EPL OIL & GAS, INC. - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
Statements we make in this quarterly report on Form 10-Q (the "Quarterly
Report") which express a belief, expectation or intention, as well as those that
are not historical fact, may constitute forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of 1995. Our
forward-looking statements are subject to various risks, uncertainties and
assumptions, including those to which we refer under the headings "Cautionary
Statement Concerning Forward-Looking Statements" and "Item 1A. Risk Factors"
included in our 2015 Annual Report and elsewhere in this Quarterly Report.
Overview
EPL Oil & Gas, Inc. ("we," "our," "us," "the Company" or "EPL") was incorporated
as a
Delaware
corporation on January 29, 1998 and is a wholly-owned subsidiary
of Energy XXI Gulf Coast, Inc. ("EGC"), a
Delaware
corporation and indirect
wholly-owned subsidiary of Energy XXI Ltd, an exempted company under the laws of
Bermuda
("Energy XXI"). We operate as an independent oil and natural gas
exploration and production company with current operations concentrated in the
U.S.
Gulf of Mexico shelf ("GoM shelf") focusing on state and federal waters
offshore
Louisiana
, which we consider our core area.
On June 3, 2014, Energy XXI, EGC, Clyde Merger Sub, Inc., a wholly-owned
subsidiary of EGC ("Merger Sub"), and EPL, completed the transactions
contemplated by the Agreement and Plan of Merger, dated as of March 12, 2014 (as
amended, the "Merger Agreement"), by and among Energy XXI, EGC, Merger Sub, and
EPL, pursuant to which Merger Sub was merged with and into EPL with EPL
continuing as the surviving corporation (the "Merger"). Pursuant to the Merger
Agreement, at the effective time of the Merger, the issued and outstanding
shares of EPL common stock were converted, in the aggregate, into the merger
consideration consisting of approximately 65% in cash and 35% in shares of
Energy XXI common stock.
As a result of the Merger, the future strategy of EPL is determined by Energy
XXI's Board of Directors. For the six months ended December 31, 2015, our
capital expenditures totaled approximately $67 million. Our current capital
expenditures are allocated to development activities, which are geared toward
the improvement of existing production and the performance of necessary
plugging, abandonment and other decommissioning activities.
Due to the uncertainty regarding future commodity prices, we plan to manage our
operating activities and financial liquidity carefully. We do not expect
production increases from our fiscal year 2016 capital program to entirely
offset production declines, resulting in slight decreases to our production. We
plan to continuously evaluate our level of operating activity in light of both
actual commodity prices and changes we are able to make to our costs of
operations and make further adjustments to our capital spending program as
appropriate. In addition, in light of current commodity prices and our leverage
position, in February 2016, Energy XXI engaged PJT Partners as a financial
advisor and Vinson & Elkins L.L.P. as a legal advisor to advise its management
and the Board, EGC and EPL regarding potential strategic alternatives such as a
refinancing or restructuring of our indebtedness or capital structure or seeking
to raise additional capital through debt or equity financing to address our
liquidity issues and high debt levels. On February 16, 2016, we elected to enter
into the 30-day grace period under the terms of the indenture governing the
8.25% Senior Notes to extend the timeline for making the cash interest payment
to March 17, 2016. The aggregate amount of the interest payments is
approximately $8.8 million. During the 30-day grace period, the Company, EGC and
Energy XXI will work with their debt holders regarding their ongoing effort to
develop and implement a comprehensive plan to restructure their balance sheets.
For additional detail, see "- Liquidity - Overview." We cannot assure you that
any refinancing or debt or equity restructuring would be possible or that
additional equity or debt financing could be obtained on acceptable terms, if at
all. If we are unable to improve our liquidity position, refinance or
restructure our debt obligations or are unsuccessful in implementing such
strategic alternatives, we may seek bankruptcy protection to continue our
efforts to restructure our business and capital structure and may have to
liquidate our assets and may receive less than the value at which those assets
are carried on our consolidated financial statements.
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We produce both oil and natural gas. Throughout this Quarterly Report, when we
refer to "total production," "total reserves," "percentage of production,"
"percentage of reserves," or any similar term, we have converted our natural gas
reserves or production into barrel of oil equivalents. For this purpose, six
thousand cubic feet of natural gas is equal to one barrel of oil, which is based
on the relative energy content of natural gas and oil. Natural gas liquids are
aggregated with oil in this Quarterly Report.
Known Trends and Uncertainties
Commodity Price Volatility and Impact on our Results of Operations, Compliance
with Debt Instruments and Liquidity. Prices for oil and natural gas historically
have been volatile and are expected to continue to be volatile. Oil and natural
gas prices declined significantly during fiscal year 2015 and the decline has
continued into fiscal year 2016. The posted price per barrel for West Texas
intermediate light sweet crude oil, or WTI, for the period from October 1, 2014
to December 31, 2015 ranged from a high of $91.01 to a low of $34.73, a decrease
of 61.8%, and the NYMEX natural gas price per MMBtu for the period October 1,
2014 to December 31, 2015 ranged from a high of $4.49 to a low of $1.76, a
decrease of 60.8%. As of December 31, 2015, the spot market price for WTI was
$37.04. Oil prices have continued to decline in 2016, with the price of WTI
crude oil per barrel dropping below $27.00 in January 2016 for the first time in
twelve years. The recent declines in oil prices have adversely affected our
financial position and results of operations and the quantities of oil and
natural gas reserves that we can economically produce.
