30, 2015, and December 31, 2014, respectively.
Fair Value
The Company’s debt is recorded at the carrying amount on 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.

10
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

 
September 30, 2015
 
December 31, 2014
 
Carrying Value
 
Fair Value
 
Carrying Value
 
Fair Value
 
(in thousands)
 
 
 
 
 
 
 
 
Credit facilities
$
3,478,175

 
$
3,478,175

 
$
2,968,175

 
$
2,968,175

Term loan
500,000

 
500,000

 
500,000

 
500,000

Senior notes, net
6,050,101

 
1,610,642

 
6,827,634

 
5,703,649

Total debt, net
$
10,028,276

 
$
5,588,817

 
$
10,295,809

 
$
9,171,824

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 was $3.55 billion as of September 30, 2015. The maturity date is April 2019. At September 30, 2015, the borrowing base under the LINN Credit Facility was $4.05 billion (which was reaffirmed in October 2015, subject to conditions described below) and availability under the revolving credit facility was approximately $1.2 billion, which includes reductions for the $500 million term loan and $6 million of outstanding letters of credit.
In October 2015, the Company entered into an amendment to the LINN Credit Facility to provide for, among other things: (i) a “springing maturity” based on the maturity of any outstanding LINN Energy junior lien debt; (ii) the ability to incur up to $4.0 billion of junior lien debt to accommodate exchanges of the Company’s outstanding unsecured senior notes and Berry Petroleum Company, LLC (“Berry”) senior notes or as additional indebtedness, but such additional indebtedness may not exceed $1.0 billion; (iii) if the Berry Consolidation (defined below) happens on or before January 1, 2016, the ability to issue up to the $1.0 billion of the additional junior lien debt described in the previous clause (ii) without a corresponding reduction in our borrowing base before the next scheduled redetermination; (iv) a minimum liquidity requirement equal to the greater of $500 million and 15% of the then effective available borrowing base after giving effect to certain redemptions or repurchases of certain debt; (v) a decrease in the covenant requiring the maintenance of an EBITDA to Interest Expense ratio of 2.5 to 1.0, such that the minimum required ratio is decreased to 2.0 to 1.0 from December 31, 2015 through December 31, 2016, to 2.25 to 1.0 from March 31, 2017 through June 30, 2017 and returning to 2.5 to 1.0 thereafter; (vi) the ability to make necessary tax-related distributions or contributions to LinnCo, LLC; (vii) an increase in the mortgage requirement on the total value of the oil and natural gas properties included on our most recent reserve report from 80% to 90%; and (viii) an increase to the applicable margin charged on borrowings under the LINN Credit Facility by 0.25% and an increase in the commitment fee under the LINN Credit Facility on the average daily unused amount of the maximum commitment amount of the lenders to 0.5% per annum.
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. Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs, along with the maturity schedule of the Company’s hedges, may impact future redeterminations.
The spring 2015 semi-annual borrowing base redetermination was completed in May 2015, and, as a result of lower commodity prices, the borrowing base under the LINN Credit Facility decreased from $4.5 billion to $4.05 billion. The fall 2015 semi-annual redetermination was completed in October 2015 and the borrowing base under the LINN Credit Facility was reaffirmed at $4.05 billion. The borrowing base will automatically decrease to $3.6 billion on January 1, 2016, subject to any additional reductions for additional junior lien debt issued since this redetermination, if the following conditions are not met on or before

11
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

January 1, 2016: (i) the issuance by the Company of at least $250 million of additional junior lien debt; (ii) repayment and extinguishment of the Berry Credit Facility (as defined below); and (iii) the guarantee by Berry of the LINN Credit Facility or the merger or consolidation of Berry with a guarantor under the LINN Credit Facility (collectively, the “Berry Consolidation”). Notwithstanding this, borrowing availability under the LINN Credit Facility will be limited to $3.6 billion (which amount includes the outstanding $500 million term loan) until the earlier of a) January 1, 2016 or b) the date of the Berry Consolidation.
The Company’s obligations under the LINN Credit Facility, as amended, 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 mortgages on properties representing at least 90% of the total value of oil and natural gas properties included on its most recent reserve report. Additionally, the obligations under the LINN Credit Facility are guaranteed by all of the Company’s material subsidiaries, other than 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, as amended, is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75% 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 0.75% and 1.75% 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 of 0.50% 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 2.75% per annum or the ABR plus a margin of 1.75% 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 1.0. 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.
Berry Credit Facility
Berry’s Second Amended and Restated Credit Agreement (“Berry Credit Facility”) had a borrowing base of $1.2 billion, subject to lender commitments, as of September 30, 2015. The maturity date is April 2019. At September 30, 2015, lender commitments under the facility were $1.2 billion but there was less than $1 million of available borrowing capacity, including outstanding letters of credit.
In October 2015, Berry entered into an amendment to the Berry Credit Facility to provide for, among other things: (i) a springing maturity based on the maturity of any outstanding Berry junior lien debt; (ii) the ability of Berry to incur junior lien debt to refinance its senior notes or as additional indebtedness, but such additional indebtedness issued may not exceed $500 million outstanding at any one time and is subject to a borrowing base reduction; (iii) a decrease in Berry’s covenant requiring the maintenance of an EBITDA to Interest Expense ratio of 2.5 to 1.0, such that the permissible ratio is decreased to 2.0 to 1.0 from December 31, 2015 through December 31, 2016, to 2.25 to 1.0 from March 31, 2017 through June 30, 2017 and returning to 2.5 to 1.0 thereafter; (iv) an increase in the mortgage requirement on the total value of the oil and natural gas properties included in Berry’s most recent reserve report from 80% to 90%; (v) an increase to the applicable margin charged on borrowings under the Berry Credit Facility by 0.25% and increase the commitment fee under the Berry Credit Facility to 0.5% per annum; and (vi) permission to prepay or exchange Berry’s senior notes with notes issued by LINN Energy.

12
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

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. The spring 2015 semi-annual borrowing base redetermination was completed in May 2015, and, as a result of lower commodity prices, the borrowing base under the Berry Credit Facility decreased from $1.4 billion to $1.2 billion. The fall 2015 semi-annual redetermination was completed in October 2015 and the borrowing base under the Berry Credit Facility decreased from $1.2 billion to $900 million. Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs may impact future redeterminations.
In connection with the reduction in Berry’s borrowing base in October 2015, Berry repaid $300 million of borrowings outstanding under the Berry Credit Facility. In connection with the reduction in Berry’s borrowing base in May 2015, LINN Energy borrowed $250 million under the LINN Credit Facility, which it contributed to Berry to post as restricted cash with Berry’s lenders. As directed by LINN Energy, the $250 million was deposited on Berry’s behalf in a security account with the administrative agent subject to a security control agreement. Berry’s ability to withdraw funds from this account is subject to a concurrent reduction of the borrowing base under the Berry Credit Facility or lender’s consent in connection with a redetermination of such borrowing base. The $250 million may be used to satisfy obligations under the Berry Credit Facility or, subject to restrictions in the indentures governing Berry’s senior notes, may be returned to LINN Energy in the future. The amount is included in “restricted cash” on the condensed consolidated balance sheet.
Berry’s obligations under the Berry Credit Facility, as amended, 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 90% 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, as amended, is determined by reference to either the LIBOR plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the Berry Credit Facility) or a Base Rate (as defined in the Berry Credit Facility) plus an applicable margin between 0.75% and 1.75% 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 of 0.5% 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 nine months ended September 30, 2015, the Company repurchased, through privately negotiated transactions and on the open market, approximately $783 million of its outstanding senior notes as follows:
•
6.50% senior notes due May 2019 – $41 million;
•
6.25% senior notes due November 2019 – $316 million;
•
8.625% senior notes due April 2020 – $177 million;
•
6.75% Berry senior notes due November 2020 – $39 million;
•
7.75% senior notes due February 2021 – $36 million;
•
6.50% senior notes due September 2021 – $148 million; and
•
6.375% Berry senior notes due September 2022 – $26 million.
In connection with the repurchases, the Company paid approximately $557 million in cash and recorded a gain on extinguishment of debt of approximately $214 million for the nine months ended September 30, 2015.

13
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

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 and determines to distribute such amounts to LINN Energy, 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 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 seeks to hedge 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, if and when resumed, 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. 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.

14
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

The following table summarizes derivative positions for the periods indicated as of September 30, 2015:
 
October 1 - December 31, 2015
 
2016
 
2017
 
2018
Natural gas positions:
 
 
 
 
 
 
 
Fixed price swaps (NYMEX Henry Hub):
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
29,753

 
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)
18,111

 
76,269

 
66,886

 
—

Average price ($/MMBtu)
$
5.00

 
$
5.00

 
$
4.88

 
$
—

Oil positions:
 
 
 
 
 
 
 
Fixed price swaps (NYMEX WTI): (1)
 
 
 
 
 
 
 
Hedged volume (MBbls)
3,890

 
11,465

 
4,755

 
—

Average price ($/Bbl)
$
87.22

 
$
90.56

 
$
89.02

 
$
—

Three-way collars (NYMEX WTI):
 
 
 
 
 
 
 
Hedged volume (MBbls)
276

 
—

 
—

 
—

Short put ($/Bbl)
$
70.00

 
$
—

 
$
—

 
$
—

Long put ($/Bbl)
$
90.00

 
$
—

 
$
—

 
$
—

Short call ($/Bbl)
$
101.62

 
$
—

 
$
—

 
$
—

Put options (NYMEX WTI):
 
 
 
 
 
 
 
Hedged volume (MBbls)
864

 
3,271

 
384

 
—

Average price ($/Bbl)
$
90.00

 
$
90.00

 
$
90.00

 
$
—

Natural gas basis differential positions: (2)
 
 
 
 
 
 
 
Panhandle basis swaps: (3)
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
21,970

 
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)
14,479

 
65,794

 
38,880

 
10,804

Hedged differential ($/MMBtu)
$
(0.23
)
 
$
(0.24
)
 
$
(0.19
)
 
$
(0.19
)
MichCon basis swaps: (3)
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
2,355

 
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)
7,443

 
34,364

 
36,730

 
986

Hedged differential ($/MMBtu)
$
(0.03
)
 
$
(0.02
)
 
$
(0.02
)
 
$
(0.08
)
Permian basis swaps: (3)
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
1,279

 
4,219

 
4,819

 
1,314

Hedged differential ($/MMBtu)
$
(0.21
)
 
$
(0.20
)
 
$
(0.20
)
 
$
(0.20
)
SoCal basis swaps: (4)
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
8,280

 
32,940

 
—

 
—

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

 
$
—


15
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

 
October 1 - December 31, 2015
 
2016
 
2017
 
2018
Oil timing differential positions:
 
 
 
 
 
 
 
Trade month roll swaps (NYMEX WTI): (5)
 
 
 
 
 
 
 
Hedged volume (MBbls)
1,828

 
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 nine months ended September 30, 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.
Settled derivatives on natural gas production for the three months and nine months ended September 30, 2015, included volumes of 47,864 MMMBtu and 142,031 MMMBtu, respectively, at an average contract price of $5.12 per MMBtu. Settled derivatives on oil production for the three months and nine months ended September 30, 2015, included volumes of 5,060 MBbls and 13,855 MBbls, respectively, at average contract prices of $87.53 per Bbl and $89.86 per Bbl. Settled derivatives on natural gas production for the three months and nine months ended September 30, 2014, included volumes of 44,621 MMMBtu and 132,408 MMMBtu, respectively, at an average contract price of $5.14 per MMBtu. Settled derivatives on oil production for the three months and nine months ended September 30, 2014, included volumes of 6,299 MBbls and 18,690 MBbls, respectively, 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.

16
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

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:
 
September 30,
2015
 
December 31,
2014
 
(in thousands)
Assets:
 
 
 
Commodity derivatives
$
1,887,082

 
$
2,014,815

Liabilities:
 
 
 
Commodity derivatives
$
35,390

 
$
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 $1.9 billion at September 30, 2015. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
Gains (Losses) on Derivatives
A summary of gains and losses on derivatives included on the condensed consolidated statements of operations is presented below:
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
 
 
 
 
 
 
 
 
Gains (losses) on oil and natural gas derivatives
$
549,029

 
$
451,702

 
$
782,622

 
$
(198,579
)
Lease operating expenses (1)
(162
)
 
—

 
2,898

 
—

Total gains (losses) on oil and natural gas derivatives
$
548,867

 
$
451,702

 
$
785,520

 
$
(198,579
)
(1) 
Consists of gains and (losses) on derivatives used to hedge exposure to differentials in consuming areas, which were entered into in March 2015.
For the three months and nine months ended September 30, 2015, the Company received net cash settlements of approximately $292 million and $858 million, respectively. For the three months and nine months ended September 30, 2014, the Company received net cash settlements of approximately $10 million and paid net cash settlements of approximately $13 million, respectively.

