Log in
Login
Password
Remember
Lost password
Become a member for free
Sign up
Sign up
Settings
Settings
Dynamic quotes 

4-Traders Homepage  >  Shares  >  Nasdaq  >  Linn Energy LLC    LINE

SummaryQuotesChartsNewsAnalysisCalendarCompanyFinancialsConsensusRevisions 
News SummaryMost relevantAll newsSector news 
The feature you requested does not exist. However, we suggest the following feature:

LINN ENERGY : Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-Q)

07/30/2015 | 05:21pm US/Eastern
The following discussion contains forward-looking statements that reflect the
Company's future plans, estimates, beliefs and expected performance. The
forward-looking statements are dependent upon events, risks and uncertainties
that may be outside the Company's control. The Company's actual results could
differ materially from those discussed in these forward-looking statements.
Factors that could cause or contribute to such differences include, but are not
limited to, market prices for oil, natural gas and NGL, production volumes,
estimates of proved reserves, capital expenditures, economic and competitive
conditions, credit and capital market conditions, regulatory changes and other
uncertainties, as well as those factors set forth in "Cautionary Statement
Regarding Forward-Looking Statements" below and in Item 1A. "Risk Factors" in
this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the
year ended December 31, 2014, and elsewhere in the Annual Report. In light of
these risks, uncertainties and assumptions, the forward-looking events discussed
may not occur.
The following discussion and analysis should be read in conjunction with the
financial statements and related notes included in this Quarterly Report on
Form 10-Q and in the Company's Annual Report on Form 10-K for the year ended
December 31, 2014. The reference to a "Note" herein refers to the accompanying
Notes to Condensed Consolidated Financial Statements contained in Item 1.
"Financial Statements."
Executive Overview
LINN Energy's mission is to acquire, develop and maximize cash flow from a
growing portfolio of long-life oil and natural gas assets. LINN Energy is an
independent oil and natural gas company that began operations in March 2003 and
completed its initial public offering in January 2006. The Company's properties
are located in eight operating regions in the United States ("U.S."):
•      Rockies, which includes properties located in Wyoming (Green River,
       Washakie and Powder River basins), Utah (Uinta Basin), North Dakota
       (Williston Basin) and Colorado (Piceance Basin);


•      Hugoton Basin, which includes properties located in Kansas, the Oklahoma
       Panhandle and the Shallow Texas Panhandle;


•      California, which includes properties located in the San Joaquin Valley
       and Los Angeles basins;


•      Mid-Continent, which includes Oklahoma properties located in the Anadarko
       and Arkoma basins, as well as waterfloods in the Central Oklahoma
       Platform;


•      Permian Basin, which includes properties located in west Texas and
       southeast New Mexico;

TexLa, which includes properties located in east Texas and north Louisiana;

South Texas; and

Michigan/Illinois, which includes properties located in the Antrim Shale
       formation in north Michigan and oil properties in south Illinois.


Results for the three months ended June 30, 2015, included the following:
•      oil, natural gas and NGL sales of approximately $496 million compared to
       $968 million for the second quarter of 2014;


•      average daily production of approximately 1,219 MMcfe/d compared to 1,131
       MMcfe/d for the second quarter of 2014;


•      net loss of approximately $379 million compared to $208 million for the
       second quarter of 2014;


•      capital expenditures, excluding acquisitions, of approximately $115
       million compared to $407 million for the second quarter of 2014; and


•      148 wells drilled (all successful) compared to 268 wells drilled (all
       successful) for the second quarter of 2014.


Results for the six months ended June 30, 2015, included the following:
•      oil, natural gas and NGL sales of approximately $947 million compared to
       $1.9 billion for the six months ended June 30, 2014;


•      average daily production of approximately 1,210 MMcfe/d compared to 1,117
       MMcfe/d for the six months ended June 30, 2014;


•      net loss of approximately $718 million compared to $293 million for the
       six months ended June 30, 2014;


•      net cash provided by operating activities of approximately $673 million
       compared to $916 million for the six months ended June 30, 2014;



                                       31

--------------------------------------------------------------------------------

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



•      capital expenditures, excluding acquisitions, of approximately $312
       million compared to $816 million for the six months ended June 30, 2014;
       and


•      344 wells drilled (all successful) compared to 468 wells drilled (467
       successful) for the six months ended June 30, 2014.