As of December 31, 2015, we were in compliance with our financial covenants
under the Revolving Credit Facility; however, based on current market conditions
and depressed commodity prices, if we are unable to execute on one of the
strategic alternatives discussed below and adequately address liquidity
concerns, we will not be in compliance with the consolidated net secured
leverage ratio covenant under the Revolving Credit Facility for the quarter
ending March 31, 2016. There is no assurance that we will be able to resolve
such non-compliance with our lenders, which may result in a default under our
Revolving Credit Facility. In addition, as described in greater detail under
"- Liquidity and Capital Resources - Overview," our ability to access available
borrowing capacity under our Revolving Credit EPL Sub-Facility will be limited
as a result of other provisions of the Revolving Credit Facility or a reduction
in our borrowing base at our next redetermination in the spring of 2016. If we
experience sustained periods of low prices for oil and natural gas, it will have
a further material adverse effect on our financial position, our results of
operations, the quantities of oil and natural gas reserves that we can
economically produce and our access to capital.
Reserve Quantities. A prolonged period of depressed commodity prices could have
a significant impact on the value and volumetric quantities of our proved
reserve portfolio, assuming no other changes in our development plans. At
December 31, 2015, our total proved reserves were 35.3 MMBOE. The unweighted
arithmetic average first-day-of-the-month prices used to determine our reserves
as of June 30, 2015 were $73.88 per barrel of oil, $31.64 per barrel for NGLs
and $3.11 per MMBtu for natural gas, which is significantly higher than current
forward strip prices. At NYMEX forward strip pricing as of January 29, 2016, we
estimate that our total proved reserve equivalent volumes as of December 31,
2015 would have been approximately 2.2% higher compared to the results obtained
using SEC pricing. Our estimated reserves as of June 30, 2015 may be further
adjusted as warranted based on any changes to our long range plan, expected
capital availability and drilling cost environment. The Company's proved
reserves declined significantly compared to prior years and may decline in
future years. Due to the depressed commodity prices and our lack of capital
resources to develop our properties, the Company believes that all of its proved
undeveloped oil and gas reserves no longer qualify as being proved as of the
period ended December 31, 2015. We have thus removed all of our proved
undeveloped oil and gas reserves from the proved category as of December 31,
2015. Almost all of the proved undeveloped reserves that were removed from the
proved category as of December 31, 2015 are still economic at current prices,
but were reclassed to the probable category because they are no longer expected
to be drilled within five years of initial booking due to current constraints on
ability to fund development drilling. In addition, as of December 31, 2015, we
identified certain of our unevaluated properties totaling to $314.4 million as
being uneconomical and have transferred such amounts to the full cost pool,
subject to amortization.
Ceiling Test Write-down. During the six months ended December 31, 2015, we
recognized write-downs of our oil and natural gas properties totaling $812.9
million. The write-downs did not impact our cash flows from operating activities
but did increase our net loss for the period and our stockholders' deficit.
Further
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ceiling test write-downs will be required if oil and natural gas prices remain
low or decline further, unproved property values decrease, estimated proved
reserve volumes are revised downward or the net capitalized cost of proved oil
and gas properties otherwise exceeds the present value of estimated future net
cash flows. Based on the average oil and natural gas price calculated as the
unweighted arithmetic average of the first-day-of-the-month price for each month
within the previous 12 months ending January 31, 2016, we presently expect to
incur further impairment of $75 million to $175 million in the third fiscal
quarter of 2016. If the current low commodity price environment or downward
trend in oil prices continues, we will incur further impairment to our full cost
pool in fiscal 2016 and beyond based on the average oil and natural gas price
calculated as the unweighted arithmetic average of the first-day-of-the-month
price for each month within the previous 12-month period under the SEC pricing
methodology.
Decreasing Service Costs. We have also seen a significant and continuing reduction in rig rates and drilling costs, which should allow us to spend less capital drilling our development wells than in prior periods.
BOEM Supplemental Financial Assurance and/or Bonding Requirements. As of
December 31, 2015, we had $189.7 million of performance bonds outstanding. As a
lessee and operator of oil and natural gas leases on the federal OCS,
approximately $67.2 million of our performance bonds are lease and/or area bonds
issued to the BOEM that the BOEM has access to and assure our commitment to
comply with the terms and conditions of those leases. We also maintain
approximately $122.5 million in performance bonds issued to predecessor third
party assignors rather than to the BOEM, including certain state regulatory
bodies of certain of the wells and facilities on these leases pursuant to a
contractual commitment made by us to those third parties at the time of
assignment with respect to the eventual decommissioning of those wells and
facilities.
In April 2015, we received letters from the BOEM stating that certain of our
subsidiaries no longer qualify for waiver of certain supplemental bonding
requirements for potential offshore decommissioning, plugging and abandonment
liabilities. The letters notified us that certain of our subsidiaries must
provide approximately $566.5 million in supplemental financial assurance and/or
bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use
and easements. In June 2015 and December 2015, we reached agreements with the
BOEM with respect to which we provided $54.7 million and $8.9 million,
respectively, of supplemental bonds issued to the BOEM (which is reflected in
the $67.2 million in lease and/or area bonds discussed above). On June 30, 2015,
we sold the East Bay field, and as a result, the $566.5 million of requested
supplemental bonding was reduced by approximately $178 million.