17
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:
 
September 30, 2015
 
Level 2
 
Netting (1)
 
Total
 
(in thousands)
Assets:
 
 
 
 
 
Commodity derivatives
$
1,887,082

 
$
(33,185
)
 
$
1,853,897

Liabilities:
 
 
 
 
 
Commodity derivatives
$
35,390

 
$
(33,185
)
 
$
2,205

 
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 nine months ended September 30, 2015); and (iv) a credit-adjusted risk-free interest rate (average of 5.5% for the nine months ended September 30, 2015). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

18
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
2,857

Liabilities associated with assets sold
(2,594
)
Current year accretion expense
22,290

Settlements
(3,749
)
Revision of estimates
2,022

Asset retirement obligations at September 30, 2015
$
518,396


Note 10 – Commitments and Contingencies
For certain statewide class action royalty payment disputes where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the courts, will result in no loss to the Company. 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 nine months ended September 30, 2015, and September 30, 2014, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
In 2008, Lehman Brothers Holdings Inc. and Lehman Brothers Commodity Services Inc. (together “Lehman”), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York. In March 2011, the Company and Lehman entered into Termination Agreements under which the Company was granted general unsecured claims against Lehman in the amount of $51 million (the “Company Claim”). In December 2011, a Chapter 11 Plan was approved by the Bankruptcy Court. In both April 2015 and April 2014, the Company received approximately $3 million of the Company Claim, of which both amounts are included in “gains (losses) on oil and natural gas derivatives” on the condensed consolidated statements of operations. In the aggregate, the Company has received approximately $49 million of the Company Claim.
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.

19
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
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands, except per unit data)
 
 
 
 
 
 
 
 
Net loss
$
(1,569,317
)
 
$
(4,100
)
 
$
(2,287,604
)
 
$
(297,307
)
Allocated to participating securities
—

 
(2,097
)
 
(3,081
)
 
(6,289
)
 
$
(1,569,317
)
 
$
(6,197
)
 
$
(2,290,685
)
 
$
(303,596
)
 
 
 
 
 
 
 
 
Basic net loss per unit
$
(4.47
)
 
$
(0.02
)
 
$
(6.72
)
 
$
(0.92
)
Diluted net loss per unit
$
(4.47
)
 
$
(0.02
)
 
$
(6.72
)
 
$
(0.92
)
 
 
 
 
 
 
 
 
Basic weighted average units outstanding
350,695

 
329,168

 
340,831

 
328,783

Dilutive effect of unit equivalents
—

 
—

 
—

 
—

Diluted weighted average units outstanding
350,695

 
329,168

 
340,831

 
328,783

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 4 million and 5 million unit options and warrants for the three months and nine months ended September 30, 2015, respectively, and approximately 6 million for both the three months and nine months ended September 30, 2014. All equivalent units were antidilutive for both the three months and nine months ended September 30, 2015, and September 30, 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:
 
September 30,
2015
 
December 31,
2014
 
(in thousands)
 
 
 
 
Accrued interest
$
126,966

 
$
105,310

Accrued compensation
37,860

 
44,875

Asset retirement obligations
16,187

 
16,187

Other
1,165

 
1,364

 
$
182,178

 
$
167,736


20
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
 
Nine Months Ended
September 30,
 
2015
 
2014
 
(in thousands)
 
 
 
 
Cash payments for interest, net of amounts capitalized
$
386,118

 
$
345,687

Cash payments for income taxes
$
627

 
$
—

 
 
 
 
Noncash investing activities:
 
 
 
Accrued capital expenditures
$
98,404

 
$
273,220

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. At September 30, 2015, “restricted cash” on the condensed consolidated balance sheet includes $250 million which LINN Energy borrowed under the LINN Credit Facility and contributed to Berry in May 2015 to post with Berry’s lenders in connection with the reduction in the Berry Credit Facility’s borrowing base. Restricted cash also includes approximately $7 million and $6 million at September 30, 2015, and December 31, 2014, respectively, of cash deposited by the Company into a separate account 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 September 30, 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 September 30, 2015, LinnCo had no significant assets or operations other than those related to its interest in LINN Energy and owned approximately 37% 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 and nine months ended September 30, 2015, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $965,000 and $2.8 million, respectively, all of which had been paid by LINN Energy on LinnCo’s behalf as of September 30, 2015. The expenses for the three months and nine months ended September 30, 2015, include approximately $491,000 and $1.5 million, respectively, 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.

21
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

For the three months and nine months ended September 30, 2014, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $644,000 and $2.1 million, respectively, of which approximately $1.9 million had been paid by LINN Energy on LinnCo’s behalf as of September 30, 2014. The expenses for the three months and nine months ended September 30, 2014, include approximately $470,000 and $1.4 million, respectively, 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 nine months ended September 30, 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 and nine months ended September 30, 2015, the Company paid approximately $41 million and $121 million, respectively, in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy. During the three months and nine months ended September 30, 2014, the Company paid approximately $94 million and $280 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 and nine months ended September 30, 2015, the Company incurred expenditures of approximately $2 million and $7 million, respectively, and for the three months and nine months ended September 30, 2014, the Company incurred expenditures of approximately $5 million and $17 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.
In 2014, the Company had a consolidated variable interest entity (“VIE”) that was not considered a subsidiary and did not guarantee any of Linn Energy, LLC’s or Berry Petroleum Company, LLC’s indebtedness; therefore, it is presented separately. The VIE structure was terminated in December 2014.

22
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2015
 
Linn Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
(in thousands)
ASSETS
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
32

 
$
61,969

 
$
282,805

 
$
—

 
$
344,806

Accounts receivable – trade, net
—

 
215,626

 
55,530

 
—

 
271,156

Accounts receivable – affiliates
3,265,327

 
6,329

 
—

 
(3,271,656
)
 
—

Derivative instruments
—

 
1,105,635

 
26,529

 
—

 
1,132,164

Other current assets
—

 
68,813

 
43,420

 
(11
)
 
112,222

Total current assets
3,265,359

 
1,458,372

 
408,284

 
(3,271,667
)
 
1,860,348

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

 
13,061,758

 
5,000,233

 
—

 
18,061,991

Less accumulated depletion and amortization
—

 
(6,517,088
)
 
(1,493,749
)
 
57,440

 
(7,953,397
)
 
—

 
6,544,670

 
3,506,484

 
57,440

 
10,108,594

 
 
 
 
 
 
 
 
 
 
Other property and equipment
—

 
584,892

 
128,891

 
—

 
713,783

Less accumulated depreciation
—

 
(171,095
)
 
(16,288
)
 
—

 
(187,383
)
 
—

 
413,797

 
112,603

 
—

 
526,400

 
 
 
 
 
 
 
 
 
 
Derivative instruments
—

 
721,397

 
336

 
—

 
721,733

Restricted cash
—

 
6,798

 
250,245

 
—

 
257,043

Notes receivable – affiliates
181,400

 
—

 
—

 
(181,400
)
 
—

Investments in consolidated subsidiaries
6,779,570

 
—

 
—

 
(6,779,570
)
 
—

Other noncurrent assets, net
88,217

 
5,387

 
10,747

 
—

 
104,351

 
7,049,187

 
733,582

 
261,328

 
(6,960,970
)
 
1,083,127

Total noncurrent assets
7,049,187

 
7,692,049

 
3,880,415

 
(6,903,530
)
 
11,718,121

Total assets
$
10,314,546

 
$
9,150,421

 
$
4,288,699

 
$
(10,175,197
)
 
$
13,578,469

 
 
 
 
 
 
 
 
 
 
LIABILITIES AND UNITHOLDERS’ CAPITAL
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable and accrued expenses
$
776

 
$
391,449

 
$
176,124

 
$
—

 
$
568,349

Accounts payable – affiliates
—

 
3,265,327

 
6,329

 
(3,271,656
)
 
—

Derivative instruments
—

 
—

 
1,462

 
—

 
1,462

Other accrued liabilities
116,969

 
52,513

 
12,707

 
(11
)
 
182,178

Total current liabilities
117,745

 
3,709,289

 
196,622

 
(3,271,667
)
 
751,989

 
 
 
 
 
 
 
 
 
 
Noncurrent liabilities:
 

 
 

 
 

 
 

 
 

Credit facilities
2,305,000

 
—

 
1,173,175

 
—

 
3,478,175

Term loan
500,000

 
—

 
—

 
—

 
500,000

Senior notes, net
5,204,297

 
—

 
845,804

 
—

 
6,050,101

Notes payable – affiliates
—

 
181,400

 
—

 
(181,400
)
 
—

Derivative instruments
—

 
320

 
423

 
—

 
743

Other noncurrent liabilities
—

 
402,225

 
200,931

 
—

 
603,156

Total noncurrent liabilities
8,009,297

 
583,945

 
2,220,333

 
(181,400
)
 
10,632,175

 
 
 
 
 
 
 
 
 
 
Unitholders’ capital:
 
 
 
 
 
 
 
 
 
Units issued and outstanding
5,327,314

 
4,831,078

 
2,757,836

 
(7,582,113
)
 
5,334,115

Accumulated income (deficit)
(3,139,810
)
 
26,109

 
(886,092
)
 
859,983

 
(3,139,810
)
 
2,187,504

 
4,857,187

 
1,871,744

 
(6,722,130
)
 
2,194,305

Total liabilities and unitholders’ capital
$
10,314,546

 
$
9,150,421

 
$
4,288,699

 
$
(10,175,197
)
 
$
13,578,469


23
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

Restricted cash
—

 
6,100

 
125

 
—

 
6,225

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

 
5,716

 
14,159

 
—

 
136,512

 
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
)
 
—

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


24
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended September 30, 2015
 
Linn Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
 
Revenues and other:
 
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$
—

 
$
286,993

 
$
140,252

 
$
—

 
$
427,245

Gains on oil and natural gas derivatives
—

 
521,365

 
27,664

 
—

 
549,029

Marketing revenues
—

 
6,004

 
9,719

 
—

 
15,723

Other revenues
—

 
4,635

 
1,672

 
—

 
6,307

 
—

 
818,997

 
179,307

 
—

 
998,304

Expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
—

 
86,745

 
67,341

 
—

 
154,086

Transportation expenses
—

 
41,121

 
13,794

 
—

 
54,915

Marketing expenses
—

 
3,633

 
5,726

 
—

 
9,359

General and administrative expenses
—

 
38,549

 
21,564

 
—

 
60,113

Exploration costs
—

 
3,072

 
—

 
—

 
3,072

Depreciation, depletion and amortization
—

 
142,211

 
63,057

 
1,950

 
207,218

Impairment of long-lived assets
—

 
1,744,449

 
510,631

 
—

 
2,255,080

Taxes, other than income taxes
—

 
31,718

 
14,520

 
—

 
46,238

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

 
(169,613
)
 
2,633

 
—

 
(166,980
)
 
—

 
1,921,885

 
699,266

 
1,950

 
2,623,101

Other income and (expenses):
 
 
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(117,096
)
 
197

 
(21,484
)
 
—

 
(138,383
)
Interest expense – affiliates
—

 
(2,207
)
 
—

 
2,207

 
—

Interest income – affiliates
2,207

 
—

 
—

 
(2,207
)
 
—

Gain on extinguishment of debt
193,363

 
—

 
4,378

 
—

 
197,741

Equity in losses from consolidated subsidiaries
(1,646,256
)
 
—

 
—

 
1,646,256

 
—

Other, net
(1,535
)
 
(76
)
 
(90
)
 
—

 
(1,701
)
 
(1,569,317
)
 
(2,086
)
 
(17,196
)
 
1,646,256

 
57,657

Loss before income taxes
(1,569,317
)
 
(1,104,974
)
 
(537,155
)
 
1,644,306

 
(1,567,140
)
Income tax expense
—

 
2,174

 
3

 
—

 
2,177

Net loss
$
(1,569,317
)
 
$
(1,107,148
)
 
$
(537,158
)
 
$
1,644,306

 
$
(1,569,317
)

25
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended September 30, 2014
 
Linn Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Non-
Guarantor VIE
 
Eliminations
 
Consolidated
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$
—

 
$
542,535

 
$
350,863

 
$
44,060

 
$
—

 
$
937,458

Gains on oil and natural gas derivatives
—

 
406,712

 
44,990

 
—

 
—

 
451,702

Marketing revenues
—

 
26,518

 
13,318

 
—

 
—

 
39,836

Other revenues
—

 
5,874

 
245

 
—

 
—

 
6,119

 
—

 
981,639

 
409,416

 
44,060

 
—

 
1,435,115

Expenses:
 
