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LINE > SEC Filings for LINE > Form 10-Q/A on 5-Nov-2013All Recent SEC Filings

Show all filings for LINN ENERGY, LLC

Form 10-Q/A for LINN ENERGY, LLC


5-Nov-2013

Quarterly Report


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, 2012, 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, 2012. 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 initial public offering in January 2006. The Company's properties are located in eight 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;

Green River Basin, which includes properties located in southwest Wyoming;

Permian Basin, which includes areas in west Texas and southeast New Mexico;

Williston/Powder River Basin, which includes the Bakken formation in North Dakota and the Powder River Basin in Wyoming;

Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois;

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, 2013, included the following:
oil, natural gas and NGL sales of approximately $488 million compared to $347 million for the second quarter of 2012;

average daily production of 780 MMcfe/d compared to 630 MMcfe/d for the second quarter of 2012;

net income of approximately $345 million compared to $237 million for the second quarter of 2012;

capital expenditures, excluding acquisitions, of approximately $334 million compared to $298 million for the second quarter of 2012; and

145 wells drilled (all successful) compared to 100 wells drilled (99 successful) for the second quarter of 2012.

Results for the six months ended June 30, 2013, included the following:
oil, natural gas and NGL sales of approximately $951 million compared to $696 million for the six months ended June 30, 2012;

average daily production of 788 MMcfe/d compared to 550 MMcfe/d for the six months ended June 30, 2012;

net income of approximately $123 million compared to $231 million for the six months ended June 30, 2012;

net cash provided by operating activities of approximately $561 million compared to net cash used in operating activities of $122 million for the six months ended June 30, 2012;

capital expenditures, excluding acquisitions, of approximately $606 million compared to $557 million for the six months ended June 30, 2012; and

258 wells drilled (all successful) compared to 181 wells drilled (178 successful) for the six months ended June 30, 2012.


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

Acquisition - Pending
On February 20, 2013, LinnCo, LLC ("LinnCo"), an affiliate of LINN Energy, and Berry Petroleum Company ("Berry") entered into a definitive merger agreement under which LinnCo would acquire all of the outstanding common shares of Berry. Under the terms of the agreement, Berry's shareholders will receive 1.25 LinnCo common shares for each Berry common share they own. This transaction, which is expected to be a tax-free exchange to Berry's shareholders, represents value of $46.2375 per common share, based on the closing price of LinnCo common shares on February 20, 2013, the last trading day before the public announcement. In connection with the proposed transaction described above, LinnCo will contribute Berry to LINN Energy in exchange for newly issued LINN Energy units, after which Berry will be an indirect wholly owned subsidiary of LINN Energy. At February 21, 2013, the date of the public announcement, the transaction had a preliminary value of approximately $4.4 billion, including the assumption of approximately $1.7 billion of Berry's debt. The transaction is subject to approvals by Berry and LinnCo shareholders, LINN Energy unitholders and regulatory agencies. Due to the pending SEC inquiry (see Note 16), the timing of closing this proposed transaction is uncertain. Divestiture - 2013
On May 31, 2013, the Company, through one of its wholly owned subsidiaries, together with the Company's partners, Panther Energy, LLC and Red Willow Mid-Continent, LLC, completed the sale of its interests in certain oil and natural gas properties located in the Mid-Continent region ("Panther Properties") to Midstates Petroleum Company, Inc. Proceeds received for the Company's portion of its interests in the properties were approximately $219 million, net of costs to sell of approximately $2 million. The Company used the net proceeds from the sale to repay borrowings under its Credit Facility, as defined in Note 6.
Financing and Liquidity
In April 2013, the Company entered into a Sixth Amended and Restated Credit Agreement ("Credit Facility"), which provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount of $4.0 billion. The borrowing base remained unchanged at $4.5 billion and does not include any assets to be acquired in the pending transaction with Berry. The maturity date is April 2018. The amended and restated agreement is substantially similar to the previous Credit Facility with revisions to permit the transactions related to the acquisition of Berry and to designate Berry as an unrestricted subsidiary under the agreement. In accordance with the provisions of the indenture related to the 2017 Senior Notes, in June 2013, the Company redeemed the remaining outstanding principal amount of $41 million. In accordance with the provisions of the indenture related to the 2018 Senior Notes, in July 2013, the Company redeemed the remaining outstanding principal amount of $14 million.