Reduction of 2015 Oil and Natural Gas Capital Budget and Distribution
The Company's 2015 budget includes a 61% reduction in total capital expenditures
to approximately $610 million, from approximately $1.6 billion spent in 2014,
and includes approximately $530 million related to its oil and natural gas
capital program. The 2015 budget contemplates significantly lower commodity
prices as compared to 2014. In January 2015, the Company reduced its
distribution to $1.25 per unit, from the previous level of $2.90 per unit, on an
annualized basis. The reduction of the 2015 budget and the distribution was
intended to solidify the Company's financial position and allow it to regain a
useful cost of capital.
In July 2015, the Company announced that management intends to recommend to the
Board of Directors that it suspend payment of the Company's distribution at the
end of the third quarter of 2015.
Alliance with GSO Capital Partners
The Company signed definitive agreements dated June 30, 2015, with affiliates of
private capital investor GSO Capital Partners LP ("GSO"), the credit platform of
The Blackstone Group L.P., to fund oil and natural gas development ("DrillCo").
Funds managed by GSO and its affiliates have agreed to commit up to $500 million
with 5-year availability to fund drilling programs on locations provided by LINN
Energy. Subject to adjustments depending on asset characteristics and return
expectations of the selected drilling plan, GSO will fund 100% of the costs
associated with new wells drilled under the DrillCo agreement and is expected to
receive an 85% working interest in these wells until it achieves a 15% internal
rate of return on annual groupings of wells, while LINN Energy is expected to
receive a 15% carried working interest during this period. Upon reaching the
internal rate of return target, GSO's interest will be reduced to 5%, while LINN
Energy's interest will increase to 95%.
Alliance with Quantum Energy Partners
The Company signed definitive agreements dated June 30, 2015, with affiliates of
private capital investor Quantum Energy Partners ("Quantum") to fund selected
future oil and natural gas acquisitions and the development of those acquired
assets ("AcqCo"). See the Company's Current Report on Form 8-K filed on July 7,
2015, for additional details regarding this transaction.
Divestiture - Pending
On July 2, 2015, the Company, through certain of its wholly owned subsidiaries,
entered into a definitive purchase and sale agreement to sell its remaining
position in Howard County in the Permian Basin for a contract price of
approximately $281 million, subject to closing adjustments. The sale is
anticipated to close in the third quarter of 2015, subject to closing
conditions. There can be no assurance that all of the conditions to closing will
be satisfied. Upon completion of this sale, the Company will have divested all
of its remaining capital intensive, high-decline rate properties.
Financing Activities
The spring 2015 semi-annual borrowing base redetermination of the Company's
Credit Facilities, as defined in Note 6, was completed in May 2015, and the
borrowing base under the LINN Credit Facility decreased from $4.5 billion to
$4.05 billion and the borrowing base under the Berry Credit Facility decreased
from $1.4 billion to $1.2 billion as a result of lower commodity prices.
Continued low or further declining commodity prices, reductions in the Company's
capital budget and the resulting reserve write-downs, along with the maturity
schedule of the Company's hedges, are expected to result in further decreases in
both borrowing bases at the October 2015 redetermination and may also impact
future redeterminations.
In connection with the reduction in Berry's borrowing base, LINN Energy borrowed
$250 million under the LINN Credit Facility, which it contributed to Berry to
post as restricted cash with Berry's lenders. As directed by LINN Energy, the
$250 million was deposited on Berry's behalf in a security account with the
administrative agent subject to a security control agreement. Berry's ability to
withdraw funds from this account is subject to a concurrent reduction of the
borrowing base under the Berry Credit Facility or lender consent in connection
with a redetermination of such borrowing base. The $250 million may

                                       32

--------------------------------------------------------------------------------

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



be used to satisfy obligations under the Berry Credit Facility or, subject to
restrictions in the indentures governing Berry's senior notes, may be returned
to LINN Energy in the future.
During the six months ended June 30, 2015, the Company, under its equity
distribution agreement, sold 3,621,983 units representing limited liability
company interests at an average unit price of $12.37 for net proceeds of
approximately $44 million (net of approximately $448,000 in commissions). The
Company used the net proceeds for general corporate purposes including the open
market repurchases of a portion of its senior notes (see Note 6). At June 30,
2015, units totaling approximately $455 million in aggregate offering price
remained available to be sold under the agreement.
In May 2015, the Company sold 16,000,000 units representing limited liability
company interests in an underwritten public offering at $11.79 per unit ($11.32
per unit, net of underwriting discount) for net proceeds of approximately $181
million (after underwriting discount and offering costs of approximately $8
million). The Company used the net proceeds from the sale of these units to
repay a portion of the outstanding indebtedness under the LINN Credit Facility,
which included debt initially incurred to fund the open market repurchases of a
portion of its senior notes during 2015 (see Note 6).
During the six months ended June 30, 2015, the Company repurchased on the open
market approximately $184 million of its outstanding senior notes. In addition,
in July 2015, the Company repurchased through privately negotiated transactions
approximately $599 million of its outstanding senior notes. See Note 6 for
additional details.
Commodity Derivatives
During the six months ended June 30, 2015, the Company entered into commodity
derivative contracts consisting of natural gas basis swaps for May 2015 through
December 2017, to hedge exposure to differentials in certain producing areas,
and oil swaps for April 2015 through December 2015. In addition, the Company
entered into natural gas basis swaps for May 2015 through December 2016 to hedge
exposure to the differential in California, where it consumes natural gas in its
heavy oil development operations.