 
 
 
 
 
 
 
 
 
 
Lease operating expenses
—

 
97,613

 
83,684

 
10,333

 
—

 
191,630

Transportation expenses
—

 
36,531

 
13,326

 
3,555

 
—

 
53,412

Marketing expenses
—

 
23,871

 
7,703

 
—

 
—

 
31,574

General and administrative expenses
—

 
52,580

 
16,566

 
6,238

 
—

 
75,384

Exploration costs
—

 
7,850

 
—

 
—

 
—

 
7,850

Depreciation, depletion and amortization
—

 
199,360

 
79,725

 
11,202

 
—

 
290,287

Impairment of long-lived assets
—

 
603,250

 
—

 
—

 


 
603,250

Taxes, other than income taxes
40

 
38,598

 
24,830

 
3,302

 
—

 
66,770

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

 
(93,257
)
 
49,011

 
8,443

 
—

 
(35,803
)
 
40

 
966,396

 
274,845

 
43,073

 
—

 
1,284,354

Other income and (expenses):
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(129,129
)
 
757

 
(19,068
)
 
(6,607
)
 
—

 
(154,047
)
Interest expense – affiliates
—

 
(2,218
)
 
—

 
—

 
2,218

 
—

Interest income – affiliates
2,218

 
—

 
—

 
—

 
(2,218
)
 
—

Equity in earnings from consolidated subsidiaries
124,435

 
—

 
—

 
—

 
(124,435
)
 
—

Other, net
(1,584
)
 
(84
)
 
(179
)
 
—

 
—

 
(1,847
)
 
(4,060
)
 
(1,545
)
 
(19,247
)
 
(6,607
)
 
(124,435
)
 
(155,894
)
Income (loss) before income taxes
(4,100
)
 
13,698

 
115,324

 
(5,620
)
 
(124,435
)
 
(5,133
)
Income tax expense (benefit)
—

 
(1,192
)
 
159

 
—

 
—

 
(1,033
)
Net income (loss)
$
(4,100
)
 
$
14,890

 
$
115,165

 
$
(5,620
)
 
$
(124,435
)
 
$
(4,100
)

26
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2015
 
Linn Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$
—

 
$
904,014

 
$
470,219

 
$
—

 
$
1,374,233

Gains on oil and natural gas derivatives
—

 
756,165

 
26,457

 
—

 
782,622

Marketing revenues
—

 
35,501

 
24,699

 
—

 
60,200

Other revenues
—

 
14,521

 
5,103

 
—

 
19,624

 
—

 
1,710,201

 
526,478

 
—

 
2,236,679

Expenses:
 
 
 
 
 
 
 
 
 
Lease operating expenses
—

 
283,333

 
184,426

 
—

 
467,759

Transportation expenses
—

 
124,872

 
39,378

 
—

 
164,250

Marketing expenses
—

 
29,990

 
17,369

 
—

 
47,359

General and administrative expenses
—

 
157,878

 
79,853

 
—

 
237,731

Exploration costs
—

 
4,032

 
—

 
—

 
4,032

Depreciation, depletion and amortization
—

 
433,649

 
199,088

 
5,227

 
637,964

Impairment of long-lived assets
—

 
2,069,866

 
782,631

 
(64,800
)
 
2,787,697

Taxes, other than income taxes
2

 
98,267

 
60,048

 
—

 
158,317

Gains on sale of assets and other, net
—

 
(194,612
)
 
(2,651
)
 
—

 
(197,263
)
 
2

 
3,007,275

 
1,360,142

 
(59,573
)
 
4,307,846

Other income and (expenses):
 
 
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(364,037
)
 
2,048

 
(65,595
)
 
—

 
(427,584
)
Interest expense – affiliates
—

 
(7,824
)
 
—

 
7,824

 
—

Interest income – affiliates
7,824

 
—

 
—

 
(7,824
)
 
—

Gain on extinguishment of debt
202,318

 
—

 
11,209

 
—

 
213,527

Equity in losses from consolidated subsidiaries
(2,124,493
)
 
—

 
—

 
2,124,493

 
—

Other, net
(9,214
)
 
(123
)
 
(723
)
 
—

 
(10,060
)
 
(2,287,602
)
 
(5,899
)
 
(55,109
)
 
2,124,493

 
(224,117
)
Loss before income taxes
(2,287,604
)
 
(1,302,973
)
 
(888,773
)
 
2,184,066

 
(2,295,284
)
Income tax benefit
—

 
(7,622
)
 
(58
)
 
—

 
(7,680
)
Net loss
$
(2,287,604
)
 
$
(1,295,351
)
 
$
(888,715
)
 
$
2,184,066

 
$
(2,287,604
)


27
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2014
 
Linn Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Non-
Guarantor VIE
 
Eliminations
 
Consolidated
 
(in thousands)
Revenues and other:
 
 
 
 
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$
—

 
$
1,755,766

 
$
1,044,359

 
$
44,060

 
$
—

 
$
2,844,185

Gains (losses) on oil and natural gas derivatives
—

 
(221,472
)
 
22,893

 
—

 
—

 
(198,579
)
Marketing revenues
—

 
60,088

 
40,567

 
—

 
—

 
100,655

Other revenues
—

 
19,154

 
238

 
—

 
—

 
19,392

 
—

 
1,613,536

 
1,108,057

 
44,060

 
—

 
2,765,653

Expenses:
 
 
 
 
 
 
 
 
 
 
 
Lease operating expenses
—

 
293,162

 
267,069

 
10,333

 
—

 
570,564

Transportation expenses
—

 
111,539

 
28,802

 
3,555

 
—

 
143,896

Marketing expenses
—

 
47,511

 
28,409

 
—

 
—

 
75,920

General and administrative expenses
—

 
126,901

 
88,379

 
6,238

 
—

 
221,518

Exploration costs
—

 
10,492

 
—

 
—

 
—

 
10,492

Depreciation, depletion and amortization
—

 
595,212

 
226,109

 
11,202

 
—

 
832,523

Impairment of long-lived assets
—

 
603,250

 
—

 
—

 
—

 
603,250

Taxes, other than income taxes
40

 
126,334

 
71,338

 
3,302

 
—

 
201,014

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

 
(92,828
)
 
56,635

 
8,443

 
—

 
(27,750
)
 
40

 
1,821,573

 
766,741

 
43,073

 
—

 
2,631,427

Other income and (expenses):
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net of amounts capitalized
(350,382
)
 
1,384

 
(66,555
)
 
(6,607
)
 
—

 
(422,160
)
Interest expense – affiliates
—

 
(5,627
)
 
—

 
—

 
5,627

 
—

Interest income – affiliates
5,627

 
—

 
—

 
—

 
(5,627
)
 
—

Equity in earnings from consolidated subsidiaries
53,244

 
—

 
—

 
—

 
(53,244
)
 
—

Other, net
(5,756
)
 
(130
)
 
(813
)
 
—

 
—

 
(6,699
)
 
(297,267
)
 
(4,373
)
 
(67,368
)
 
(6,607
)
 
(53,244
)
 
(428,859
)
Income (loss) before income taxes
(297,307
)
 
(212,410
)
 
273,948

 
(5,620
)
 
(53,244
)
 
(294,633
)
Income tax expense
—

 
2,597

 
77

 
—

 
—

 
2,674

Net income (loss)
$
(297,307
)
 
$
(215,007
)
 
$
273,871

 
$
(5,620
)
 
$
(53,244
)
 
$
(297,307
)


28
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2015
 
Linn Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Eliminations
 
Consolidated
 
(in thousands)
Cash flow from operating activities:
 
 
 
 
 
 
 
 
 
Net loss
$
(2,287,604
)
 
$
(1,295,351
)
 
$
(888,715
)
 
$
2,184,066

 
$
(2,287,604
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
 
 
 
 
 
 
Depreciation, depletion and amortization
—

 
433,649

 
199,088

 
5,227

 
637,964

Impairment of long-lived assets
—

 
2,069,866

 
782,631

 
(64,800
)
 
2,787,697

Unit-based compensation expenses
—

 
47,918

 
—

 
—

 
47,918

Gain on extinguishment of debt
(202,318
)
 
—

 
(11,209
)
 
—

 
(213,527
)
Amortization and write-off of deferred financing fees
22,677

 
—

 
1,121

 
—

 
23,798

Gains on sale of assets and other, net
—

 
(192,247
)
 
(1,521
)
 
—

 
(193,768
)
Equity in losses from consolidated subsidiaries
2,124,493

 
—

 
—

 
(2,124,493
)
 
—

Deferred income taxes
—

 
(8,205
)
 
(58
)
 
—

 
(8,263
)
Derivatives activities:
 
 
 
 
 
 
 
 
 
Total gains
—

 
(756,165
)
 
(29,355
)
 
—

 
(785,520
)
Cash settlements
—

 
810,314

 
48,054

 
—

 
858,368

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

 
163,353

 
43,709

 
—

 
207,062

Decrease in accounts receivable – affiliates
813,653

 
6,876

 
—

 
(820,529
)
 
—

Decrease in other assets
—

 
1,164

 
1,519

 
—

 
2,683

Decrease in accounts payable and accrued expenses
—

 
(28,331
)
 
(8,295
)
 
—

 
(36,626
)
Decrease in accounts payable and accrued expenses – affiliates
—

 
(813,653
)
 
(6,876
)
 
820,529

 
—

Increase (decrease) in other liabilities
27,462

 
(12,086
)
 
(20,789
)
 
—

 
(5,413
)
Net cash provided by operating activities
498,363

 
427,102

 
109,304

 
—

 
1,034,769

Cash flow from investing activities:
 
 
 
 
 
 
 
 
 
Development of oil and natural gas properties
—

 
(500,130
)
 
(3,076
)
 
—

 
(503,206
)
Purchases of other property and equipment
—

 
(38,769
)
 
(12,760
)
 
—

 
(51,529
)
Investment in affiliates
(91,455
)
 
—

 
—

 
91,455

 
—

Change in notes receivable with affiliate
(50,900
)
 
—

 
—

 
50,900

 
—

Settlement of advance to affiliate
—

 
—

 
129,217

 
(129,217
)
 
—

Proceeds from sale of properties and equipment and other
(2,826
)
 
344,535

 
22,486

 
—

 
364,195

Net cash provided by (used in) investing activities
(145,181
)
 
(194,364
)
 
135,867

 
13,138

 
(190,540
)

29
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
233,427

 
—

 
—

 
—

 
233,427

Proceeds from borrowings
1,405,000

 
—

 
—

 
—

 
1,405,000

Repayments of debt
(1,646,491
)
 
—

 
(55,418
)
 
—

 
(1,701,909
)
Distributions to unitholders
(323,878
)
 
—

 
—

 
—

 
(323,878
)
Financing fees and offering costs
(8,771
)
 
—

 
(3
)
 
—

 
(8,774
)
Change in notes payable with affiliate
—

 
50,900

 
—

 
(50,900
)
 
—

Settlement of advance from affiliate
—

 
(129,217
)
 
—

 
129,217

 
—

Capital contributions – affiliates
—

 
—

 
91,455

 
(91,455
)
 
—

Excess tax benefit from unit-based compensation
(9,467
)
 
—

 
—

 
—

 
(9,467
)
Other
(3,008
)
 
(92,637
)
 
14

 
—

 
(95,631
)
Net cash provided by (used in) financing activities
(353,188
)
 
(170,954
)
 
36,048

 
(13,138
)
 
(501,232
)
 
 
 
 
 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents
(6
)
 
61,784

 
281,219

 
—

 
342,997

Cash and cash equivalents:
 
 
 
 
 
 
 
 
 
Beginning
38

 
185

 
1,586

 
—

 
1,809

Ending
$
32

 
$
61,969

 
$
282,805

 
$
—

 
$
344,806


30
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2014
 
Linn Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Non-
Guarantor VIE
 
Eliminations
 
Consolidated
 
(in thousands)
Cash flow from operating activities:
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
$
(297,307
)
 
$
(215,007
)
 
$
273,871

 
$
(5,620
)
 
$
(53,244
)
 
$
(297,307
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 
 
 
 
 
 
 
 
 
 
 
Depreciation, depletion and amortization
—

 
595,212

 
226,109

 
11,202

 
—

 
832,523

Impairment of long-lived assets
—

 
603,250

 
—

 
—

 
—

 
603,250

Unit-based compensation expenses
—

 
43,692

 
—

 
—

 
—

 
43,692

Amortization and write-off of deferred financing fees
31,564

 
—

 
(5,174
)
 
2,846

 
—

 
29,236

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

 
(81,492
)
 
48,357

 
—

 
—

 
(33,135
)
Equity in earnings from consolidated subsidiaries
(53,244
)
 
