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

Show all filings for LINN ENERGY, LLC

Form 10-K/A for LINN ENERGY, LLC


5-Nov-2013

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion and analysis should be read in conjunction with the "Consolidated Financial Statements" and "Notes to Consolidated Financial Statements," which are included in this Annual Report on Form 10-K in Item 8. "Financial Statements and Supplementary Data." 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 discussed below and elsewhere in this Annual Report on Form 10-K, particularly in Item 1A. "Risk Factors." In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
A reference to a "Note" herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. "Financial Statements and Supplementary Data."
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;

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 year ended December 31, 2012, included the following:
oil, natural gas and NGL sales of approximately $1.6 billion compared to $1.2 billion in 2011;

average daily production of 671 MMcfe/d compared to 369 MMcfe/d in 2011;

net loss of approximately $387 million compared to net income of $438 million in 2011;

net cash provided by operating activities of approximately $351 million compared to $519 million in 2011;

capital expenditures, excluding acquisitions, of approximately $1.1 billion compared to $697 million in 2011; and

440 wells drilled (436 successful) compared to 294 wells drilled (292 successful) in 2011.

Acquisitions
On July 31, 2012, the Company completed the acquisition of certain oil and natural gas properties in the Jonah Field located in the Green River Basin of southwest Wyoming from BP America Production Company ("BP") for total consideration of approximately $990 million. The acquisition included approximately 806 Bcfe of proved reserves as of the acquisition date. 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 ("JV Agreement") with an affiliate of Anadarko Petroleum Corporation ("Anadarko") whereby the Company participates 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%


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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued

of its interest in the field in exchange for future funding of $400 million of Anadarko's development costs. As of December 31, 2012, the Company has paid approximately $201 million towards the future funding commitment. The acquisition included approximately 16 MMBoe (96 Bcfe) of proved reserves as of the JV Agreement date.
On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties and the Jayhawk natural gas processing plant located in the Hugoton Basin in Kansas from BP for total consideration of approximately $1.16 billion. The acquisition included approximately 689 Bcfe of proved reserves as of the acquisition date.
During 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 $122 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. Estimates of proved reserves as of the acquisition date for all of the above referenced acquisitions as well as estimates of proved reserves at December 31, 2012, were prepared by the independent engineering firm, DeGolyer and MacNaughton. Acquisition - Subsequent Event
On February 21, 2013, LinnCo, LLC ("LinnCo"), an affiliate of LINN Energy, and Berry Petroleum Company ("Berry") announced they had signed a definitive merger agreement under which LinnCo would acquire all of the outstanding common shares of Berry. The transaction has a preliminary value of approximately $4.3 billion, including the assumption of debt, and is expected to close by June 30, 2013, subject to approvals by Berry and LinnCo shareholders, Linn Energy's unitholders and regulatory agencies.
Under the terms of the agreement, Berry's shareholders will receive 1.25 of 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.
Financing and Liquidity
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. The Credit Facility has a borrowing base of $4.5 billion with a maximum commitment amount of $3.0 billion. The maturity date is April 2017. At January 31, 2013, the borrowing capacity under the Credit Facility was approximately $1.8 billion, which includes a $5 million reduction in availability for outstanding letters of credit.
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 December 31, 2012, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.
In January 2012, the Company also 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.
On May 8, 2012, the Company filed a registration statement on Form S-4 to register exchange notes that are identical in all material respects to those of the outstanding May 2019 Senior Notes, except that the transfer restrictions, registration rights and additional interest provisions relating to the outstanding notes do not apply to the exchange notes. On September 24, 2012, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its


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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued

$750 million outstanding principal amount of May 2019 Senior Notes for an equal amount of new May 2019 Senior Notes. The offer expired on October 23, 2012. On October 17, 2012, LinnCo completed its initial public offering (the "LinnCo IPO") of 34,787,500 common shares representing limited liability company interests for net proceeds of approximately $1.2 billion. The net proceeds LinnCo received from the offering were used to acquire 34,787,500 LINN Energy units which are equal to the number of LinnCo shares sold in the offering. The Company used the proceeds from the sale of the units to LinnCo to pay the expenses of the offering and repay a portion of the outstanding indebtedness under its Credit Facility.
Commodity Derivatives
During the year ended December 31, 2012, the Company entered into commodity derivative contracts consisting of oil swaps for 2012 through 2017, natural gas swaps for 2012 through 2018, and oil and natural gas puts for 2012 through 2017 and paid premiums for put options of approximately $583 million. The Company also entered into natural gas basis swaps for 2012 through 2016 and trade month roll swaps for 2012 through 2017. Currently, the Company has limited abilities to hedge its NGL production because there is no commercially viable market established for this purpose. Therefore, the Company does not directly hedge its NGL production.
Operating Regions
Following is a discussion of the Company's eight operating regions. Mid-Continent
The Mid-Continent region includes properties located in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays). Wells in this diverse region produce from both oil and natural gas reservoirs at depths ranging from 1,500 feet to over 18,000 feet. The Granite Wash formation and other shallower producing horizons are currently being developed using horizontal drilling and multi-stage stimulations. In the northern Texas Panhandle and extending into western Oklahoma, the Cleveland formation is being developed as a horizontal oil play. Elsewhere in Oklahoma, several producing formations are being targeted using similar horizontal drilling and completion technologies. The majority of wells in this region are mature, low-decline oil and natural gas wells. Mid-Continent proved reserves represented approximately 34% of total proved reserves at December 31, 2012, of which 59% were classified as proved developed. This region produced 313 MMcfe/d or 48% of the Company's 2012 average daily production. During 2012, the Company invested approximately $578 million to drill in this region. During 2013, the Company anticipates spending approximately 49% of its total oil and natural gas capital budget for development activities in the Mid-Continent region, primarily in the Granite Wash formation.
To more efficiently transport its natural gas in the Mid-Continent region to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 300 miles of pipeline and associated compression and metering facilities. In connection with the horizontal development activities in the Granite Wash formation, the Company continues to expand this gathering system which connects to numerous natural gas processing facilities in the region.
Hugoton Basin
The Hugoton Basin is a large oil and natural gas producing area located in the central portion of the Texas Panhandle extending into southwestern Kansas. The Company's Texas properties in the basin primarily produce from the Brown Dolomite formation at depths of approximately 3,200 feet. The Company's Kansas properties in the basin, acquired in March 2012, primarily produce from the Council Grove and Chase formations at depths ranging from 2,500 feet to 3,000 feet. Hugoton Basin proved reserves represented approximately 21% of total proved reserves at December 31, 2012, of which 85% were classified as proved developed. This region produced 120 MMcfe/d or 18% of the Company's 2012 average daily production. During 2012, the Company invested approximately $11 million to drill in this region. During 2013, the Company anticipates spending approximately 3% of its total oil and natural gas capital budget for development activities in the Hugoton Basin region.
To more efficiently transport its natural gas in the Texas Panhandle to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 665 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. The Company also owns and operates the Jayhawk natural gas


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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued

processing plant in southwestern Kansas with a capacity of approximately 450 MMcfe/d, allowing it to extract maximum value from the liquids-rich natural gas produced in the area. The Company's production in the area is delivered to the plant via a system of approximately 2,100 miles of pipeline and related facilities operated by the Company, of which approximately 250 miles of pipeline are owned by the Company.
Green River Basin
The Green River Basin region consists of properties acquired in July 2012. These properties are located in southwest Wyoming and primarily produce natural gas at depths ranging from 8,000 feet to 12,000 feet. Green River Basin proved reserves represented approximately 21% of total proved reserves at December 31, 2012, of which 43% were classified as proved developed. This region produced 62 MMcfe/d or 9% of the Company's 2012 average daily production. During 2012, the Company invested approximately $22 million to drill in this region. During 2013, the Company anticipates spending approximately 12% of its total oil and natural gas capital budget for development activities in the Green River Basin region. Permian Basin
The Permian Basin is one of the largest and most prolific oil and natural gas basins in the U.S. The Company's properties are located in west Texas and southeast New Mexico and produce at depths ranging from 2,000 feet to 12,000 feet. The Wolfberry trend is located in the north central portion of the basin where the Company has been actively drilling vertical oil wells since 2010. The Company also produces oil and natural gas from mature, low-decline wells including several waterflood properties located across the basin. Permian Basin proved reserves represented approximately 8% of total proved reserves at December 31, 2012, of which 56% were classified as proved developed. This region produced 83 MMcfe/d or 12% of the Company's 2012 average daily production. During 2012, the Company invested approximately $240 million to drill in this region. During 2013, the Company anticipates spending approximately 20% of its total oil and natural gas capital budget for development activities in the Permian Basin region, primarily in the Wolfberry trend. Michigan/Illinois
The Michigan/Illinois region includes properties producing from the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois. These wells produce at depths ranging from 600 feet to 4,000 feet. Michigan/Illinois proved reserves represented approximately 6% of total proved reserves at December 31, 2012, of which 94% were classified as proved developed. This region produced 35 MMcfe/d or 5% of the Company's 2012 average daily production. During 2013, the Company anticipates spending approximately 1% of its total oil and natural gas capital budget for development activities in the Michigan/Illinois region.
Williston/Powder River Basin
The Williston/Powder River Basin region includes the Bakken formation in North Dakota and the Powder River Basin in Wyoming. The Company's nonoperated properties in the Williston Basin, one of the premier oil basins in the U.S., produce at depths ranging from 9,000 feet to 12,000 feet. The Company's properties in the Powder River Basin, acquired in April 2012, consist of a CO2 flood operated by Anadarko in the Salt Creek Field. Williston/Powder River Basin proved reserves represented approximately 4% of total proved reserves at December 31, 2012, of which 66% were classified as proved developed. This region produced 29 MMcfe/d or 4% of the Company's 2012 average daily production. During 2012, the Company invested approximately $124 million to drill in this region. During 2013, the Company anticipates spending approximately 12% of its total oil and natural gas capital budget for development activities in the Williston/Powder River Basin region.
California
The California region consists of the Brea Olinda Field of the Los Angeles Basin. The Brea Olinda Field was discovered in 1880 and produces from the shallow Pliocene formation to the deeper Miocene formation at depths ranging from 1,000 feet to 7,500 feet. California proved reserves represented approximately 4% of total proved reserves at December 31, 2012, of which 96% were classified as proved developed. This region produced 13 MMcfe/d or 2% of the Company's 2012 average daily production. During 2012, the Company invested approximately $1 million to drill in this region. During 2013, the Company anticipates spending approximately 2% of its total oil and natural gas capital budget for development activities in the California region.


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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued

East Texas
The East Texas region consists of properties acquired in May 2012. These properties are located in east Texas and primarily produce natural gas from the Cotton Valley formation at depths of approximately 11,000 feet. Proved reserves for these mature, low-decline producing properties, all of which are proved developed, represented approximately 2% of total proved reserves at December 31, 2012. This region produced 16 MMcfe/d or 2% of the Company's 2012 average daily production. During 2013, the Company anticipates spending approximately 1% of its total oil and natural gas capital budget for development activities in the East Texas region.


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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued

Results of Operations
Year Ended December 31, 2012, Compared to Year Ended December 31, 2011

                                                   Year Ended December 31,
                                                    2012              2011          Variance
                                                                (in thousands)
Revenues and other:
Natural gas sales                              $     367,550     $    278,714     $    88,836
Oil sales                                            946,304          714,385         231,919
NGL sales                                            287,326          168,938         118,388
Total oil, natural gas and NGL sales               1,601,180        1,162,037         439,143
Gains on oil and natural gas derivatives (1)         124,762          449,940        (325,178 )
Marketing and other revenues                          48,298           10,477          37,821
                                                   1,774,240        1,622,454         151,786
Expenses:
Lease operating expenses                             317,699          232,619          85,080
Transportation expenses                               77,322           28,358          48,964
Marketing expenses                                    31,821            3,681          28,140
General and administrative expenses (2)              173,206          133,272          39,934
Exploration costs                                      1,915            2,390            (475 )
Depreciation, depletion and amortization             606,150          334,084         272,066
Impairment of long-lived assets                      422,499                -         422,499
Taxes, other than income taxes                       131,679           78,522          53,157
Losses on sale of assets and other, net                1,539            3,494          (1,955 )
                                                   1,763,830          816,420         947,410
Other income and (expenses)                         (394,236 )       (362,129 )       (32,107 )
Income (loss) before income taxes                   (383,826 )        443,905        (827,731 )
Income tax expense                                     2,790            5,466          (2,676 )
Net income (loss)                              $    (386,616 )   $    438,439     $  (825,055 )