                                       33

--------------------------------------------------------------------------------

  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, 2015, Compared to Three Months Ended June 30, 2014
                                                    Three Months Ended
                                                         June 30,
                                                    2015           2014         Variance
                                                              (in thousands)
Revenues and other:
Natural gas sales                               $  149,908     $  205,050     $  (55,142 )
Oil sales                                          310,454        651,509       (341,055 )
NGL sales                                           36,057        111,291        (75,234 )
Total oil, natural gas and NGL sales               496,419        967,850       (471,431 )

Losses on oil and natural gas derivatives (191,188 ) (408,788 ) 217,600 Marketing and other revenues

                        16,597         37,889        (21,292 )
                                                   321,828        596,951       (275,123 )
Expenses:
Lease operating expenses                           140,652        184,901        (44,249 )
Transportation expenses                             55,795         44,854         10,941
Marketing expenses                                   9,159         23,274        (14,115 )
General and administrative expenses (1)             98,650         66,906         31,744
Exploration costs                                      564          1,551           (987 )
Depreciation, depletion and amortization           215,732        274,435        (58,703 )
Taxes, other than income taxes                      58,034         68,531        (10,497 )

(Gains) losses on sale of assets and other, net (17,996 ) 5,467 (23,463 )

                                                   560,590        669,919       (109,329 )
Other income and (expenses)                       (143,095 )     (136,849 )       (6,246 )
Loss before income taxes                          (381,857 )     (209,817 )     (172,040 )
Income tax benefit                                  (2,730 )       (1,947 )         (783 )
Net loss                                        $ (379,127 )   $ (207,870 )   $ (171,257 )

(1) General and administrative expenses for the three months ended June 30,

     2015, and June 30, 2014, include approximately $11 million and $9 million,
     respectively, of noncash unit-based compensation expenses.



                                       34

--------------------------------------------------------------------------------

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



                                             Three Months Ended
                                                  June 30,
                                              2015           2014       Variance
Average daily production:
Natural gas (MMcf/d)                            666             493       35  %
Oil (MBbls/d)                                  64.8            74.5      (13 )%
NGL (MBbls/d)                                  27.4            31.8      (14 )%
Total (MMcfe/d)                               1,219           1,131        8  %

Weighted average prices: (1)
Natural gas (Mcf)                        $     2.47        $   4.57      (46 )%
Oil (Bbl)                                $    52.65        $  96.06      (45 )%
NGL (Bbl)                                $    14.44        $  38.42      (62 )%

Average NYMEX prices:
Natural gas (MMBtu)                      $     2.64        $   4.67      (43 )%
Oil (Bbl)                                $    57.94        $ 102.99      (44 )%

Costs per Mcfe of production:
Lease operating expenses                 $     1.27        $   1.80      (29 )%
Transportation expenses                  $     0.50        $   0.44       14  %

General and administrative expenses (2) $ 0.89 $ 0.65 37 % Depreciation, depletion and amortization $ 1.94 $ 2.67 (27 )% Taxes, other than income taxes

           $     0.52        $   0.67      (22 )%


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


(2)  General and administrative expenses for the three months ended June 30,
     2015, and June 30, 2014, include approximately $11 million and $9 million,
     respectively, of noncash unit-based compensation expenses.




                                       35

--------------------------------------------------------------------------------

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

of Operations - Continued




Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales decreased by approximately $472 million or 49% to
approximately $496 million for the three months ended June 30, 2015, from
approximately $968 million for the three months ended June 30, 2014, due to
lower oil, natural gas and NGL prices partially offset by higher production
volumes. Lower oil, natural gas and NGL prices resulted in a decrease in
revenues of approximately $256 million, $127 million and $60 million,
respectively.
Average daily production volumes increased to approximately 1,219 MMcfe/d for
the three months ended June 30, 2015, from 1,131 MMcfe/d for the three months
ended June 30, 2014. Higher natural gas production volumes resulted in an
increase in revenues of approximately $72 million. Lower oil and NGL production
volumes resulted in a decrease in revenues of approximately $85 million and $16
million, respectively.
The following table sets forth average daily production by region:
                                        Three Months Ended
                                             June 30,
                                          2015           2014       Variance
Average daily production (MMcfe/d):
Rockies                                   445             278     167      60  %
Hugoton Basin                             255             151     104      69  %
California                                187             172      15       9  %
Mid-Continent                             100             297    (197 )   (66 )%
Permian Basin                              85             169     (84 )   (50 )%
TexLa                                      80              31      49     156  %
South Texas                                36               -      36       -
Michigan/Illinois                          31              33      (2 )    (5 )%
                                        1,219           1,131      88       8  %

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


                                       36

--------------------------------------------------------------------------------

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

of Operations - Continued

See below for details regarding capital expenditures for the periods presented:

                                                Three Months Ended
                                                     June 30,
                                                2015          2014
                                                  (in thousands)

Oil and natural gas                          $   99,430    $ 389,313
Plant and pipeline                                2,749        6,268
Other                                            12,614       10,932

