LINN ENERGY, LLC - 10-K - Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion and analysis should be read in conjunction with the
financial statements and related notes, 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 based on expectations,
estimates and assumptions. Actual results may differ materially from those
discussed in the 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"
in Item 1. "Business" and in Item 1A. "Risk Factors."
When referring to Linn Energy, LLC ("LINN Energy" or the "Company"), the intent
is to refer to LINN Energy and its consolidated subsidiaries as a whole or on an
individual basis, depending on the context in which the statements are made.
The 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."):
• Hugoton Basin, which includes properties located in
Kansas
, the
Oklahoma
Panhandle and the Shallow Texas Panhandle;
• 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);
•
California
, which includes properties located in the
San Joaquin Valley
and
Los Angeles
basins;
• TexLa, which includes properties located in east
Texas
and north
Louisiana
;
• Mid-Continent, which includes
Oklahoma
properties located in the
Anadarko
and
Arkoma
basins, as well as waterfloods in the Central Oklahoma Platform;
•
Michigan
/
Illinois
, which includes properties located in the Antrim Shale
formation in north
Michigan
and oil properties in south
Illinois
;
• Permian Basin, which includes properties located in west
Texas
and southeast
New Mexico
; and
•
South Texas
.
For a discussion of the Company's eight operating regions, see Item 1 "Business." Results for the year ended December 31, 2015, included the following: • oil, natural gas and NGL sales of approximately $1.7 billion compared to
$3.6 billion for 2014;
• average daily production of approximately 1,188 MMcfe/d compared to 1,210
MMcfe/d for 2014;
• net loss of approximately $4.8 billion compared to $452 million for 2014;
• net cash provided by operating activities of approximately $1.2 billion
compared to $1.7 billion for 2014;
• capital expenditures, excluding acquisitions, of approximately $518 million
compared to $1.6 billion for 2014; and
• 589 wells drilled (584 successful) compared to 918 wells drilled (917
successful) for 2014.
Process to Explore Strategic Alternatives Related to the Company's Capital
Structure
In February 2016, the Company announced that it had initiated a process to
explore strategic alternatives to strengthen its balance sheet and maximize the
value of the Company. The Company's Board of Directors and management are in the
process of evaluating strategic alternatives to help provide the Company with
financial stability, but no assurance can be given as to the outcome or timing
of this process. The Company has retained Lazard as its financial advisor and
Kirkland & Ellis LLP as its legal advisor to assist the Board of Directors and
management team with the strategic review process.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
Going Concern Uncertainty
The Company's liquidity outlook has changed since the third quarter of 2015 due
to continued low commodity prices, which are expected to result in significantly
lower levels of cash flow from operating activities in the future as the
Company's current commodity derivative contracts expire, and have limited the
Company's ability to access the capital markets. In addition, each of the
Company's Credit Facilities is subject to scheduled redeterminations of its
borrowing base, semi-annually in April and October, based primarily on reserve
reports using lender commodity price expectations at such time. Continued low
commodity prices, reductions in the Company's capital budget and the resulting
reserve write-downs, along with the maturity schedule of the Company's hedges,
are expected to adversely impact the upcoming April redeterminations and will
likely have a significant negative impact on the Company's liquidity.
As a result of these and other factors, the following issues have adversely
impacted the Company's ability to continue as a going concern:
• the Company's ability to comply with financial covenants and ratios in its
Credit Facilities and indentures has been affected by continued low
commodity prices. Absent a waiver or amendment, failure to meet these
covenants and ratios would result in a default and, to the extent the
applicable lenders so elect, an acceleration of the Company's existing
indebtedness, causing such debt of approximately $3.6 billion to be
immediately due and payable. Based on the Company's current estimates and
expectations for commodity prices in 2016, the Company does not expect to
remain in compliance with all of the restrictive covenants contained in
its Credit Facilities throughout 2016 unless those requirements are waived
or amended. The Company does not currently have adequate liquidity to
repay all of its outstanding debt in full if such debt were accelerated;
• because the Credit Facilities are effectively fully drawn, any reduction
of the borrowing bases under the Company's Credit Facilities would require
mandatory prepayments to the extent existing indebtedness exceeds the new
borrowing bases. The Company may not have sufficient cash on hand to be
able to make any such mandatory prepayments; and
• the Company's ability to make interest payments as they become due and
repay indebtedness upon maturities (whether under existing terms or as a
result of acceleration) is impacted by the Company's liquidity. As of
February 29, 2016, there was less than $1 million of available borrowing
capacity under the Credit Facilities.
The Company's Board of Directors and management are in the process of evaluating
strategic alternatives to help provide the Company with financial stability, but
no assurance can be given as to the outcome or timing of this process.
The report of the Company's independent registered public accounting firm that
accompanies its audited consolidated financial statements in this Annual Report
on Form 10-K contains an explanatory paragraph regarding the substantial doubt
about the Company's ability to continue as a going concern. The consolidated
financial statements do not include any adjustments that might result from the
outcome of the going concern uncertainty.
The Company's Credit Facilities contain the requirement to deliver audited
consolidated financial statements without a going concern or like qualification
or exception. Consequently, as of the filing date, March 15, 2016, the Company
is in default under the LINN Credit Facility. If the Company is unable to obtain
a waiver or other suitable relief from the lenders under the LINN Credit
Facility prior to the expiration of the 30 day grace period, an Event of Default
(as defined in the applicable agreements) will result and the lenders holding a
majority of the commitments under the LINN Credit Facility could accelerate the
outstanding indebtedness, which would make it immediately due and payable. If
the Company is unable to obtain a waiver from or otherwise reach an agreement
with the lenders under the LINN Credit Facility and the indebtedness under the
LINN Credit Facility is accelerated, then an Event of Default under LINN
Energy's senior notes and second lien notes would occur, which, if it continues
beyond any applicable cure periods, would, to the extent the applicable lenders
so elect, result in the acceleration of those obligations. Furthermore, an Event
of Default under the LINN Credit Facility will also result in an Event of
Default under the Berry Credit Facility, which in the absence of a waiver or
other suitable relief and upon the election of the agent or lenders holding a
majority of commitments under the Berry Credit Facility would result in the
acceleration of indebtedness under the Berry Credit Facility. Such Event of
Default would trigger an Event of Default under the Berry senior notes. If such
Event of Default continues beyond any applicable cure periods, such Event of
Default would result in an acceleration of the Berry senior notes.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
Additionally, the indenture governing the second lien notes ("Second Lien
Indenture") required the Company to deliver mortgages by February 18, 2016,
subject to a 45 day grace period. The Company elected to exercise its right to
the grace period and not deliver the mortgages, and as a result, the Company is
currently in default under the Second Lien Indenture. If the Company does not
deliver the mortgages within the 45 day grace period or is otherwise unable to
obtain a waiver or other suitable relief from the holders under the Second Lien
Indenture prior to the expiration of the 45 day grace period, an Event of
Default (as defined in the Second Lien Indenture) will result and if the trustee
or noteholders holding at least 25% in the aggregate outstanding principal
amount of the second lien notes so elect would accelerate the second lien notes
causing them to be immediately due and payable.
Furthermore, the Company has decided to defer making interest payments totaling
approximately $60 million due March 15, 2016, including approximately $30
million on LINN Energy's 7.75% senior notes due February 2021, approximately $12
million on LINN Energy's 6.50% senior notes due September 2021 and approximately
$18 million on Berry's senior notes due September 2022, which will result in the
Company being in default under these senior notes. The indentures governing each
of the applicable series of notes permit the Company a 30 day grace period to
make the interest payments. If the Company fails to make the interest payments
within the grace period, or is otherwise unable to obtain a waiver or suitable
relief from the holders of these senior notes, an Event of Default will result
and if the trustee or noteholders holding at least 25% in the aggregate
outstanding principal amount of each series of notes so elect would accelerate
the notes causing them to be immediately due and payable.
An Event of Default under the Second Lien Indenture or any of the indentures
governing the senior notes triggers a cross-default under the LINN Credit
Facility and Berry Credit Facility and, as discussed above, if the applicable
lenders so elect would result in acceleration under the LINN Credit Facility and
Berry Credit Facility. In addition, as discussed above, an acceleration of the
obligations under the Second Lien Indenture or LINN Credit Facility would
trigger a cross-default to LINN Energy's senior notes and if the applicable
lenders so elect would result in a cross-acceleration under LINN Energy's senior
notes, and an acceleration of the Berry Credit Facility if the applicable
lenders so elect would result in cross-acceleration under the Berry senior
notes.
If lenders, and subsequently noteholders, accelerate the Company's outstanding
indebtedness, it will become immediately due and payable and the Company will
not have sufficient liquidity to repay those amounts. If the Company is unable
to reach an agreement with its creditors prior to any of the above described
accelerations, the Company could be required to immediately file for protection
under Chapter 11 of the
U.S.
Bankruptcy Code.
The Company is currently in discussions with various stakeholders and is
pursuing or considering a number of actions including: (i) obtaining additional
sources of capital from asset sales, private issuances of equity or
equity-linked securities, debt for equity swaps, or any combination thereof;
(ii) pursuing in- and out-of-court restructuring transactions; (iii) obtaining
waivers or amendments from its lenders; and (iv) continuing to minimize its
capital expenditures, reduce costs and maximize cash flows from operations.
There can be no assurance that sufficient liquidity can be obtained from one or
more of these actions or that these actions can be consummated within the period
needed.
Reduction and Suspension of Distribution
In January 2015, the Company reduced its distribution to $1.25 per unit, from
the previous level of $2.90 per unit, on an annualized basis. Monthly
distributions were paid by the Company through September 2015. In October 2015,
following the recommendation from management, the Company's Board of Directors
determined to suspend payment of the Company's distribution and reserve any
excess cash that would otherwise be available for distribution. The Company's
Board of Directors and management believe the suspension to be in the best
long-term interest of all Company stakeholders. The Company's Board of Directors
will continue to evaluate the Company's ability to reinstate the distribution.
For additional information, see "Distribution Practices" below.
2016 Oil and Natural Gas Capital Budget
For 2016, the Company estimates its total capital expenditures, excluding
acquisitions, will be approximately $340 million, including approximately $250
million related to its oil and natural gas capital program and approximately $75
million related to its plant and pipeline capital. The 2016 budget contemplates
continued low commodity prices and is under continuous review and subject to
ongoing adjustments. The Company expects to fund its capital expenditures
primarily from net cash
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
provided by operating activities; however, there is uncertainty regarding the
Company's liquidity as discussed above. In addition, at this level of capital
spending, the Company expects its total reserves to decline.
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 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%. As of December 31, 2015, no development
activities had been funded under the agreement.
Alliance with Quantum Energy Partners
The Company signed definitive agreements dated June 30, 2015, with affiliates of
private capital investor Quantum Energy Partners to fund selected future oil and
natural gas acquisitions and the development of those acquired assets ("AcqCo").
See the Company's Current Report on Form 8-K filed on July 7, 2015, for
additional details regarding these agreements.
Divestiture
On August 31, 2015, the Company, through certain of its wholly owned
subsidiaries, completed the sale of its remaining position in
Howard County
in
the Permian Basin ("Howard County Assets Sale"). Cash proceeds received from the
sale of these properties were approximately $276 million. The Company used the
net proceeds from the sale to repay a portion of the outstanding indebtedness
under the LINN Credit Facility.
Financing Activities
In February 2016, the Company borrowed approximately $919 million under the LINN
Credit Facility, which represented the remaining undrawn amount that was
available under the LINN Credit Facility, the proceeds of which were deposited
in an unencumbered account with a bank that is not a lender under either the
LINN or Berry Credit Facility. These funds are intended to be used for general
corporate purposes. As of February 29, 2016, total borrowings (including
outstanding letters of credit) under the LINN Credit Facility were $3.6 billion
with no remaining availability. Total borrowings under the Berry Credit Facility
were approximately $899 million with less than $1 million available.
In November 2015, the Company entered into separate, privately-negotiated,
exchange agreements ("Exchange Agreements") with certain holders of the
Company's outstanding 6.50% senior notes due May 2019, 6.25% senior notes due
November 2019, 8.625% senior notes due April 2020, 7.75% senior notes due
February 2021 and 6.50% senior notes due September 2021 ("Exchanged Notes"). The
Exchange Agreements provided that the Company issue $1.0 billion in aggregate
principal amount of new 12.00% senior secured second lien notes due December
2020 ("Second Lien Notes") in exchange for approximately $2.0 billion in
aggregate principal amount of the Company's Exchanged Notes held by such
holders.
In addition, during the year ended December 31, 2015, the Company repurchased at
a discount, through privately negotiated transactions and on the open market,
approximately $992 million of its outstanding senior notes.