In October 2015, we received information from the BOEM indicating that we could
receive additional demands of supplemental financial assurance for amounts in
addition to the $566.5 million initially sought by the BOEM in April 2015,
primarily relating to certain properties that are no longer exempt from
supplemental bonding as a result of co-lessees losing their exemptions. However,
we believe a substantial portion of the additional supplemental financial
assurance and/or bonding that could be sought by the BOEM may relate to
circumstances that could eventually be removed from our responsibility (in terms
of providing added assurance or bonding), including, for example, lease
interests of co-lessees, leases that have since been divested by us, and leases
where we are not the permitted operator and no drilling of wells has occurred.
We would expect that most, if not all, of our co-lessees with the remaining
working interest in such lease interests will provide their share of the bonding
but we can provide no assurance that such cooperation by these co-lessees will
occur.
Since we received the additional information from the BOEM in October 2015, we
have had a series of discussions and exchanges of information with the BOEM on
the long-term financial assurance plan, culminating most recently in our
submittal of an updated version of the long-term financial assurance plan to the
BOEM for approval on February 2, 2016. The long-term plan calls for a series of
actions by us during various dates in 2016, including by June 1, 2016 and
September 1, 2016, which actions are designed to address the supplemental
financial assurance liabilities initially identified by the BOEM, as such
liabilities are further modified by the BOEM based on information we provide and
our performance under the plan. This long-term plan requires approval by the
BOEM in order for us to proceed with addressing these supplemental financial
assurance liabilities. While we believe that the long-term financial assurance
plan is close to being approved by the BOEM, we can provide no assurance as to a
certain date by which the long-term plan will be approved or that the BOEM will
not have further revisions to our proposal.
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If our co-lessees and us are unable to agree on allocation of supplemental
financial assurance and/or bonding amounts for such specified leases and present
such agreed upon allocations to the BOEM for approval, the BOEM may direct
supplemental financial assurance and/or bonding amounts for 100% of the lease
interests to us, which would substantially increase the supplemental financial
assurance and/or bonding requirements. We expect that the BOEM will assess
additional supplemental financial assurance and/or bonding requirements on us in
such other letters that may be issued later if those items are not addressed in
our plan.
Unrelated to the BOEM's April 2015 directive, on September 22, 2015, the BOEM
issued Draft Guidance relating to supplemental bonding procedures that will,
among other things, eliminate the "waiver" exemption currently allowed by BOEM
with respect to supplemental bonding and, instead, broaden the self-insurance
approach that would allow more operators on the OCS to seek self-insurance for a
portion of their supplemental bond obligations, but only for an amount that is
no more than 10% of such operators' tangible net worth. In addition, the Draft
Guidance would implement a phased-in period for establishing compliance with
supplemental bonding obligations, whereby operators may seek payment of
estimated costs of decommissioning obligations owed under a "tailored plan" that
is approved by the BOEM and would require payment of the supplemental bonding
amount in three approximately equal installments of one-third each, by no later
than 120, 240 and 360 calendar days, respectively, from the date of BOEM
approval of the tailored plan. Furthermore, with issuance of an Advanced Notice
of Proposed Rulemaking in August 2014, the BOEM is actively seeking to bolster
its financial assurance requirements mandated by rule for all companies
operating in federal waters.
While the Draft Guidance, once implemented by the BOEM, would allow an increased
number of operators (relative to those operators under the existing NTL
regarding supplemental financial assurance and bonding) to self-insure for their
decommissioning liabilities that is no more than 10% of their tangible net
worth, there is no assurance that the BOEM will allow us to utilize
self-insurance programs and we currently do not plan for self-insurance under
the long-term financial assurance plan that we plan to submit to the BOEM.
In addition to the Draft Guidance describing revised supplemental bonding
procedures that may be used by the bureau, the BOEM is actively seeking to
bolster its financial assurance requirements mandated by rule for all companies
operating in federal waters. The cost of compliance with our existing
supplemental bonding requirements, including the directives issued by the BOEM
in April 2015 and June 2015, any other future directives, or any other changes
to the BOEM's current NTL supplemental bonding requirements or supplemental
bonding regulations applicable to us or our subsidiaries' properties could
materially and adversely affect our financial condition, cash flows, and results
of operations. In addition, we may be required to provide cash collateral or
letters of credit to support the issuance of such bonds or other surety. Such
letters of credit would likely be issued under our Revolving Credit EPL
Sub-Facility and would reduce the amount of borrowings available under such
facility in the amount of any such letter of credit obligations.
We can provide no assurance that we can continue to obtain bonds or other surety
in all cases or that we will have sufficient availability under our Revolving
Credit EPL Sub-Facility to support such supplemental bonding requirements. If we
are unable to obtain the additional required bonds or assurances as requested,
the BOEM may require any of our operations on federal leases to be suspended,
cancelled or otherwise impose monetary penalties, and one or more of such
actions could have a material adverse effect on our business, prospects, results
of operations, financial condition, and liquidity.
Oil Spill Response Plan. We maintain a Regional Oil Spill Response Plan (the
"OSRP") that defines our response requirements, procedures and remediation plans
in the event we have an oil spill. Oil Spill Response Plans are approved by the
Bureau of Safety and Environmental Enforcement ("BSEE"). The OSRP is reviewed at
least annually, and updated as necessary, which updates also require BSEE
approval. The OSRP specifications are consistent with the requirements set forth
by the BSEE. Additionally, the OSRP is tested and drills are conducted annually
at all levels of the Company.
