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Linn Energy, LLC 10-Q 2012
LINE 6.30.2012 10Q

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q

x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2012

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
65-1177591
(State or other jurisdiction of incorporation or organization)
(IRS Employer
Identification No.)
600 Travis, Suite 5100
Houston, Texas
77002
(Address of principal executive offices)
(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 registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

As of June 30, 2012, there were 199,557,167 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 a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

MBbls/d. MBbls per day.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

MMBbls. One million barrels of oil or other liquid hydrocarbons.

MMBoe. One million barrels of oil equivalent, determined using a ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf.

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcf/d. MMcf per day.

MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

MMcfe/d. MMcfe per day.

MMMBtu. One billion British thermal units.


ii


PART I – FINANCIAL INFORMATION
Item 1.
Financial Statements
LINN ENERGY, LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
 
June 30,
2012
 
December 31,
2011
 
(Unaudited)
 
 
 
(in thousands,
except unit amounts)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
1,883

 
$
1,114

Accounts receivable – trade, net
321,012

 
284,565

Derivative instruments
489,530

 
255,063

Other current assets
69,884

 
80,734

Total current assets
882,309

 
621,476

 
 
 
 
Noncurrent assets:
 
 
 
Oil and natural gas properties (successful efforts method)
9,995,748

 
7,835,650

Less accumulated depletion and amortization
(1,426,132
)
 
(1,033,617
)
 
8,569,616

 
6,802,033

 
 
 
 
Other property and equipment
427,902

 
197,235

Less accumulated depreciation
(58,696
)
 
(48,024
)
 
369,206

 
149,211

 
 
 
 
Derivative instruments
924,317

 
321,840

Other noncurrent assets
434,654

 
105,577

 
1,358,971

 
427,417

Total noncurrent assets
10,297,793

 
7,378,661

Total assets
$
11,180,102

 
$
8,000,137

 
 
 
 
LIABILITIES AND UNITHOLDERS’ CAPITAL
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
667,541

 
$
403,450

Derivative instruments
3,461

 
14,060

Other accrued liabilities
108,841

 
75,898

Total current liabilities
779,843

 
493,408

 
 
 
 
Noncurrent liabilities:
 
 
 
Credit facility
1,150,000

 
940,000

Senior notes, net
4,855,547

 
3,053,657

Derivative instruments
250

 
3,503

Other noncurrent liabilities
262,799

 
80,659

Total noncurrent liabilities
6,268,596

 
4,077,819

 
 
 
 
Commitments and contingencies (Note 10)


 


 
 
 
 
Unitholders’ capital:
 
 
 
199,557,167 units and 177,364,558 units issued and outstanding at June 30, 2012, and December 31, 2011, respectively
3,223,223

 
2,751,354

Accumulated income
908,440

 
677,556

 
4,131,663

 
3,428,910

Total liabilities and unitholders’ capital
$
11,180,102

 
$
8,000,137


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
June 30,
 
Six Months Ended
June 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands, except per unit amounts)
Revenues and other:
 
 
 
 
 
 
 
Oil, natural gas and natural gas liquids sales
$
347,227

 
$
302,390

 
$
696,122

 
$
543,097

Gains (losses) on oil and natural gas derivatives
439,647

 
205,515

 
441,678

 
(163,961
)
Marketing revenues
10,841

 
1,509

 
12,131

 
2,682

Other revenues
2,882

 
1,157

 
4,756

 
2,280

 
800,597

 
510,571

 
1,154,687

 
384,098

Expenses:
 
 
 
 
 
 
 
Lease operating expenses
70,129

 
56,363

 
141,765

 
102,264

Transportation expenses
21,815

 
6,476

 
32,377

 
12,331

Marketing expenses
6,458

 
1,044

 
7,150

 
1,853

General and administrative expenses
41,185

 
31,543

 
84,506

 
62,103

Exploration costs
407

 
550

 
817

 
995

Bad debt expenses
(38
)
 
33

 
(22
)
 
(5
)
Depreciation, depletion and amortization
143,506

 
79,345

 
260,782

 
145,711

Impairment of long-lived assets
146,499

 

 
146,499

 

Taxes, other than income taxes
30,656

 
20,318

 
55,851

 
36,045

Losses on sale of assets and other, net
36

 
977

 
1,514

 
1,591

 
460,653

 
196,649

 
731,239

 
362,888

Other income and (expenses):
 
 
 
 
 
 
 
Loss on extinguishment of debt

 
(9,810
)
 

 
(94,372
)
Interest expense, net of amounts capitalized
(94,390
)
 
(62,361
)
 
(171,909
)
 
(125,825
)
Other, net
(7,956
)
 
(2,972
)
 
(11,225
)
 
(4,718
)
 
(102,346
)
 
(75,143
)
 
(183,134
)
 
(224,915
)
Income (loss) before income taxes
237,598

 
238,779

 
240,314

 
(203,705
)
Income tax expense
(512
)
 
(1,670
)
 
(9,430
)
 
(5,868
)
Net income (loss)
$
237,086

 
$
237,109

 
$
230,884

 
$
(209,573
)
 
 
 
 
 
 
 
 
Net income (loss) per unit:
 
 
 
 
 
 
 
Basic
$
1.19

 
$
1.34

 
$
1.17

 
$
(1.25
)
Diluted
$
1.19

 
$
1.33

 
$
1.16

 
$
(1.25
)
Weighted average units outstanding:
 
 
 
 
 
 
 
Basic
197,507

 
175,035

 
195,382

 
169,104

Diluted
198,160

 
175,797

 
196,039

 
169,104

 
 
 
 
 
 
 
 
Distributions declared per unit
$
0.725

 
$
0.66

 
$
1.415

 
$
1.32


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 Income
 
Total Unitholders’ Capital
 
(in thousands)
 
 
 
 
 
 
 
 
December 31, 2011
177,365

 
$
2,751,354

 
$
677,556

 
$
3,428,910

Sale of units, net of underwriting discounts and expenses of $30,007
21,090

 
731,455

 

 
731,455

Issuance of units
1,102

 
4,494

 