The spring 2015 semi-annual borrowing base redeterminations of the Company's
Credit Facilities, as defined in Note 6, were completed in May 2015 and, as a
result of lower commodity prices, the borrowing base under the LINN Credit
Facility decreased from $4.5 billion to $4.05 billion and the borrowing base
under the Berry Credit Facility decreased from $1.4 billion to $1.2 billion,
including $250 million posted as restricted cash (discussed below). The fall
2015 semi-annual redeterminations were completed in October 2015 and the
borrowing base under the LINN Credit Facility was reaffirmed at $4.05 billion,
subject to certain conditions being met on or before January 1, 2016, and the
borrowing base under the Berry Credit Facility decreased from $1.2 billion to
$900 million, including the $250 million of restricted cash. In connection with
the reduction in Berry's borrowing base in October 2015, Berry repaid $300
million of borrowings outstanding under the
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
Berry Credit Facility. The borrowing base under the LINN Credit Facility
automatically decreased to $3.6 billion on January 1, 2016, since certain
conditions were not met. Also, in October 2015, LINN Energy and Berry each
entered into an amendment to its Credit Facility.
Continued low commodity prices, reductions in the Company's capital budget and
the resulting reserve write-downs, along with the maturity schedule of the
Company's hedges, are expected to adversely impact future redeterminations.
In connection with the reduction in Berry's borrowing base in May 2015, LINN
Energy borrowed $250 million under the LINN Credit Facility and contributed it
to Berry to post as restricted cash with Berry's lenders. As directed by LINN
Energy, the $250 million was deposited on Berry's behalf in a security account
with the administrative agent subject to a security control agreement. Berry's
ability to withdraw funds from this account is subject to a concurrent reduction
of the borrowing base under the Berry Credit Facility or lender's consent in
connection with a redetermination of such borrowing base. The $250 million may
be used to satisfy obligations under the Berry Credit Facility or, subject to
restrictions in the indentures governing Berry's senior notes, may be returned
to LINN Energy in the future.
See Note 6 for additional details about the Company's debt.
During the year ended December 31, 2015, the Company, under its equity
distribution agreement, sold 3,621,983 units representing limited liability
company interests at an average price of $12.37 per unit 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
December 31, 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.
Commodity Derivatives
During the year ended December 31, 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.
During the fourth quarter of 2015, the Company canceled certain of its commodity
derivative contracts, consisting of Permian basis swaps for 2016 and 2017, trade
month roll swaps for 2016 and 2017, and positions representing oil swaps which
could have been extended at counterparty election for 2017. The Company received
net cash settlements of approximately $5 million from the cancellations.
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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, 2015, Compared to Year Ended December 31, 2014
Year Ended December 31,
2015 2014 Variance
(in thousands)
Revenues and other:
Natural gas sales $ 602,688 $ 894,043 $ (291,355 )
Oil sales 983,337 2,295,491 (1,312,154 )
NGL sales 140,246 421,005 (280,759 )
Total oil, natural gas and NGL sales 1,726,271 3,610,539 (1,884,268 )
Gains on oil and natural gas derivatives 1,056,189 1,206,179 (149,990 )
Marketing and other revenues 100,874 166,585 (65,711 )
2,883,334 4,983,303 (2,099,969 )
Expenses:
Lease operating expenses 617,764 805,164 (187,400 )
Transportation expenses 219,721 207,331 12,390
Marketing expenses 57,144 117,465 (60,321 )
General and administrative expenses (1) 296,887 293,073
3,814
Exploration costs 9,473 125,037 (115,564 )
Depreciation, depletion and amortization 805,757 1,073,902 (268,145 )
Impairment of long-lived assets 5,813,954 2,303,749
3,510,205
Taxes, other than income taxes 181,895 267,403 (85,508 )
Gains on sale of assets and other, net (197,409 ) (366,500 ) 169,091
7,805,186 4,826,624 2,978,562
Other income and (expenses) 155,580 (604,051 ) 759,631
Loss before income taxes (4,766,272 ) (447,372 ) (4,318,900 )
Income tax expense (benefit) (6,461 ) 4,437 (10,898 )
Net loss $ (4,759,811 ) $ (451,809 ) $ (4,308,002 )
(1) General and administrative expenses for the years ended December 31, 2015,
and December 31, 2014, include approximately $47 million and $45 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,
2015 2014 Variance
Average daily production:
Natural gas (MMcf/d) 642 572 12 %
Oil (MBbls/d) 62.4 72.9 (14 )%
NGL (MBbls/d) 28.6 33.5 (15 )%
Total (MMcfe/d) 1,188 1,210 (2 )%
Weighted average prices: (1)
Natural gas (Mcf) $ 2.57 $ 4.29 (40 )%
Oil (Bbl) $ 43.16 $ 86.28 (50 )%
NGL (Bbl) $ 13.45 $ 34.40 (61 )%
Average NYMEX prices:
Natural gas (MMBtu) $ 2.66 $ 4.41 (40 )%
Oil (Bbl) $ 48.80 $ 93.00 (48 )%
Costs per Mcfe of production:
Lease operating expenses $ 1.42 $ 1.82 (22 )%
Transportation expenses $ 0.51 $ 0.47 9 %
General and administrative expenses (2) $ 0.68 $ 0.66 3 %
Depreciation, depletion and amortization $ 1.86 $ 2.43 (23 )%
Taxes, other than income taxes $ 0.42 $ 0.61
(31 )%
(1) Does not include the effect of gains (losses) on derivatives.
(2) General and administrative expenses for the years ended December 31, 2015,
and December 31, 2014, include approximately $47 million and $45 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 decreased by approximately $1.9 billion or 52% to
approximately $1.7 billion for the year ended December 31, 2015, from
approximately $3.6 billion for the year ended December 31, 2014, due to lower
oil, natural gas and NGL prices and lower production volumes. Lower oil, natural
gas and NGL prices resulted in a decrease in revenues of approximately $982
million, $402 million and $218 million, respectively.
Average daily production volumes decreased to approximately 1,188 MMcfe/d for
the year ended December 31, 2015, from approximately 1,210 MMcfe/d for the year
ended December 31, 2014. Lower oil and NGL production volumes resulted in a
decrease in revenues of approximately $330 million and $62 million,
respectively. Higher natural gas production volumes resulted in an increase in
revenues of approximately $110 million.
The following table sets forth average daily production by region:
Year Ended December 31,
2015 2014
Variance
Average daily production (MMcfe/d):
Rockies 426 318 108 34 %
Hugoton Basin 252 188 64 35 %
California 185 171 14 8 %
Mid-Continent 100 287 (187 ) (65 )%
TexLa 82 48 34 70 %
Permian Basin 80 153 (73 ) (48 )%
South Texas 32 12 20 172 %
Michigan/Illinois 31 33 (2 ) (5 )%
1,188 1,210 (22 ) (2 )%
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 ("Devon" and the acquisition, 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 ("Pioneer" and the acquisition, 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 ("Granite Wash Assets Sale") on December 15, 2014,
partially offset by the impact of the Devon Assets Acquisition. The increase in
average daily production volumes in the TexLa region primarily reflects the
impact of the Devon Assets Acquisition. The decrease in average daily production
volumes in the Permian Basin region primarily reflects lower production volumes
as a result of the properties relinquished in the two exchanges with Exxon XTO
and ExxonMobil, the properties sold to Fleur de Lis Energy, LLC ("Permian Basin
Assets Sale") on November 14, 2014, and the Howard County Assets Sale on
August 31, 2015. The increase in average daily production volumes in the
South Texas
region reflects the full year 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 with minimal development capital
spending.
Gains (Losses) on Oil and Natural Gas Derivatives
Gains on oil and natural gas derivatives were approximately $1.1 billion and
$1.2 billion for the years ended December 31, 2015, and December 31, 2014,
respectively, representing a decrease of approximately $150 million. Gains on
oil and natural gas derivatives decreased primarily due to changes in fair value
of the derivative contracts. The results for 2015 and 2014 also include cash
settlements of approximately $5 million and $12 million, respectively, related
to canceled derivatives
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
contracts. In addition, the results for 2015 and 2014 include gains of
approximately $4 million and $7 million, respectively, related to the recoveries
of a bankruptcy claim (see Note 11). 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 year ended December 31, 2015, the Company had commodity derivative
contracts for approximately 81% of its natural gas production and 83% of its oil
production. During the year ended December 31, 2014, the Company had commodity
derivative contracts for approximately 85% 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 7A. "Quantitative and Qualitative
Disclosures About Market Risk" and Note 7 and Note 8 for additional details
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 $66 million or 39% to approximately $101
million for the year ended December 31, 2015, from approximately $167 million
for the year ended December 31, 2014. The decrease was primarily due to lower
revenues generated by the Jayhawk natural gas processing plant in
Kansas
,
principally driven by a change in contract terms, lower electricity sales
revenues generated by the Company's
California
cogeneration facilities and the
impact of properties sold during the fourth quarter of 2014, partially offset by
higher helium sales revenue in the Hugoton Basin.
Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle,
supervision, maintenance, tools and supplies, and workover expenses. Lease
operating expenses decreased by approximately $187 million or 23% to
approximately $618 million for the year ended December 31, 2015, from
approximately $805 million for the year ended December 31, 2014. The decrease
was primarily due to cost savings initiatives, lower costs as a result of the
properties sold during the fourth quarter of 2014 and a decrease in steam costs
caused by lower prices for natural gas used in steam generation, partially
offset by costs associated with properties acquired during the third quarter of
2014. Lease operating expenses per Mcfe also decreased to $1.42 per Mcfe for the
year ended December 31, 2015, from $1.82 per Mcfe for the year ended
December 31, 2014.
Transportation Expenses
Transportation expenses increased by approximately $13 million or 6% to
approximately $220 million for the year ended December 31, 2015, from
approximately $207 million for the year ended December 31, 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 $0.51 per Mcfe for the year ended December 31, 2015, from $0.47 per
Mcfe for the year ended December 31, 2014.
Marketing Expenses
Marketing expenses represent third-party activities associated with
company-owned gathering systems, plants and facilities. Marketing expenses
decreased by approximately $60 million or 51% to approximately $57 million for
the year ended December 31, 2015, from approximately $117 million for the year
ended December 31, 2014. The decrease was primarily due to lower expenses
associated with the Jayhawk natural gas processing plant in
Kansas
, principally
driven by a change in contract terms, 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
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
increased by approximately $4 million or 1% to approximately $297 million for
the year ended December 31, 2015, from approximately $293 million for the year
ended December 31, 2014. The increase was primarily due to higher advisory fees
related to the alliance agreements partially offset by lower acquisition
expenses. General and administrative expenses per Mcfe also increased to $0.68
per Mcfe for the year ended December 31, 2015, from $0.66 per Mcfe for the year
ended December 31, 2014.
Exploration Costs
Exploration costs decreased by approximately $116 million to approximately $9
million for the year ended December 31, 2015, from approximately $125 million
for the year ended December 31, 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 $268 million
or 25% to approximately $806 million for the year ended December 31, 2015, from
approximately $1.1 billion for the year ended December 31, 2014. The decrease
was primarily due to the divestitures of properties in 2014 with higher rates
compared to the rates of properties acquired in 2014, lower rates as a result of
the impairments recorded in the prior year and the first and third quarters of
2015, and lower total production volumes. Depreciation, depletion and
amortization per Mcfe also decreased to $1.86 per Mcfe for the year ended
December 31, 2015, from $2.43 per Mcfe for the year ended December 31, 2014. As
a result of the uncertainty regarding the Company's future commitment to
capital, the Company reclassified all of its proved undeveloped reserves to
unproved as of December 31, 2015, which may impact depletion in the future.
Impairment of Long-Lived Assets
The Company recorded the following noncash impairment charges (before and after
tax) associated with proved and unproved oil and natural gas properties:
Year Ended December 31,
2015 2014
(in thousands)
Rockies region $ 1,758,939 $ 585,705
Hugoton Basin region 1,667,768 -
California region 537,511 22
TexLa region 430,859 4,836
Mid-Continent region 405,370 244,413
Permian Basin region 71,990 1,337,444
South Texas region 42,433 131,329
Proved oil and natural gas properties 4,914,870 2,303,749 TexLa region
416,846 -
Permian Basin region 226,922 -
Rockies region 184,137 -
California region 71,179 -
Unproved oil and natural gas properties 899,084 -
Impairment of long-lived assets $ 5,813,954 $ 2,303,749
The impairment charges in 2015 were due to a decline in commodity prices,
changes in expected capital development and a decline in the Company's estimates
of proved reserves. The impairment charges in 2014 include approximately $1.7
billion due to a steep decline in commodity prices during the fourth quarter of
2014 and approximately $603 million due to the divestiture of certain high
valued unproved properties in the Midland Basin in which the expected cash flows
were previously included in the impairment assessment for proved oil and natural
gas properties.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
Subsequent to December 31, 2015, the prices of oil, natural gas and NGL have
continued to be volatile. In the future, if forward price curves continue to
decline, the Company may have additional impairments which could have a material
impact on its results of operations.