—

 
—

 
—

 
53,244

 
—

Deferred income taxes
—

 
2,542

 
77

 
—

 
—

 
2,619

Derivatives activities:
 
 
 
 
 
 
 
 
 
 
 
Total (gains) losses
—

 
221,472

 
(22,893
)
 
—

 
—

 
198,579

Cash settlements
—

 
5,623

 
(18,130
)
 
—

 
—

 
(12,507
)
Changes in assets and liabilities:
 
 
 
 
 
 
 
 
 
 
 
Increase in accounts receivable – trade, net
—

 
(1,343
)
 
(10,611
)
 
(44,060
)
 
—

 
(56,014
)
Decrease in accounts receivable – affiliates
469,499

 
16,950

 
—

 
—

 
(486,449
)
 
—

(Increase) decrease in other assets
312

 
(10,723
)
 
4,551

 
9,144

 
—

 
3,284

Increase (decrease) in accounts payable and accrued expenses
18

 
107,673

 
(10,619
)
 
15,163

 
—

 
112,235

Decrease in accounts payable and accrued expenses – affiliates
—

 
(468,896
)
 
(5,722
)
 
(11,831
)
 
486,449

 
—

Increase (decrease) in other liabilities
63,806

 
(18,053
)
 
(36,626
)
 
228

 
—

 
9,355

Net cash provided by (used in) operating activities
214,648

 
800,900

 
443,190

 
(22,928
)
 
—

 
1,435,810

 
 
 
 
 
 
 
 
 
 
 
 

31
LINN ENERGY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued
(Unaudited)

 
Linn Energy, LLC
 
Guarantor Subsidiaries
 
Non-
Guarantor Subsidiary
 
Non-
Guarantor VIE
 
Eliminations
 
Consolidated
 
(in thousands)
Cash flow from investing activities:
 
 
 
 
 
 
 
 
 
 
 
Acquisition of oil and natural gas properties and joint-venture funding
—

 
(76,627
)
 
(3,912
)
 
(2,521,393
)
 
—

 
(2,601,932
)
Development of oil and natural gas properties
—

 
(750,450
)
 
(426,028
)
 
—

 
—

 
(1,176,478
)
Purchases of other property and equipment
—

 
(41,822
)
 
(8,316
)
 
—

 
—

 
(50,138
)
Investment in affiliates
(167,721
)
 
—

 
—

 
—

 
167,721

 
—

Change in notes receivable with affiliate
(35,300
)
 
—

 
—

 
—

 
35,300

 
—

Advance to related party
(1,285,000
)
 
(1,285,000
)
 
—

 
—

 
2,570,000

 
—

Proceeds from sale of properties and equipment and other
(13,188
)
 
5,447

 
256

 
—

 
—

 
(7,485
)
Net cash used in investing activities
(1,501,209
)
 
(2,148,452
)
 
(438,000
)
 
(2,521,393
)
 
2,773,021

 
(3,836,033
)
 
 
 
 
 
 
 
 
 
 
 
 
Cash flow from financing activities:
 
 
 
 
 
 
 
 
 
 
 
Proceeds from borrowings
4,000,024

 
—

 
—

 
1,300,000

 
—

 
5,300,024

Repayments of debt
(1,950,000
)
 
—

 
(206,124
)
 
—

 
—

 
(2,156,124
)
Distributions to unitholders
(721,235
)
 
—

 
—

 
—

 
—

 
(721,235
)
Financing fees and offering costs
(57,968
)
 
—

 
(10,646
)
 
—

 
—

 
(68,614
)
Change in notes payable with affiliate
—

 
35,300

 
—

 
—

 
(35,300
)
 
—

Advance from related party
—

 
1,285,000

 
—

 
1,285,000

 
(2,570,000
)
 
—

Capital contributions – affiliates
—

 
—

 
167,721

 
—

 
(167,721
)
 
—

Excess tax benefit from unit-based compensation
4,031

 
—

 
—

 
—

 
—

 
4,031

Other
11,705

 
38,032

 
(606
)
 
—

 
—

 
49,131

Net cash provided by (used in) financing activities
1,286,557

 
1,358,332

 
(49,655
)
 
2,585,000

 
(2,773,021
)
 
2,407,213

 
 
 
 
 
 
 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents
(4
)
 
10,780

 
(44,465
)
 
40,679

 
—

 
6,990

Cash and cash equivalents:
 
 
 
 
 
 
 
 
 
 
 
Beginning
52

 
1,078

 
51,041

 
—

 
—

 
52,171

Ending
$
48

 
$
11,858

 
$
6,576

 
$
40,679

 
$
—

 
$
59,161


32

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 September 30, 2015, included the following:
•
oil, natural gas and NGL sales of approximately $427 million compared to $937 million for the third quarter of 2014;
•
average daily production of approximately 1,198 MMcfe/d compared to 1,245 MMcfe/d for the third quarter of 2014;
•
net loss of approximately $1.6 billion compared to $4 million for the third quarter of 2014;
•
capital expenditures, excluding acquisitions, of approximately $113 million compared to $369 million for the third quarter of 2014; and
•
41 wells drilled (38 successful) compared to 210 wells drilled (all successful) for the third quarter of 2014.
Results for the nine months ended September 30, 2015, included the following:
•
oil, natural gas and NGL sales of approximately $1.4 billion compared to $2.8 billion for the nine months ended September 30, 2014;
•
average daily production of approximately 1,206 MMcfe/d compared to 1,160 MMcfe/d for the nine months ended September 30, 2014;
•
net loss of approximately $2.3 billion compared to $297 million for the nine months ended September 30, 2014;
•
net cash provided by operating activities of approximately $1.0 billion compared to $1.4 billion for the nine months ended September 30, 2014;
•
capital expenditures, excluding acquisitions, of approximately $424 million compared to $1.2 billion for the nine months ended September 30, 2014; and

33
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

•
311 wells drilled (308 successful) compared to 678 wells drilled (677 successful) for the nine months ended September 30, 2014.
Reduction and Suspension of Distribution
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. Monthly distributions were paid by the Company through September 2015. In October 2015, following the recommendation from management, the Company’s Board of Directors determined to suspend payment of the Company’s distribution and reserve any excess cash. The Company’s Board of Directors and management believe this suspension to be in the best long-term interest of all Company stakeholders. The Company’s Board of Directors will continue to evaluate the Company’s ability to reinstate the distribution. For additional information, see “Distribution Practices” below.
Reduction of 2015 Oil and Natural Gas Capital Budget
The Company’s 2015 budget includes a 65% reduction in total capital expenditures to approximately $550 million, from approximately $1.6 billion spent in 2014, and includes approximately $470 million related to its oil and natural gas capital program. The 2015 budget contemplates significantly lower commodity prices as compared to 2014, and the reduction of the capital budget was intended to solidify the Company’s financial position.
Alliance with GSO Capital Partners
The Company signed definitive agreements dated June 30, 2015, with affiliates of private capital investor GSO Capital Partners LP (“GSO”), the credit platform of The Blackstone Group L.P., to fund oil and natural gas development (“DrillCo”). 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 adjustments depending on asset characteristics and return expectations of the selected drilling plan, 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%.
Alliance with Quantum Energy Partners
The Company signed definitive agreements dated June 30, 2015, with affiliates of private capital investor Quantum Energy Partners (“Quantum”) to fund selected future oil and natural gas acquisitions and the development of those acquired assets (“AcqCo”). See the Company’s Current Report on Form 8-K filed on July 7, 2015, for additional details regarding these agreements.
Divestiture – 2015
On August 31, 2015, the Company, through certain of its wholly owned subsidiaries, completed the sale of its remaining position in Howard County in the Permian Basin (the “Howard County Assets Sale”). Cash proceeds received from the sale of these properties were approximately $276 million. The Company used the net proceeds from the sale to repay a portion of the outstanding indebtedness under the LINN Credit Facility, which included debt initially incurred to fund the repurchase of a portion of its senior notes during 2015 (see Note 6).
Financing Activities
In October 2015, LINN Energy and Berry Petroleum Company, LLC (“Berry”) each entered into an amendment to its credit facility. See Note 6 for additional details.
The spring 2015 semi-annual borrowing base redetermination of the Company’s Credit Facilities, as defined in Note 6, was completed in May 2015, and, as a result of lower commodity prices, the borrowing base under the LINN Credit Facility decreased from $4.5 billion to $4.05 billion and the borrowing base under the Berry Credit Facility decreased from $1.4 billion to $1.2 billion. The fall 2015 semi-annual redetermination was completed in October 2015 and the borrowing base under the LINN Credit Facility was reaffirmed at $4.05 billion; however, the borrowing base will automatically decrease to $3.6 billion

34
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

on January 1, 2016, subject to any additional reductions for additional junior lien debt issued since this redetermination, if the following conditions are not met on or before December 31, 2015: (i) the issuance by the Company of at least $250 million of additional junior lien debt; (ii) repayment and extinguishment of the Berry Credit Facility; and (iii) the guarantee by Berry of the LINN Credit Facility or the merger or consolidation of Berry with a guarantor under the LINN Credit Facility. Notwithstanding this, borrowing availability under the LINN Credit Facility will be limited to $3.6 billion (which amount includes the outstanding $500 million term loan) until the earlier of a) January 1, 2016 or b) the date of the actions described in the prior sentence. The borrowing base under the Berry Credit Facility decreased from $1.2 billion to $900 million.
Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs, along with the maturity schedule of the Company’s hedges, may impact future redeterminations.
In connection with the reduction in Berry’s borrowing base in October 2015, Berry repaid $300 million of borrowings outstanding under the Berry Credit Facility. In connection with the reduction in Berry’s borrowing base in May 2015, LINN Energy borrowed $250 million under the LINN Credit Facility, which it contributed to Berry to post as restricted cash with Berry’s lenders. As directed by LINN Energy, the $250 million was deposited on Berry’s behalf in a security account with the administrative agent subject to a security control agreement. Berry’s ability to withdraw funds from this account is subject to a concurrent reduction of the borrowing base under the Berry Credit Facility or lender’s consent in connection with a redetermination of such borrowing base. The $250 million may be used to satisfy obligations under the Berry Credit Facility or, subject to restrictions in the indentures governing Berry’s senior notes, may be returned to LINN Energy in the future.
During the nine months ended September 30, 2015, the Company, under its equity distribution agreement, sold 3,621,983 units representing limited liability company interests at an average unit price of $12.37 for net proceeds of approximately $44 million (net of approximately $448,000 in commissions). The Company used the net proceeds for general corporate purposes, including the open market repurchases of a portion of its senior notes (see Note 6). At September 30, 2015, units totaling approximately $455 million in aggregate offering price remained available to be sold under the agreement.
In May 2015, the Company sold 16,000,000 units representing limited liability company interests in an underwritten public offering at $11.79 per unit ($11.32 per unit, net of underwriting discount) for net proceeds of approximately $181 million (after underwriting discount and offering costs of approximately $8 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under the LINN Credit Facility, which included debt initially incurred to fund the open market repurchases of a portion of its senior notes during 2015 (see Note 6).
During the nine months ended September 30, 2015, the Company repurchased, through privately negotiated transactions and on the open market, approximately $783 million of its outstanding senior notes. See Note 6 for additional details.
Commodity Derivatives
During the nine months ended September 30, 2015, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for May 2015 through December 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.

35
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Results of Operations
Three Months Ended September 30, 2015, Compared to Three Months Ended September 30, 2014
 
Three Months Ended
September 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
Revenues and other:
 
 
 
 
 
Natural gas sales
$
156,641

 
$
221,374

 
$
(64,733
)
Oil sales
241,467

 
614,407

 
(372,940
)
NGL sales
29,137

 
101,677

 
(72,540
)
Total oil, natural gas and NGL sales
427,245

 
937,458

 
(510,213
)
Gains on oil and natural gas derivatives
549,029

 
451,702

 
97,327

Marketing and other revenues
22,030

 
45,955

 
(23,925
)
 
998,304

 
1,435,115

 
(436,811
)
Expenses:
 
 
 
 
 
Lease operating expenses
154,086

 
191,630

 
(37,544
)
Transportation expenses
54,915

 
53,412

 
1,503

Marketing expenses
9,359

 
31,574

 
(22,215
)
General and administrative expenses (1)
60,113

 
75,384

 
(15,271
)
Exploration costs
3,072

 
7,850

 
(4,778
)
Depreciation, depletion and amortization
207,218

 
290,287

 
(83,069
)
Impairment of long-lived assets
2,255,080

 
603,250

 
1,651,830

Taxes, other than income taxes
46,238

 
66,770

 
(20,532
)
Gains on sale of assets and other, net
(166,980
)
 
(35,803
)
 
(131,177
)
 
2,623,101

 
1,284,354

 
1,338,747

Other income and (expenses)
57,657

 
(155,894
)
 
213,551

Loss before income taxes
(1,567,140
)
 
(5,133
)
 
(1,562,007
)
Income tax expense (benefit)
2,177

 
(1,033
)
 
3,210

Net loss
$
(1,569,317
)
 
$
(4,100
)
 
$
(1,565,217
)
(1) 
General and administrative expenses for the three months ended September 30, 2015, and September 30, 2014, include approximately $13 million and $9 million, respectively, of noncash unit-based compensation expenses.