 
4,494

Distributions to unitholders
 
 
(282,166
)
 

 
(282,166
)
Unit-based compensation expenses
 
 
14,834

 

 
14,834

Excess tax benefit from unit-based compensation
 
 
3,252

 

 
3,252

Net income
 
 

 
230,884

 
230,884

June 30, 2012
199,557

 
$
3,223,223

 
$
908,440

 
$
4,131,663


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


3


LINN ENERGY, LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
June 30,
 
2012
 
2011
 
(in thousands)
Cash flow from operating activities:
 
 
 
Net income (loss)
$
230,884

 
$
(209,573
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
260,782

 
145,711

Impairment of long-lived assets
146,499

 

Unit-based compensation expenses
14,834

 
11,181

Loss on extinguishment of debt

 
94,372

Amortization and write-off of deferred financing fees and other
15,793

 
12,413

(Gains) losses on sale of assets and other, net
111

 
(161
)
Deferred income tax
5,991

 
2,790

Mark-to-market on derivatives:
 
 
 
Total (gains) losses
(441,678
)
 
163,961

Cash settlements
174,316

 
104,512

Premiums paid for derivatives
(583,434
)
 

Changes in assets and liabilities:
 
 
 
Increase in accounts receivable – trade, net
(14,372
)
 
(82,202
)
(Increase) decrease in other assets
(1,840
)
 
2,333

Increase in accounts payable and accrued expenses
39,346

 
74,348

Increase (decrease) in other liabilities
30,339

 
(15,923
)
Net cash provided by (used in) operating activities
(122,429
)
 
303,762

 
 
 
 
Cash flow from investing activities:
 
 
 
Acquisition of oil and natural gas properties
(1,762,933
)
 
(847,780
)
Development of oil and natural gas properties
(481,140
)
 
(225,889
)
Purchases of other property and equipment
(22,433
)
 
(18,657
)
Proceeds from sale of properties and equipment and other
575

 
10,590

Net cash used in investing activities
(2,265,931
)
 
(1,081,736
)
 
 
 
 
Cash flow from financing activities:
 
 
 
Proceeds from sale of units
761,362

 
648,971

Proceeds from borrowings
3,954,802

 
1,359,240

Repayments of debt
(1,945,000
)
 
(1,064,679
)
Distributions to unitholders
(282,166
)
 
(222,391
)
Financing fees, offering expenses and other, net
(103,121
)
 
(111,987
)
Excess tax benefit from unit-based compensation
3,252

 
2,587

Net cash provided by financing activities
2,389,129

 
611,741

 
 
 
 
Net increase (decrease) in cash and cash equivalents
769

 
(166,233
)
Cash and cash equivalents:
 
 
 
Beginning
1,114

 
236,001

Ending
$
1,883

 
$
69,768

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 the United States (“U.S.”), in the Mid-Continent, the Hugoton Basin, the Permian Basin, Michigan, Illinois, the Williston/Powder River Basin, California and east Texas. Effective January 1, 2012, the Company realigned its existing regions and in May 2012 added the East Texas region and now has seven operating regions in the U.S.: Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays); Hugoton Basin, which includes properties located primarily in Kansas and the Shallow Texas Panhandle; Permian Basin, which includes areas in west Texas and southeast New Mexico; Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois; Williston/Powder River Basin, which includes the Bakken formation in North Dakota and the Powder River Basin in Wyoming; California, which includes the Brea Olinda Field of the Los Angeles Basin; and East Texas, which includes properties located in east Texas. The realignment had no effect on the Company’s operations.

Principles of Consolidation and Reporting

The condensed consolidated financial statements at June 30, 2012, and for the three months and six months ended June 30, 2012, and June 30, 2011, are unaudited, but in the opinion of management include all adjustments (consisting of normal recurring adjustments) necessary for a 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, 2011. 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) or unitholders’ capital.

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.

5

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


Recently Issued Accounting Standards

In December 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The ASU requires disclosure of both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The ASU will be applied retrospectively and is effective for periods beginning on or after January 1, 2013. The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.

In May 2011, the FASB issued an ASU that further addresses fair value measurement accounting and related disclosure requirements. The ASU clarifies the FASB’s intent regarding the application of existing fair value measurement and disclosure requirements, changes the fair value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair value measurements. The ASU is to be applied prospectively and is effective for periods beginning after December 15, 2011. The Company adopted the ASU effective January 1, 2012. The adoption of the requirements of the ASU, which expanded disclosures, had no effect on the Company’s results of operations or financial position.

Note 2 – Acquisitions

Acquisitions – 2012

On May 1, 2012, the Company completed the acquisition of certain oil and natural gas properties located in east Texas. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid approximately $168 million in total consideration for these properties. The transaction was financed primarily with borrowings under the Company’s Credit Facility, as defined in Note 6.

On April 3, 2012, the Company entered into a joint-venture agreement (“Agreement”) with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) whereby the Company will participate as a partner in the CO2 enhanced oil recovery development of the Salt Creek field, located in the Powder River Basin of Wyoming. Anadarko assigned the Company 23% of its interest in the field in exchange for future funding of $400 million of Anadarko’s development costs. The results of operations of these properties have been included in the condensed consolidated financial statements since the Agreement date. The Company assigned approximately $392 million to the net assets acquired as of the Agreement date, which reflects an imputed discount of approximately $8 million on the future funding of this transaction. As of June 30, 2012, the Company has paid approximately $54 million towards the future funding commitment.
On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin in Kansas from BP America Production Company (“BP”). The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid approximately $1.17 billion in total consideration for these properties. The transaction was financed primarily with proceeds from the March 2012 debt offering, as described below.

During the six months ended June 30, 2012, the Company completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition dates. The Company, in the aggregate, paid approximately $67 million in total consideration for these properties.