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

Results of Operations
Three Months Ended June 30, 2013, Compared to Three Months Ended June 30, 2012
                                            Three Months Ended
                                                 June 30,
                                            2013          2012        Variance
                                                     (in thousands)
Revenues and other:
Natural gas sales                        $ 160,766     $  59,258     $ 101,508
Oil sales                                  261,912       224,344        37,568
NGL sales                                   65,529        63,625         1,904
Total oil, natural gas and NGL sales       488,207       347,227       140,980
Gains on oil and natural gas derivatives   326,733       439,647      (112,914 )
Marketing and other revenues                23,885        13,723        10,162
                                           838,825       800,597        38,228
Expenses:
Lease operating expenses                    83,584        70,129        13,455
Transportation expenses                     29,298        21,815         7,483
Marketing expenses                           9,360         6,458         2,902
General and administrative expenses (1)     46,305        41,185         5,120
Exploration costs                              818           407           411
Depreciation, depletion and amortization   198,629       143,506        55,123
Impairment of long-lived assets            (14,851 )     146,499      (161,350 )
Taxes, other than income taxes              32,397        30,656         1,741
Gains on sale of assets and other, net        (959 )          (2 )        (957 )
                                           384,581       460,653       (76,072 )
Other income and (expenses)               (110,216 )    (102,346 )      (7,870 )
Income before income taxes                 344,028       237,598       106,430
Income tax expense (benefit)                (1,129 )         512        (1,641 )
Net income                               $ 345,157     $ 237,086     $ 108,071

(1) General and administrative expenses for the three months ended June 30, 2013, and June 30, 2012, include approximately $7 million and $6 million, respectively, of noncash unit-based compensation expenses.


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



                                             Three Months Ended
                                                  June 30,
                                               2013           2012      Variance
Average daily production:
Natural gas (MMcf/d)                            429             317       35  %
Oil (MBbls/d)                                  31.5            28.2       12  %
NGL (MBbls/d)                                  27.0            24.0       13  %
Total (MMcfe/d)                                 780             630       24  %

Weighted average prices (unhedged): (1)
Natural gas (Mcf)                        $     4.12         $  2.06      100  %
Oil (Bbl)                                $    91.27         $ 87.36        4  %
NGL (Bbl)                                $    26.69         $ 29.08       (8 )%

Average NYMEX prices:
Natural gas (MMBtu)                      $     4.09         $  2.22       84  %
Oil (Bbl)                                $    94.22         $ 93.49        1  %

Costs per Mcfe of production:
Lease operating expenses                 $     1.18         $  1.22       (3 )%
Transportation expenses                  $     0.41         $  0.38        8  %
General and administrative expenses (2)  $     0.65         $  0.72      (10 )%
Depreciation, depletion and amortization $     2.80         $  2.50       12  %
Taxes, other than income taxes           $     0.46         $  0.53      (13 )%

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

(2) General and administrative expenses for the three months ended June 30, 2013, and June 30, 2012, include approximately $7 million and $6 million, respectively, of noncash unit-based compensation expenses.


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

Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales increased approximately $141 million or 41% to approximately $488 million for the three months ended June 30, 2013, from approximately $347 million for the three months ended June 30, 2012, due to higher production volumes and higher natural gas and oil prices partially offset by lower NGL prices. Higher natural gas and oil prices resulted in an increase in revenues of approximately $81 million and $11 million, respectively. Lower NGL prices resulted in a decrease in revenues of approximately $6 million. Average daily production volumes increased to 780 MMcfe/d during the three months ended June 30, 2013, from 630 MMcfe/d during the three months ended June 30, 2012. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $26 million, $21 million and $8 million, respectively.
The following sets forth average daily production by region:

                                         Three Months Ended
                                              June 30,
                                            2013           2012      Variance
Average daily production (MMcfe/d):
Mid-Continent                            315                306      9      3  %
Hugoton Basin                            140                151    (11 )   (8 )%
Green River Basin                        138                  -    138      -
Permian Basin                             84                 80      4      5  %
Williston/Powder River Basin              35                 29      6     22  %
Michigan/Illinois                         33                 35     (2 )   (5 )%
East Texas                                22                 16      6     39  %
California                                13                 13      -      -
                                         780                630    150     24  %