36
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

 
Three Months Ended
September 30,
 
 
 
2015
 
2014
 
Variance
Average daily production:
 
 
 
 
 
Natural gas (MMcf/d)
644

 
600

 
7
 %
Oil (MBbls/d)
63.1

 
74.0

 
(15
)%
NGL (MBbls/d)
29.2

 
33.5

 
(13
)%
Total (MMcfe/d)
1,198

 
1,245

 
(4
)%
 
 
 
 
 
 
Weighted average prices: (1)
 
 
 
 
 
Natural gas (Mcf)
$
2.64

 
$
4.01

 
(34
)%
Oil (Bbl)
$
41.58

 
$
90.31

 
(54
)%
NGL (Bbl)
$
10.84

 
$
33.01

 
(67
)%
 
 
 
 
 
 
Average NYMEX prices:
 
 
 
 
 
Natural gas (MMBtu)
$
2.77

 
$
4.06

 
(32
)%
Oil (Bbl)
$
46.43

 
$
97.17

 
(52
)%
 
 
 
 
 
 
Costs per Mcfe of production:
 
 
 
 
 
Lease operating expenses
$
1.40

 
$
1.67

 
(16
)%
Transportation expenses
$
0.50

 
$
0.47

 
6
 %
General and administrative expenses (2)
$
0.55

 
$
0.66

 
(17
)%
Depreciation, depletion and amortization
$
1.88

 
$
2.54

 
(26
)%
Taxes, other than income taxes
$
0.42

 
$
0.58

 
(28
)%
(1) 
Does not include the effect of gains (losses) on derivatives.
(2) 
General and administrative expenses for the three months ended September 30, 2015, and September 30, 2014, include approximately $13 million and $9 million, respectively, of noncash unit-based compensation expenses.


37
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 $510 million or 54% to approximately $427 million for the three months ended September 30, 2015, from approximately $937 million for the three months ended September 30, 2014, due to lower oil, natural gas and NGL prices and lower production volumes. Lower oil, natural gas and NGL prices resulted in a decrease in revenues of approximately $283 million, $81 million and $59 million, respectively.
Average daily production volumes decreased to approximately 1,198 MMcfe/d for the three months ended September 30, 2015, from 1,245 MMcfe/d for the three months ended September 30, 2014. Lower oil and NGL production volumes resulted in a decrease in revenues of approximately $90 million and $13 million, respectively. Higher natural gas production volumes resulted in an increase in revenues of approximately $16 million.
The following table sets forth average daily production by region:
 
Three Months Ended
September 30,
 
 
 
 
 
2015
 
2014
 
Variance
Average daily production (MMcfe/d):
 
 
 
 
 
 
 
Rockies
429

 
333

 
96

 
29
 %
Hugoton Basin
254

 
201

 
53

 
27
 %
California
183

 
172

 
11

 
6
 %
Mid-Continent
105

 
289

 
(184
)
 
(64
)%
Permian Basin
77

 
154

 
(77
)
 
(50
)%
TexLa
87

 
51

 
36

 
71
 %
South Texas
32

 
12

 
20

 
158
 %
Michigan/Illinois
31

 
33

 
(2
)
 
(8
)%
 
1,198

 
1,245

 
(47
)
 
(4
)%
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. (“Exxon XTO”), on August 15, 2014, and the acquisition of properties from Pioneer Natural Resources Company (the “Pioneer Assets Acquisition”) on September 11, 2014. 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 (“ExxonMobil”) 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 Exxon XTO and ExxonMobil, the properties sold to Fleur de Lis Energy, LLC (the “Permian Basin Assets Sale”) on November 14, 2014, and the Howard County Assets Sale on August 31, 2015. 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.
Gains (Losses) on Oil and Natural Gas Derivatives
Gains on oil and natural gas derivatives were approximately $549 million and $452 million for the three months ended September 30, 2015, and September 30, 2014, respectively, representing an increase of approximately $97 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

38
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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 September 30, 2015, the Company had commodity derivative contracts for approximately 81% of its natural gas production and 87% of its oil production. During the three months ended September 30, 2014, the Company had commodity derivative contracts for approximately 81% of its natural gas production and 93% 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 decreased by approximately $24 million or 52% to approximately $22 million for the three months ended September 30, 2015, from approximately $46 million for the three months ended September 30, 2014. The decrease was primarily due to lower revenues generated by the Jayhawk natural gas processing plant in Kansas, lower electricity sales revenues generated by the Company’s California cogeneration facilities and the impact of properties sold during the fourth quarter of 2014, partially offset by higher helium sales revenue in the Hugoton Basin.
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 $38 million or 20% to approximately $154 million for the three months ended September 30, 2015, from approximately $192 million for the three months ended September 30, 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 lower prices for 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 $1.40 per Mcfe for the three months ended September 30, 2015, from $1.67 per Mcfe for the three months ended September 30, 2014.
Transportation Expenses
Transportation expenses increased by approximately $2 million or 3% to approximately $55 million for the three months ended September 30, 2015, from approximately $53 million for the three months ended September 30, 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 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 September 30, 2015, from $0.47 per Mcfe for the three months ended September 30, 2014.
Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses decreased by approximately $23 million or 70% to approximately $9 million for the three months ended September 30, 2015, from approximately $32 million for the three months ended September 30, 2014. The decrease was primarily due to lower expenses associated with the Jayhawk natural gas processing plant in Kansas and 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 decreased by approximately $15 million or 20% to approximately $60 million for the three months ended September 30, 2015, from approximately $75 million for the three months ended September 30, 2014. The decrease was primarily due to lower acquisition expenses and salaries and benefits related expenses. General and administrative expenses per Mcfe also decreased

39
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

to $0.55 per Mcfe for the three months ended September 30, 2015, from $0.66 per Mcfe for the three months ended September 30, 2014.
Exploration Costs
Exploration costs decreased by approximately $5 million or 61% to approximately $3 for the three months ended September 30, 2015, from approximately $8 million for the three months ended September 30, 2014. The decrease was primarily due to lower leasehold impairment expenses on unproved properties partially offset by higher seismic data expenses.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $83 million or 29% to approximately $207 million for the three months ended September 30, 2015, from approximately $290 million for the three months ended September 30, 2014. The decrease was primarily due to the divestitures of properties in 2014 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 and the first quarter of 2015, and lower total production volumes. Depreciation, depletion and amortization per Mcfe also decreased to $1.88 per Mcfe for the three months ended September 30, 2015, from $2.54 per Mcfe for the three months ended September 30, 2014.
Impairment of Long-Lived Assets
The Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties:
 
Three Months Ended
September 30,
 
2015
 
2014
 
(in thousands)
 
 
 
 
Rockies region
$
1,182,337

 
$
—

California region
330,311

 
—

TexLa region
375,567

 
—

Mid-Continent region
366,865

 
—

Permian Basin region
—

 
603,250

 
$
2,255,080

 
$
603,250

The impairment charges in 2015 were due to a decline in commodity prices and the Company’s estimates of proved reserves, and the impairment in 2014 was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for proved oil and natural gas properties.
Gains on Sale of Assets and Other, Net
During the three months ended September 30, 2015, the Company recorded a net gain of approximately $174 million, including costs to sell of approximately $1 million, on the Howard County Assets Sale. During the three months ended September 30, 2014, the Company recorded a net gain of approximately $45 million, including costs to sell of approximately $3 million, on the noncash exchange of a portion of its Permian Basin properties to Exxon XTO for properties in the Hugoton Basin. See Note 2 for additional details of the divestiture and exchange of properties.

40
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Taxes, Other Than Income Taxes
 
Three Months Ended
September 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
 
 
 
 
 
 
Severance taxes
$
14,621

 
$
37,986

 
$
(23,365
)
Ad valorem taxes
26,027

 
24,513

 
1,514

California carbon allowances
5,548

 
4,202

 
1,346

Other
42

 
69

 
(27
)
 
$
46,238

 
$
66,770

 
$
(20,532
)
Taxes, other than income taxes decreased by approximately $21 million or 31% for the three months ended September 30, 2015, compared to the three months ended September 30, 2014. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower oil, natural gas and NGL prices and lower production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, 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 and higher costs for acquired allowances.
Other Income and (Expenses)
 
Three Months Ended
September 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
 
 
 
 
 
 
Interest expense, net of amounts capitalized
$
(138,383
)
 
$
(154,047
)
 
$
15,664

Gain on extinguishment of debt
197,741

 
—

 
197,741

Other, net
(1,701
)
 
(1,847
)
 
146

 
$
57,657

 
$
(155,894
)
 
$
213,551

Other income and (expenses) decreased by approximately $214 million for the three months ended September 30, 2015, compared to the three months ended September 30, 2014. Interest expense decreased primarily due to lower outstanding debt during the period and lower amortization of financing fees and expenses primarily related to the bridge loan and term loan that were repaid during 2014, partially offset by a decrease in capitalized interest. In addition, for the three months ended September 30, 2015, the Company recorded a gain on extinguishment of debt of approximately $198 million as a result of the repurchases of a portion of its senior notes. See “Debt” under “Liquidity and Capital Resources” below for additional details.
Income Tax Expense (Benefit)
The Company is a limited liability company treated as a 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 income tax expense of approximately $2 million for the three months ended September 30, 2015, compared to an income tax benefit of approximately $1 million for the three months ended September 30, 2014. The income tax expense is primarily due to higher income from the Company’s taxable subsidiaries during the three months ended September 30, 2015, compared to the same period in 2014.

41
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Net Income (Loss)
Net loss increased to approximately $1.6 billion for the three months ended September 30, 2015, from approximately $4 million for the three months ended September 30, 2014. The increase was primarily due to higher impairment charges and lower production revenues, partially offset by lower other expenses and higher gains on oil and natural gas derivatives. See discussions above for explanations of variances.

42
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Results of Operations
Nine Months Ended September 30, 2015, Compared to Nine Months Ended September 30, 2014
 
Nine Months Ended
September 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
Revenues and other:
 
 
 
 
 
Natural gas sales
$
478,645

 
$
653,113

 
$
(174,468
)
Oil sales
787,158

 
1,861,561

 
(1,074,403
)
NGL sales
108,430

 
329,511

 
(221,081
)
Total oil, natural gas and NGL sales
1,374,233

 
2,844,185

 
(1,469,952
)
Gains (losses) on oil and natural gas derivatives
782,622

 
(198,579
)
 
981,201

Marketing and other revenues
79,824

 
120,047

 
(40,223
)
 
2,236,679

 
2,765,653

 
(528,974
)
Expenses:
 
 
 
 
 
Lease operating expenses
467,759

 
570,564

 
(102,805
)
Transportation expenses
164,250

 
143,896

 
20,354

Marketing expenses
47,359

 
75,920

 
(28,561
)
General and administrative expenses (1)
237,731

 
221,518

 
16,213

Exploration costs
4,032

 
10,492

 
(6,460
)
Depreciation, depletion and amortization
637,964

 
832,523

 
(194,559
)
Impairment of long-lived assets
2,787,697

 
603,250

 
2,184,447

Taxes, other than income taxes
158,317

 
201,014

 
(42,697
)
Gains on sale of assets and other, net
(197,263
)
 
(27,750
)
 
(169,513
)
 
4,307,846

 
2,631,427

 
1,676,419

Other income and (expenses)
(224,117
)
 
(428,859
)
 
204,742

Loss before income taxes
(2,295,284
)
 
(294,633
)
 
(2,000,651
)
Income tax expense (benefit)
(7,680
)
 
2,674

 
(10,354
)
Net loss
$
(2,287,604
)
 
$
(297,307
)
 
$
(1,990,297
)
(1) 
General and administrative expenses for the nine months ended September 30, 2015, and September 30, 2014, include approximately $41 million and $37 million, respectively, of noncash unit-based compensation expenses.