These acquisitions were accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

6

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


The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands):
Assets:
 
Current
$
7,358

Noncurrent
208,423

Oil and natural gas properties
1,625,246

Total assets acquired
$
1,841,027

 
 
Liabilities:
 
Current
$
208,139

Asset retirement obligations
34,096

Noncurrent
196,600

Total liabilities assumed
$
438,835

Net assets acquired
$
1,402,192


Current assets include receivables and inventory and noncurrent assets include other property and equipment. Current liabilities include payables, ad valorem taxes payable and environmental liabilities. Current liabilities and noncurrent liabilities, as of the Agreement date, consist of payables of approximately $195 million and $197 million, respectively, related to the future funding commitment associated with the Anadarko transaction discussed above. As of June 30, 2012, the Company has paid approximately $54 million towards this commitment.

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) 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.

The revenues and expenses related to certain properties acquired from BP, Plains Exploration & Production Company (“Plains”), Panther Energy Company, LLC and Red Willow Mid-Continent, LLC (collectively referred to as “Panther”), SandRidge Exploration and Production, LLC (“SandRidge”) and an affiliate of Concho Resources Inc. (“Concho”) are included in the condensed consolidated results of operations of the Company as of March 30, 2012, December 15, 2011, June 1, 2011, April 1, 2011, and March 31, 2011, respectively. The following unaudited pro forma financial information presents a summary of the Company’s condensed consolidated results of operations for the six months ended June 30, 2012, and three months and six months ended June 30, 2011, assuming the acquisition from BP had been completed as of January 1, 2011, and the acquisitions from Plains, Panther, SandRidge and Concho had been completed as of January 1, 2010, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of these dates.
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2012
 
2011
 
(in thousands, except per unit amounts)
 
 
 
 
 
 
Total revenues and other
$
647,633

 
$
1,211,569

 
$
640,027

Total operating expenses
$
268,273

 
$
779,199

 
$
514,965

Net income (loss)
$
276,393

 
$
220,419

 
$
(159,406
)
 
 
 
 
 
 
Net income (loss) per unit:
 
 
 
 
 
Basic
$
1.56

 
$
1.11

 
$
(0.94
)
Diluted
$
1.56

 
$
1.11

 
$
(0.94
)

7

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


Acquisition - Pending
On June 21, 2012, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the Green River Basin area of southwest Wyoming from BP for a contract price of approximately $1.03 billion. The Company paid a deposit of approximately $308 million in June 2012, which is reported in “other noncurrent assets” on the condensed consolidated balance sheet at June 30, 2012. The Company anticipates the acquisition will close on or before July 31, 2012, subject to closing conditions, and will be financed with borrowings under its Credit Facility, as defined in Note 6.
Acquisition – 2011

On June 1, 2011, the Company completed the acquisition of certain oil and natural gas properties in the Cleveland play, located in the Texas Panhandle, from Panther. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid approximately $224 million in total consideration for these properties. The transaction was financed primarily with proceeds from the Company’s May 2011 debt offering.

On May 2, 2011 and May 11, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Williston Basin. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition dates. The Company paid approximately $153 million in total consideration for these acquisitions. The transactions were financed initially with borrowings under the Company’s Credit Facility.

On April 1, 2011 and April 5, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Permian Basin, including properties from SandRidge. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition dates. The Company paid approximately $239 million in total consideration for these acquisitions. The transactions were financed initially with borrowings under the Company’s Credit Facility.

On March 31, 2011, the Company completed the acquisition of certain oil and natural gas properties in the Williston Basin from Concho. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid $194 million in cash and recorded a receivable from Concho of $2 million, resulting in total consideration for the acquisition of approximately $192 million. The transaction was financed primarily with proceeds from the Company’s March 2011 public offering of units, as described below.

Note 3 – Unitholders’ Capital

Equity Distribution Agreement

In August 2011, the Company entered into an equity distribution agreement, pursuant to which it may from time to time issue and sell units representing limited liability company interests having an aggregate offering price of up to $500 million. Sales of units, if any, will be made through a sales agent by means of ordinary brokers’ transactions, in block transactions, or as otherwise agreed with the agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.

In January 2012, the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $2 million in commissions and professional service expenses). The Company used the net proceeds for general corporate purposes, including the repayment of a portion of the indebtedness outstanding under its Credit Facility. At June 30, 2012, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.


8

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


Public Offering of Units

In January 2012, the Company sold 19,550,000 units representing limited liability company interests at $35.95 per unit ($34.512 per unit, net of underwriting discount) for net proceeds of approximately $674 million (after underwriting discount and offering expenses of approximately $28 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under its Credit Facility.

In March 2011, the Company sold 16,726,067 units representing limited liability company interests at $38.80 per unit ($37.248 per unit, net of underwriting discount) for net proceeds of approximately $623 million (after underwriting discount and offering expenses of approximately $26 million). The Company used a portion of the net proceeds from the sale of these units to fund the March 2011 redemptions of a portion of the outstanding 2017 Senior Notes and 2018 Senior Notes, and to fund the cash tender offers and related expenses for a portion of the remaining 2017 Senior Notes and 2018 Senior Notes (see Note 6). The Company used the remaining net proceeds from the sale of units to finance a portion of the March 31, 2011, acquisition in the Williston/Powder River Basin region.

Distributions

Under the Company’s limited liability company agreement, the Company’s unitholders are entitled to receive a quarterly distribution of available cash to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Distributions paid by the Company during the six months ended June 30, 2012, are presented on the condensed consolidated statement of unitholders’ capital. On April 24, 2012, the Company’s Board of Directors approved an increase in the quarterly cash distribution from $0.69 per unit to $0.725 per unit with respect to the first quarter of 2012, representing an increase of 5%. On July 24, 2012, the Company’s Board of Directors declared a cash distribution of $0.725 per unit with respect to the second quarter of 2012. The distribution, totaling approximately $145 million, will be paid on August 14, 2012, to unitholders of record as of the close of business on August 7, 2012.