We have contracted with a spill response management consultant to provide
management expertise, personnel and equipment, under our supervision, in the
event of an incident requiring a coordinated response. Additionally, we are a
member of Clean Gulf Associates ("CGA"), a not-for-profit association of
producing
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and pipeline companies operating in the Gulf of Mexico that has the appropriate
equipment, including aircraft dispersant capabilities through its contract with
Airborne Support Inc. and access to appropriate personnel to simultaneously
respond to multiple spills. In the event of a spill, CGA mobilizes appropriate
equipment and personnel to CGA members.
Hurricanes. Since the majority of our production originates in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.
Results of Operations
Three Months Ended December 31, 2015 Compared to Three Months Ended December 31,
2014
Our consolidated net loss for the three months ended December 31, 2015 was
$544.5 million as compared to $454.6 million for the three months ended December
31, 2014. The increase in the net loss was primarily due to no income tax
benefit and lower revenues due to lower oil and natural gas sales prices in the
second quarter of fiscal 2015, partially offset by lower impairment of oil and
natural gas properties.
Revenues
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Three Months Ended
December 31, Percent
2015 2014 Decrease Decrease
(In thousands)
Oil $ 54,408 $ 120,828 $ (66,420 ) (55.0 )%
Natural gas 8,256 12,548 (4,292 ) (34.2 )%
Gain on
derivative
financial
instruments 906 22,262 (21,356 ) (95.9 )%
Total Revenues $ 63,570 $ 155,638 $ (92,068 ) (59.2 )%
Our consolidated revenues decreased $92.1 million in the second quarter of
fiscal 2016 as compared to the same period in the prior fiscal year. Lower
revenues were primarily due to lower commodity sales prices and lower gain on
derivative financial instruments. Revenue variances related to commodity prices,
sales volumes and hedging activities are presented in the following table and
described below.
Price and Volume Variances
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Three Months Ended Percent Revenue
December 31, Increase Increase Increase
2015 2014 (Decrease) (Decrease) (Decrease)
(In thousands)
Price Variance
Oil sales prices
(per Bbl) $ 38.18 $ 71.12 $ (32.94 ) (46.3 )% $ (55,958 )
Natural gas sales
prices (per Mcf) 1.85 3.52 (1.67 ) (47.4 )% (5,943 )
Gain on
derivative
financial
instruments (per
BOE) 0.42 9.71 (9.29 ) (95.7 )% (21,356 )
Total price
variance (83,257 )
Volume Variance
Oil sales volumes
(MBbls) 1,425 1,699 (274 ) (16.1 )% (10,462 )
Natural gas sales
volumes (MMcf) 4,455 3,564 891 25.0 % 1,651
BOE sales volumes
(MBOE) 2,167 2,293 (126 ) (5.5 )%
Percent of BOE
from oil 66 % 74 %
Total volume
variance (8,811 )
Total price and
volume variance $ (92,068 )
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Price Variances
Commodity prices are one of the key drivers of our earnings and net operating
cash flow. Lower commodity prices decreased revenues by $83.3 million in the
second quarter of fiscal 2016 as compared to the same period in the prior fiscal
year. Average oil prices decreased $32.94 per barrel in the second quarter of
fiscal 2016, resulting in lower revenues of $56.0 million. Average natural gas
prices decreased $1.67 per Mcf in the second quarter of fiscal 2016 compared to
the second quarter of fiscal 2015, resulting in lower revenues of $5.9 million.
For the second quarter of fiscal 2016, our hedging activities resulted in a gain
on derivative activities of $0.42 per BOE compared to a gain of $9.71 per BOE
for the same period in the prior fiscal year, resulting in lower revenues of
$21.4 million. The gain on derivatives for the three months ended December 31,
2014 reflects a gain on settlements and monetization of our derivative contracts
of approximately $16.28 per barrel of oil.
Commodity prices are affected by many factors that are outside of our control,
and we cannot accurately predict future commodity prices. Depressed commodity
prices over an extended period of time will result in reduced cash from
operating activities, potentially causing us to further reduce our capital
expenditure program. As a result of our high level of indebtedness and commodity
prices, we have significantly reduced our planned capital spending, and such
curtailment of the development of our properties will eventually lead to a
decline in our production and reserves. A decline in our production and reserves
will further reduce our liquidity and ability to satisfy our debt obligations by
negatively impacting our cash flow from operating activities and the value of
our assets.
Volume Variances
Sales volumes are another key driver of our earnings and net operating cash
flow. Oil sales volumes decreased 3.0 MBbls per day in the second quarter of
fiscal 2016 as compared to the same period in the prior fiscal year, resulting
in lower revenues of $10.5 million. Natural gas sales volumes increased by 9.7
MMcf per day for the second quarter of fiscal 2016 as compared to the same
period in the prior fiscal year, resulting in higher revenues of $1.7 million.
Overall sales volumes decreased because of natural well declines, reduced
drilling activity resulting in less new production, and irregular downtime due
to third party pipelines. In the low commodity price environment, we expect to
see further production declines due to natural declines and limited activity in
the fields.