(Gains) Losses on Sale of Assets and Other, Net
During the year ended December 31, 2015, the Company recorded a net gain of
approximately $177 million, including costs to sell of approximately $1 million,
on the Howard County Assets Sale. During the year ended December 31, 2014, the
Company recorded the following net gains and losses on divestitures and
exchanges of properties:
• Net gain of approximately $294 million, including costs to sell of
approximately $10 million, on the Granite Wash Assets Sale;
• Net loss of approximately $28 million, including costs to sell of
approximately $2 million, on the Permian Basin Assets Sale;
• Net gain of approximately $20 million, including costs to sell of
approximately $3 million, on the noncash exchange of a portion of its
Permian Basin properties to ExxonMobil for properties in
California's
South Belridge Field;
• Net gain of approximately $65 million, including costs to sell of
approximately $3 million, on the noncash exchange of a portion of its
Permian Basin properties to Exxon XTO, for properties in the Hugoton
Basin; and
• Net gain of approximately $36 million on the sale of the Company's
interests in certain non-producing oil and natural gas properties located
in the Mid-Continent region.
See Note 2 for additional details of divestitures and exchanges of properties. Taxes, Other Than Income Taxes
Year Ended December 31,
2015 2014 Variance
(in thousands)
Severance taxes $ 62,000 $ 133,933 $ (71,933 )
Ad valorem taxes 99,368 114,955 (15,587 )
California
carbon allowances 20,573 18,212 2,361 Other
(46 ) 303 (349 )
$ 181,895 $ 267,403 $ (85,508 )
Taxes, other than income taxes decreased by approximately $86 million or 32% for
the year ended December 31, 2015, compared to the year ended December 31, 2014.
Severance taxes, which are a function of revenues generated from production,
decreased primarily due to lower oil, natural gas and NGL prices and lower
production volumes. Ad valorem taxes, which are based on the value of reserves
and production equipment and vary by location, decreased primarily due to a
lower estimated valuation on certain of the Company's properties, partially
offset by acquisitions completed during the third quarter of 2014.
California
carbon allowances increased primarily due to an increase in estimated emissions
for which credits are needed and higher costs for acquired allowances.
Other Income and (Expenses)
Year Ended December 31,
2015 2014 Variance
(in thousands)
Interest expense, net of amounts capitalized $ (546,453 ) $ (587,838 )
$ 41,385
Gain on extinguishment of debt 719,259 - 719,259
Other, net (17,226 ) (16,213 ) (1,013 )
$ 155,580 $ (604,051 ) $ 759,631
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
Other income and (expenses) decreased by approximately $760 million for the year
ended December 31, 2015, compared to the year ended December 31, 2014. Interest
expense decreased primarily due to lower outstanding debt during the period and
lower amortization of financing fees and expenses primarily related to the
bridge loan and term loan that were repaid during 2014 and senior notes that
were repurchased during 2015, partially offset by a decrease in capitalized
interest. In addition, for the year ended December 31, 2015, the Company
recorded a gain on extinguishment of debt of approximately $719 million as a
result of the repurchases of a portion of its senior notes and the exchange of
Exchanged Notes for the Second Lien Notes. See "Debt" under "Liquidity and
Capital Resources" below for additional details. Other expenses increased during
2015 primarily due to write-offs of deferred financing fees related to the
Credit Facilities.
Income Tax Expense (Benefit)
The Company is a limited liability company treated as a partnership for federal
and state income tax purposes, with the exception of the state of
Texas
, in
which income tax liabilities and/or benefits of the Company are passed through
to its unitholders. Limited liability companies are subject to
Texas
margin tax.
In addition, certain of the Company's subsidiaries are Subchapter C-corporations
subject to federal and state income taxes. The Company recognized an income tax
benefit of approximately $6 million for the year ended December 31, 2015,
compared to income tax expense of approximately $4 million for the year ended
December 31, 2014. The income tax benefit was primarily due to lower income from
the Company's taxable subsidiaries in 2015 compared to 2014.
Net Loss
Net loss increased by approximately $4.3 billion to approximately $4.8 billion
for the year ended December 31, 2015, from approximately $452 million for the
year ended December 31, 2014. The increase was primarily due to higher
impairment charges, lower production revenues and lower gains on oil and natural
gas derivatives, partially offset by the gain on extinguishment of debt and
lower expenses, including interest. See discussion above for explanations of
variances.
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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, 2014, Compared to Year Ended December 31, 2013
Year Ended December 31,
2014 2013 Variance
(in thousands)
Revenues and other:
Natural gas sales $ 894,043 $ 585,501 $ 308,542
Oil sales 2,295,491 1,152,213 1,143,278
NGL sales 421,005 335,526 85,479
Total oil, natural gas and NGL sales 3,610,539 2,073,240 1,537,299
Gains on oil and natural gas derivatives 1,206,179 177,857 1,028,322
Marketing and other revenues 166,585 80,558 86,027
4,983,303 2,331,655 2,651,648
Expenses:
Lease operating expenses 805,164 372,523 432,641
Transportation expenses 207,331 128,440 78,891
Marketing expenses 117,465 37,892 79,573
General and administrative expenses (1) 293,073 236,271 56,802
Exploration costs 125,037 5,251 119,786
Depreciation, depletion and amortization 1,073,902 829,311 244,591
Impairment of long-lived assets 2,303,749 828,317 1,475,432
Taxes, other than income taxes 267,403 138,631 128,772
(Gains) losses on sale of assets and other, net (366,500 ) 13,637 (380,137 )
4,826,624 2,590,273 2,236,351
Other income and (expenses) (604,051 ) (434,918 ) (169,133 )
Loss before income taxes (447,372 ) (693,536 ) 246,164
Income tax expense (benefit) 4,437 (2,199 ) 6,636
Net loss $ (451,809 ) $ (691,337 ) $ 239,528
(1) General and administrative expenses for the years ended December 31, 2014,
and December 31, 2013, include approximately $45 million and $37 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,
2014 2013 Variance
Average daily production:
Natural gas (MMcf/d) 572 443 29 %
Oil (MBbls/d) 72.9 33.5 118 %
NGL (MBbls/d) 33.5 29.7 13 %
Total (MMcfe/d) 1,210 822 47 %
Weighted average prices: (1)
Natural gas (Mcf) $ 4.29 $ 3.62 19 %
Oil (Bbl) $ 86.28 $ 94.15 (8 )%
NGL (Bbl) $ 34.40 $ 30.96 11 %
Average NYMEX prices:
Natural gas (MMBtu) $ 4.41 $ 3.65 21 %
Oil (Bbl) $ 93.00 $ 97.97 (5 )%
Costs per Mcfe of production:
Lease operating expenses $ 1.82 $ 1.24 47 %
Transportation expenses $ 0.47 $ 0.43 9 %
General and administrative expenses (2) $ 0.66 $ 0.79 (16 )%
Depreciation, depletion and amortization $ 2.43 $ 2.76 (12 )%
Taxes, other than income taxes $ 0.61 $ 0.46 33 %
(1) Does not include the effect of gains (losses) on derivatives.
(2) General and administrative expenses for the years ended December 31, 2014,
and December 31, 2013, include approximately $45 million and $37 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 $1.5 billion or 74% to
approximately $3.6 billion for the year ended December 31, 2014, from
approximately $2.1 billion for the year ended December 31, 2013, due to higher
production volumes and higher natural gas and NGL prices partially offset by
lower oil prices. Higher natural gas and NGL prices resulted in an increase in
revenues of approximately $138 million and $42 million, respectively. Lower oil
prices resulted in a decrease in revenues of approximately $209 million.
Average daily production volumes increased to approximately 1,210 MMcfe/d for
the year ended December 31, 2014, from approximately 822 MMcfe/d for the year
ended December 31, 2013. Higher oil, natural gas and NGL production volumes
resulted in an increase in revenues of approximately $1.4 billion, $171 million
and $43 million, respectively.
The following table sets forth average daily production by region:
Year Ended December 31,
2014 2013
Variance
Average daily production (MMcfe/d):
Rockies 318 187 131 71 %
Mid-Continent 287 330 (43 ) (13 )%
Hugoton Basin 188 143 45 31 %
California 171 19 152 824 %
Permian Basin 153 87 66 76 %
TexLa 48 22 26 122 %
Michigan/Illinois 33 34 (1 ) (3 )%
South Texas 12 - 12 -
1,210 822 388 47 %
The increase in average daily production volumes in the Rockies region primarily
reflects the impact of the Berry acquisition in December 2013, the Devon Assets
Acquisition on August 29, 2014, and development capital spending. The decrease
in average daily production volumes in the Mid-Continent region primarily
reflects lower development capital spending in the Granite Wash and lower
production volumes as a result of the properties sold in the Granite Wash Assets
Sale on December 15, 2014, partially offset by the impact of the Devon Assets
Acquisition. 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, the Pioneer Assets Acquisition on
September 11, 2014, and development capital spending. The increase in average
daily production volumes in the
California
region primarily reflects the impact
of the Berry acquisition and the impact of the properties received in the
exchange with ExxonMobil on November 21, 2014. The increase in average daily
production volumes in the Permian Basin region primarily reflects the impact of
an acquisition in October 2013, the Berry acquisition and development capital
spending, partially offset by lower production volumes as a result of the
properties relinquished in the two exchanges with Exxon XTO and ExxonMobil and
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 Berry acquisition and the Devon Assets Acquisition. The
Michigan
/
Illinois
region consists of a low-decline asset base and continues to produce at
consistent levels. Average daily production volumes in the
South Texas
region
reflect the impact of the Devon Assets Acquisition.
Gains (Losses) on Oil and Natural Gas Derivatives
Gains on oil and natural gas derivatives were approximately $1.2 billion and
$178 million for the years ended December 31, 2014, and December 31, 2013,
respectively, representing an increase of $1.0 billion. Gains on oil and natural
gas derivatives increased primarily due to changes in fair value on unsettled
derivative contracts. The results for 2014 also include cash settlements of
approximately $12 million related to canceled derivatives contracts. In
addition, the results for 2014 and 2013 include gains of approximately $7
million and $11 million, respectively, related to the recoveries of a bankruptcy
claim (see Note 11). 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
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
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 year ended December 31, 2014, the Company had commodity derivative
contracts for approximately 85% of its natural gas production and 94% of its oil
production. During the year ended December 31, 2013, the Company had commodity
derivative contracts for approximately 107% of its natural gas production and
127% 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 7A. "Quantitative and Qualitative
Disclosures About Market Risk" and Note 7 and Note 8 for additional details
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 increased by approximately $86 million or 107% to approximately $167
million for the year ended December 31, 2014, from approximately $81 million for
the year ended December 31, 2013. The increase was primarily due to electricity
sales revenues generated by the Company's
California
cogeneration facilities
acquired and certain contracts assumed in the Berry acquisition in December
2013, as well as higher revenues generated by 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 $432 million or 116% to
approximately $805 million for the year ended December 31, 2014, from
approximately $373 million for the year ended December 31, 2013. Lease operating
expenses increased primarily due to costs associated with properties acquired in
the Berry acquisition and acquisitions completed during the third quarter of
2014 (see Note 2). Lease operating expenses per Mcfe also increased to $1.82 per
Mcfe for the year ended December 31, 2014, from $1.24 per Mcfe for the year
ended December 31, 2013, primarily due to higher unit rates on newly acquired
oil properties.
Transportation Expenses
Transportation expenses increased by approximately $79 million or 61% to
approximately $207 million for the year ended December 31, 2014, from
approximately $128 million for the year ended December 31, 2013. The increase
was primarily due to costs associated with properties acquired in the Berry
acquisition and acquisitions during the third quarter of 2014. Transportation
expenses per Mcfe also increased to $0.47 per Mcfe for the year ended
December 31, 2014, from $0.43 per Mcfe for the year ended December 31, 2013,
primarily due to higher rates on Berry properties acquired in the Rockies
region.