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:
 
June 30,
2012

 
December 31,
2011
 
(in thousands)
Proved properties:
 
 
 
Leasehold acquisition
$
7,460,077

 
$
6,040,239

Development
2,019,012

 
1,484,486

Unproved properties
516,659

 
310,925

 
9,995,748

 
7,835,650

Less accumulated depletion and amortization
(1,426,132
)
 
(1,033,617
)
 
$
8,569,616

 
$
6,802,033


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 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

9

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


average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.
Based on the analysis described above, for the three months and six months ended June 30, 2012, the Company recorded a noncash impairment charge, before and after tax, of approximately $146 million associated with proved oil and natural gas properties related to lower commodity prices. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair-value measurement. The charge is included in “impairment of long-lived assets” on the condensed consolidated statements of operations. The Company recorded no impairment charge of proved oil and natural gas properties for the three months or six months ended June 30, 2011.
Note 5 – Unit-Based Compensation

During the six months ended June 30, 2012, the Company granted an aggregate 953,668 restricted units to employees, primarily as part of its annual review of employee compensation, with an aggregate fair value of approximately $35 million. The restricted units vest over three years. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
 
 
 
 
 
 
 
 
General and administrative expenses
$
6,289

 
$
5,290

 
$
13,911

 
$
10,694

Lease operating expenses
374

 
253

 
923

 
487

Total unit-based compensation expenses
$
6,663

 
$
5,543

 
$
14,834

 
$
11,181

Income tax benefit
$
2,462

 
$
2,408

 
$
5,481

 
$
4,132


Note 6 – Debt

The following summarizes debt outstanding:
 
June 30, 2012
 
December 31, 2011
 
Carrying Value
 
Fair Value (1)
 
Carrying Value
 
Fair Value (1)
 
(in millions, except percentages)
 
 
 
 
 
 
 
 
Credit facility (2)
$
1,150

 
$
1,150

 
$
940

 
$
940

11.75% senior notes due 2017
41

 
45

 
41

 
46

9.875% senior notes due 2018
14

 
15

 
14

 
16

6.50% senior notes due May 2019
750

 
738

 
750

 
742

6.25% senior notes due November 2019
1,800

 
1,753

 

 

8.625% senior notes due 2020
1,300

 
1,401

 
1,300

 
1,406

7.75% senior notes due 2021
1,000

 
1,043

 
1,000

 
1,036

Less current maturities

 

 

 

 
6,055

 
$
6,145

 
4,045

 
$
4,186

Unamortized discount
(49
)
 
 
 
(51
)
 
 
Total debt, net of discount
$
6,006

 
 
 
$
3,994

 
 

(1) 
The carrying value of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.


10

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


(2) 
Variable interest rates of 2.02% and 2.57% at June 30, 2012, and December 31, 2011, respectively.
Credit Facility
The Company’s Fifth Amended and Restated Credit Agreement (“Credit Facility”) provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount. In October 2011, as part of the semi-annual redetermination, a borrowing base of $3.0 billion was approved by the lenders with a maximum commitment amount of $1.5 billion. In February 2012, lenders approved an increase in the maximum commitment amount to $2.0 billion. In May 2012, the Company entered into an amendment to its Credit Facility to increase the borrowing base to $3.5 billion and extend the maturity date from April 2016 to April 2017.
During the six months ended June 30, 2012, in connection with amendments to its Credit Facility, the Company incurred financing fees and expenses of approximately $5 million, which will be amortized over the life of the Credit Facility. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.
At June 30, 2012, available borrowing capacity under the Credit Facility was approximately $646 million, which includes a $4 million reduction in availability for outstanding letters of credit and a $200 million reduction in availability related to a restriction on swap agreements outstanding associated with the pending acquisition (see Note 2). The $200 million reduction in availability under the Credit Facility will no longer apply once the pending acquisition has closed.
In July 2012, the Company entered into an amendment to its Credit Facility to increase the maximum commitment amount from $2.0 billion to $3.0 billion.
Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October, as well as upon requested interim redeterminations, by the lenders at their sole discretion. The Company also has the right to request one additional borrowing base redetermination per year at its discretion, as well as the right to an additional redetermination each year in connection with certain acquisitions. Significant declines in commodity prices may result in a decrease in the borrowing base. The Company’s obligations under the Credit Facility are secured by mortgages on its and certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in its direct and indirect material subsidiaries. The Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on the most recent reserve report, or 2) a Collateral Coverage Ratio of at least 2.5 to 1. Collateral Coverage Ratio is defined as ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount. Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material subsidiaries and are required to be guaranteed by any future material subsidiaries.
At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.5% and 2.5% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.5% and 1.5% per annum (depending on the then-current level of borrowings under the 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 LIBOR. The Company is required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum between 0.375% and 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base. The Company is in compliance with all financial and other covenants of the Credit Facility.
Senior Notes Due November 2019
On March 2, 2012, the Company issued $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (“November 2019 Senior Notes”) at a price of 99.989%. The November 2019 Senior Notes were sold to a group of initial purchasers and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Company received net proceeds of approximately $1.77 billion (after deducting the initial purchasers’ discount of $198,000 and offering expenses of approximately $29 million). The Company used the net proceeds to fund the BP acquisition (see Note 2). The remaining proceeds were used to repay indebtedness under the Company’s Credit Facility and for general corporate purposes. The financing fees and expenses of