Costs and Expenses and Other (Income) Expense
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Three Months Ended December 31, Increase
2015 2014 (Decrease)
Total Per Total Per Total
$ BOE $ BOE $
(In thousands, except per unit amounts)
Cost and expenses
Lease operating
expense $ 30,889 $ 14.25 $ 55,304 $ 24.12 $ (24,415 )
Transportation 664 0.31 1,149 0.50 (485 )
Depreciation,
depletion and
amortization 62,333 28.76 88,547 38.62 (26,214 )
Accretion of
asset retirement
obligations 6,317 2.92 6,098 2.66 219
Impairment of oil
and natural gas
properties 504,772 232.94 690,312 301.05 (185,540 )
General and
administrative 9,978 4.60 6,810 2.97 3,168
Taxes, other than
on earnings 39 0.02 1,944 0.85 (1,905 )
Total costs and
expenses $ 614,992 $ 283.80 $ 850,164 $ 370.77 $ (235,172 )
Other (income)
expense
Other income, net $ (2,393 ) $ (1.10 ) $ (4 ) $ - $ (2,389 )
Gain on early
extinguishment of
debt (21,269 ) (9.81 ) - - (21,269 )
Interest expense 16,772 7.74 10,947 4.77 5,825
Total other
(income) expense,
net $ (6,890 ) $ (3.17 ) $ 10,943 $ 4.77 $ (17,833 )
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Costs and expenses decreased $235.2 million in the second quarter of fiscal 2016
as compared to the same period in the prior fiscal year, principally due to the
decrease in impairment of oil and gas properties, depreciation, depletion and
amortization ("DD&A") and lease operating expense and other factors discussed
further below.
At the end of each quarter, we compare the present value of estimated future net
cash flows from proved reserves (computed using the unweighted arithmetic
average of the first-day-of-the-month historical price for each month within the
previous 12-month period discounted at 10%, plus the lower of cost or fair
market value of unproved properties and excluding cash flows related to
estimated abandonment costs) to our full cost pool of oil and natural gas
properties, net of related deferred taxes. We refer to this comparison as a
"ceiling test." If the net capitalized costs of these oil and gas properties
exceed the estimated discounted future net cash flows, we are required to
write-down the value of our oil and natural gas properties to the value of the
discounted cash flows. As a result of our ceiling tests, we recognized ceiling
test impairments of our oil and natural gas properties of $504.8 million for the
quarter ended December 31, 2015 and $690.3 million for the quarter ended
December 31, 2014.
Lease operating expense decreased $24.4 million in the second quarter of fiscal
2016 as compared to the same period in the prior fiscal year. This decrease was
primarily due to lower direct lease operating expenses stemming from declining
service costs resulting from the decline in commodity prices and decrease in
demand for oil field services. Lease operating expense per BOE declined from
$24.12 for the quarter ended December 31, 2014 to $14.25 for the quarter ended
December 31, 2015.
DD&A expense decreased $26.2 million in the second quarter of fiscal 2016 as
compared to the same period in the prior fiscal year, primarily due to a
decrease in the DD&A per BOE rate of $9.86. The decrease in the DD&A rate in the
second quarter of fiscal 2016 was primarily due to the reduction in our full
cost pool due to the impairments of our oil and natural gas properties in prior
quarterly periods of fiscal year 2015 and 2016 resulting from the ceiling test,
partially offset by the reduction in proved reserve estimates.
General and administrative expense increased $3.2 million in the second quarter
of fiscal 2016 as compared to the same period in the prior fiscal year,
primarily due to an increase in the cost of services allocated to us pursuant to
an intercompany services and cost allocation agreement with an affiliate.
Interest expense increased approximately $5.8 million in the second quarter of
fiscal 2016 as compared to the same period in the prior fiscal year, primarily
due to interest on the promissory note payable to EGC.
During the three months ended December 31, 2015, we repurchased $29.8 million of
our 8.25% Senior Notes in open market transactions at a total cost of
approximately $10.0 million, and we recorded a gain on the repurchases totalling
approximately $21.3 million, including the amount of associated unamortized
premium.
Income Taxes
The income tax expense for the second quarter of fiscal 2016 is computed based
on our estimated annual effective tax/(benefit) rate for the full fiscal year.
We recorded no income tax expense (benefit) in the second quarter of fiscal 2016
compared to income tax benefit of $250.9 million in the second quarter of fiscal
2015. For the second quarter of fiscal 2015, our effective income tax rate was
35.6%. The decrease in the tax rate is primarily due to the book loss for the
quarter, the forecast book loss for the year and our inability to currently
record any additional net deferred tax assets due to a preponderance of negative
evidence as to future realizability of these deferred tax assets. Please see
Note 9 - Income Taxes in Notes to Consolidated Financial Statements in this
Quarterly Report.
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Six Months Ended December 31, 2015 Compared to Six Months Ended December 31, 2014
Our consolidated net loss for the six months ended December 31, 2015 was $879.1
million as compared to $761.0 million for the six months ended December 31,
2014. The increase in the net loss was primarily due to lower revenues due to
lower oil and natural gas sales prices, higher impairment of oil and natural gas
properties, and no income tax benefit in the fiscal 2016 period.