(1) During the year ended December 31, 2011, the Company canceled (before the contract settlement date) derivative contracts on estimated future oil and natural gas production resulting in gains of approximately $27 million. The proceeds from the cancellation of the derivative contracts were reallocated within the Company's derivatives portfolio.

(2) General and administrative expenses for the years ended December 31, 2012, and December 31, 2011, include approximately $28 million and $21 million, respectively, of noncash unit-based compensation expenses.


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Item 7.  Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued

                                                Year Ended December 31,
                                                    2012               2011      Variance
Average daily production:
Natural gas (MMcf/d)                                349                  175       99  %
Oil (MBbls/d)                                      29.2                 21.5       36  %
NGL (MBbls/d)                                      24.5                 10.8      127  %
Total (MMcfe/d)                                     671                  369       82  %

Weighted average prices (unhedged): (1)
Natural gas (Mcf)                          $       2.87              $  4.35      (34 )%
Oil (Bbl)                                  $      88.59              $ 91.24       (3 )%
NGL (Bbl)                                  $      32.10              $ 42.88      (25 )%

Average NYMEX prices:
Natural gas (MMBtu)                        $       2.79              $  4.05      (31 )%
Oil (Bbl)                                  $      94.20              $ 95.12       (1 )%

Costs per Mcfe of production:
Lease operating expenses                   $       1.29              $  1.73      (25 )%
Transportation expenses                    $       0.31              $  0.21       48  %
General and administrative expenses (2)    $       0.71              $  0.99      (28 )%
Depreciation, depletion and amortization   $       2.47              $  2.48        -
Taxes, other than income taxes             $       0.54              $  0.58       (7 )%

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

(2) General and administrative expenses for the years ended December 31, 2012, and December 31, 2011, include approximately $28 million and $21 million, respectively, of noncash unit-based compensation expenses.


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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Continued

Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales increased by approximately $439 million or 38% to approximately $1.6 billion for the year ended December 31, 2012, from approximately $1.2 billion for the year ended December 31, 2011, due to higher production volumes partially offset by lower commodity prices. Lower natural gas, NGL and oil prices resulted in a decrease in revenues of approximately $189 million, $96 million and $28 million, respectively.
Average daily production volumes increased to 671 MMcfe/d during the year ended December 31, 2012, from 369 MMcfe/d during the year ended December 31, 2011. Higher natural gas, oil and NGL production volumes resulted in an increase in revenues of approximately $277 million, $260 million and $215 million, respectively.
The following sets forth average daily production by region:

                                            Year Ended December 31,
                                                 2012               2011       Variance
Average daily production (MMcfe/d):
Mid-Continent                                313                     195    118      61  %
Hugoton Basin                                120                      39     81     208  %
Permian Basin                                 83                      73     10      14  %
Green River Basin                             62                       -     62       -
Michigan/Illinois                             35                      36     (1 )    (2 )%
Williston/Powder River Basin                  29                      12     17     129  %
East Texas                                    16                       -     16       -
California                                    13                      14     (1 )    (6 )%
                                             671                     369    302      82  %

The increase in average daily production volumes in the Mid-Continent region primarily reflects the Company's 2011 and 2012 capital drilling programs in the Granite Wash formation, as well as the impact of the acquisition in the Cleveland horizontal play in June 2011 and the acquisition from Plains in December 2011. The increase in average daily production volumes in the Hugoton Basin region primarily reflects the impact of the acquisition from BP in March 2012. The increase in average daily production volumes in the Permian Basin region reflects the impact of acquisitions in 2011 and subsequent development capital spending. Average daily production volumes in the Green River Basin region reflect the impact of the acquisitions in 2012. The Michigan/Illinois and California regions consist of low-decline asset bases and continue to produce at . . .

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