11

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


approximately $29 million incurred in connection with the November 2019 Senior Notes will be amortized over the life of the notes. Such amortized financing fees and expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.
The November 2019 Senior Notes were issued under an indenture dated March 2, 2012 (“November 2019 Indenture”), mature November 1, 2019, and bear interest at 6.25%. Interest is payable semi-annually on May 1 and November 1, beginning November 1, 2012. The November 2019 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries has guaranteed the November 2019 Senior Notes on a senior unsecured basis. The November 2019 Indenture provides that the Company may redeem: (i) on or prior to November 1, 2015, up to 35% of the aggregate principal amount of the November 2019 Senior Notes at a redemption price of 106.25% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to November 1, 2015, all or part of the November 2019 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the November 2019 Indenture) and accrued and unpaid interest; and (iii) on or after November 1, 2015, all or part of the November 2019 Senior Notes at a redemption price equal to 103.125%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The November 2019 Indenture also provides that, if a change of control (as defined in the November 2019 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the November 2019 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.
The November 2019 Indenture contains covenants substantially similar to those under the Company’s May 2019 Senior Notes, 2010 Issued Senior Notes and Original Senior Notes, as defined below, that, among other things, limit the Company’s 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 the November 2019 Senior Notes.
In connection with the issuance and sale of the November 2019 Senior Notes, the Company entered into a Registration Rights Agreement (“November 2019 Registration Rights Agreement”) with the initial purchasers. Under the November 2019 Registration Rights Agreement, the Company agreed to use its reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the November 2019 Senior Notes in exchange for outstanding November 2019 Senior Notes within 400 days after the notes were issued. In certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the November 2019 Senior Notes. If the Company fails to satisfy these obligations, the Company may be required to pay additional interest to holders of the November 2019 Senior Notes under certain circumstances.
Senior Notes Due May 2019
On May 13, 2011, the Company issued $750 million in aggregate principal amount of 6.50% senior notes due 2019 (the “May 2019 Senior Notes”). The indentures related to the May 2019 Senior Notes contain redemption provisions and covenants that are substantially similar to those of the November 2019 Senior Notes. On May 8, 2012, the Company filed a registration statement on Form S-4 to register exchange notes that are also substantially similar to the November 2019 Senior Notes. As of July 26, 2012, the registration statement has not been declared effective. The deadline for registration has passed and the Company will be required to pay additional interest which is expected to be less than $500,000.
Senior Notes Due 2020 and Senior Notes Due 2021
The Company has $1.3 billion in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”) and $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (the “2021 Senior Notes,” and together with the 2020 Senior Notes, the “2010 Issued Senior Notes”). The indentures related to the 2010 Issued Senior Notes contain redemption provisions and covenants that are substantially similar to those of the November 2019 Senior Notes. However, in 2011, the Company caused the trustee to remove the restrictive legends from each of the 2010 Issued Senior Notes making them freely tradable (other than with respect to persons that are affiliates of the Company), thereby terminating the Company’s

12

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


obligations under each of the registration rights agreements entered into in connection with the issuance of the 2010 Issued Senior Notes.
Senior Notes Due 2017 and Senior Notes Due 2018
The Company also has $41 million (originally $250 million) in aggregate principal amount of 11.75% senior notes due 2017 (the “2017 Senior Notes”) and $14 million (originally $256 million) in aggregate principal amount of 9.875% senior notes due 2018 (the “2018 Senior Notes” and together with the 2017 Senior Notes, the “Original Senior Notes”). The indentures related to the Original Senior Notes initially contained redemption provisions and covenants that were substantially similar to those of the November 2019 Senior Notes; however, in conjunction with the tender offers in 2011, the indentures were amended and most of the covenants and certain default provisions were eliminated. The amendments became effective upon the execution of the supplemental indentures to the indentures governing the Original Senior Notes.
In March 2011 and June 2011, in accordance with the indentures related to the Original Senior Notes, the Company redeemed and also repurchased through cash tender offers, a portion of the Original Senior Notes. In connection with the redemptions and cash tender offers of a portion of the Original Senior Notes, the Company recorded a loss on extinguishment of debt of approximately $10 million and $94 million for the three months and six months ended June 30, 2011, respectively.
Note 7 – Derivatives
Commodity Derivatives
The Company utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements. The Company has historically entered into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

13

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


The following table summarizes derivative positions for the periods indicated as of June 30, 2012:
 
July 1 – December 31, 2012
 
2013
 
2014
 
2015
 
2016
 
2017
Natural gas positions:
 
 
 
 
 
 
 
 
 
 
 
Fixed price swaps:
 
 
 
 
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
43,910

 
87,290

 
97,401

 
118,041

 
121,841

 
120,122

Average price ($/MMBtu)
$
5.16

 
$
5.22

 
$
5.25

 
$
5.19

 
$
4.20

 
$
4.26

Puts: (1)
 
 
 
 
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
38,894

 
86,198

 
79,628

 
71,854

 
76,269

 
66,886

Average price ($/MMBtu)
$
5.41

 
$
5.37

 
$
5.00

 
$
5.00

 
$
5.00

 
$
4.88

Total:
 
 
 
 
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
82,804

 
173,488

 
177,029

 
189,895

 
198,110

 
187,008

Average price ($/MMBtu)
$
5.28

 
$
5.29

 
$
5.14

 
$
5.12

 
$
4.51

 
$
4.48

 
 
 
 
 
 
 
 
 
 
 
 
Oil positions:
 
 
 
 
 
 
 
 
 
 
 
Fixed price swaps: (2)
 
 
 
 
 
 
 
 
 
 
 
Hedged volume (MBbls)
4,730

 
11,871

 
11,903

 
11,599

 
11,464

 
4,755

Average price ($/Bbl)
$
96.72

 
$
94.97

 
$
92.92

 
$
96.23

 
$
90.56

 
$
89.02

Puts:
 
 
 
 
 
 
 
 
 
 
 
Hedged volume (MBbls)
1,251

 
3,105

 
3,960

 
3,426

 
3,271

 
384

Average price ($/Bbl)
$
99.32

 
$
97.86

 
$
91.30

 
$
90.00

 
$
90.00

 
$
90.00

Total:
 
 
 
 
 
 
 
 
 
 
 
Hedged volume (MBbls)
5,981

 
14,976

 
15,863

 
15,025

 
14,735

 
5,139

Average price ($/Bbl)
$
97.26

 
$
95.57

 
$
92.52

 
$
94.81

 
$
90.44

 
$
89.10

 
 
 
 
 
 
 
 
 
 
 
 
Natural gas basis differential positions: (3)
 
 
 
 
 
 
 
 
 
 
 
Panhandle basis swaps:
 
 
 
 
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
37,535

 
77,800

 
79,388

 
87,162

 
19,764

 

Hedged differential ($/MMBtu)
$
(0.55
)
 
$
(0.56
)
 
$
(0.33
)
 
$
(0.33
)
 
$
(0.31
)
 
$

NWPL - Rockies basis swaps:
 
 
 
 
 
 
 
 
 
 
 
Hedge volume (MMMBtu)
14,122

 
34,785

 
36,026

 
38,362

 
39,199

 

Hedge differential ($/MMBtu)
$
(0.20
)
 
$
(0.20
)
 
$
(0.20
)
 