Revenues
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Six Months Ended
December 31, Percent
2015 2014 Decrease Decrease
(In thousands)
Oil $ 127,780 $ 279,144 $ (151,364 ) (54.2 )%
Natural gas 20,874 26,502 (5,628 ) (21.2 )%
Gain on
derivative
financial
instruments 3,684 44,119 (40,435 ) (91.6 )%
Total Revenues $ 152,338 $ 349,765 $ (197,427 ) (56.4 )%
Our consolidated revenues decreased $197.4 million in the first six months of
fiscal 2016 as compared to the same period in the prior fiscal year. Lower
revenues were primarily due to lower commodity sales prices and lower gain on
derivative financial instruments. Revenue variances related to commodity prices,
sales volumes and hedging activities are presented in the following table and
described below.
Price and Volume Variances
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Six Months Ended Percent Revenue
December 31, Increase Increase Increase
2015 2014 (Decrease) (Decrease) (Decrease)
(In thousands)
Price Variance
Oil sales prices
(per Bbl) $ 41.69 $ 83.05 $ (41.36 ) (49.8 )% $ (139,024 )
Natural gas sales
prices (per Mcf) 2.26 3.72 (1.46 ) (39.1 )% (10,372 )
Gain on
derivative
financial
instruments (per
BOE) 0.80 9.70 (8.90 ) (91.7 )% (40,435 )
Total price
variance (189,831 )
Volume Variance
Oil sales volumes
(MBbls) 3,065 3,361 (296 ) (8.8 )% (12,340 )
Natural gas sales
volumes (MMcf) 9,223 7,127 2,096 29.4 % 4,744
BOE sales volumes
(MBOE) 4,602 4,549 53 1.2 %
Percent of BOE
from oil 67 % 74 %
Total volume
variance (7,596 )
Total price and
volume variance $ (197,427 )
Price Variances
Lower commodity prices decreased revenues by $189.8 million in the first six
months of fiscal 2016 as compared to the same period in the prior fiscal year.
Average oil prices decreased $41.36 per barrel in the first six months of fiscal
2016, resulting in lower revenues of $139.0 million. Average natural gas prices
decreased $1.46 per Mcf in the first six months of fiscal 2016 compared to the
first six months of fiscal 2015, resulting in lower revenues of $10.4 million.
For the first six months of fiscal 2016, our hedging activities resulted in a
gain on derivative activities of $0.80 per BOE compared to a gain of $9.70 per
BOE for the same period in the prior fiscal year, resulting in lower revenues of
$40.4 million. The gain on derivatives for the six months ended December 31,
2014 reflects a gain on settlements and monetization of our derivative contracts
of approximately $8.77 per barrel of oil.
Volume Variances
Oil sales volumes decreased 1.6 MBbls per day in the first six months of fiscal
2016 as compared to the same period in the prior fiscal year, resulting in lower
revenues of $12.3 million. Natural gas sales volumes
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were higher in the first six months of fiscal 2016, increasing 11.4 MMcf per day
for the first six months of fiscal 2016 as compared to the same period in the
prior fiscal year, resulting in higher revenues of $4.7 million.
Costs and Expenses and Other (Income) Expense
[[Image Removed]] [[Image Removed]] [[Image Removed]] [[Image Removed]] [[Image Removed]] [[Image Removed]]
Six Months Ended
December 31, Increase
2015 2014 (Decrease)
Total Per Total Per Total
$ BOE $ BOE $
(In thousands, except per unit amounts)
Cost and expenses
Lease operating
expense $ 57,042 $ 12.40 $ 111,604 $ 24.53 $ (54,562 )
Transportation 1,387 0.30 1,774 0.39 (387 )
Depreciation,
depletion and
amortization 119,993 26.07 162,292 35.68 (42,299 )
Accretion of
asset retirement
obligations 13,058 2.84 12,279 2.70 779
Impairment of oil
and natural gas
properties 812,850 176.63 690,312 151.75 122,538
Goodwill
impairment - - 329,293 72.39 (329,293 )
General and
administrative 17,922 3.89 14,852 3.26 3,070
Taxes, other than
on earnings (896 ) (0.19 ) 4,472 0.98 (5,368 )
Other - - 21 - (21 )
Total costs and
expenses $ 1,021,356 $ 221.94 $ 1,326,899 $ 291.68 $ (305,543 )
Other (income)
expense
Other income, net $ (2,405 ) $ (0.52 ) $ (4 ) $ - $ (2,401 )
Gain on early
extinguishment of
debt (21,269 ) (4.62 ) - - (21,269 )
Interest expense 33,756 7.34 21,848 4.80 11,908
Total other
expense, net $ 10,082 $ 2.20 $ 21,844 $ 4.80 $ (11,762 )
Costs and expenses decreased $305.5 million in the first six months of fiscal
2016 as compared to the same period in the prior fiscal year, principally due to
decreases in goodwill impairment, lease operating expense and DD&A, partially
offset by an increase in impairment of oil and natural gas properties. Please
see further discussion below.
As a result of our ceiling tests, we recognized ceiling test impairments of our
oil and natural gas properties totaling $812.9 million for the six months ended
December 31, 2015 and $690.3 million for the six months ended December 31, 2014.
During the six months ended December 31, 2014, we recorded a non-cash impairment
charge of $329.3 million to reduce the carrying value of goodwill to zero at
September 30, 2014. At September 30, 2014, we performed a goodwill impairment
test after assessing relevant events and circumstances, primarily the decline in
oil prices since June 30, 2014. In the first step of the goodwill impairment
test, we determined that the fair value of our reporting unit was less than the
carrying amount, including goodwill, primarily due to price deterioration in
forward pricing curves and an increase in our weighted average cost of capital,
both of which adversely impacted the fair value of our estimated reserves.