Capital expenditures, excluding acquisitions $ 114,793 $ 406,513



Gains (Losses) on Oil and Natural Gas Derivatives
Losses on oil and natural gas derivatives were approximately $191 million for
the three months ended June 30, 2015, compared to approximately $409 million for
the three months ended June 30, 2014, representing a variance of approximately
$218 million. Losses on oil and natural gas derivatives were primarily due to
changes in fair value of the derivative contracts. The fair value on unsettled
derivatives contracts changes as future commodity price expectations change
compared to the contract prices on the derivatives. If the expected future
commodity prices increase compared to the contract prices on the derivatives,
losses are recognized; and if the expected future commodity prices decrease
compared to the contract prices on the derivatives, gains are recognized.
During the three months ended June 30, 2015, the Company had commodity
derivative contracts for approximately 78% of its natural gas production and 82%
of its oil production. During the three months ended June 30, 2014, the Company
had commodity derivative contracts for approximately 98% of its natural gas
production and 92% of its oil production. The Company does not hedge the portion
of natural gas production used to economically offset natural gas consumption
related to its heavy oil development operations in California.
The Company determines the fair value of its oil and natural gas derivatives
utilizing pricing models that use a variety of techniques, including market
quotes and pricing analysis. See Item 3. "Quantitative and Qualitative
Disclosures About Market Risk" and Note 7 and Note 8 for additional information
about the Company's commodity derivatives. For information about the Company's
credit risk related to derivative contracts, see "Counterparty Credit Risk"
under "Liquidity and Capital Resources" below.
Marketing and Other Revenues
Marketing revenues represent third-party activities associated with
company-owned gathering systems, plants and facilities. Marketing and other
revenues decreased by approximately $21 million or 56% to approximately $17
million for the three months ended June 30, 2015, from approximately $38 million
for the three months ended June 30, 2014. The decrease was primarily due to
lower revenues generated by the Jayhawk natural gas processing plant in Kansas,
lower electricity sales revenues generated by the Company's California
cogeneration facilities and the impact of properties sold during the fourth
quarter of 2014, partially offset by higher helium sales revenues in the Hugoton
Basin.
Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle,
supervision, maintenance, tools and supplies, and workover expenses. Lease
operating expenses decreased by approximately $44 million or 24% to
approximately $141 million for the three months ended June 30, 2015, from
approximately $185 million for the three months ended June 30, 2014. The
decrease was primarily due to lower costs as a result of the properties sold
during the fourth quarter of 2014, a decrease in steam costs caused by a lower
price of natural gas used in steam generation and cost savings initiatives,
partially offset by costs associated with properties acquired during the third
quarter of 2014. Lease operating expenses per Mcfe also decreased to $1.27 per
Mcfe for the three months ended June 30, 2015, from $1.80 per Mcfe for the three
months ended June 30, 2014.

                                       37

--------------------------------------------------------------------------------

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



Transportation Expenses
Transportation expenses increased by approximately $11 million or 24% to
approximately $56 million for the three months ended June 30, 2015, from
approximately $45 million for the three months ended June 30, 2014. The increase
was primarily due to costs associated with properties acquired during the third
quarter of 2014 partially offset by lower costs as a result of the properties
sold during the fourth quarter of 2014. Transportation expenses per Mcfe also
increased to $0.50 per Mcfe for the three months ended June 30, 2015, from $0.44
per Mcfe for the three months ended June 30, 2014.
Marketing Expenses
Marketing expenses represent third-party activities associated with
company-owned gathering systems, plants and facilities. Marketing expenses
decreased by approximately $14 million or 61% to approximately $9 million for
the three months ended June 30, 2015, from approximately $23 million for the
three months ended June 30, 2014. The decrease was primarily due to lower
expenses associated with the Jayhawk natural gas processing plant in Kansas and
lower electricity generation expenses incurred by the Company's California
cogeneration facilities.
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field
operations and reflect the costs of employees including executive officers,
related benefits, office leases and professional fees. General and
administrative expenses increased by approximately $32 million or 47% to
approximately $99 million for the three months ended June 30, 2015, from
approximately $67 million for the three months ended June 30, 2014. The increase
was primarily due to higher advisory fees related to the alliance agreements and
higher salaries and benefits related expenses, principally driven by severance
costs. General and administrative expenses per Mcfe also increased to $0.89 per
Mcfe for the three months ended June 30, 2015, from $0.65 per Mcfe for the three
months ended June 30, 2014.
Exploration Costs
Exploration costs decreased by approximately $1 million or 64% to approximately
$564,000 for the three months ended June 30, 2015, from approximately $2 million
for the three months ended June 30, 2014. The decrease was primarily due to
lower leasehold impairment expenses on unproved properties.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $58 million
or 21% to approximately $216 million for the three months ended June 30, 2015,
from approximately $274 million for the three months ended June 30, 2014. The
decrease was primarily due to the 2014 divestitures of properties with higher
rates compared to the rates of properties acquired in 2014, as well as lower
rates as a result of the impairments recorded in the prior year and the first
quarter of 2015, partially offset by higher total production volumes.
Depreciation, depletion and amortization per Mcfe also decreased to $1.94 per
Mcfe for the three months ended June 30, 2015, from $2.67 per Mcfe for the three
months ended June 30, 2014.
Taxes, Other Than Income Taxes
                                Three Months Ended
                                     June 30,
                                 2015         2014       Variance
                                         (in thousands)

Severance taxes              $    20,676    $ 35,765    $ (15,089 )
Ad valorem taxes                  31,780      28,046        3,734

California carbon allowances 5,548 4,607 941 Other

                                 30         113          (83 )
                             $    58,034    $ 68,531    $ (10,497 )