$
(0.20
)
 
$
(0.20
)
 
$

MichCon basis swaps:
 
 
 
 
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
4,894

 
9,600

 
9,490

 
9,344

 

 

Hedged differential ($/MMBtu)
$
0.12

 
$
0.10

 
$
0.08

 
$
0.06

 
$

 
$

Houston Ship Channel basis swaps:
 
 
 
 
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
3,146

 
5,731

 
5,256

 
4,891

 
4,575

 

Hedged differential ($/MMBtu)
$
(0.10
)
 
$
(0.10
)
 
$
(0.10
)
 
$
(0.10
)
 
$
(0.10
)
 
$

Permian basis swaps:
 
 
 
 
 
 
 
 
 
 
 
Hedged volume (MMMBtu)
2,282

 
4,636

 
4,891

 
5,074

 

 

Hedged differential ($/MMBtu)
$
(0.19
)
 
$
(0.20
)
 
$
(0.21
)
 
$
(0.21
)
 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
 
Oil timing differential positions:
 
 
 
 
 
 
 
 
 
 
 
Trade month roll swaps: (4)
 
 
 
 
 
 
 
 
 
 
 
Hedged volume (MBbls)
3,284

 
6,944

 
7,254

 
7,251

 
7,446

 
6,486

Hedged differential ($/Bbl)
$
0.21

 
$
0.22

 
$
0.22

 
$
0.24

 
$
0.25

 
$
0.25


(1) 
Includes certain outstanding natural gas puts of approximately 5,329 MMMBtu for the period July 1, 2012, through December 31, 2012, 10,570 MMMBtu for each of the years ending December 31, 2013, December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to hedge revenues associated with NGL production.

14

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


(2) 
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, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

(3) 
Settle on the respective pricing index to hedge basis differential associated with natural gas production.

(4) 
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 price of light crude oil 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 six months ended June 30, 2012, the Company entered into commodity derivative contracts consisting of oil and natural gas swaps and puts for 2012 through 2017, and paid premiums for put options of approximately $583 million. Also during the six months ended June 30, 2012, the Company entered into natural gas basis swaps for 2012 through 2016 and trade month roll swaps for 2012 through 2017.
Settled derivatives on natural gas production for the three months and six months ended June 30, 2012, included volumes of 34,438 MMMBtu and 58,080 MMMBtu, respectively, at average contract prices of $5.45 per MMBtu and $5.61 per MMBtu. Settled derivatives on oil production for the three months and six months ended June 30, 2012, included volumes of 2,731 MBbls and 5,308 MBbls, respectively, at average contract prices of $98.08 and $98.01 per Bbl. Settled derivatives on natural gas production for the three months and six months ended June 30, 2011, included volumes of 16,106 MMMBtu and 32,178 MMMBtu, respectively, at average contract prices of $8.24 per MMBtu and $8.25 per MMBtu. Settled derivatives on oil production for the three months and six months ended June 30, 2011, included volumes of 1,839 MBbls and 3,671 MBbls, respectively, at an average contract price of $84.08 per Bbl. The natural gas derivatives are settled based on the closing price of NYMEX 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 light crude oil for each day of the delivery month.

Balance Sheet Presentation

The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis:
 
June 30,
2012

 
December 31,
2011
 
(in thousands)
Assets:
 
 
 
Commodity derivatives
$
1,730,071

 
$
880,175

Liabilities:
 
 
 
Commodity derivatives
$
319,935

 
$
320,835


By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil and natural gas 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 $1.7 billion at June 30, 2012. 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

15

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


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 is somewhat mitigated.

Gains (Losses) on Derivatives

Gains and losses on derivatives, including realized and unrealized gains and losses, are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.” Realized gains (losses), excluding canceled derivatives, represent amounts related to the settlement of derivative instruments and are aligned with the underlying production. Unrealized gains (losses) represent the change in fair value of the derivative instruments and are noncash items.

The following presents the Company’s reported gains and losses on derivative instruments:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2012
 
2011
 
2012
 
2011
 
(in thousands)
Realized gains:
 
 
 
 
 
 
 
Commodity derivatives
$
117,740

 
$
42,081

 
$
172,995

 
$
97,890

Recovery of bankruptcy claim (see Note 10)
18,277

 

 
18,277

 

 
136,017

 
42,081

 
191,272

 
97,890

Unrealized gains (losses):
 
 
 
 
 
 
 
Commodity derivatives
303,630

 
163,434

 
250,406

 
(261,851
)
Total gains (losses):
 
 
 
 
 
 
 
Total
$
439,647

 
$
205,515

 
$
441,678

 
$
(163,961
)

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 uses certain pricing models to determine the fair value of its derivative financial instruments. 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 securities 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.

The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
 
June 30, 2012
 
Level 2
 
Netting (1)
 
Total
 
(in thousands)
Assets:
 
 
 
 
 
Commodity derivatives
$
1,730,071

 
$
(316,224
)
 
$
1,413,847

Liabilities:
 
 
 
 
 
Commodity derivatives
$
319,935

 
$
(316,224
)
 
$
3,711


(1) 
Represents counterparty netting under agreements governing such derivatives.

Note 9 – Asset Retirement Obligations

Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other noncurrent liabilities” on the condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the

16

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


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 six months ended June 30, 2012); and (iv) a credit-adjusted risk-free interest rate (average of 7.36% for the six months ended June 30, 2012). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

The following presents a reconciliation of the asset retirement obligations (in thousands):
Asset retirement obligations at December 31, 2011
$
71,142

Liabilities added from acquisitions
34,096

Liabilities added from drilling
574

Current year accretion expense
3,373

Settlements
(1,506
)
Revision of estimates
942

Asset retirement obligations at June 30, 2012
$
108,621


Note 10 – Commitments and Contingencies

The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. The Company has established reserves that management currently believes are adequate to provide for potential liabilities based upon its evaluation of these matters. For a certain statewide class action royalty payment dispute 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 court, will result in no loss to the Company. Discovery related to class certification has concluded. Briefing and the hearing on class certification have been deferred by court order pending the Tenth Circuit Court of Appeals’ resolution of interlocutory appeals of two unrelated class certification orders. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any. 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.