Therefore, we performed the second step of the goodwill impairment test, which
led us to conclude that there was no remaining implied fair value attributable
to goodwill at September 30, 2014.
Lease operating expense decreased $54.6 million in the first six months of
fiscal 2016 as compared to the same period in the prior fiscal year. This
decrease was primarily due to lower direct lease operating expenses stemming
from declining service costs resulting from the decline in commodity prices and
decrease in demand for oil field services. Lease operating expense per BOE
declined from $24.53 for the six months ended December 31, 2014 to $12.40 for
the six months ended December 31, 2015.
DD&A expense decreased $42.3 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to a decrease in the DD&A per BOE rate of $9.61. The decrease
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in the DD&A rate in the first six months of fiscal 2016 was primarily due to the
reduction in our full cost pool due to the impairments of our oil and natural
gas properties in prior quarterly periods of fiscal year 2015 and 2016 resulting
from the ceiling test, partially offset by the reduction in proved reserve
estimates.
General and administrative expense increased $3.1 million in the first six
months of fiscal 2016 as compared to the same period in the prior fiscal year,
primarily due to an increase in the cost of services allocated to us pursuant to
an intercompany services and cost allocation agreement with an affiliate lower
capitalized amounts.
Interest expense increased approximately $11.9 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to interest on the promissory note payable to EGC.
During the six months ended December 31, 2015, we repurchased $29.8 million of
our 8.25% Senior Notes in open market transactions at a total cost of
approximately $10.0 million, and we recorded a gain on the repurchases totalling
approximately $21.3 million, including the amount of associated unamortized
premium.
Income Taxes
The income tax expense for the first six months of fiscal 2016 is computed based
on our estimated annual effective tax/(benefit) rate for the full fiscal year.
We recorded no income tax expense (benefit) in the first six months of fiscal
2016 compared to income tax benefit of $238.0 million in the first six months of
fiscal 2015. For the first six months of fiscal 2015, our effective income tax
rate was 23.8%. The decrease in the tax rate is primarily due to the book loss
for the period, the forecast book loss for the year and our inability to
currently record any additional net deferred tax assets due to a preponderance
of negative evidence as to future realizability of these deferred tax assets.
See Note 9 - Income Taxes in Notes to Consolidated Financial Statements in this
Quarterly Report.
Liquidity and Capital Resources
Overview
Currently, we fund our operations primarily through cash flows from operating
activities and advances from EGC. Future cash flows are subject to a number of
variables and are highly dependent on the prices we receive for oil and natural
gas production. Oil prices and natural gas prices declined severely during
fiscal year 2015 and have declined even further through fiscal 2016 to date. The
price of WTI crude oil per barrel dropped below $27.00 per barrel in January
2016 for the first time in twelve years. These lower commodity prices have
negatively impacted revenues, earnings and cash flows, and sustained low oil and
natural gas prices will have a material and adverse effect on our liquidity
position.
As of December 31, 2015, we had $150 million in borrowings outstanding under the
Revolving Credit Facility, to which we are party with EGC, and we were in
compliance with our financial covenants; however, based on current market
conditions and depressed commodity prices, if Energy XXI is unable to execute on
one of the strategic alternatives discussed below and adequately address
liquidity concerns, we will not be in compliance with the consolidated net
secured leverage ratio covenant under the Revolving Credit Facility for the
quarter ending March 31, 2016. In addition, as part of our quarterly compliance
certificates required under the Revolving Credit Facility, we must make certain
representations, including representations about our solvency, and we must
remain in compliance with the financial ratios in the Revolving Credit Facility.
Generally, the solvency representation requires, among other things, for us to
determine at the time we desire to make a future borrowing, or issue or extend
letters of credit, that the fair market value of our assets exceeds the face
amount of our liabilities. The current commodity environment creates substantial
uncertainty in determining fair market value of oil and natural gas assets which
accordingly may impact our ability to continue to give the required
representation.
Energy XXI is evaluating various alternatives with respect to the Revolving
Credit Facility, but there is no certainty that it will be able to implement any
alternatives or otherwise resolve our covenant issues. If the lenders under the
Revolving Credit Facility are unwilling to provide us with the covenant
flexibility we seek, and we are unable to comply with those covenants, we may be
forced to repay or refinance amounts then outstanding under the Revolving Credit
Facility, and there is no assurance that we will reach an agreement
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with our lenders on any such amendment or waiver. Absent success in these
pursuits, a resultant breach under the Revolving Credit Facility would cause a
default under such facility, potentially resulting in acceleration of all
amounts outstanding under the Revolving Credit Facility. If the lenders under
the Revolving Credit Facility were to accelerate the indebtedness under the
Revolving Credit Facility as a result of such defaults, such acceleration would
cause a cross-default or cross-acceleration of all of our, EGC and Energy XXI's
other outstanding indebtedness. Such a cross-default or cross-acceleration could
have a wider impact on our liquidity than might otherwise arise from a default
or acceleration of a single debt instrument. If an event of default occurs, or
if other debt agreements cross-default, and the lenders under the affected debt
agreements accelerate the maturity of any loans or other debt outstanding, we
will not have sufficient liquidity to repay all of our outstanding indebtedness.