Taxes, other than income taxes decreased by approximately $10 million or 15% for the three months ended June 30, 2015, compared to the three months ended June 30, 2014. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to acquisitions completed during the third quarter of 2014. California carbon allowances increased primarily due to an


                                       38

--------------------------------------------------------------------------------

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

of Operations - Continued




increase in estimated emissions for which credits are needed, caused by
production increases and higher costs for acquired allowances.
Other Income and (Expenses)
                                                 Three Months Ended
                                                      June 30,
                                                 2015           2014        Variance
                                                          (in thousands)

Interest expense, net of amounts capitalized $ (146,100 ) $ (134,300 ) $ (11,800 ) Gain on extinguishment of debt

                    9,151              -         9,151
Other, net                                       (6,146 )       (2,549 )      (3,597 )
                                             $ (143,095 )   $ (136,849 )   $  (6,246 )


Other income and (expenses) increased by approximately $6 million for the three
months ended June 30, 2015, compared to the three months ended June 30, 2014.
Interest expense increased primarily due to higher outstanding debt during the
period and higher amortization of financing fees and expenses associated with
the senior notes issued in September 2014 and amendments made to the Company's
Credit Facilities during 2014. For the three months ended June 30, 2015, the
Company recorded a gain on extinguishment of debt of approximately $9 million as
a result of the repurchases of a portion of its senior notes. See "Debt" under
"Liquidity and Capital Resources" below for additional details. Other expenses
increased primarily due to write-offs of deferred financing fees related to the
Credit Facilities during 2015.
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 $3 million and $2 million for the three months ended
June 30, 2015, and June 30, 2014, respectively. The income tax benefit increased
primarily due to lower income from the Company's taxable subsidiaries during the
three months ended June 30, 2015, compared to the same period in 2014.
Net Income (Loss)
Net loss increased by approximately $171 million or 82% to approximately $379
million for the three months ended June 30, 2015, from approximately $208
million for the three months ended June 30, 2014. The increase was primarily due
to lower production revenues, partially offset by decreased losses on oil and
natural gas derivatives and lower expenses. See discussions above for
explanations of variances.

                                       39

--------------------------------------------------------------------------------

  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, 2015, Compared to Six Months Ended June 30, 2014
                                                       Six Months Ended
                                                           June 30,
                                                      2015           2014         Variance
                                                                (in thousands)
Revenues and other:
Natural gas sales                                 $  322,004     $  431,739     $ (109,735 )
Oil sales                                            545,691      1,247,154       (701,463 )
NGL sales                                             79,293        227,834       (148,541 )
Total oil, natural gas and NGL sales                 946,988      1,906,727       (959,739 )
Gains (losses) on oil and natural gas derivatives    233,593       (650,281 )      883,874
Marketing and other revenues                          57,794         74,092        (16,298 )
                                                   1,238,375      1,330,538        (92,163 )
Expenses:
Lease operating expenses                             313,673        378,934        (65,261 )
Transportation expenses                              109,335         90,484         18,851
Marketing expenses                                    38,000         44,346         (6,346 )
General and administrative expenses (1)              177,618        146,134         31,484
Exploration costs                                        960          2,642         (1,682 )
Depreciation, depletion and amortization             430,746        542,236       (111,490 )
Impairment of long-lived assets                      532,617              -        532,617
Taxes, other than income taxes                       112,079        134,244        (22,165 )

(Gains) losses on sale of assets and other, net (30,283 ) 8,053 (38,336 )

                                                   1,684,745      1,347,073        337,672
Other income and (expenses)                         (281,774 )     (272,965 )       (8,809 )
Loss before income taxes                            (728,144 )     (289,500 )     (438,644 )
Income tax expense (benefit)                          (9,857 )        3,707        (13,564 )
Net loss                                          $ (718,287 )   $ (293,207 )   $ (425,080 )

(1) General and administrative expenses for both the six months ended June 30,

     2015, and June 30, 2014, include approximately $28 million of noncash
     unit-based compensation expenses.



                                       40

--------------------------------------------------------------------------------

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



                                            Six Months Ended
                                                June 30,
                                            2015        2014       Variance
Average daily production:
Natural gas (MMcf/d)                           659         487       35  %
Oil (MBbls/d)                                 63.8        72.9      (12 )%
NGL (MBbls/d)                                 28.1        32.2      (13 )%
Total (MMcfe/d)                              1,210       1,117        8  %

Weighted average prices: (1)
Natural gas (Mcf)                        $    2.70    $   4.90      (45 )%
Oil (Bbl)                                $   47.27    $  94.55      (50 )%
NGL (Bbl)                                $   15.58    $  39.14      (60 )%

Average NYMEX prices:
Natural gas (MMBtu)                      $    2.81    $   4.80      (41 )%
Oil (Bbl)                                $   53.29    $ 100.84      (47 )%

Costs per Mcfe of production:
Lease operating expenses                 $    1.43    $   1.87      (24 )%
Transportation expenses                  $    0.50    $   0.45       11  %

General and administrative expenses (2) $ 0.81 $ 0.72 13 % Depreciation, depletion and amortization $ 1.97 $ 2.68 (26 )% Taxes, other than income taxes

           $    0.51    $   0.66      (23 )%


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


(2)  General and administrative expenses for both the six months ended June 30,
     2015, and June 30, 2014, include approximately $28 million of noncash
     unit-based compensation expenses.