The increase in average daily production volumes in the Mid-Continent region primarily reflects the Company's 2012 and 2013 capital drilling programs in the Granite Wash formation, partially offset by a decrease of approximately 7 MMcfe/d of production volumes related to one month's production of the Panther Properties sold on May 31, 2013. The decrease in average daily production volumes in the Hugoton Basin region reflects downtime related to weather and plant maintenance, and the effects of natural declines, partially offset by the results of the Company's development capital spending. Average daily production volumes in the Green River Basin region reflect the impact of the acquisition from BP America Production Company ("BP") in July 2012, partially offset by a reduction caused by ethane rejection in the region. The increase in average daily production volumes in the Permian Basin region primarily reflects development capital spending, partially offset by downtime from third parties' infrastructure. The increase in average daily production volumes in the Williston/Powder River Basin region reflects development capital spending in the Williston Basin. The Michigan/Illinois and California regions consist of low-decline asset bases and continue to produce at consistent levels. The increase in average daily production volumes in the East Texas region reflects the impact of the acquisition in May 2012. Gains on Oil and Natural Gas Derivatives Gains on oil and natural gas derivatives decreased by approximately $113 million to gains of approximately $327 million for the three months ended June 30, 2013, from gains of approximately $440 million for the three months ended June 30, 2012. Gains on oil and natural gas derivatives decreased primarily due to reduced cash settlements during the period and changes in fair value on unsettled derivatives contracts. The results for 2013 and 2012 also include gains of approximately $5 million and $18 million, respectively, related to the recoveries of a bankruptcy claim (see Note 10). The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized. During the three months ended June 30, 2013, the Company had commodity derivative contracts for approximately 111% of its natural gas production, including natural gas put options used to indirectly hedge NGL revenues, and 130% of its oil production. During the three months ended June 30, 2012, the Company had commodity derivative contracts for approximately


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

120% of its natural gas production, including natural gas put options used to indirectly hedge NGL revenues, and 106% of its oil production.
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" in "Liquidity and Capital Resources" below. Marketing and Other Revenues
Marketing revenues represent third-party activities associated with company-owned gathering systems and plants. Marketing and other revenues increased by approximately $10 million or 74% to approximately $24 million for the three months ended June 30, 2013, from approximately $14 million for the three months ended June 30, 2012, primarily due to higher revenues generated from the Jayhawk natural gas processing plant. Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $14 million or 19% to approximately $84 million for the three months ended June 30, 2013, from approximately $70 million for the three months ended June 30, 2012. Lease operating expenses increased primarily due to higher costs associated with horizontal wells drilled in the Mid-Continent region during the second half of 2012 and also properties acquired during 2012. Lease operating expenses per Mcfe decreased to $1.18 per Mcfe for the three months ended June 30, 2013, from $1.22 per Mcfe for the three months ended June 30, 2012, primarily due to lower rates on newly acquired properties and cost saving initiatives. Transportation Expenses
Transportation expenses increased by approximately $7 million or 34% to approximately $29 million for the three months ended June 30, 2013, from approximately $22 million for the three months ended June 30, 2012, primarily due to the BP acquisitions in 2012.
Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems and plants. Marketing expenses increased by approximately $3 million or 45% to approximately $9 million for the three months ended June 30, 2013, from approximately $6 million for the three months ended June 30, 2012, primarily due to higher expenses associated with the Jayhawk natural gas processing plant.
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 $5 million or 12% to approximately $46 million for the three months ended June 30, 2013, from approximately $41 million for the three months ended June 30, 2012. The increase was primarily due to an increase in salaries and benefits related expenses of approximately $5 million, driven primarily by increased employee headcount, and an increase in professional services expenses of approximately $2 million, partially offset by a decrease in acquisition related expenses of approximately $3 million. Although general and administrative expenses increased, the unit rate decreased to $0.65 per Mcfe for the three months ended June 30, 2013, from $0.72 per Mcfe for the three months ended June 30, 2012, as a result of efficiencies gained from being a larger, more scalable organization. Depreciation, Depletion and Amortization Depreciation, depletion and amortization increased by approximately $55 million or 38% to approximately $199 million for the three months ended June 30, 2013, from approximately $144 million for the three months ended June 30, 2012. Higher depletion rates and higher total production volumes were the primary reasons for the increased expense. Depreciation, depletion and amortization per Mcfe also increased to $2.80 per Mcfe for the three months ended June 30, 2013, from $2.50 per Mcfe for the three months ended June 30, 2012, primarily due to negative reserve revisions from the prior year, partially offset by lower rates on properties acquired in 2012.