43
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

 
Nine Months Ended
September 30,
 
 
 
2015
 
2014
 
Variance
Average daily production:
 
 
 
 
 
Natural gas (MMcf/d)
654

 
525

 
25
 %
Oil (MBbls/d)
63.6

 
73.2

 
(13
)%
NGL (MBbls/d)
28.5

 
32.6

 
(13
)%
Total (MMcfe/d)
1,206

 
1,160

 
4
 %
 
 
 
 
 
 
Weighted average prices: (1)
 
 
 
 
 
Natural gas (Mcf)
$
2.68

 
$
4.56

 
(41
)%
Oil (Bbl)
$
45.36

 
$
93.10

 
(51
)%
NGL (Bbl)
$
13.94

 
$
37.01

 
(62
)%
 
 
 
 
 
 
Average NYMEX prices:
 
 
 
 
 
Natural gas (MMBtu)
$
2.80

 
$
4.55

 
(38
)%
Oil (Bbl)
$
51.00

 
$
99.61

 
(49
)%
 
 
 
 
 
 
Costs per Mcfe of production:
 
 
 
 
 
Lease operating expenses
$
1.42

 
$
1.80

 
(21
)%
Transportation expenses
$
0.50

 
$
0.45

 
11
 %
General and administrative expenses (2)
$
0.72

 
$
0.70

 
3
 %
Depreciation, depletion and amortization
$
1.94

 
$
2.63

 
(26
)%
Taxes, other than income taxes
$
0.48

 
$
0.63

 
(24
)%
(1) 
Does not include the effect of gains (losses) on derivatives.
(2) 
General and administrative expenses for the nine months ended September 30, 2015, and September 30, 2014, include approximately $41 million and $37 million, respectively, of noncash unit-based compensation expenses.

44
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 $1.4 billion or 52% to approximately $1.4 billion for the nine months ended September 30, 2015, from approximately $2.8 billion for the nine months ended September 30, 2014, due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Lower oil, natural gas and NGL prices resulted in a decrease in revenues of approximately $829 million, $334 million and $179 million, respectively.
Average daily production volumes increased to approximately 1,206 MMcfe/d for the nine months ended September 30, 2015, from 1,160 MMcfe/d for the nine months ended September 30, 2014. Lower oil and NGL production volumes resulted in a decrease in revenues of approximately $246 million and $42 million, respectively. Higher natural gas production volumes resulted in an increase in revenues of approximately $160 million.
The following table sets forth average daily production by region:
 
Nine Months Ended
September 30,
 
 
 
 
 
2015
 
2014
 
Variance
Average daily production (MMcfe/d):
 
 
 
 
 
 
 
Rockies
433

 
295

 
138

 
47
 %
Hugoton Basin
252

 
165

 
87

 
52
 %
California
187

 
167

 
20

 
12
 %
Mid-Continent
102

 
295

 
(193
)
 
(65
)%
Permian Basin
85

 
163

 
(78
)
 
(48
)%
TexLa
82

 
38

 
44

 
115
 %
South Texas
34

 
4

 
30

 
724
 %
Michigan/Illinois
31

 
33

 
(2
)
 
(6
)%
 
1,206

 
1,160

 
46

 
4
 %
The increase in average daily production volumes in the Rockies region primarily reflects the impact of 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 XTO on August 15, 2014, and the Pioneer Assets Acquisition on September 11, 2014. The increase in average daily production volumes in the California region primarily reflects the impact of the properties received in the exchange with ExxonMobil 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 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 Exxon XTO and ExxonMobil, the properties sold in the Permian Basin Assets Sale on November 14, 2014, and the Howard County Assets Sale on August 31, 2015. 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.
Gains (Losses) on Oil and Natural Gas Derivatives
Gains on oil and natural gas derivatives were approximately $783 million for the nine months ended September 30, 2015, compared to losses of approximately $199 million for the nine months ended September 30, 2014, representing a variance of approximately $982 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.

45
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

During the nine months ended September 30, 2015, the Company had commodity derivative contracts for approximately 80% of both its natural gas and oil production. During the nine months ended September 30, 2014, the Company had commodity derivative contracts for approximately 92% of its natural gas production and 93% 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 decreased by approximately $40 million or 34% to approximately $80 million for the nine months ended September 30, 2015, from approximately $120 million for the nine months ended September 30, 2014. The decrease was primarily due to lower revenues generated by the Jayhawk natural gas processing plant in Kansas, lower electricity sales revenues generated by the Company’s California cogeneration facilities and the impact of properties sold during the fourth quarter of 2014, partially offset by higher helium sales revenue in the Hugoton Basin.
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 $103 million or 18% to approximately $468 million for the nine months ended September 30, 2015, from approximately $571 million for the nine months ended September 30, 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 lower prices for 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 $1.42 per Mcfe for the nine months ended September 30, 2015, from $1.80 per Mcfe for the nine months ended September 30, 2014.
Transportation Expenses
Transportation expenses increased by approximately $20 million or 14% to approximately $164 million for the nine months ended September 30, 2015, from approximately $144 million for the nine months ended September 30, 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 result of the properties sold during the fourth quarter of 2014. Transportation expenses per Mcfe also increased to $0.50 per Mcfe for the nine months ended September 30, 2015, from $0.45 per Mcfe for the nine months ended September 30, 2014.
Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses decreased by approximately $29 million or 38% to approximately $47 million for the nine months ended September 30, 2015, from approximately $76 million for the nine months ended September 30, 2014. The decrease was primarily due to lower expenses associated with the Jayhawk natural gas processing plant in Kansas and 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 increased by approximately $16 million or 7% to approximately $238 million for the nine months ended September 30, 2015, from approximately $222 million for the nine months ended September 30, 2014. The increase was primarily due to higher advisory fees related to the alliance agreements and higher salaries and benefits related expenses, principally driven by severance costs, partially offset by lower acquisition expenses. General and administrative expenses per Mcfe also increased to $0.72 per Mcfe for the nine months ended September 30, 2015, from $0.70 per Mcfe for the nine months ended September 30, 2014.

46
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Exploration Costs
Exploration costs decreased by approximately $6 million or 62% to approximately $4 million for the nine months ended September 30, 2015, from approximately $10 million for the nine months ended September 30, 2014. The decrease was primarily due to lower leasehold impairment expenses on unproved properties partially offset by higher seismic data expenses.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $195 million or 23% to approximately $638 million for the nine months ended September 30, 2015, from approximately $833 million for the nine months ended September 30, 2014. The decrease was primarily due to the divestitures of properties in 2014 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 and the first quarter of 2015, partially offset by higher total production volumes. Depreciation, depletion and amortization per Mcfe also decreased to $1.94 per Mcfe for the nine months ended September 30, 2015, from $2.63 per Mcfe for the nine months ended September 30, 2014.
Impairment of Long-Lived Assets
The Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties:
 
Nine Months Ended
September 30,
 
2015
 
2014
 
(in thousands)
 
 
 
 
Rockies region
$
1,182,337

 
$
—

California region
537,511

 
—

TexLa region
408,667

 
—

Mid-Continent region
372,568

 
—

Shallow Texas Panhandle Brown Dolomite formation
277,914

 
—

South Texas region
8,700

 
—

Permian Basin region
—

 
603,250

 
$
2,787,697

 
$
603,250

The impairment charges in 2015 were due to a decline in commodity prices and the Company’s estimates of proved reserves, and the impairment in 2014 was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for proved oil and natural gas properties.
Gains on Sale of Assets and Other, Net
During the nine months ended September 30, 2015, the Company recorded a net gain of approximately $174 million, including costs to sell of approximately $1 million, on the Howard County Assets Sale. During the nine months ended September 30, 2014, the Company recorded a net gain of approximately $45 million, including costs to sell of approximately $3 million, on the noncash exchange of a portion of its Permian Basin properties to Exxon XTO for properties in the Hugoton Basin. See Note 2 for additional details of the divestiture and exchange of properties.

47
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Taxes, Other Than Income Taxes
 
Nine Months Ended
September 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
 
 
 
 
 
 
Severance taxes
$
49,187

 
$
105,867

 
$
(56,680
)
Ad valorem taxes
91,923

 
81,635

 
10,288

California carbon allowances
17,247

 
13,328

 
3,919

Other
(40
)
 
184

 
(224
)
 
$
158,317

 
$
201,014

 
$
(42,697
)
Taxes, other than income taxes decreased by approximately $43 million or 21% for the nine months ended September 30, 2015, compared to the nine months ended September 30, 2014. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower oil, natural gas and NGL prices 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 and higher costs for acquired allowances.
Other Income and (Expenses)
 
Nine Months Ended
September 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
 
 
 
 
 
 
Interest expense, net of amounts capitalized
$
(427,584
)
 
$
(422,160
)
 
$
(5,424
)
Gain on extinguishment of debt
213,527

 
—

 
213,527

Other, net
(10,060
)
 
(6,699
)
 
(3,361
)
 
$
(224,117
)
 
$
(428,859
)
 
$
204,742

Other income and (expenses) decreased by approximately $205 million for the nine months ended September 30, 2015, compared to the nine months ended September 30, 2014. Interest expense increased primarily due to higher outstanding debt during the period and a decrease in capitalized interest, partially offset by lower amortization of financing fees and expenses primarily related to the bridge loan and term loan that were repaid during 2014. In addition, for the nine months ended September 30, 2015, the Company recorded a gain on extinguishment of debt of approximately $214 million as a result of the repurchases of a portion of its senior notes. See “Debt” under “Liquidity and Capital Resources” below for additional details. Other expenses increased during 2015 primarily due to write-offs of deferred financing fees related to the Credit Facilities.
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 $8 million for the nine months ended September 30, 2015, compared to income tax expense of approximately $3 million for the nine months ended September 30, 2014. The income tax benefit was primarily due to lower income from the Company’s taxable subsidiaries during the nine months ended September 30, 2015, compared to the same period in 2014.
Net Income (Loss)
Net loss increased by approximately $2.0 billion or 669% to approximately $2.3 billion for the nine months ended September 30, 2015, from approximately $297 million for the nine months ended September 30, 2014. The increase was

48
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

primarily due to higher impairment charges and lower production revenues, partially offset by higher gains on oil and natural gas derivatives and lower expenses. 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 nine months ended September 30, 2015, the Company’s total capital expenditures, excluding acquisitions, were approximately $424 million.
See below for details regarding capital expenditures for the periods presented:
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
 
 
 
 
 
 
 
 
Oil and natural gas
$
91,439

 
$
351,493

 
$
373,842

 
$
1,138,006

Plant and pipeline
8,887

 
3,882

 
13,889

 
15,545

Other
12,526

 
13,451

 
36,701

 
31,228

Capital expenditures, excluding acquisitions
$
112,852

 
$
368,826

 
$
424,432

 
$
1,184,779

For 2015, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $550 million, including approximately $470 million related to its oil and natural gas capital program and approximately $25 million related to its plant and pipeline capital. This estimate reflects amounts for the development of properties associated with previous 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 operating activities. At September 30, 2015, there was approximately $1.2 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.
In October 2015, LINN Energy and Berry each entered into an amendment to its credit facility.  See Note 6 for additional details.
The spring 2015 semi-annual borrowing base redetermination of the Company’s Credit Facilities was completed in May 2015, and, as a result of lower commodity prices, the borrowing base under the LINN Credit Facility decreased from $4.5 billion to $4.05 billion and the borrowing base under the Berry Credit Facility decreased from $1.4 billion to $1.2 billion. The fall 2015 semi-annual redetermination was completed in October 2015 and the borrowing base under the LINN Credit Facility was reaffirmed at $4.05 billion; however, the borrowing base will automatically decrease to $3.6 billion on January 1, 2016, subject to any additional reductions for additional junior lien debt issued since this redetermination, if the following conditions are not met on or before December 31, 2015: (i) the issuance by the Company of at least $250 million of additional junior lien debt; (ii) repayment and extinguishment of the Berry Credit Facility; and (iii) the guarantee by Berry of the LINN Credit Facility or the merger or consolidation of Berry with a guarantor under the LINN Credit Facility. Notwithstanding this, borrowing availability under the LINN Credit Facility will be limited to $3.6 billion (which amount includes the outstanding $500 million term loan) until the earlier of a) January 1, 2016 or b) the date of the actions described in the prior sentence. The borrowing base under the Berry Credit Facility decreased from $1.2 billion to $900 million.
Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs, along with the maturity schedule of the Company’s hedges, may impact future redeterminations.
In connection with the reduction in Berry’s borrowing base in October 2015, Berry repaid $300 million of borrowings outstanding under the Berry Credit Facility. In connection with the reduction in Berry’s borrowing base in May 2015, LINN Energy borrowed $250 million under the LINN Credit Facility, which it contributed to Berry to post as restricted cash with Berry’s lenders. As directed by LINN Energy, the $250 million was deposited on Berry’s behalf in a security account with the administrative agent subject to a security control agreement. Berry’s ability to withdraw funds from this account is subject to a

49
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

concurrent reduction of the borrowing base under the Berry Credit Facility or lender’s consent in connection with a redetermination of such borrowing base. The $250 million may be used to satisfy obligations under the Berry Credit Facility or, subject to restrictions in the indentures governing Berry’s senior notes, may be returned to LINN Energy in the future.
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:
 
Nine Months Ended
September 30,
 
 
 
2015
 
2014
 
Variance
 
(in thousands)
Net cash:
 
 
 
 
 
Provided by operating activities
$
1,034,769

 
$
1,435,810

 
$
(401,041
)
Used in investing activities
(190,540
)
 
(3,836,033
)
 
3,645,493

Provided by (used in) financing activities
(501,232
)
 
2,407,213

 
(2,908,445
)
Net increase in cash and cash equivalents
$
342,997

 
$
6,990

 
$
336,007

Operating Activities
Cash provided by operating activities for the nine months ended September 30, 2015, was approximately $1.0 billion, compared to approximately $1.4 billion for the nine months ended September 30, 2014. The decrease was primarily due to lower production related revenues principally due to lower commodity prices partially offset by higher cash settlements on derivatives.
Investing Activities
The following provides a comparative summary of cash flow from investing activities:
 
Nine Months Ended
September 30,
 
2015
 
2014
 
(in thousands)
Cash flow from investing activities:
 
 
 
Acquisition of oil and natural gas properties and joint-venture funding
$
—

 
$
(2,601,932
)
Capital expenditures
(554,735
)
 
(1,226,616
)
Proceeds from sale of properties and equipment and other
364,195

 
(7,485
)
 
$
(190,540
)
 
$
(3,836,033
)
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. Proceeds from sale of properties and equipment and other for the nine months ended September 30, 2015, include approximately $276 million in net cash proceeds received from the Howard County Assets Sale in August 2015 (see Note 2).