                                       41

--------------------------------------------------------------------------------

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

of Operations - Continued




Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales decreased by approximately $960 million or 50% to
approximately $947 million for the six months ended June 30, 2015, from
approximately $1.9 billion for the six months ended June 30, 2014, due to lower
oil, natural gas and NGL prices partially offset by higher production volumes.
Lower oil, natural gas and NGL prices resulted in a decrease in revenues of
approximately $545 million, $262 million and $120 million, respectively.
Average daily production volumes increased to approximately 1,210 MMcfe/d for
the six months ended June 30, 2015, from 1,117 MMcfe/d for the six months ended
June 30, 2014. Higher natural gas production volumes resulted in an increase in
revenues of approximately $152 million. Lower oil and NGL production volumes
resulted in a decrease in revenues of approximately $156 million and $29
million, respectively.
The following table sets forth average daily production by region:
                                       Six Months Ended
                                           June 30,
                                         2015         2014       Variance
Average daily production (MMcfe/d):
Rockies                                  434           275     159      58  %
Hugoton Basin                            251           147     104      70  %
California                               189           164      25      15  %
Mid-Continent                            101           300    (199 )   (66 )%
Permian Basin                             90           167     (77 )   (46 )%
TexLa                                     79            31      48     152  %
South Texas                               35             -      35       -
Michigan/Illinois                         31            33      (2 )    (6 )%
                                       1,210         1,117      93       8  %

The increase in average daily production volumes in the Rockies region primarily reflects the impact of the Devon Assets Acquisition on August 29, 2014, and development capital spending. The increase in average daily production volumes in the Hugoton Basin region primarily reflects the impact of the properties received in the exchange with Exxon XTO on August 15, 2014, and the Pioneer Assets Acquisition on September 11, 2014. The increase in average daily production volumes in the California region primarily reflects the impact of the properties received in the exchange with ExxonMobil on November 21, 2014, and development capital spending. The decrease in average daily production volumes in the Mid-Continent region primarily reflects lower production volumes as a result of the Granite Wash Assets Sale on December 15, 2014, partially offset by the impact of the Devon Assets Acquisition. The decrease in average daily production volumes in the Permian Basin region primarily reflects lower production volumes as a result of the properties relinquished in the two exchanges with Exxon XTO and ExxonMobil and the properties sold in the Permian Basin Assets Sale on November 14, 2014. The increase in average daily production volumes in the TexLa region primarily reflects the impact of the Devon Assets Acquisition. Average daily production volumes in the South Texas region reflect the impact of the Devon Assets Acquisition. The decrease in average daily production volumes in the Michigan/Illinois region primarily reflects a low-decline asset base and minimal development capital spending.


                                       42

--------------------------------------------------------------------------------

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

of Operations - Continued

See below for details regarding capital expenditures for the periods presented:

                                                Six Months Ended
                                                    June 30,
                                                2015         2014
                                                 (in thousands)

Oil and natural gas                          $ 282,403    $ 786,513
Plant and pipeline                               5,002       11,663
Other                                           24,175       17,777

Capital expenditures, excluding acquisitions $ 311,580 $ 815,953



Gains (Losses) on Oil and Natural Gas Derivatives
Gains on oil and natural gas derivatives were approximately $234 million for the
six months ended June 30, 2015, compared to losses of approximately $650 million
for the six months ended June 30, 2014, representing a variance of approximately
$884 million. Gains on oil and natural gas derivatives were primarily due to
changes in fair value of the derivative contracts. The fair value on unsettled
derivatives contracts changes as future commodity price expectations change
compared to the contract prices on the derivatives. If the expected future
commodity prices increase compared to the contract prices on the derivatives,
losses are recognized; and if the expected future commodity prices decrease
compared to the contract prices on the derivatives, gains are recognized.
During the six months ended June 30, 2015, the Company had commodity derivative
contracts for approximately 79% of its natural gas production and 76% of its oil
production. During the six months ended June 30, 2014, the Company had commodity
derivative contracts for approximately 100% of its natural gas production and
94% of its oil production. The Company does not hedge the portion of natural gas
production used to economically offset natural gas consumption related to its
heavy oil development operations in California.
The Company determines the fair value of its oil and natural gas derivatives
utilizing pricing models that use a variety of techniques, including market
quotes and pricing analysis. See Item 3. "Quantitative and Qualitative
Disclosures About Market Risk" and Note 7 and Note 8 for additional information
about the Company's commodity derivatives. For information about the Company's
credit risk related to derivative contracts, see "Counterparty Credit Risk"
under "Liquidity and Capital Resources" below.
Marketing and Other Revenues
Marketing revenues represent third-party activities associated with
company-owned gathering systems, plants and facilities. Marketing and other
revenues decreased by approximately $16 million or 22% to approximately $58
million for the six months ended June 30, 2015, from approximately $74 million
for the six months ended June 30, 2014. The decrease was primarily due to lower
electricity sales revenues generated by the Company's California cogeneration
facilities, lower revenues generated by the Jayhawk natural gas processing plant
in Kansas and the impact of properties sold during the fourth quarter of 2014,
partially offset by higher helium sales in the Hugoton Basin.
Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle,
supervision, maintenance, tools and supplies, and workover expenses. Lease
operating expenses decreased by approximately $65 million or 17% to
approximately $314 million for the six months ended June 30, 2015, from
approximately $379 million for the six months ended June 30, 2014. The decrease
was primarily due to lower costs as a result of the properties sold during the
fourth quarter of 2014, a decrease in steam costs caused by a lower price of
natural gas used in steam generation and cost savings initiatives, partially
offset by costs associated with properties acquired during the third quarter of
2014. Lease operating expenses per Mcfe also decreased to $1.43 per Mcfe for the
six months ended June 30, 2015, from $1.87 per Mcfe for the six months ended
June 30, 2014.