In 2008, Lehman Brothers Holdings Inc. (“Lehman Holdings”) and Lehman Brothers Commodity Services Inc. (“Lehman Commodity Services”) (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 (“Plan”) was approved by the Bankruptcy Court. Based on the recovery estimates described in the approved disclosure statement relating to the Plan, the Company expects to ultimately receive a substantial portion of the Company Claim. On April 19, 2012, an initial distribution under the Plan of approximately $25 million was received by the Company resulting in a gain of approximately $18 million which is included in gains (losses) on oil and natural gas derivatives on the condensed consolidated statement of operations.

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.


17

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 income (loss):
 
Net Income (Loss)
(Numerator)
 
Units
(Denominator)
 
Per Unit
Amount
 
(in thousands)
 
 
Three months ended June 30, 2012:
 
 
 
 
 
Net income:
 
 
 
 
 
Allocated to units
$
237,086

 
 
 
 
Allocated to unvested restricted units
(2,232
)
 
 
 
 
 
$
234,854

 
 
 
 
Net income per unit:
 
 
 
 
 
Basic net income per unit
 
 
197,507

 
$
1.19

Dilutive effect of unit equivalents
 
 
653

 

Diluted net income per unit
 
 
198,160

 
$
1.19

 
 
 
 
 
 
Three months ended June 30, 2011:
 
 
 
 
 
Net income:
 
 
 
 
 
Allocated to units
$
237,109

 
 
 
 
Allocated to unvested restricted units
(2,475
)
 
 
 
 
 
$
234,634

 
 
 
 
Net income per unit:
 
 
 
 
 
Basic net income per unit
 
 
175,035

 
$
1.34

Dilutive effect of unit equivalents
 
 
762

 
(0.01
)
Diluted net income per unit
 
 
175,797

 
$
1.33

 
 
 
 
 
 
Six months ended June 30, 2012:
 
 
 
 
 
Net income:
 
 
 
 
 
Allocated to units
$
230,884

 
 
 
 
Allocated to unvested restricted units
(2,735
)
 
 
 
 
 
$
228,149

 
 
 
 
Net income per unit:
 
 
 
 
 
Basic net income per unit
 
 
195,382

 
$
1.17

Dilutive effect of unit equivalents
 
 
657

 
(0.01
)
Diluted net income per unit
 
 
196,039

 
$
1.16

 
 
 
 
 
 
Six months ended June 30, 2011:
 
 
 
 
 
Net loss:
 
 
 
 
 
Allocated to units
$
(209,573
)
 
 
 
 
Allocated to unvested restricted units
(2,439
)
 
 
 
 
 
$
(212,012
)
 
 
 
 
Net loss per unit:
 
 
 
 
 
Basic net loss per unit
 
 
169,104

 
$
(1.25
)
Dilutive effect of unit equivalents
 
 

 

Diluted net loss per unit
 
 
169,104

 
$
(1.25
)


18

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


There were no anti-dilutive unit equivalents for the three months or six months ended June 30, 2012, or the three months ended June 30, 2011. Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 2 million unit options and warrants for the six months ended June 30, 2011. All equivalent units were anti-dilutive for the six months ended June 30, 2011.

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, with income tax liabilities and/or benefits of the Company passed through to unitholders. Limited liability companies are subject to Texas margin tax. Limited liability companies were also subject to state income taxes in the state of Michigan during the three months and six months ended June 30, 2012. 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” 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:
 
June 30,
2012

 
December 31,
2011
 
(in thousands)
 
 
 
 
Accrued compensation
$
17,068

 
$
19,581

Accrued interest
91,351

 
55,170

Other
422

 
1,147

 
$
108,841

 
$
75,898


Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
 
Six Months Ended
June 30,
 
2012
 
2011
 
(in thousands)
 
 
 
 
Cash payments for interest, net of amounts capitalized
$
128,617

 
$
124,173

Cash payments for income taxes
$
306

 
$
476

 
 
 
 
Noncash investing activities:
 
 
 
In connection with the acquisition of oil and natural gas properties, liabilities were assumed as follows:
 
 
 
Fair value of assets acquired
$
1,841,027

 
$
850,313

Cash paid, net of cash acquired
(1,455,433
)
 
(847,780
)
Receivables from sellers
772

 
5,855

Payables to sellers
(422
)
 
(5,241
)
Liabilities assumed
$
385,944

 
$
3,147



19

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


Included in “acquisition of oil and natural gas properties” on the condensed consolidated statement of cash flows for the six months ended June 30, 2012, is a deposit paid by the Company of approximately $308 million for the pending acquisition (see Note 2).

For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $4 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at June 30, 2012, and December 31, 2011, and represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facility. At June 30, 2012, and December 31, 2011, approximately $13 million and $54 million, respectively, were included in “accounts payable and accrued expenses” on the condensed consolidated balance sheets which represents reclassified net outstanding checks. The Company presents these net outstanding checks as cash flows from financing activities on the condensed consolidated statements of cash flows.

Note 14 – Subsidiary Guarantors

The November 2019 Senior Notes, the May 2019 Senior Notes, the 2010 Issued Notes and the Original Senior Notes are guaranteed by all of the Company’s material subsidiaries. The Company is a holding company and has no independent assets or operations of its own, the guarantees under each series of notes are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.


20


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

The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control. The Company’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement” below and in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2011, 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, 2011. A 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 IPO in January 2006. The Company’s properties are located in seven operating regions in the United States (“U.S.”):

Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays);
Hugoton Basin, which includes properties located primarily in Kansas and the Shallow Texas Panhandle;
Permian Basin, which includes areas in west Texas and southeast New Mexico;
Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois;
Williston/Powder River Basin, which includes the Bakken formation in North Dakota and the Powder River Basin in Wyoming;
California, which includes the Brea Olinda Field of the Los Angeles Basin; and
East Texas, which includes properties located in east Texas.