50
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Financing Activities
Cash used in financing activities for the nine months ended September 30, 2015, was approximately $501 million, compared to cash provided by financing activities of approximately $2.4 billion for the nine months ended September 30, 2014. The decrease in financing cash flow needs was primarily attributable to decreased capital expenditures and acquisition activity during the nine months ended September 30, 2015, as compared to the nine months ended September 30, 2014. The following provides a comparative summary of proceeds from borrowings and repayments of debt:
 
Nine Months Ended
September 30,
 
2015
 
2014
 
(in thousands)
Proceeds from borrowings:
 
 
 
LINN Credit Facility
$
1,405,000

 
$
1,900,000

Senior notes
—

 
1,100,024

Bridge loan and term loan
—

 
2,300,000

 
$
1,405,000

 
$
5,300,024

Repayments of debt:
 
 
 
LINN Credit Facility
$
(1,145,000
)
 
$
(950,000
)
Senior notes
(556,909
)
 
(206,124
)
Bridge loan
—

 
(1,000,000
)
 
$
(1,701,909
)
 
$
(2,156,124
)
In addition, in May 2015, LINN Energy borrowed $250 million under the LINN Credit Facility, which it contributed to Berry to post as restricted cash with Berry’s lenders (see Note 6).
Debt
The following summarizes the Company’s outstanding debt:
 
September 30,
2015
 
December 31, 2014
 
(in thousands, except percentages)
 
 
 
 
LINN credit facility
$
2,305,000

 
$
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
1,159,215

 
1,200,000

6.25% senior notes due November 2019
1,483,928

 
1,800,000

8.625% senior notes due April 2020
1,123,483

 
1,300,000

6.75% Berry senior notes due November 2020
261,100

 
299,970

7.75% senior notes due February 2021
963,774

 
1,000,000

6.50% senior notes due September 2021
502,010

 
650,000

6.375% Berry senior notes due September 2022
572,700

 
599,163

Net unamortized discounts and premiums
(16,109
)
 
(21,499
)
Total debt, net
$
10,028,276

 
$
10,295,809

During the nine months ended September 30, 2015, the Company repurchased, through privately negotiated transactions and on the open market, approximately $783 million of its outstanding senior notes as follows:
•
6.50% senior notes due May 2019 – $41 million;
•
6.25% senior notes due November 2019 – $316 million;
•
8.625% senior notes due April 2020 – $177 million;

51
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

•
6.75% Berry senior notes due November 2020 – $39 million;
•
7.75% senior notes due February 2021 – $36 million;
•
6.50% senior notes due September 2021 – $148 million; and
•
6.375% Berry senior notes due September 2022 – $26 million.
At September 30, 2015, there was approximately $1.2 billion of available borrowing capacity under the LINN Credit Facility but less than $1 million available under the Berry Credit Facility. 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.
Financial Covenants
The Credit Facilities, as amended in October 2015, 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 currently, 2.0 to 1.0 from December 31, 2015 through December 31, 2016, 2.25 to 1.0 from March 31, 2017 through June 30, 2017 and returning to 2.5 to 1.0 thereafter, and 2) a ratio of 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
 
 
 
December 31, 2014
 
March 31, 2015
 
June 30,
2015
 
September 30,
2015
 
Twelve Months Ended September 30, 2015
LINN Credit Facility:
 
 
 
 
 
 
 
 
 
Interest Coverage Ratio
2.7

 
2.9

 
3.0

 
3.4

 
3.0

Current Ratio
2.6

 
3.0

 
2.9

 
2.8

 
2.8

Berry Credit Facility:
 
 
 
 
 
 
 
 
 
Interest Coverage Ratio
6.5

 
1.7

 
2.6

 
2.2

 
3.3

Current Ratio (1)
0.6

 
0.6

 
0.5

 
2.0

 
2.0

Current Ratio (consolidated) (1)
2.9

 
3.2

 
2.9

 
2.6

 
2.6

(1) 
The 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 September 30, 2015, and the Current Ratio as of September 30, 2015, to demonstrate its compliance for the quarter ended September 30, 2015, as well as the Interest Coverage Ratio for each of the preceding four quarters on an individual basis (rather than on a last twelve months basis) and the Current Ratio as of the end of each of the preceding four quarters to provide investors with trend information about the Company’s ongoing compliance with these financial covenants. If the Company fails to demonstrate compliance with either or both of the Interest Coverage Ratio or the Current Ratio as of the end of the quarter and such failure continues beyond applicable cure periods, an event of default would occur and the Company would be unable to make additional borrowings and outstanding indebtedness may be accelerated. The Company 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.

52
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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.
At-the-Market Offering Program
The Company’s Board of Directors has authorized the sale of 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 units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.
During the nine months ended September 30, 2015, the Company, under its equity distribution agreement, sold 3,621,983 units representing limited liability company interests at an average unit price of $12.37 for net proceeds of approximately $44 million (net of approximately $448,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional services expenses of approximately $459,000. The Company used the net proceeds for general corporate purposes, including the open market repurchases of a portion of its senior notes (see Note 6). At September 30, 2015, units totaling approximately $455 million in aggregate offering price remained available to be sold under the agreement.
Public Offering of Units
In May 2015, the Company sold 16,000,000 units representing limited liability company interests in an underwritten public offering at $11.79 per unit ($11.32 per unit, net of underwriting discount) for net proceeds of approximately $181 million (after underwriting discount and offering costs of approximately $8 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under the LINN Credit Facility, which included debt initially incurred to fund the open market repurchases of a portion of its senior notes during 2015 (see Note 6).

53
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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 nine months ended September 30, 2015:
Date Paid
 
Distributions
Per Unit
 
Total
Distributions
 
 
 
 
(in millions)
 
 
 
 
 
September 2015
 
$
0.1042

 
$
37

August 2015
 
$
0.1042

 
$
37

July 2015
 
$
0.1042

 
$
37

June 2015
 
$
0.1042

 
$
37

May 2015
 
$
0.1042

 
$
35

April 2015
 
$
0.1042

 
$
35

March 2015
 
$
0.1042

 
$
35

February 2015
 
$
0.1042

 
$
35

January 2015
 
$
0.1042

 
$
35

In October 2015, the Company’s Board of Directors determined to suspend payment of the Company’s distribution. For additional information, see “Distribution Practices” below.
Off-Balance Sheet Arrangements
The Company does not currently have any off-balance sheet arrangements.
Contingencies
See Part II. Item 1. “Legal Proceedings” for information regarding legal proceedings that the Company is party to and any contingencies related to these legal proceedings.
Commitments and Contractual Obligations
The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in the table of contractual obligations in the 2014 Annual Report on Form 10-K. With the exception of the repurchases of approximately $783 million of its outstanding senior notes, 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.
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.

54
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The Company’s Board of Directors reviews historical financial results and forecasts for future periods, including oil and natural gas development activities and the impact of significant acquisitions or dispositions, as well as considers the level of the Company’s indebtedness and its liquidity position 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, or the Company’s Board of Directors determines that it is necessary to reserve cash for the future conduct of business, it may determine to reduce, suspend or discontinue paying distributions. For example, in October 2015, following the recommendation from management, the Company’s Board of Directors determined to suspend payment of the Company’s distribution and reserve any excess cash that would otherwise be available for distribution. The Board of Directors will continue to evaluate the Company’s ability to reinstate the distribution using the considerations discussed above.
For 2015, the Company’s Board of Directors approved an oil and natural gas capital budget of approximately $470 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 paid through September 2015 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.

55
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
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
361,287

 
$
520,175

 
$
1,034,769

 
$
1,435,810

Distributions to unitholders
(111,247
)
 
(240,652
)
 
(323,878
)
 
(721,235
)
Excess of net cash provided by operating activities after distributions to unitholders
250,040

 
279,523

 
710,891

 
714,575

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

 
(213,252
)
 
NM*

 
(606,120
)
Development of oil and natural gas properties (2)
(91,439
)
 
NM*

 
(373,842
)
 
NM*

Cash recoveries of bankruptcy claim (3)
—

 
—

 
(2,877
)
 
(2,913
)
Cash received (paid) for acquisitions or divestitures – revenues less operating expenses (4)
—

 
79,555

 
(2,712
)
 
79,555

Provision for legal matters (5)
—

 
—

 
(1,000
)
 
1,598

Changes in operating assets and liabilities and other, net (6)
(47,265
)
 
(57,443
)
 
(184,937
)
 
(69,249
)
Excess 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 (7)
NM*

 
$
88,383

 
NM*

 
$
117,446

Excess 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 (7)
$
111,336

 
NM*

 
$
145,523

 
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, if and when resumed. 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.

56
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

(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; however, in October 2015, the Company’s Board of Directors approved the suspension of the Company’s distribution. 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.
(3) 
Represent the recoveries of a bankruptcy claim against Lehman Brothers which was not a transaction occurring in the ordinary course of the Company’s business.
(4) 
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. Beginning with the quarter ended June 30, 2015, the Board decided to no longer make this discretionary adjustment.
(5) 
Represents reserves and settlements related to legal matters.
(6) 
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.
(7) 
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. In a period where no distribution is paid, the Company will retain all excess of net operating cash flow for future operations, future capital expenditures, future debt service or other future obligations.
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 and determines to distribute such amounts to LINN Energy, 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 $563 million at September 30, 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 September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
361,287

 
$
520,175

 
$
1,034,769

 
$
1,435,810

Distributions to unitholders
(111,247
)
 
(240,652
)
 
(323,878
)
 
(721,235
)
Excess of net cash provided by operating activities after distributions to unitholders
250,040

 
279,523

 
710,891

 
714,575

Plus (less):
 
 
 
 
 
 
 
Net cash provided by (used in) financing activities (excluding distributions to unitholders)
(105,557
)
 
2,702,683

 
(177,354
)
 
3,128,448

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

 
(2,576,041
)
 
—

 
(2,601,932
)
Development of oil and natural gas properties
(86,859
)
 
(370,861
)
 
(503,206
)
 
(1,176,478
)
Purchases of other property and equipment
(22,242
)
 
(18,727
)
 
(51,529
)
 
(50,138
)
Proceeds from sale of properties and equipment and other
305,481

 
4,245

 
364,195

 
(7,485
)
Net increase in cash and cash equivalents
$
340,863

 
$
20,822

 
$
342,997

 
$
6,990


57
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Critical Accounting Policies and Estimates
The discussion and analysis of the Company’s financial condition and results of operations is based on the condensed 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.
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 resume payment of distributions in the future or maintain or grow them after such resumption;
•
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 and commencement of activities in the Company’s strategic alliances with GSO and Quantum, which may take longer than anticipated, may be more costly than anticipated as a result of unexpected factors or events and may have an unanticipated adverse effect on the Company’s business.
All of these types of statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, are forward-looking statements. These forward-looking statements may be found in Item 2. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.
The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on Company expectations, which reflect estimates and assumptions made by Company management. These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors. Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control. In addition, management’s assumptions may prove to be inaccurate. The Company cautions that the forward-looking statements contained in this Quarterly Report on Form 10-Q are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors set forth in Item 1A. “Risk Factors” in this Quarterly