Marketing Expenses
Marketing expenses represent third-party activities associated with
company-owned gathering systems, plants and facilities. Marketing expenses
increased by approximately $79 million or 210% to approximately $117 million for
the year ended December 31, 2014, from approximately $38 million for the year
ended December 31, 2013. The increase was primarily due to electricity
generation expenses incurred by the Company's
California
cogeneration facilities
acquired and certain contracts assumed in the Berry acquisition, as well as
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 $57 million or 24% to
approximately $293 million for the year ended December 31, 2014, from
approximately $236 million for the year ended December 31, 2013. The increase
was primarily due to higher salaries and benefits related expenses, primarily
driven by increased employee headcount and unit-based compensation, higher
professional services expenses and higher various other administrative expenses,
partially offset by lower non-payroll related
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
acquisition expenses. Although general and administrative expenses increased,
the unit rate decreased to $0.66 per Mcfe for the year ended December 31, 2014,
from $0.79 per Mcfe for the year ended December 31, 2013.
Exploration Costs
Exploration costs increased by approximately $120 million to approximately $125
million for the year ended December 31, 2014, from approximately $5 million for
the year ended December 31, 2013. The increase was due to higher leasehold
impairment expenses on unproved properties, primarily in
Michigan
, the
Mid-Continent and the Powder River Basin.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased by approximately $245 million
or 29% to approximately $1.1 billion for the year ended December 31, 2014, from
approximately $829 million for the year ended December 31, 2013. Higher total
production volumes were the primary reason for the increased expense.
Depreciation, depletion and amortization per Mcfe decreased to $2.43 per Mcfe
for the year ended December 31, 2014, from $2.76 per Mcfe for the year ended
December 31, 2013, primarily due to a lower rate in the Granite Wash formation
as a result of the impairment recorded in the prior year and properties held for
sale at September 30, 2014, that were divested on December 15, 2014.
Impairment of Long-Lived Assets
The Company recorded the following noncash impairment charges (before and after
tax) associated with proved oil and natural gas properties:
Year Ended December 31,
2014 2013
(in thousands)
Permian Basin region $ 1,337,444 $ -
Rockies region 585,705 -
Mid-Continent region 244,413 828,317
South Texas region 131,329 -
TexLa region 4,836 -
California region 22 -
$ 2,303,749 $ 828,317
The impairment charges in 2014 include approximately $1.7 billion due to a steep
decline in commodity prices during the fourth quarter of 2014 and approximately
$603 million due to the divestiture of certain high valued unproved properties
in the Midland Basin in which the expected cash flows were previously included
in the impairment assessment for proved oil and natural gas properties. The
impairment charges in 2013 include approximately $791 million associated with
properties in the Granite Wash formation related to asset performance resulting
in reserve revisions and a decline in commodity prices as well as approximately
$37 million associated with the write-down of the carrying value of the Panther
Operated Cleveland Properties sold in May 2013 (see Note 2).
(Gains) Losses on Sale of Assets and Other, Net
During the year ended December 31, 2014, the Company recorded the following net
gains and losses on divestitures and exchanges of properties:
• Net gain of approximately $294 million, including costs to sell of
approximately $10 million, on the Granite Wash Assets Sale;
• Net loss of approximately $28 million, including costs to sell of
approximately $2 million, on the Permian Basin Assets Sale;
• Net gain of approximately $20 million, including costs to sell of
approximately $3 million, on the noncash exchange of a portion of its
Permian Basin properties to ExxonMobil for properties in
California's
South Belridge Field;
• Net gain of approximately $65 million, including costs to sell of
approximately $3 million, on the noncash exchange of a portion of its
Permian Basin properties to Exxon XTO, for properties in the Hugoton
Basin; and
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
• Net gain of approximately $36 million on the sale of the Company's
interests in certain non-producing oil and natural gas properties located
in the Mid-Continent region.
See Note 2 for additional details of divestitures and exchanges of properties. Taxes, Other Than Income Taxes
Year Ended December 31,
2014 2013 Variance
(in thousands)
Severance taxes $ 133,933 $ 90,655 $ 43,278
Ad valorem taxes 114,955 48,547 66,408
California carbon allowances 18,212 355 17,857
Other 303 (926 ) 1,229
$ 267,403 $ 138,631 $ 128,772
Taxes, other than income taxes increased by approximately $129 million or 93%
for the year ended December 31, 2014, compared to the year ended December 31,
2013. Severance taxes, which are a function of revenues generated from
production, increased primarily due to higher production volumes and higher
natural gas and NGL prices partially offset by lower oil prices. Ad valorem
taxes, which are primarily based on the value of reserves and production
equipment and vary by location, increased primarily due to the Berry acquisition
and acquisitions completed during the third quarter of 2014.
California
carbon
allowances increased primarily due to the
California
properties acquired in the
Berry acquisition.
Other Income and (Expenses)
Year Ended December 31,
2014 2013 Variance
(in thousands)
Interest expense, net of amounts capitalized $ (587,838 ) $ (421,137 )
$ (166,701 )
Loss on extinguishment of debt - (5,304 ) 5,304
Other, net (16,213 ) (8,477 ) (7,736 )
$ (604,051 ) $ (434,918 ) $ (169,133 )
Other income and (expenses) increased by approximately $169 million for the year
ended December 31, 2014, compared to the year ended December 31, 2013. Interest
expense increased primarily due to higher outstanding debt during the period and
higher amortization of financing fees and expenses associated with the bridge
loan and term loan that were repaid during 2014, the senior notes issued in
September 2014 and amendments made to the Company's Credit Facilities during
2014 and 2013. For the year ended December 31, 2013, the Company recorded a loss
on extinguishment of debt of approximately $5 million as a result of the
redemption of the remaining outstanding senior notes due 2017 and 2018. 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 term loan that was repaid and the LINN Credit Facility that was
amended during 2014. There were no such write-offs during 2013.
Income Tax Expense (Benefit)
The Company is a limited liability company treated as a partnership for federal
and state income tax purposes, with the exception of the state of
Texas
, in
which income tax liabilities and/or benefits of the Company are passed through
to its unitholders. Limited liability companies are subject to
Texas
margin tax.
In addition, certain of the Company's subsidiaries are Subchapter C-corporations
subject to federal and state income taxes. The Company recognized income tax
expense of approximately $4 million for the year ended December 31, 2014,
compared to an income tax benefit of approximately $2 million for the year ended
December 31, 2013. Income tax expense increased primarily due to higher income
from the Company's taxable subsidiaries in 2014 compared to 2013.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
Net Loss
Net loss decreased by approximately $239 million or 35% to approximately $452
million for the year ended December 31, 2014, from approximately $691 million
for the year ended December 31, 2013. The decrease was primarily due to higher
production revenues and higher gains on oil and natural gas derivatives,
partially offset by higher impairment charges and other expenses, including
interest. See discussions above for explanations of variances.
Liquidity and Capital Resources
The Company's liquidity outlook has changed since the third quarter of 2015 due
to continued low commodity prices. The significant risks and uncertainties
described under "Executive Overview" raise substantial doubt about the Company's
ability to continue as a going concern. The report of the Company's independent
registered public accounting firm that accompanies its audited consolidated
financial statements in this Annual Report on Form 10-K contains an explanatory
paragraph regarding the substantial doubt about the Company's ability to
continue as a going concern.
The Company's Credit Facilities contain the requirement to deliver audited
consolidated financial statements without a going concern or like qualification
or exception. Consequently, as of the filing date, March 15, 2016, the Company
is in default under the LINN Credit Facility. If the Company is unable to obtain
a waiver or other suitable relief from the lenders under the LINN Credit
Facility prior to the expiration of the 30 day grace period, an Event of Default
will result and the lenders holding a majority of the commitments under the LINN
Credit Facility could accelerate the outstanding indebtedness, which would make
it immediately due and payable. If the Company is unable to obtain a waiver from
or otherwise reach an agreement with the lenders under the LINN Credit Facility
and the indebtedness under the LINN Credit Facility is accelerated, then an
Event of Default under LINN Energy's senior notes and second lien notes would
occur, which, if it continues beyond any applicable cure periods, would, to the
extent the applicable lenders so elect, result in the acceleration of those
obligations. Furthermore, an Event of Default under the LINN Credit Facility
will also result in an Event of Default under the Berry Credit Facility, which
in the absence of a waiver or other suitable relief and upon the election of the
agent or lenders holding a majority of commitments under the Berry Credit
Facility would result in the acceleration of indebtedness under the Berry Credit
Facility. Such Event of Default would trigger an Event of Default under the
Berry senior notes. If such Event of Default continues beyond any applicable
cure periods, such Event of Default would result in an acceleration of the Berry
senior notes.
Additionally, the indenture governing the second lien notes ("Second Lien
Indenture") required the Company to deliver mortgages by February 18, 2016,
subject to a 45 day grace period. The Company elected to exercise its right to
the grace period and not deliver the mortgages, and as a result, the Company is
currently in default under the Second Lien Indenture. If the Company does not
deliver the mortgages within the 45 day grace period or is otherwise unable to
obtain a waiver or other suitable relief from the holders under the Second Lien
Indenture prior to the expiration of the 45 day grace period, an Event of
Default will result and if the trustee or noteholders holding at least 25% in
the aggregate outstanding principal amount of the second lien notes so elect
would accelerate the second lien notes causing them to be immediately due and
payable.
Furthermore, the Company has decided to defer making interest payments totaling
approximately $60 million due March 15, 2016, including approximately $30
million on LINN Energy's 7.75% senior notes due February 2021, approximately $12
million on LINN Energy's 6.50% senior notes due September 2021 and approximately
$18 million on Berry's senior notes due September 2022, which will result in the
Company being in default under these senior notes. The indentures governing each
of the applicable series of notes permit the Company a 30 day grace period to
make the interest payments. If the Company fails to make the interest payments
within the grace period, or is otherwise unable to obtain a waiver or suitable
relief from the holders of these senior notes, an Event of Default will result
and if the trustee or noteholders holding at least 25% in the aggregate
outstanding principal amount of each series of notes so elect would accelerate
the notes causing them to be immediately due and payable.
An Event of Default under the Second Lien Indenture or any of the indentures
governing the senior notes triggers a cross-default under the LINN Credit
Facility and Berry Credit Facility and, as discussed above, if the applicable
lenders so elect would result in acceleration under the LINN Credit Facility and
Berry Credit Facility. In addition, as discussed above, an acceleration of the
obligations under the Second Lien Indenture or LINN Credit Facility would
trigger a cross-default to LINN Energy's senior notes and if the applicable
lenders so elect would result in a cross-acceleration under LINN Energy's
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
senior notes, and an acceleration of the Berry Credit Facility if the applicable
lenders so elect would result in cross-acceleration under the Berry senior
notes.
If lenders, and subsequently noteholders, accelerate the Company's outstanding
indebtedness, it will become immediately due and payable and the Company will
not have sufficient liquidity to repay those amounts. If the Company is unable
to reach an agreement with its creditors prior to any of the above described
accelerations, the Company could be required to immediately file for protection
under Chapter 11 of the
U.S.
Bankruptcy Code.
The Company is currently in discussions with various stakeholders and is
pursuing or considering a number of actions including: (i) obtaining additional
sources of capital from asset sales, private issuances of equity or
equity-linked securities, debt for equity swaps, or any combination thereof;
(ii) pursuing in- and out-of-court restructuring transactions; (iii) obtaining
waivers or amendments from its lenders; and (iv) continuing to minimize its
capital expenditures, reduce costs and maximize cash flows from operations.
There can be no assurance that sufficient liquidity can be obtained from one or
more of these actions or that these actions can be consummated within the period
needed.
The Company has utilized 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 year
ended December 31, 2015, the Company's total capital expenditures, excluding
acquisitions, were approximately $518 million.
See below for details regarding capital expenditures for the periods presented:
Year Ended December 31,
2015 2014 2013
(in thousands)
Oil and natural gas $ 450,286 $ 1,487,996 $ 1,166,866
Plant and pipeline 20,580 19,756 63,035
Other 46,829 48,182 34,664
Capital expenditures, excluding acquisitions $ 517,695 $ 1,555,934 $ 1,264,565
For 2016, the Company estimates its total capital expenditures, excluding
acquisitions, will be approximately $340 million, including approximately $250
million related to its oil and natural gas capital program and approximately $75
million related to its plant and pipeline capital. This estimate is under
continuous review and subject to ongoing adjustments. The Company expects to
fund its capital expenditures primarily from net cash provided by operating
activities; however, there is uncertainty regarding the Company's liquidity as
discussed above.
In February 2016, the Company borrowed approximately $919 million under the LINN
Credit Facility, which represented the remaining undrawn amount that was
available under the LINN Credit Facility, the proceeds of which were deposited
in an unencumbered account with a bank that is not a lender under either the
LINN or Berry Credit Facility. As of February 29, 2016, there was less than $1
million of available borrowing capacity under the Credit Facilities. See
"Process to Explore Strategic Alternatives Related to the Company's Capital
Structure" under "Executive Overview" for additional details.