Results for the three months ended June 30, 2012, included the following:

oil, natural gas and NGL sales of approximately $347 million compared to $302 million for the second quarter of 2011;
average daily production of 630 MMcfe/d compared to 358 MMcfe/d for the second quarter of 2011;
realized gains on commodity derivatives of approximately $118 million compared to $42 million for the second quarter of 2011;
adjusted EBITDA of approximately $319 million compared to $264 million for the second quarter of 2011;
adjusted net income of approximately $61 million compared to $83 million for the second quarter of 2011;
capital expenditures, excluding acquisitions, of approximately $298 million compared to $137 million for the second quarter of 2011; and
100 wells drilled (99 successful) compared to 55 wells drilled (all successful) for the second quarter of 2011.

Results for the six months ended June 30, 2012, included the following:

oil, natural gas and NGL sales of approximately $696 million compared to $543 million for the six months ended June 30, 2011;
average daily production of 550 MMcfe/d compared to 335 MMcfe/d for the six months ended June 30, 2011;
realized gains on commodity derivatives of approximately $173 million compared to $98 million for the six months ended June 30, 2011;
adjusted EBITDA of approximately $621 million compared to $474 million for the six months ended June 30, 2011;
adjusted net income of approximately $110 million compared to $146 million for the six months ended June 30, 2011;
capital expenditures, excluding acquisitions, of approximately $557 million compared to $250 million for the six months ended June 30, 2011; and

21

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

181 wells drilled (178 successful) compared to 101 wells drilled (99 successful) for the six months ended June 30, 2011.

Adjusted EBITDA and adjusted net income are non-GAAP financial measures used by management to analyze Company performance. Adjusted EBITDA is a measure used by Company management to evaluate cash flow and the Company’s ability to sustain or increase distributions. The most significant reconciling items between net income (loss) and adjusted EBITDA are interest expense and noncash items, including the change in fair value of derivatives, and depreciation, depletion and amortization. Adjusted net income is used by Company management to evaluate its operational performance from oil and natural gas properties, prior to unrealized (gains) losses on derivatives, realized (gains) losses on canceled derivatives, realized gain on recovery of bankruptcy claim, impairment of long-lived assets, loss on extinguishment of debt and (gains) losses on sale of assets, net. See “Non-GAAP Financial Measures” on page 37 for a reconciliation of each non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP.

Acquisitions

On May 1, 2012, the Company completed the acquisition of certain oil and natural gas properties located in east Texas for total consideration of approximately $168 million. The acquisition included approximately 110 Bcfe of proved reserves as of the acquisition date.
On April 3, 2012, the Company entered into a joint-venture agreement ("Agreement") with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) whereby the Company will participate as a partner in the CO2 enhanced oil recovery development of the Salt Creek field, located in the Powder River Basin of Wyoming. Anadarko assigned the Company 23% of its interest in the field in exchange for future funding of $400 million of Anadarko’s development costs. As of June 30, 2012, the Company has paid approximately $54 million towards the future funding commitment. The acquisition included approximately 16 MMBoe (96 Bcfe) of proved reserves as of the Agreement date.

On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin in Kansas from BP America Production Company (“BP”) for total consideration of approximately $1.17 billion. The acquisition included approximately 701 Bcfe of proved reserves as of the acquisition date.
During the six months ended June 30, 2012, the Company completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The Company, in the aggregate, paid approximately $67 million in total consideration for these properties.

Proved reserves as of the acquisition date for all of the above referenced acquisitions were estimated using the average oil and natural gas prices during the preceding 12-month period, determined as an unweighted average of the first-day-of-the-month prices for each month.

Acquisition - Pending
On June 21, 2012, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the Green River Basin area of southwest Wyoming from BP for a contract price of approximately $1.03 billion. The Company paid a deposit of approximately $308 million in June 2012, which is reported in “other noncurrent assets” on the condensed consolidated balance sheet at June 30, 2012. The Company anticipates the acquisition will close on or before July 31, 2012, subject to closing conditions, and will be financed with borrowings under its Credit Facility, as defined in Note 6.
Financing and Liquidity

In January 2012, the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $2 million in commissions and professional services expenses). The Company used the net proceeds for general corporate purposes, including the repayment of a portion of the indebtedness outstanding under its Credit Facility. At June 30, 2012, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.


22

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

In January 2012, the Company completed a public offering of units for net proceeds of approximately $674 million. The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under its Credit Facility.

In March 2012, the Company issued $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (see Note 6) and used the net proceeds of approximately $1.77 billion to fund the Hugoton acquisition (see Note 2). The remaining proceeds were used to repay indebtedness under the Company's Credit Facility and for general corporate purposes.

The Company’s Fifth Amended and Restated Credit Agreement (“Credit Facility”) provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) maximum commitment amount. In May 2012, the Company entered into an amendment to its Credit Facility to extend the maturity date from April 2016 to April 2017. In July 2012, the Company entered into an amendment to its Credit Facility to increase the maximum commitment amount from $2.0 billion to $3.0 billion.


23

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

Results of Operations

Three Months Ended June 30, 2012, Compared to Three Months Ended June 30, 2011
 
Three Months Ended
June 30,
 
 
 
2012
 
2011
 
Variance
 
(in thousands)
Revenues and other:
 
 
 
 
 
Natural gas sales
$
59,258

 
$
70,800

 
$
(11,542
)
Oil sales
224,344

 
191,454

 
32,890

NGL sales
63,625

 
40,136

 
23,489

Total oil, natural gas and NGL sales
347,227

 
302,390

 
44,837

Gains on oil and natural gas derivatives
439,647

 
205,515

 
234,132

Marketing and other revenues
13,723

 
2,666

 
11,057

 
800,597

 
510,571

 
290,026

Expenses:
 
 
 
 
 
Lease operating expenses
70,129

 
56,363

 
13,766

Transportation expenses
21,815

 
6,476

 
15,339

Marketing expenses
6,458

 
1,044

 
5,414

General and administrative expenses (1)
41,185

 
31,543

 
9,642

Exploration costs
407

 
550

 
(143
)
Depreciation, depletion and amortization
143,506

 
79,345

 
64,161

Impairment of long-lived assets
146,499

 

 
146,499

Taxes, other than income taxes
30,656

 
20,318