58
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2014, and elsewhere in the Annual Report. The forward-looking statements speak only as of the date made and, other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures. All of the Company’s market risk sensitive instruments were entered into for purposes other than trading.
The following should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Company’s 2014 Annual Report on Form 10-K. The reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”
Commodity Price Risk
As an important part of its business strategy, the Company seeks to hedge 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 if and when resumed, 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. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials. By removing a portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices.
The appropriate level of production to be hedged is an ongoing consideration and is based on a variety of factors, including current and future expected commodity market prices, cost and availability of put option contracts, the level of acquisition activity and the Company’s overall risk profile, including leverage and size and scale considerations. In addition, when commodity prices are depressed and forward commodity price curves are flat or in backwardation, the Company may determine that the benefit of hedging its anticipated production at these levels is outweighed by its resultant inability to obtain higher revenues for its production if commodity prices recover during the duration of the contracts. As a result, the appropriate percentage of production volumes to be hedged may change over time.
The Company 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. 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. The Company does not enter into derivative contracts for trading purposes. 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 September 30, 2015, the fair value of fixed price swaps, put option contracts and three-way collars was a net asset of approximately $1.7 billion. A 10% increase in the index oil and natural gas prices above the September 30, 2015, prices would result in a net asset of approximately $1.5 billion, which represents a decrease in the fair value of approximately $250 million;

59
Item 3.    Quantitative and Qualitative Disclosures About Market Risk - Continued

conversely, a 10% decrease in the index oil and natural gas prices below the September 30, 2015, prices would result in a net asset of approximately $2.0 billion, which represents an increase in the fair value of approximately $249 million.
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 September 30, 2015, and December 31, 2014, and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.
The Company cannot be assured that its counterparties will be able to perform under its derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, the Company’s cash flows and ability to pay distributions could be impacted.
Interest Rate Risk
At September 30, 2015, the Company had long-term debt outstanding under its credit facilities and term loan of approximately $4.0 billion which incurred interest at floating rates (see Note 6). A 1% increase in the LIBOR would result in an estimated $40 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 September 30, 2015, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 2.11%. A 1% increase in the average public bond yield spread would result in an estimated $18,000 increase in net income for the nine months ended September 30, 2015. At September 30, 2015, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 3.03%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $17 million decrease in net income for the nine months ended September 30, 2015.
At December 31, 2014, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 1.85%. 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

60
Item 3.    Quantitative and Qualitative Disclosures About Market Risk - Continued

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.
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 September 30, 2015.
Changes in the Company’s Internal Control Over Financial Reporting
The Company’s management is also responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. The Company’s internal controls were designed to provide reasonable assurance as to the reliability of its financial reporting and the preparation and presentation of the condensed 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 third quarter of 2015 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

61

Part II – Other Information

Item 1.
Legal Proceedings
For certain statewide class action royalty payment disputes where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the courts, will result in no loss to the Company. 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, and in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2015. Except as set forth below, as of the date of this report, these risk factors have not changed materially. This information should be considered carefully, together with other information in this report and other reports and materials we file with the United States Securities and Exchange Commission.
Our Board of Directors has the ability to reserve any or all of our cash on hand at the end of a quarter for purposes other than distribution to unitholders, including reduction of indebtedness.
Although we may have generated sufficient net cash provided by operating activities during any particular quarter, our Board of Directors has the ability under our limited liability company agreement to establish a cash reserve, which could encompass all of the cash otherwise available for distribution, to provide for the proper conduct of our business in both the short and long term. To provide for the proper conduct of our business, the Board of Directors can determine to reserve cash to reduce indebtedness, among other things. For example, in October 2015, our Board of Directors approved a suspension of our distribution. Our decision to reserve all of our cash on hand for such allowed purposes and not distribute it may significantly impact our unitholders, as well as our business and operations. The market value of our units may remain depressed or further decrease unless and until we resume a distribution. In addition, further refinancing or restructuring of our debt may require us to accept covenants that further restrict our ability to reinstate distributions. External perceptions of the health of our business and our liquidity may also be impacted, which could further limit our ability to access capital markets, cause our vendors to tighten our credit terms and cause a strain in our relationship with landowners and other business partners.
If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.
We cannot assure you that our business will generate sufficient cash flow from operations to service our outstanding indebtedness, or that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other capital needs. If we do not generate sufficient cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:
•
refinancing or restructuring all or a portion of our debt;
•
obtaining alternative financing;
•
selling assets;
•
reducing or delaying capital investments;
•
seeking to raise additional capital; or
•
revising or delaying our strategic plans.
However, we cannot assure you that we would be able to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations and capital requirements or that these actions would be permitted under the terms of our various debt instruments.
Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our business, financial condition, results of operations, cash flows and prospects. Any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit

62
Item 1A.    Risk Factors - Continued

rating, which could harm our ability to incur additional indebtedness on acceptable terms. Further, if for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our Credit Facilities, as defined in Note 6, could terminate their commitments to loan money, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. In addition, the lenders under our Credit Facilities could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on our senior notes. If the amounts outstanding under our Credit Facilities or any of our other indebtedness were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.
We are currently dependent on our Credit Facilities for liquidity. Any further reduction of the borrowing bases under our Credit Facilities could reduce or eliminate our ability to borrow under the Credit Facilities and may require us to repay indebtedness under our Credit Facilities earlier than anticipated, which would adversely impact our liquidity.
Subject to amounts reserved in the discretion of our Board of Directors to provide for the proper conduct of our business, our limited liability company agreement provides that we make distributions to our unitholders of available cash. Therefore, we have not historically accumulated cash to preserve liquidity and have been dependent on the capital markets and our Credit Facilities for liquidity. Due to low commodity prices and other factors, the capital markets have been constrained. Although our Board of Directors approved a suspension of our distribution, if these constraints continue, we will continue to be primarily reliant on our Credit Facilities, and to the extent available, the excess of net cash provided by operating activities, for liquidity.
At September 30, 2015, there was approximately $1.2 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. Each of our Credit Facilities is subject to scheduled redeterminations, semi-annually in April and October, of its borrowing base, based primarily on reserve reports using lender commodity price expectations at such time. As a result of lower commodity prices, in May 2015, the borrowing base under the LINN Credit Facility decreased from $4.5 billion to $4.05 billion and the borrowing base under the Berry Credit Facility decreased from $1.4 billion to $1.2 billion. In October 2015, the borrowing base under the LINN Credit Facility was reaffirmed at $4.05 billion, subject to certain conditions related to the Berry Consolidation, as defined in Note 6, and the borrowing base under the Berry Credit Facility decreased from $1.2 billion to $900 million. Continued low commodity prices, reductions in our capital budget and the resulting reserve write-downs, along with the maturity schedule of our hedges, may impact future redeterminations.
To the extent our borrowing bases are reduced to or below the amount of borrowings outstanding, we would be unable to continue to borrow and any excess borrowings may become due within a short time span. We may not have the financial resources to make mandatory prepayments and our liquidity would be significantly impacted.
Unitholders are required to pay taxes on their share of our taxable income, including their share of ordinary income and capital gain upon dispositions of properties by us or cancellation of debt, even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, gain, loss and deduction, or specific items thereof, may be substantially different than the unitholder’s interest in our economic profits.
Our unitholders are required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
For example, our previously announced repurchases of approximately $783 million of our outstanding senior notes at prices lower than face amount have resulted, and any similar transactions in the future will result, in the cancellation of debt income that will be allocated to our unitholders. Some or all of our unitholders may be allocated substantial amounts of such taxable income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect to each unitholder would depend on the unitholder's individual tax position with respect to the units; however, taxable income allocations from us, including cancelation of debt income, increase a unitholder’s tax basis in their units.

63
Item 1A.    Risk Factors - Continued

In addition, we may sell a portion of our properties and use the proceeds to pay down debt or acquire other properties rather than distributing the proceeds to our unitholders, and some or all of our unitholders may be allocated substantial taxable income with respect to that sale. A unitholder’s share of our taxable income upon a disposition of property by us may be ordinary income or capital gain or some combination thereof. Even where we dispose of properties that are capital assets, what otherwise would be capital gains may be recharacterized as ordinary income in order to “recapture” ordinary deductions that were previously allocated to that unitholder related to the same property.
A unitholder’s share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially less than, the unitholder’s interest in our economic profits. This may occur, for example, in the case of a unitholder who purchases units at a time when the value of our units or of one or more of our properties is relatively low or a unitholder who acquires units directly from us in exchange for property whose fair market value exceeds its tax basis at the time of the exchange. Cash distributions from us decrease a unitholder’s tax basis in its units, and the amount, if any, of excess distributions over a unitholder’s tax basis in its units will, in effect, become taxable income to the unitholder, above and beyond the unitholder’s share of our taxable income and gain (or specific items thereof).
Restrictive covenants in the indentures governing our senior notes and in the LINN Credit Facility could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
The indentures governing our senior notes impose significant operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:
•
make distributions to our unitholders or make other restricted payments;
•
incur or guarantee additional indebtedness;
•
create or incur liens;
•
engage in mergers or consolidations or sell or otherwise dispose of all or substantially all of our assets;
•
make certain dispositions and transfers of assets;
•
engage in transactions with affiliates;
•
make investments; and
•
refinance certain indebtedness.
In addition, the LINN Credit Facility contains a number of significant covenants that, among other things, restrict our ability to:
•
dispose of assets;
•
incur or guarantee additional indebtedness;
•
make distributions to our unitholders;
•
create liens on our assets;
•
make investments or acquisitions;
•
repurchase, redeem or retire our capital stock or senior notes;
•
merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;
•
engage in specified transactions with subsidiaries and affiliates; and
•
pursue other corporate activities.
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under the indentures governing our senior notes and under the LINN Credit Facility. The restrictions contained in those indentures and the LINN Credit Facility could:
•
limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan; and
•
adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest.
Also, the LINN Credit Facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our

64
Item 1A.    Risk Factors - Continued

control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general or otherwise conduct necessary corporate activities. Further declines in oil, natural gas and NGL prices, or a prolonged period of oil, natural gas and NGL prices at current levels, could eventually result in our failing to meet one or more of the financial covenants under the indentures governing our senior notes or the LINN Credit Facility, which could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.
A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our senior notes or the LINN Credit Facility. A default under the LINN Credit Facility or the indentures governing our senior notes, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder. The accelerated debt would become immediately due and payable, which would in turn trigger cross-acceleration and cross-default rights under our other debt. If that should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. In addition, if an event of default under the LINN Credit Facility occurred, the lenders could foreclose on the collateral and compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on our senior notes. If the amounts outstanding under the LINN Credit Facility, the senior notes or any of our other indebtedness were to be accelerated, our assets may not be sufficient to repay in full the money owed to the lenders or to our other debt holders.
Moreover, any new indebtedness we incur may impose financial restrictions and other covenants on us that may be more restrictive than the LINN Credit Facility or the indentures governing our senior notes.
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
The Company’s Board of Directors has authorized the repurchase of 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 nine months ended September 30, 2015, and as of September 30, 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


65

Item 6.
Exhibits
Exhibit Number
 
Description
 
 
 
2.1
—
Purchase and Sale Agreement by and between Linn Energy Holdings, LLC and Linn Operating, Inc., as seller, and Rock Oil Holdings LLC, as buyer, executed on July 2, 2015 (incorporated herein by reference to Exhibit 2.1 to Quarterly Report on Form 10-Q filed on July 30, 2015)
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)
10.1*
—
Separation Agreement by and between Linn Operating, Inc. and Kolja Rockov, effective as of August 31, 2015
10.2
—
Seventh Amendment to Sixth Amended and Restated Credit Agreement, dated as of October 21, 2015, among Linn Energy, LLC, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and each of the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to Current Report on Form 8-K filed on October 22, 2015)
10.3
—
Eleventh Amendment and Borrowing Base Agreement, dated as of October 21, 2015, among Berry Petroleum Company, LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and each of the lenders party thereto (incorporated herein by reference to Exhibit 10.2 to Current Report on Form 8-K filed on October 22, 2015)
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 David B. Rottino, 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 David B. Rottino, 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.

66

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
LINN ENERGY, LLC
 
(Registrant)
 
 
Date: November 5, 2015
/s/ Darren R. Schluter
 
Darren R. Schluter
 
Vice President and Controller
 
(Duly Authorized Officer and Principal Accounting Officer)
 
 
 
 
Date: November 5, 2015
/s/ David B. Rottino
 
David B. Rottino
 
Executive Vice President and Chief Financial Officer
 
(Principal Financial Officer)


67

LinnCo, LLC Reports