In November 2015, the Company issued $1.0 billion in aggregate principal amount
of new Second Lien Notes in exchange for approximately $2.0 billion in aggregate
principal amount of certain of its outstanding senior notes. The exchanges were
accounted for as a troubled debt restructuring ("TDR"). See Note 6 for
additional details. TDR accounting requires that interest payments on the Second
Lien Notes reduce the carrying value of the debt with no interest expense
recognized. As a result, the Company's reported interest expense will be
significantly less than the contractual interest payments throughout the term of
the Second Lien Notes. For the year ended December 31, 2015, accrued contractual
interest on the Second Lien Notes was approximately $14 million, and no interest
payments were made during the year.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
In October 2015, LINN Energy and Berry each entered into an amendment to its
credit facility. See Note 6 for additional details.
The spring 2015 semi-annual borrowing base redeterminations of the Company's
Credit Facilities were completed in May 2015, and as a result of lower commodity
prices, the borrowing base under the LINN Credit Facility decreased from $4.5
billion to $4.05 billion and the borrowing base under the Berry Credit Facility
decreased from $1.4 billion to $1.2 billion. The fall 2015 semi-annual
redeterminations were completed in October 2015 and the borrowing base under the
LINN Credit Facility was reaffirmed at $4.05 billion, subject to certain
conditions being met on or before January 1, 2016, and the borrowing base under
the Berry Credit Facility decreased from $1.2 billion to $900 million. In
connection with the reduction in Berry's borrowing base in October 2015, Berry
repaid $300 million of borrowings outstanding under the Berry Credit Facility.
The borrowing base under the LINN Credit Facility automatically decreased to
$3.6 billion on January 1, 2016, since certain conditions were not met.
Continued low commodity prices, reductions in the Company's capital budget and
the resulting reserve write-downs, along with the maturity schedule of the
Company's hedges, are expected to adversely impact future redeterminations. The
Company may have insufficient cash on hand to be able to make mandatory
prepayments under the Credit Facilities.
In connection with the reduction in Berry's borrowing base in May 2015, LINN
Energy borrowed $250 million under the LINN Credit Facility and contributed it
to Berry to post as restricted cash with Berry's lenders. As directed by LINN
Energy, the $250 million was deposited on Berry's behalf in a security account
with the administrative agent subject to a security control agreement. Berry's
ability to withdraw funds from this account is subject to a concurrent reduction
of the borrowing base under the Berry Credit Facility or lender's consent in
connection with a redetermination of such borrowing base. The $250 million may
be used to satisfy obligations under the Berry Credit Facility or, subject to
restrictions in the indentures governing Berry's senior notes, may be returned
to LINN Energy in the future.
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. See Item 1A. "Risk Factors," for additional information about
liquidity risks, the risk that the Company may be unable to repay or refinance
its existing and future debt as it becomes due, and other risks that could
affect the Company.
Statements of Cash Flows
The following is a comparative cash flow summary:
Year Ended December 31,
2015 2014 2013
(in thousands)
Net cash:
Provided by operating activities $ 1,249,457 $ 1,711,890 $ 1,166,212
Used in investing activities (307,302 ) (1,920,104 ) (1,253,317 )
Provided by (used in) financing activities (941,796 )
157,852 138,033 Net increase (decrease) in cash and cash equivalents $ 359 $ (50,362 ) $ 50,928
Operating Activities
Cash provided by operating activities for the year ended December 31, 2015, was
approximately $1.2 billion, compared to approximately $1.7 billion for the year
ended December 31, 2014. The decrease was primarily due to lower production
related revenues principally due to lower commodity prices, partially offset by
higher cash settlements on derivatives.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
Cash provided by operating activities for the year ended December 31, 2014, was
approximately $1.7 billion, compared to approximately $1.2 billion for the year
ended December 31, 2013. The increase was primarily due to higher production
related revenues principally due to increased production volumes and higher
natural gas and NGL prices, partially offset by higher expenses and lower cash
settlements on derivatives.
Investing Activities
The following provides a comparative summary of cash flow from investing
activities:
Year Ended December 31,
2015 2014 2013
(in thousands)
Cash flow from investing activities:
Acquisition of oil and natural gas properties
and joint-venture funding, net of cash acquired $ - $ (2,479,252 ) $ (279,213 )
Capital expenditures (675,597 ) (1,644,417 ) (1,170,377 )
Proceeds from sale of properties and equipment
and other 368,295 2,203,565 196,273
$ (307,302 ) $ (1,920,104 ) $ (1,253,317 )
The primary use of cash in investing activities is for capital spending,
including acquisitions and the development of the Company's oil and natural gas
properties. The Company made no acquisitions of properties during 2015. The
increase in 2014 compared to 2013 was primarily due to two significant cash
acquisitions of properties from Pioneer and Devon consummated during 2014,
compared to one significant cash acquisition of properties in the Permian Basin
region consummated during 2013. The amount reported for the year ended
December 31, 2013, includes approximately $451 million of cash acquired in the
Berry acquisition. See Note 2 for additional details of acquisitions.
Capital expenditures decreased during 2015 primarily due to lower spending on
development activities throughout the Company's various operating regions as a
result of declining commodity prices. Capital expenditures were higher during
2014 compared to 2013 primarily due to increased development activities of
properties in the Rockies,
California
and Permian Basin regions, partially
offset by decreased development activities of properties in the Mid-Continent
region.
Proceeds from the sale of properties and equipment and other for the year ended
December 31, 2015, include approximately $276 million in net cash proceeds
received from the Howard County Assets Sale in August 2015. Proceeds from sale
of properties and equipment and other for the year ended December 31, 2014,
include approximately $1.8 billion and $352 million in net cash proceeds
received from the Granite Wash Assets Sale and the Permian Basin Assets Sale,
respectively, compared to $218 million in net cash proceeds received from the
sale of the Panther Operated Cleveland Properties in 2013. See Note 2 for
additional details of divestitures.
Financing Activities
Cash used in financing activities for the year ended December 31, 2015, was
approximately $942 million compared to cash provided by financing activities of
approximately $158 million for the year ended December 31, 2014. Financing cash
flow needs decreased primarily due to reduced capital expenditures and
acquisition activity for the year ended December 31, 2015. Cash provided by
financing activities was approximately $138 million for the year ended
December 31, 2013.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
The following provides a comparative summary of proceeds from borrowings and
repayments of debt:
Year Ended December 31,
2015 2014 2013
(in thousands)
Proceeds from borrowings: LINN Credit Facility $ 1,445,000 $ 2,540,000 $ 1,730,000 Senior notes
- 1,100,024 -
Bridge loan and term loans - 2,300,000 500,000
$ 1,445,000 $ 5,940,024 $ 2,230,000
Repayments of debt:
LINN Credit Facility $ (1,275,000 ) $ (2,305,000 ) $ (1,350,000 )
Berry Credit Facility (300,000 ) - -
Senior notes (608,879 ) (206,124 ) (54,898 )
Bridge loan and term loan - (2,300,000 ) -
$ (2,183,879 ) $ (4,811,124 ) $ (1,404,898 )
In addition, in May 2015, LINN Energy borrowed $250 million under the LINN
Credit Facility and contributed it to Berry to post as restricted cash with
Berry's lenders (see Note 6).
In November 2015, the Company issued $1.0 billion in aggregate principal amount
of Second Lien Notes in exchange for approximately $2.0 billion in aggregate
principal amount of certain of its outstanding senior notes. See Note 6 for
additional details.
Debt
The following summarizes the Company's outstanding debt:
December 31,
2015 2014
(in
thousands, except percentages)
LINN Credit Facility $ 2,215,000 $ 1,795,000
Berry Credit Facility 873,175 1,173,175
Term loan 500,000 500,000
6.50% senior notes due May 2019 562,234 1,200,000
6.25% senior notes due November 2019 581,402 1,800,000
8.625% senior notes due April 2020 718,596 1,300,000
6.75% Berry senior notes due November 2020 261,100 299,970
12.00% senior secured second lien notes due December 2020 (1) 1,000,000
-
Interest payable on second lien notes due December 2020 (1) 608,333 -
7.75% senior notes due February 2021 779,474 1,000,000
6.50% senior notes due September 2021 381,423 650,000
6.375% Berry senior notes due September 2022 572,700 599,163
Net unamortized discounts and premiums (8,694 ) (21,499 )
Total debt, net 9,044,743 10,295,809
Less current portion (2) (3,716,508 ) -
Total long-term debt, net $
5,328,235 $ 10,295,809
(1) In November 2015, the Company issued $1.0 billion in aggregate principal
amount of new Second Lien Notes in exchange for approximately $2.0 billion
in aggregate principal amount of certain of its outstanding senior notes.
The exchanges were accounted for
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
as a TDR. See Note 6 for additional details. TDR accounting requires that
interest payments on the Second Lien Notes reduce the carrying value of the debt
with no interest expense recognized.
(2) Due to existing and anticipated covenant violations, the Company's Credit
Facilities and term loan were classified as current at December 31, 2015.
The current portion also includes approximately $128 million of interest
payable on the Second Lien Notes due within one year.
During the year ended December 31, 2015, the Company repurchased, through privately negotiated transactions and on the open market, approximately $992 million of its outstanding senior notes as follows: • 6.50% senior notes due May 2019 - $53 million;
• 6.25% senior notes due November 2019 - $395 million;
• 8.625% senior notes due April 2020 - $295 million;
• 6.75% Berry senior notes due November 2020 - $39 million;
• 7.75% senior notes due February 2021 - $36 million;
• 6.50% senior notes due September 2021 - $148 million; and
• 6.375% Berry senior notes due September 2022 - $26 million.
In connection, with the repurchases, the Company paid approximately $609 million
in cash and recorded a gain on extinguishment of debt of approximately $367
million for the year ended December 31, 2015.
In February 2016, the Company borrowed approximately $919 million under the LINN
Credit Facility, which represented the remaining undrawn amount that was
available under the LINN Credit Facility, the proceeds of which were deposited
in an unencumbered account with a bank that is not a lender under either the
LINN or Berry Credit Facility. As of February 29, 2016, there was less than $1
million of available borrowing capacity under the Credit Facilities. For
additional information related to the Company's outstanding debt, see Note 6.
The Company plans to file Berry's stand-alone financial statements with the
Securities and Exchange Commission at a later date.
Financial Covenants
The Credit Facilities, as amended in October 2015, contain requirements and
financial covenants, among others, to maintain: 1) a ratio of EBITDA to Interest
Expense (as each term is defined in the LINN Credit Facility) and Adjusted
EBITDAX to Interest Expense (as each term is defined in the Berry Credit
Facility) ("Interest Coverage Ratio") for the preceding four quarters of greater
than 2.5 to 1.0 through September 30, 2015, 2.0 to 1.0 currently, 2.25 to 1.0
from March 31, 2017 through June 30, 2017 and returning to 2.5 to 1.0
thereafter, and 2) a ratio of adjusted current assets to adjusted current
liabilities (as described in the LINN Credit Facility) and Current Assets to
Current Liabilities (as each term is defined in the Berry Credit Facility)
("Current Ratio") as of the last day of any fiscal quarter of greater than 1.0
to 1.0. The Interest Coverage Ratio is intended as a measure of the Company's
ability to make interest payments on its outstanding indebtedness and the
Current Ratio is intended as a measure of the Company's solvency. The Company is
required to demonstrate compliance with each of these ratios on a quarterly
basis. The following represents the calculations of the Interest Coverage Ratio
and the Current Ratio as presented to the lenders under the Credit Facilities:
Twelve Months
At or for the Quarter Ended Ended
March 31, September 30, December 31, December 31,
2015 June 30, 2015 2015 2015 2015
LINN Credit Facility:
Interest Coverage Ratio 2.9 3.0 3.4 3.5 3.2
Current Ratio 3.0 2.9 2.8 2.0 2.0
Berry Credit Facility:
Interest Coverage Ratio 1.7 2.6 2.2 1.6 2.0
Current Ratio (1) 0.6 0.5 2.0 0.4 0.4
Current Ratio
(consolidated) (1) 3.2 2.9 2.6 1.7 1.7
(1) The Berry Credit Facility allows Berry to demonstrate its compliance with
the Current Ratio financial covenant on a consolidated basis with LINN
Energy for up to three quarters of each calendar year.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
The Company has included disclosure of the Interest Coverage Ratio for the
twelve months ended December 31, 2015, and the Current Ratio as of December 31,
2015, to demonstrate its compliance for the quarter ended December 31, 2015, as
well as the Interest Coverage Ratio for each of the preceding four quarters on
an individual basis (rather than on a last twelve months basis) and the Current
Ratio as of the end of each of the preceding four quarters to provide investors
with trend information about the Company's ongoing compliance with these
financial covenants. If the Company fails to demonstrate compliance with either
or both of the Interest Coverage Ratio or the Current Ratio as of the end of the
quarter and such failure continues beyond applicable cure periods, an event of
default would occur and the Company would be unable to make additional
borrowings and outstanding indebtedness may be accelerated. The Company depends,
in part, on its Credit Facilities for future capital needs. In addition, the
Company has drawn on the LINN Credit Facility in the past to fund or partially
fund cash distribution payments. Absent such borrowings, the Company would have
at times experienced a shortfall in cash available to pay the declared cash
distribution amount. For additional information, see "Distribution Practices"
below.