                                       43

--------------------------------------------------------------------------------

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



Transportation Expenses
Transportation expenses increased by approximately $19 million or 21% to
approximately $109 million for the six months ended June 30, 2015, from
approximately $90 million for the six months ended June 30, 2014. The increase
was primarily due to costs associated with properties acquired during the third
quarter of 2014 partially offset by lower costs as a result of the properties
sold during the fourth quarter of 2014. Transportation expenses per Mcfe also
increased to $0.50 per Mcfe for the six months ended June 30, 2015, from $0.45
per Mcfe for the six months ended June 30, 2014.
Marketing Expenses
Marketing expenses represent third-party activities associated with
company-owned gathering systems, plants and facilities. Marketing expenses
decreased by approximately $6 million or 14% to approximately $38 million for
the six months ended June 30, 2015, from approximately $44 million for the six
months ended June 30, 2014. The decrease was primarily due to lower electricity
generation expenses incurred by the Company's California cogeneration facilities
and lower expenses associated with the Jayhawk natural gas processing plant in
Kansas.
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 $32 million or 22% to
approximately $178 million for the six months ended June 30, 2015, from
approximately $146 million for the six months ended June 30, 2014. The increase
was primarily due to higher advisory fees related to the alliance agreements and
higher salaries and benefits related expenses, principally driven by severance
costs. General and administrative expenses per Mcfe also increased to $0.81 per
Mcfe for the six months ended June 30, 2015, from $0.72 per Mcfe for the six
months ended June 30, 2014.
Exploration Costs
Exploration costs decreased by approximately $2 million or 64% to approximately
$1 million for the six months ended June 30, 2015, from approximately $3 million
for the six months ended June 30, 2014. The decrease was primarily due to lower
leasehold impairment expenses on unproved properties.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $111 million
or 21% to approximately $431 million for the six months ended June 30, 2015,
from approximately $542 million for the six months ended June 30, 2014. The
decrease was primarily due to the 2014 divestitures of properties with higher
rates compared to the rates of properties acquired in 2014, as well as lower
rates as a result of the impairments recorded in the prior year and the first
quarter of 2015, partially offset by higher total production volumes.
Depreciation, depletion and amortization per Mcfe also decreased to $1.97 per
Mcfe for the six months ended June 30, 2015, from $2.68 per Mcfe for the six
months ended June 30, 2014.
Impairment of Long-Lived Assets
The Company recorded no impairment charges for the three months ended June 30,
2015, or the six months ended June 30, 2014. During the first quarter of 2015,
the Company recorded noncash impairment charges, before and after tax, of
approximately $533 million associated with proved oil and natural gas
properties. The impairment was due to a decline in commodity prices. Following
are the impairment charges recorded:
• Shallow Texas Panhandle Brown Dolomite formation - $278 million;


California region - $207 million;

TexLa region - $33 million;

South Texas region - $9 million; and

• Mid-Continent region - $6 million.




                                       44

--------------------------------------------------------------------------------

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


Taxes, Other Than Income Taxes

                                 Six Months Ended
                                     June 30,
                                2015          2014       Variance
                                         (in thousands)

Severance taxes              $  34,566     $  67,881    $ (33,315 )
Ad valorem taxes                65,896        57,122        8,774

California carbon allowances 11,699 9,126 2,573 Other

                              (82 )         115         (197 )
                             $ 112,079     $ 134,244    $ (22,165 )


Taxes, other than income taxes decreased by approximately $22 million or 17% for the six months ended June 30, 2015, compared to the six months ended June 30, 2014. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to acquisitions completed during the third quarter of 2014. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed, caused by production increases and higher costs for acquired allowances. Other Income and (Expenses)

                                                  Six Months Ended
                                                      June 30,
                                                 2015           2014        Variance
                                                          (in thousands)

Interest expense, net of amounts capitalized $ (289,201 ) $ (268,113 ) $ (21,088 ) Gain on extinguishment of debt

                   15,786              -        15,786
Other, net                                       (8,359 )       (4,852 )      (3,507 )
                                             $ (281,774 )   $ (272,965 )   $  (8,809 )