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

Impairment of Long-Lived Assets
During the three months ended June 30, 2013, the Company recorded an adjustment of approximately $15 million to reduce the initial impairment charge recorded in March 2013 to reflect the fair value less costs to sell the Panther Properties sold in May 2013 (see Note 2). At March 31, 2013, the carrying value of the Panther Properties was reduced to fair value less costs to sell resulting in an impairment charge of approximately $57 million and the properties were classified as "assets held for sale." During the three 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 a decline in commodity prices. Taxes, Other Than Income Taxes
Taxes, other than income taxes, which consist primarily of severance and ad valorem taxes, increased by approximately $1 million or 6% to approximately $32 million for the three months ended June 30, 2013, from approximately $31 million for the three months ended June 30, 2012. Severance taxes, which are a function of revenues generated from production, increased by approximately $4 million compared to the three months ended June 30, 2012, primarily due to higher production volumes and higher natural gas and oil prices partially offset by lower NGL prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, decreased by approximately $2 million compared to the three months ended June 30, 2012, primarily due to an adjustment related to the properties acquired in the Green River Basin region partially offset by taxes associated with property acquisitions in 2012 and higher rates on the Company's base properties.

Other Income and (Expenses)
                                                 Three Months Ended
                                                      June 30,
                                                 2013           2012        Variance
                                                          (in thousands)

Interest expense, net of amounts capitalized $ (103,847 )   $  (94,390 )   $ (9,457 )
Loss on extinguishment of debt                   (4,187 )            -       (4,187 )
Other, net                                       (2,182 )       (7,956 )      5,774
                                             $ (110,216 )   $ (102,346 )   $ (7,870 )

Other income and (expenses) increased by approximately $8 million for the three months ended June 30, 2013, compared to the three months ended June 30, 2012. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with amendments made to the Company's Credit Facility during 2012 and 2013. In addition, for the three months ended June 30, 2013, the Company recorded a loss on extinguishment of debt of approximately $4 million as a result of the redemption of the remaining outstanding 2017 Senior Notes. See "Debt" in "Liquidity and Capital Resources" below for additional details. Other expenses decreased primarily due to no write-offs of deferred financing fees related to the amendment of the Credit Facility for the three months ended June 30, 2013, compared to approximately $6 million for the three months ended June 30, 2012. 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 $1 million for the three months ended June 30, 2013, compared to an income tax expense of approximately $1 million for the three months ended June 30, 2012. Income tax expense decreased primarily due to lower income from the Company's taxable subsidiaries during the three months ended June 30, 2013, compared to the same period in 2012. Net Income
Net income increased by approximately $108 million to approximately $345 million for the three months ended June 30, 2013, from approximately $237 million for the three months ended June 30, 2012. The increase was primarily due to higher production revenues and lower expenses, including interest, partially offset by lower gains on oil and natural gas derivatives. See discussions above for explanations of variances.


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

Results of Operations

Six Months Ended June 30, 2013, Compared to Six Months Ended June 30, 2012
                                              Six Months Ended
                                                  June 30,
                                             2013           2012         Variance
                                                       (in thousands)
Revenues and other:
Natural gas sales                        $  295,510     $  125,043     $  170,467
Oil sales                                   503,710        455,509         48,201
NGL sales                                   151,719        115,570         36,149
Total oil, natural gas and NGL sales        950,939        696,122        254,817
Gains on oil and natural gas derivatives    218,363        441,678       (223,315 )
Marketing and other revenues                 38,583         16,887         21,696
                                          1,207,885      1,154,687         53,198
. . .
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