See "Going Concern Uncertainty" above under "Executive Overview" for information
about the impact to the Company's compliance with its covenants resulting from
the auditors' opinion issued in connection with the consolidated financial
statements that includes a going concern explanation.
Contingencies
See Item 3. "Legal Proceedings" for information regarding legal proceedings that
the Company is party to and any contingencies related to these legal
proceedings.
Commitments and Contractual Obligations
The following is a summary of the Company's commitments and contractual
obligations as of December 31, 2015:
Payments
Due
Contractual Obligations Total 2016 2017 - 2018
2019 - 2020 2021 and Beyond
(in thousands)
Debt obligations:
Credit facilities (1) $ 3,088,175 $ 3,088,175 $ - $ - $ -
Term loan (1) 500,000 500,000 - - -
Second lien notes (2) 1,608,333 128,333 240,000 1,240,000 -
Senior notes 3,856,929 - - 2,123,332 1,733,597
Interest (3) 1,684,097 376,647 753,292 433,693 120,465
Operating lease
obligations:
Office, property and
equipment leases 69,977 10,647 16,408 15,586 27,336
Other:
Commodity derivatives 3,098 2,241 857 - -
Asset retirement
obligations 523,541 14,234 20,501 23,303 465,503
Firm natural gas
transportation
contracts (4) 146,981 33,446 57,389 41,651 14,495
Other 3,464 2,503 122 122 717
$ 11,484,595 $ 4,156,226 $ 1,088,569 $ 3,877,687 $ 2,362,113
(1) The contractual maturity date for the Credit Facilities and term loan is
April 2019; however, the LINN Credit Facility and term loan are subject to
springing maturities based on the maturity of any outstanding LINN Energy
junior lien debt and, based on current junior lien debt outstanding, may
mature as early as November 2018. Due to existing and anticipated covenant
violations, the Company's Credit Facilities and term loan were classified as
current at December 31, 2015.
(2) Represents $1.0 billion of Second Lien Notes and approximately $608 million
of future contractual interest payable reflected on the consolidated balance
sheet at December 31, 2015. The maturity date reflected for the Second Lien
Notes is December 2020; however, these notes are subject to a springing
maturity based on the maturity of any outstanding LINN Energy unsecured debt
and, based on current unsecured debt outstanding, may mature as early as
February 2019.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
(3) Represents interest on the LINN Credit Facility computed at 2.66% through
contractual maturity in April 2019, and interest on the Berry Credit
Facility and term loan each computed at 3.17% through contractual maturities
in April 2019. Interest on the December 2020 Second Lien Notes computed at a
fixed rate of 12.00%. Interest on the May 2019 senior notes, November 2019
senior notes, April 2020 senior notes, Berry November 2020 senior notes,
February 2021 senior notes, September 2021 senior notes and Berry September
2022 senior notes computed at fixed rates of 6.50%, 6.25%, 8.625%, 6.75%,
7.75%, 6.50% and 6.375%, respectively.
(4) Represent certain firm commitments to transport natural gas production to
market and to transport natural gas for use in the Company's cogeneration
and conventional steam generation facilities. The remaining terms of these
contracts range from two to eight years and require a minimum monthly charge
regardless of whether the contracted capacity is used or not.
Counterparty Credit Risk
The Company accounts for its commodity derivatives at fair value. The Company's
counterparties are current participants or affiliates of participants in its
Credit Facilities or were participants or affiliates of participants in its
Credit Facilities at the time it originally entered into the derivatives. The
LINN Credit Facility and the Berry Credit Facility are secured by each company's
oil, natural gas and NGL reserves; therefore, the Company is not required to
post any collateral. The Company does not receive collateral from its
counterparties. The Company minimizes the credit risk in derivative instruments
by: (i) limiting its exposure to any single counterparty; (ii) entering into
derivative instruments only with counterparties that meet the Company's minimum
credit quality standard, or have a guarantee from an affiliate that meets the
Company's minimum credit quality standard; and (iii) monitoring the
creditworthiness of the Company's counterparties on an ongoing basis. In
accordance with the Company's standard practice, its commodity derivatives are
subject to counterparty netting under agreements governing such derivatives and
therefore the risk of loss due to counterparty nonperformance is somewhat
mitigated.
At-the-Market Offering Program
The Company's Board of Directors has authorized the sale of up to $500 million
of units under an at-the-market offering program. Sales of units, if any, will
be made under an equity distribution agreement by means of ordinary brokers'
transactions, through the facilities of the NASDAQ Global Select Market, any
other national securities exchange or facility thereof, a trading facility of a
national securities association or an alternate trading system, to or through a
market maker or directly on or through an electronic communication network, a
"dark pool" or any similar market venue, at market prices, in block
transactions, or as otherwise agreed with a sales agent. The Company expects to
use the net proceeds from any sale of units for general corporate purposes,
which may include, among other things, capital expenditures, acquisitions and
the repayment of debt.
During the year ended December 31, 2015, the Company, under its equity
distribution agreement, sold 3,621,983 units representing limited liability
company interests at an average price of $12.37 per unit for net proceeds of
approximately $44 million (net of approximately $448,000 in commissions). In
connection with the issuance and sale of these units, the Company also incurred
professional services expenses of approximately $459,000. The Company used the
net proceeds for general corporate purposes, including the open market
repurchases of a portion of its senior notes (see Note 6). At December 31, 2015,
units totaling approximately $455 million in aggregate offering price remained
available to be sold under the agreement.
Public Offering of Units
In May 2015, the Company sold 16,000,000 units representing limited liability
company interests in an underwritten public offering at $11.79 per unit ($11.32
per unit, net of underwriting discount) for net proceeds of approximately $181
million (after underwriting discount and offering costs of approximately $8
million). The Company used the net proceeds from the sale of these units to
repay a portion of the outstanding indebtedness under the LINN Credit Facility.
Issuance of Units for Berry Acquisition
On December 16, 2013, the Company completed the transactions contemplated by the
merger agreement under which LinnCo, LLC ("LinnCo"), an affiliate of LINN
Energy, acquired all of the outstanding common shares of Berry and the
contribution agreement between LinnCo and the Company, under which LinnCo
contributed Berry to the Company in exchange for LINN Energy units. Under the
merger agreement, as amended, Berry's shareholders received 1.68 LinnCo common
shares for each Berry common share they owned, totaling 93,756,674 LinnCo common
shares. Under the
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for
93,756,674 newly issued LINN Energy units with a value of approximately $2.8
billion.
Distributions
Under the Company's limited liability company agreement, unitholders are
entitled to receive a distribution of available cash, which includes cash on
hand plus borrowings less any reserves established by the Company's Board of
Directors to provide for the proper conduct of the Company's business (including
reserves for future capital expenditures, including drilling, acquisitions and
anticipated future credit needs) or to fund distributions, if any, over the next
four quarters. The following provides a summary of distributions paid by the
Company during the year ended December 31, 2015:
Distributions Total
Date Paid Per Unit Distributions
(in millions)
September 2015 $ 0.1042 $ 37
August 2015 $ 0.1042 $ 37
July 2015 $ 0.1042 $ 37
June 2015 $ 0.1042 $ 37
May 2015 $ 0.1042 $ 35
April 2015 $ 0.1042 $ 35
March 2015 $ 0.1042 $ 35
February 2015 $ 0.1042 $ 35
January 2015 $ 0.1042 $ 35
In October 2015, the Company's Board of Directors determined to suspend payment
of the Company's distribution. For additional information, see "Distribution
Practices" below.
Distribution Practices
The Company's Board of Directors determines the appropriate level of
distributions on a periodic basis in accordance with the provisions of the
Company's limited liability company agreement. Management considers the timing
and size of planned capital expenditures and long-term views about expected
results in determining the amount of its distributions. Capital spending and
resulting production and net cash provided by operating activities do not
typically occur evenly throughout the year due to a variety of factors which are
difficult to predict, including rig availability, weather, well performance, the
timing of completions and the commodity price environment.
The Company's Board of Directors reviews historical financial results and
forecasts for future periods, including oil and natural gas development
activities and the impact of significant acquisitions or dispositions, as well
as considers the level of the Company's indebtedness and its liquidity position
in making a determination to increase, decrease or maintain the current level of
distribution. If shortfalls are sustained over time and forecasts demonstrate
expectations for continued future shortfalls, or the Company's Board of
Directors determines that it is necessary to reserve cash for the future conduct
of business, it may determine to reduce, suspend or discontinue paying
distributions. For example, in October 2015, following the recommendation from
management, the Company's Board of Directors determined to suspend payment of
the Company's distribution and reserve any excess cash that would otherwise be
available for distribution. The Board of Directors will continue to evaluate the
Company's ability to reinstate the distribution based on the considerations
discussed above.
For 2015, the Company intended to fund interest expense, its total oil and
natural gas development costs and distributions to unitholders paid through
September 2015 from net cash provided by operating activities, and presents
"excess (shortfall) of net cash provided by operating activities after
distributions to unitholders and discretionary adjustments considered by the
Board of Directors" after deducting total oil and natural gas development costs.
Previously, the Company intended to fund interest expense, a portion of its oil
and natural gas development costs and distributions to unitholders from net cash
provided by operating activities and presented "excess (shortfall) of net cash
provided by operating activities after distributions to unitholders and
discretionary adjustments considered by the Board of Directors" after deducting
only a portion of oil and natural gas development costs.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
The Company funds acquisitions and premiums paid for derivatives, if any,
primarily with proceeds from debt or equity offerings, borrowings under the LINN
Credit Facility or other external sources of funding. Although it is the
Company's practice to acquire or modify derivative instruments with external
sources of funding, any cash settlements on derivatives are reported as net cash
provided by operating activities and may be used to fund distributions, if any.
See below for details regarding the discretionary adjustments considered by the
Company's Board of Directors in assessing the appropriate distribution amount
for each period, as well as the extent to which sources of funding have been
sufficient for the periods presented:
Year Ended December 31,
2015 2014 2013
(in thousands)
Net cash provided by operating activities $ 1,249,457 $ 1,711,890 $ 1,166,212 Distributions to unitholders
(323,878 ) (962,048 ) (682,241 )
Excess of net cash provided by operating
activities after distributions to unitholders 925,579 749,842 483,971
Discretionary adjustments considered by the
Board of Directors:
Discretionary reductions for a portion of oil
and natural gas development costs (1) NM* (823,562 ) (476,507 )
Development of oil and natural gas properties
(2) (450,286 ) NM* NM*
Cash settlements on canceled derivatives (3) (4,679 ) (12,281 )
-
Cash recoveries of bankruptcy claim (4) (4,232 ) (6,639 ) (11,222 )
Cash received (paid) for acquisitions or
divestitures - revenues less operating
expenses (5) (2,712 ) 91,890 7,144
Provision for legal matters (6) (1,000 ) 1,598 1,000
Changes in operating assets and liabilities and
other, net (7) (94,365 ) 23,228 (9,030 )
Excess of net cash provided by operating
activities after distributions to unitholders
and discretionary adjustments considered by the
Board of Directors, including total development
of oil and natural gas properties (8) $ 368,305 NM* NM*
Excess (shortfall) of net cash provided by
operating activities after distributions to
unitholders and discretionary adjustments
considered by the Board of Directors, including
a portion of oil and natural gas development
costs (8) NM* $
24,076 $ (4,644 )
* Not meaningful due to the 2015 change in presentation.
(1) Represent discretionary reductions for a portion of oil and natural gas
development costs, an estimated component of total development costs. The
Board of Directors establishes the discretionary reductions with the
objective of replacing proved developed producing reserves, current
production and cash flow, taking into consideration the Company's overall
commodity mix. Management evaluates all of these objectives as part of the
decision-making process to determine the discretionary reductions for a
portion of oil and natural gas development costs for the year, although
every objective may not be met in each year. Furthermore, there may be
certain years in which commodity prices and other economic conditions do not
merit capital spending at a level sufficient to accomplish any of these
objectives. The 2014 amounts were established by the Board of Directors at
the end of the previous year, allocated across four quarters, and were
intended to fully offset declines in production and proved developed
producing reserves during the year as compared to the prior year.