Other income and (expenses) increased by approximately $9 million for the six
months ended June 30, 2015, compared to the six months ended June 30, 2014.
Interest expense increased primarily due to higher outstanding debt during the
period and higher amortization of financing fees and expenses associated with
the senior notes issued in September 2014 and amendments made to the Company's
Credit Facilities during 2014. For the six months ended June 30, 2015, the
Company recorded a gain on extinguishment of debt of approximately $16 million
as a result of the repurchases of a portion of its senior notes. See "Debt"
under "Liquidity and Capital Resources" below for additional details. Other
expenses increased primarily due to write-offs of deferred financing fees
related to the Credit Facilities during 2015.
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 $10 million for the six months ended June 30, 2015,
compared to income tax expense of approximately $4 million for the six months
ended June 30, 2014. The income tax benefit was primarily due to lower income
from the Company's taxable subsidiaries during the six months ended June 30,
2015, compared to the same period in 2014.

                                       45

--------------------------------------------------------------------------------

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



Net Income (Loss)
Net loss increased by approximately $425 million or 145% to approximately $718
million for the six months ended June 30, 2015, from approximately $293 million
for the six months ended June 30, 2014. The increase was primarily due to lower
production revenues and higher impairment charges, partially offset by higher
gains on oil and natural gas derivatives and lower expenses. See discussions
above for explanations of variances.
Liquidity and Capital Resources
The Company utilizes funds from debt and equity offerings, borrowings under its
Credit Facilities and net cash provided by operating activities for capital
resources and liquidity. To date, the primary use of capital has been for
acquisitions and the development of oil and natural gas properties. For the six
months ended June 30, 2015, the Company's total capital expenditures, excluding
acquisitions, were approximately $312 million. For 2015, the Company estimates
its total capital expenditures, excluding acquisitions, will be approximately
$610 million, including approximately $530 million related to its oil and
natural gas capital program and approximately $40 million related to its plant
and pipeline capital. This estimate reflects amounts for the development of
properties associated with acquisitions (see Note 2), is under continuous review
and subject to ongoing adjustments. The Company expects to fund the capital
expenditures primarily with net cash provided by operating activities. At
June 30, 2015, there was approximately $1.5 billion of available borrowing
capacity under the LINN Credit Facility but less than $1 million available under
the Berry Credit Facility, each as defined in Note 6.
The spring 2015 semi-annual borrowing base redetermination of the Company's
Credit Facilities was completed in May 2015, and the borrowing base under the
LINN Credit Facility decreased from $4.5 billion to $4.05 billion and the
borrowing base under the Berry Credit Facility decreased from $1.4 billion to
$1.2 billion as a result of lower commodity prices. In connection with the
reduction in Berry's borrowing base, LINN Energy borrowed $250 million under the
LINN Credit Facility, which it contributed to Berry to post as restricted cash
with Berry's lenders. As directed by LINN Energy, the $250 million was deposited
on Berry's behalf in a security account with the administrative agent subject to
a security control agreement. Berry's ability to withdraw funds from this
account is subject to a concurrent reduction of the borrowing base under the
Berry Credit Facility or lender consent in connection with a redetermination of
such borrowing base. The $250 million may be used to satisfy obligations under
the Berry Credit Facility or, subject to restrictions in the indentures
governing Berry's senior notes, may be returned to LINN Energy in the future.
As the Company pursues growth, it continually monitors the capital resources
available to meet future financial obligations and planned capital expenditures.
The Company's future success in growing reserves and production volumes will be
highly dependent on the capital resources available and its success in drilling
for or acquiring additional reserves. The Company actively reviews acquisition
opportunities on an ongoing basis. If the Company were to make significant
additional acquisitions for cash, it would need to borrow additional amounts
under its Credit Facilities, if available, or obtain additional debt or equity
financing. The Company's Credit Facilities and indentures governing its senior
notes impose certain restrictions on the Company's ability to obtain additional
debt financing. Based upon current expectations, the Company believes its
liquidity and capital resources will be sufficient to conduct its business and
operations.

© Edgar Online, source Glimpses

React to this article
Latest news on LINN ENERGY LLC
07/30 LINN ENERGY : Management's Discussion and Analysis of Financial Condition and Re..
07/30 Oil companies slash spending, jobs as prices slide for second time
07/30 LINN ENERGY : Results of Operations and Financial Condition (form 8-K)
07/09 LINN ENERGY : Entry into a Material Definitive Agreement (form 8-K)
07/09 LINN ENERGY LLC : ex-dividend day
07/07 LINN ENERGY : Entry into a Material Definitive Agreement (form 8-K)
07/07 LINN ENERGY : Announces Sale of Remaining Permian Basin Wolfcamp Acreage for $28..
07/07 LINN ENERGY : secures up to $500 million funding from GSO Partners
07/07 LINN ENERGY : sells remaining Permian basin acreage for $281 million
07/07 LINN ENERGY : Energy News Roundup: European Cities Going Green, Japan Turns To R..
Advertisement
Chart
Duration : Period :
Linn Energy LLC Technical Analysis Chart | LINE | US5360201009 | 4-Traders
Income Statement Evolution
More Financials