The portion of oil and natural gas development costs includes estimated drilling
and development costs associated with projects to convert a portion of
non-producing reserves to producing status. However, the amounts do not include
the historical cost of acquired properties as those amounts have already been
spent in prior periods, were financed primarily with external sources of funding
and do not affect the Company's ability to pay distributions in the current
period. The Company's existing reserves, inventory of drilling locations and
production levels will decline over time as a result of development and
production activities. Consequently, if the Company were to limit its total
capital expenditures to this portion of oil and natural gas development costs
and not acquire new reserves, total reserves would decrease over time, resulting
in an inability to maintain production at current levels, which could adversely
affect the Company's ability to pay a distribution, if and when resumed.
However, the Company's current total reserves do not include reserve additions
that may result from converting existing probable and possible resources to
additional proved reserves, potential additional discoveries or technological
advancements on the Company's existing acreage position.
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
(2) Represents total capital expenditures for the development of oil and natural
gas properties as presented on an accrual basis. For 2015, the Company
intends to fund its total oil and natural gas capital program, in addition
to interest expense and distributions to unitholders, from net cash provided
by operating activities; however, in October 2015, the Company's Board of
Directors approved the suspension of the Company's distribution. Previously,
the Company intended to fund only a portion of its oil and natural gas
capital program, in addition to interest expense and distributions to
unitholders, from net cash provided by operating activities.
(3) Represent derivatives canceled prior to the contract settlement date.
(4) Represent the recoveries of a bankruptcy claim against Lehman Brothers which
was not a transaction occurring in the ordinary course of the Company's
business.
(5) Represents adjustments to the purchase price of acquisitions and
divestitures, based on the Company's contractual right to revenues less
operating expenses for periods from the effective date of a transaction to
the closing date of a transaction. When the Company is the buyer, it is
legally entitled to revenues less operating expenses generated during this
period, and the Company's Board of Directors has historically made a
discretionary adjustment to include this cash in the amount available for
distribution. Conversely, when the Company is the seller, the Company's
Board of Directors has historically made a discretionary adjustment to
reduce this cash from the amount available for distribution during the
period. Beginning with the quarter ended June 30, 2015, the Board decided to
no longer make this discretionary adjustment.
(6) Represents reserves and settlements related to legal matters.
(7) Represents primarily working capital adjustments. These adjustments may or
may not impact cash provided by (used in) operating activities during the
respective period, but are included as discretionary adjustments considered
by the Company's Board of Directors as the Board historically has not varied
the distribution it declares period to period based on uneven cash flows.
The Company's Board of Directors, when determining the appropriate level of
cash distributions, excluded the impact of the timing of cash receipts and
payments; as such, this adjustment is necessary to show the historical
amounts considered by the Company's Board of Directors in assessing the
appropriate distribution amount for each period. This adjustment also
includes a reduction for accrued contractual interest on the Second Lien
Notes of approximately $14 million for the year ended December 31, 2015.
(8) Represents the excess (shortfall) of net operating cash flow after
distributions to unitholders and discretionary adjustments. Any excess was
retained by the Company for future operations, future capital expenditures,
future debt service or other future obligations. Any shortfall was funded
with cash on hand and/or borrowings under the LINN Credit Facility. In a
period where no distribution is paid, the Company will retain all excess of
net operating cash flow for future operations, future capital expenditures,
future debt service or other future obligations.
Any cash generated by Berry is currently being used by Berry to fund its
activities. To the extent that Berry generates cash in excess of its needs and
determines to distribute such amounts to LINN Energy, the indentures governing
Berry's senior notes limit the amount it may distribute to LINN Energy to the
amount available under a "restricted payments basket," and Berry may not
distribute any such amounts unless it is permitted by the indentures to incur
additional debt pursuant to the consolidated coverage ratio test set forth in
the Berry indentures. Berry's restricted payments basket was approximately $529
million at December 31, 2015, and may be increased in accordance with the terms
of the Berry indentures by, among other things, 50% of Berry's future net
income, reductions in its indebtedness and restricted investments, and future
capital contributions.
A summary of the significant sources and uses of funding for the respective
periods is presented below:
Year Ended December 31,
2015 2014 2013
(in thousands)
Net cash provided by operating activities $ 1,249,457 $ 1,711,890
$ 1,166,212
Distributions to unitholders (323,878 ) (962,048 ) (682,241 )
Excess of net cash provided by operating
activities after distributions to
unitholders 925,579 749,842
483,971
Plus (less):
Net cash provided by (used in) financing
activities (excluding distributions to
unitholders) (617,918 ) 1,119,900
820,274
Acquisition of oil and natural gas
properties and joint-venture funding, net of
cash acquired - (2,479,252 ) (279,213 )
Development of oil and natural gas
properties (608,889 ) (1,569,877 ) (1,078,025 )
Purchases of other property and equipment (66,708 ) (74,540 ) (92,352 )
Proceeds from sale of properties and
equipment and other 368,295 2,203,565
196,273
Net increase (decrease) in cash and cash
equivalents $ 359 $ (50,362 ) $ 50,928
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
Critical Accounting Policies and Estimates
The discussion and analysis of the Company's financial condition and results of
operations is based on the consolidated financial statements, which have been
prepared in accordance with
U.S.
generally accepted accounting principles. The
preparation of these financial statements requires management of the Company to
make estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, and related disclosures of contingent assets
and liabilities. These estimates and assumptions are based on management's best
estimates and judgment. Management evaluates its estimates and assumptions on an
ongoing basis using historical experience and other factors that are believed to
be reasonable under the circumstances. Such estimates and assumptions are
adjusted when facts and circumstances dictate. Actual results may differ from
these estimates and assumptions used in the preparation of the financial
statements.
Below are expanded discussions of the Company's more significant accounting
policies, estimates and judgments, i.e., those that reflect more significant
estimates and assumptions used in the preparation of its financial statements.
See Note 1 for details about additional accounting policies and estimates made
by Company management.
Recently Issued Accounting Standards
For a discussion of recently issued accounting standards, see Note 1.
Oil and Natural Gas Reserves
Proved reserves are based on the quantities of oil, natural gas and NGL that by
analysis of geoscience and engineering data can be estimated with reasonable
certainty to be economically producible from a given date forward, from known
reservoirs, and under existing economic conditions, operating methods and
government regulations prior to the time at which contracts providing the right
to operate expire, unless evidence indicates that renewal is reasonably certain.
The independent engineering firm, DeGolyer and MacNaughton, prepared a reserve
and economic evaluation of all of the Company properties on a well-by-well basis
as of December 31, 2015, and the reserve estimates reported herein were prepared
by DeGolyer and MacNaughton. The reserve estimates were reviewed and approved by
the Company's senior engineering staff and management, with final approval by
its Executive Vice President and Chief Operating Officer.
Reserves and their relation to estimated future net cash flows impact the
Company's depletion and impairment calculations. As a result, adjustments to
depletion and impairment are made concurrently with changes to reserve
estimates. The process performed by the independent engineers to prepare reserve
amounts included their estimation of reserve quantities, future production
rates, future net revenue and the present value of such future net revenue,
based in part on data provided by the Company. The estimates of reserves conform
to the guidelines of the SEC, including the criteria of "reasonable certainty,"
as it pertains to expectations about the recoverability of reserves in future
years.
The accuracy of reserve estimates is a function of many factors including the
following: the quality and quantity of available data, the interpretation of
that data, the accuracy of various mandated economic assumptions and the
judgments of the individuals preparing the estimates. In addition, reserve
estimates are a function of many assumptions, all of which could deviate
significantly from actual results. As such, reserve estimates may materially
vary from the ultimate quantities of oil, natural gas and NGL eventually
recovered. For additional information regarding estimates of reserves, including
the standardized measure of discounted future net cash flows, see "Supplemental
Oil and Natural Gas Data (Unaudited)" in Item 8. "Financial Statements and
Supplementary Data" and see also Item 1. "Business."
Oil and Natural Gas Properties
Proved Properties
The Company accounts for oil and natural gas properties in accordance with the
successful efforts method. In accordance with this method, all leasehold and
development costs of proved properties are capitalized and amortized on a
unit-of-production basis over the remaining life of the proved reserves and
proved developed reserves, respectively. Costs of retired, sold or abandoned
properties that constitute a part of an amortization base are charged or
credited, net of proceeds, to accumulated depreciation, depletion and
amortization unless doing so significantly affects the unit-of-production
amortization rate, in which case a gain or loss is recognized currently. Gains
or losses from the disposal of other properties are recognized currently.
Expenditures for maintenance and repairs necessary to maintain properties in
operating condition
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
are expensed as incurred. Estimated dismantlement and abandonment costs are
capitalized, net of salvage, at their estimated net present value and amortized
on a unit-of-production basis over the remaining life of the related proved
developed reserves. The Company capitalizes interest on borrowed funds related
to its share of costs associated with the drilling and completion of new oil and
natural gas wells. Interest is capitalized only during the periods in which
these assets are brought to their intended use. The Company capitalized interest
costs of approximately $5 million, $9 million and $2 million for the years ended
December 31, 2015, December 31, 2014, and December 31, 2013, respectively.
The Company evaluates the impairment of its proved oil and natural gas
properties on a field-by-field basis whenever events or changes in circumstances
indicate that the carrying value may not be recoverable. The carrying values of
proved properties are reduced to fair value when the expected undiscounted
future cash flows of proved and risk-adjusted probable and possible reserves are
less than net book value. The fair values of proved properties are measured
using valuation techniques consistent with the income approach, converting
future cash flows to a single discounted amount. Significant inputs used to
determine the fair values of proved properties include estimates of:
(i) reserves; (ii) future operating and development costs; (iii) future
commodity prices; and (iv) a market-based weighted average cost of capital rate.
These inputs require significant judgments and estimates by the Company's
management at the time of the valuation and are the most sensitive and subject
to change. The underlying commodity prices embedded in the Company's estimated
cash flows are the product of a process that begins with New York Mercantile
Exchange forward curve pricing, adjusted for estimated location and quality
differentials, as well as other factors that Company management believes will
impact realizable prices.
Based on the analysis described above, for the years ended December 31, 2015,
December 31, 2014, and December 31, 2013, the Company recorded noncash
impairment charges (before and after tax) of approximately $4.9 billion, $2.3
billion and $791 million, respectively, associated with proved oil and natural
gas properties. The carrying values of the impaired proved properties were
reduced to fair value, estimated using inputs characteristic of a Level 3 fair
value measurement. The impairment charges are included in "impairment of
long-lived assets" on the consolidated statements of operations.
Unproved Properties
Costs related to unproved properties include costs incurred to acquire unproved
reserves. Because these reserves do not meet the definition of proved reserves,
the related costs are not classified as proved properties. Unproved leasehold
costs are capitalized and amortized on a composite basis if individually
insignificant, based on past success, experience and average lease-term lives.
Individually significant leases are reclassified to proved properties if
successful and expensed on a lease by lease basis if unsuccessful or the lease
term expires. Unamortized leasehold costs related to successful exploratory
drilling are reclassified to proved properties and depleted on a
unit-of-production basis. The Company assesses unproved properties for
impairment quarterly on the basis of its experience in similar situations and
other factors such as the primary lease terms of the properties, the average
holding period of unproved properties and the relative proportion of such
properties on which proved reserves have been found in the past.
Based primarily on no future plans to develop properties in certain operating
areas as a result of declines in commodity prices, for the year ended
December 31, 2015, the Company recorded noncash impairment charges (before and
after tax) of approximately $899 million associated with unproved oil and
natural gas properties. The carrying values of the impaired unproved properties
were reduced to fair value, estimated using inputs characteristic of a Level 3
fair value measurement. The impairment charges are included in "impairment of
long-lived assets" on the consolidated statement of operations.
Exploration Costs
Geological and geophysical costs, delay rentals, amortization and impairment of
unproved leasehold costs and costs to drill exploratory wells that do not find
proved reserves are expensed as exploration costs. The costs of any exploratory
wells are carried as an asset if the well finds a sufficient quantity of
reserves to justify its capitalization as a producing well and as long as the
Company is making sufficient progress towards assessing the reserves and the
economic and operating viability of the project. The Company recorded noncash
leasehold impairment expenses related to unproved properties of approximately $2
million, $125 million and $5 million for the years ended December 31, 2015,
December 31, 2014, and December 31, 2013, respectively, which are included in
"exploration costs" on the consolidated statements of operations.
Revenue Recognition
Sales of oil, natural gas and NGL are recognized when the product has been
delivered to a custody transfer point, persuasive evidence of a sales
arrangement exists, the rights and responsibility of ownership pass to the
purchaser upon delivery,
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
collection of revenue from the sale is reasonably assured and the sales price is
fixed or determinable. In addition, the Company engages in the purchase,
gathering and transportation of third-party natural gas and subsequently markets
such natural gas to independent purchasers under separate arrangements. As such,
the Company separately reports third-party marketing revenues and marketing
expenses.
Derivative Instruments
The Company has hedged a portion of its forecasted production to reduce exposure
to fluctuations in oil and natural gas prices. The current direct NGL hedging
market is constrained in terms of price, volume, duration and number of
counterparties, which limits the Company's ability to effectively hedge its NGL
production. The Company also hedges its exposure to natural gas differentials in
certain operating areas but does not currently hedge exposure to oil
differentials. By removing a portion of the price volatility associated with
future production, the Company expects to mitigate, but not eliminate, the
potential effects of variability in net cash provided by operating activities
due to fluctuations in commodity prices.
The Company maintains a substantial portion of its hedges in the form of swap
contracts. From time to time, the Company has chosen to purchase put option
contracts to hedge volumes in excess of those already hedged with swap
contracts. In 2013, the Company assumed certain derivative contracts that Berry
had entered into prior to the acquisition date, including swap contracts,
collars and three-way collars. The Company does not enter into derivative
contracts for trading purposes.
A swap contract specifies a fixed price that the Company will receive from the
counterparty as compared to floating market prices, and on the settlement date
the Company will receive or pay the difference between the swap price and the
market price. A put option requires the Company to pay the counterparty a
premium equal to the fair value of the option at the purchase date and receive
from the counterparty the excess, if any, of the fixed price floor over the
market price at the settlement date. Collar contracts specify floor and ceiling
prices to be received as compared to floating market prices. Three-way collar
contracts combine a short put (the lower price), a long put (the middle price)
and a short call (the higher price) to provide a higher ceiling price as
compared to a regular collar and limit downside risk to the market price plus
the difference between the middle price and the lower price if the market price
drops below the lower price.
Derivative instruments are recorded at fair value and included on the
consolidated balance sheets as assets or liabilities. The Company did not
designate any of its contracts as cash flow hedges; therefore, the changes in
fair value of these instruments are recorded in current earnings. The Company
determines the fair value of its oil and natural gas derivatives utilizing
pricing models that use a variety of techniques, including market quotes and
pricing analysis. Inputs to the pricing models include publicly available prices
and forward price curves generated from a compilation of data gathered from
third parties. Company management validates the data provided by third parties
by understanding the pricing models used, obtaining market values from other
pricing sources, analyzing pricing data in certain situations and confirming
that those instruments trade in active markets. Assumed credit risk adjustments,
based on published credit ratings, public bond yield spreads and credit default
swap spreads are applied to the Company's commodity derivatives. See Note 7 and
Note 8 for additional details about the Company's derivative financial
instruments. See Item 7A. "Quantitative and Qualitative Disclosures About Market
Risk" for sensitivity analysis regarding the Company's derivative financial
instruments.
The Company may from time to time enter into derivative contracts in the form of
interest rate swaps to minimize the effects of fluctuations in interest rates.
At December 31, 2015, the Company had no outstanding derivative contracts in the
form of interest rate swaps.
Acquisition Accounting
The Company accounts for business combinations under the acquisition method of
accounting (see Note 2). Accordingly, the Company recognizes amounts for
identifiable assets acquired and liabilities assumed equal to their estimated
acquisition date fair values. Transaction and integration costs associated with
business combinations are expensed as incurred. Any excess of the acquisition
price over the estimated fair value of net assets acquired is recorded as
goodwill while any excess of the estimated fair value of net assets acquired
over the acquisition price is recorded in current earnings as a gain.
The Company makes various assumptions in estimating the fair values of assets
acquired and liabilities assumed. As fair value is a market-based measurement,
it is determined based on the assumptions that market participants would use.
The
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Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Continued
most significant assumptions relate to the estimated fair values of proved and
unproved oil and natural gas properties. The fair values of these properties are
measured using valuation techniques that convert future cash flows to a single
discounted amount. Significant inputs to the valuation include estimates of:
(i) reserves; (ii) future operating and development costs; (iii) future
commodity prices; and (iv) a market-based weighted average cost of capital rate.
The market-based weighted average cost of capital rate is subjected to
additional project-specific risking factors. To compensate for the inherent risk
of estimating and valuing unproved properties, the discounted future net
revenues of probable and possible reserves are reduced by additional
risk-weighting factors. In addition, when appropriate, the Company reviews
comparable purchases and sales of oil and natural gas properties within the same
regions, and uses that data as a proxy for fair market value; i.e., the amount a
willing buyer and seller would enter into in exchange for such properties.
While the estimated fair values of the assets acquired and liabilities assumed
have no effect on cash flow, they can have an effect on future results of
operations. Generally, higher fair values assigned to oil and natural gas
properties result in higher future depreciation, depletion and amortization
expense, which results in decreased future net income. Also, a higher fair value
assigned to oil and natural gas properties, based on higher future estimates of
commodity prices, could increase the likelihood of impairment in the event of
lower commodity prices or higher operating costs than those originally used to
determine fair value. The recording of impairment expense has no effect on cash
flow but results in a decrease in net income for the period in which the
impairment is recorded.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Company's primary market risks are attributable to fluctuations in commodity
prices and interest rates. These risks can affect the Company's business,
financial condition, operating results and cash flows. See below for
quantitative and qualitative information about these risks. The disclosures are
not meant to be precise indicators of expected future losses, but rather
indicators of reasonably possible losses. This forward-looking information
provides indicators of how the Company views and manages its ongoing market risk
exposures.
The following should be read in conjunction with the financial statements and
related notes included elsewhere in this Annual Report on Form 10-K. The
reference to a "Note" herein refers to the accompanying Notes to Consolidated
Financial Statements contained in Item 8. "Financial Statements and
Supplementary Data."
Commodity Price Risk
The Company's most significant market risk relates to prices of oil, natural gas
and NGL. The Company expects commodity prices to remain volatile and
unpredictable. As commodity prices decline or rise significantly, revenues and
cash flows are likewise affected. In addition, future declines in commodity
prices may result in noncash write-downs of the Company's carrying amounts of
its assets.
The Company has hedged a portion of its forecasted production to reduce exposure
to fluctuations in oil and natural gas prices and provide long-term cash flow
predictability to manage its business, service debt, and, if and when resumed,
pay distributions. The current direct NGL hedging market is constrained in terms
of price, volume, duration and number of counterparties, which limits the
Company's ability to effectively hedge its NGL production. The Company also
hedges its exposure to natural gas differentials in certain operating areas but
does not currently hedge exposure to oil differentials. By removing a portion of
the price volatility associated with future production, the Company expects to
mitigate, but not eliminate, the potential effects of variability in net cash
provided by operating activities due to fluctuations in commodity prices.
The appropriate level of production to be hedged is an ongoing consideration and
is based on a variety of factors, including current and future expected
commodity market prices, cost and availability of put option contracts, the
level of acquisition activity and the Company's overall risk profile, including
leverage and size and scale considerations. In addition, when commodity prices
are depressed and forward commodity price curves are flat or in backwardation,
the Company may determine that the benefit of hedging its anticipated production
at these levels is outweighed by its resultant inability to obtain higher
revenues for its production if commodity prices recover during the duration of
the contracts. As a result, the appropriate percentage of production volumes to
be hedged may change over time.
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Table of Contents Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Continued
The Company maintains a substantial portion of its hedges in the form of swap
contracts. From time to time, the Company has chosen to purchase put option
contracts to hedge volumes in excess of those already hedged with swap
contracts; however, the Company did not purchase any put options in 2015, 2014
or 2013. In 2013, the Company assumed certain derivative contracts that Berry
Petroleum Company, now Berry Petroleum Company, LLC ("Berry") had entered into
prior to the acquisition date, including swap contracts, collars and three-way
collars. The Company does not enter into derivative contracts for trading
purposes. There have been no significant changes to the Company's objectives,
general strategies or instruments used to manage the Company's commodity price
risk exposures from the year ended December 31, 2014.
In certain historical periods, the Company paid an incremental premium to
increase the fixed price floors on existing put options because the Company
typically hedges multiple years in advance and in some cases commodity prices
had increased significantly beyond the initial hedge prices. As a result, the
Company determined that the existing put option strike prices did not provide
reasonable downside protection in the context of the current market.
At December 31, 2015, the fair value of fixed price swaps and put option
contracts was a net asset of approximately $1.7 billion. A 10% increase in the
index oil and natural gas prices above December 31, 2015, prices would result in
a net asset of approximately $1.5 billion, which represents a decrease in the
fair value of approximately $190 million; conversely, a 10% decrease in the
index oil and natural gas prices below December 31, 2015, prices would result in
a net asset of approximately $1.9 billion, which represents an increase in the
fair value of approximately $190 million.
At December 31, 2014, the fair value of fixed price swaps, put option contracts,
collars and three-way collars was a net asset of approximately $1.8 billion. A
10% increase in the index oil and natural gas prices above December 31, 2014,
prices would result in a net asset of approximately $1.4 billion, which
represents a decrease in the fair value of approximately $423 million;
conversely, a 10% decrease in the index oil and natural gas prices below
December 31, 2014, prices would result in a net asset of approximately $2.2
billion, which represents an increase in the fair value of approximately $421
million.
The Company determines the fair value of its oil and natural gas derivatives
utilizing pricing models that use a variety of techniques, including market
quotes and pricing analysis. Inputs to the pricing models include publicly
available prices and forward price curves generated from a compilation of data
gathered from third parties. Company management validates the data provided by
third parties by understanding the pricing models used, obtaining market values
from other pricing sources, analyzing pricing data in certain situations and
confirming that those instruments trade in active markets.
The prices of oil, natural gas and NGL have been extremely volatile, and the
Company expects this volatility to continue. Prices for these commodities may
fluctuate widely in response to relatively minor changes in the supply of and
demand for such commodities, market uncertainty and a variety of additional
factors that are beyond its control. Actual gains or losses recognized related
to the Company's derivative contracts will likely differ from those estimated at
December 31, 2015, and will depend exclusively on the price of the commodities
on the specified settlement dates provided by the derivative contracts.
The Company cannot be assured that its counterparties will be able to perform
under its derivative contracts. If a counterparty fails to perform and the
derivative arrangement is terminated, the Company's cash flows could be
impacted.
Interest Rate Risk
At December 31, 2015, the Company had debt outstanding under its credit
facilities and term loan of approximately $3.6 billion which incurred interest
at floating rates (see Note 6). A 1% increase in the London Interbank Offered
Rate ("LIBOR") would result in an estimated $36 million increase in annual
interest expense.
At December 31, 2014, the Company had debt outstanding under its credit
facilities and term loan of approximately $3.5 billion which incurred interest
at floating rates. A 1% increase in the LIBOR would result in an estimated $35
million increase in annual interest expense.
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Table of Contents Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Continued
Counterparty Credit Risk
The Company accounts for its commodity derivatives at fair value on a recurring
basis (see Note 8). The fair value of these derivative financial instruments
includes the impact of assumed credit risk adjustments, which are based on the
Company's and counterparties' published credit ratings, public bond yield
spreads and credit default swap spreads, as applicable.
At December 31, 2015, the average public bond yield spread utilized to estimate
the impact of the Company's credit risk on derivative liabilities was
approximately 3.23%. A 1% increase in the average public bond yield spread would
result in an estimated $25,000 increase in net income for the year ended
December 31, 2015. At December 31, 2015, the credit default swap spreads
utilized to estimate the impact of counterparties' credit risk on derivative
assets ranged between 0% and 2.64%. A 1% increase in each of the counterparties'
credit default swap spreads would result in an estimated $15 million decrease in
net income for the year ended December 31, 2015.
At December 31, 2014, the average public bond yield spread utilized to estimate
the impact of the Company's credit risk on derivative liabilities was
approximately 1.85%. A 1% increase in the average public bond yield spread would
result in an estimated $18,000 increase in net income for the year ended
December 31, 2014. At December 31, 2014, the credit default swap spreads
utilized to estimate the impact of counterparties' credit risk on derivative
assets ranged between 0% and 2.15%. A 1% increase in each of the counterparties'
credit default swap spreads would result in an estimated $20 million decrease in
net income for the year ended December 31, 2014.
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