EGC may face other impediments to accessing available borrowing capacity under
the Revolving Credit Facility. Borrowings under the First Lien Credit Agreement
are limited to a borrowing base based on oil and natural gas reserve values
which are redetermined on a periodic basis. During the quarter ended December
31, 2015, we, EGC and our lenders completed our fall borrowing base
redetermination with no changes to the existing borrowing base of $150 million
for EPL, although we were required to maintain restricted cash of $30 million
with respect to amounts outstanding under the Revolving Credit EPL Sub-Facility.
As of December 31, 2015, we have fully utilized amounts available under our
Revolving Credit EPL Sub-Facility. If we experience the continuation of low oil
and natural gas prices, or if they decline even further, we anticipate that our
Revolving Credit EPL Sub-Facility borrowing base and commitment amounts will
likely be reduced in the spring of 2016 as part of our next borrowing base
redetermination, which would require us to repay any outstanding indebtedness in
excess of any reduced borrowing base.
In addition, in response to commodity price declines, our fiscal year 2016
capital budget was substantially reduced compared to actual capital expenditures
in fiscal year 2015. The curtailment of the development of our properties will
eventually lead to a decline in our production and reserves. In addition, due to
the depressed commodity prices and our lack of capital resources to develop our
properties, the Company believes that all of its proved undeveloped oil and gas
reserves no longer qualify as being proved as of the period ended December 31,
2015. We have thus removed all of our proved undeveloped oil and gas reserves
from the proved category as of December 31, 2015. Almost all of the proved
undeveloped reserves that were removed from the proved category as of December
31, 2015 are still economic at current prices, but were reclassed to the
probable category because they are no longer expected to be drilled within five
years of initial booking due to current constraints on ability to fund
development drilling. In addition, as of December 31, 2015, we identified
certain of our unevaluated properties totaling to $314.4 million as being
uneconomical and have transferred such amounts to the full cost pool, subject to
amortization. A decline in our production and reserves will further reduce our
liquidity and ability to satisfy our debt obligations by negatively impacting
our cash flow from operating activities and the value of our assets.
We may experience a further strain on our liquidity if the BOEM requires us to
provide additional bonding as a means to assure our decommissioning obligations,
or if the surety companies providing such bonds on our behalf require us to
provide additional cash collateral for such bonds. Any further expense in
providing additional bonds or restrictions on our cash to collateralize existing
bonds or new bonds would further reduce our liquidity.
Beginning on January 11, 2016, Energy XXI's common stock has generally traded on
NASDAQ at less than $1.00 per share. Due to certain NASDAQ requirements, there
is no assurance that the price of Energy XXI's common stock will comply with the
requirements for continued listing of its shares on NASDAQ. A delisting of
Energy XXI's common stock could constitute a "fundamental change" under the
terms of its $400 million aggregate principal amount of 3.0% Senior Convertible
Notes due 2018 (the "3.0% Senior Convertible Notes"). If such a fundamental
change occurs at any time prior to the maturity of the 3.0% Senior Convertible
Notes, each holder of such notes shall have the right to require Energy XXI to
repurchase all or part of such holder's 3.0% Senior Convertible Notes in
accordance with the terms of the 3.0% Senior Convertible Notes. We cannot assure
that Energy XXI would have adequate liquidity to fund such a repurchase given
its severe liquidity constraints. Such acceleration would cause a cross-default
or cross-acceleration of all of Energy XXI's other outstanding indebtedness,
including our indebtedness. Such a cross-default or cross-acceleration could
have a wider impact on our liquidity than might otherwise arise from
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a default or acceleration of a single debt instrument. If an event of default
occurs, or if other debt agreements cross-default, and the lenders under the
affected debt agreements accelerate the maturity of any loans or other debt
outstanding, we will not have sufficient liquidity to repay all of our
outstanding indebtedness.
As described below under "- Our Indebtedness and Available Credit," we had total
indebtedness of $976.5 million as of December 31, 2015, and taking into account
the bond repurchases completed subsequent to December 31, 2015 of approximately
$266.6 million in aggregate principal amount (carrying value of approximately
$279.4 million) of our 8.25% Senior Notes at a total price of approximately
$11.4 million, including accrued interest of $10.4 million, we had total
indebtedness of $697.1 million as of February 15, 2016. All of our outstanding
indebtedness will mature within the next three years. In addition, the Revolving
Credit Facility is scheduled to mature on April 9, 2018; however, the maturity
of the Revolving Credit Facility will accelerate if EGC's 9.25% Senior Notes are
not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not
retired or refinanced by July 15, 2017. All of the factors described above have
placed considerable pressure on our ability to pay the principal and interest on
our long-term debt and to satisfy our other liabilities, continue our
development activities to maintain and grow reserves and our ability to
refinance our debt as it becomes due. As a result of the commodity price decline
and the Company's substantial debt burden, absent a material improvement in oil
and gas prices or a refinancing or restructuring of our debt obligations or
other improvement in liquidity, the Company believes forecasted cash and
expected available credit capacity will not be sufficient to meet commitments as
they come due for the next twelve months. This raises substantial doubt
regarding the Company's ability to continue as a going concern.
In February 2016, Energy XXI engaged PJT Partners as a financial advisor and
Vinson & Elkins L.L.P. as a legal advisor to advise its management and Board,
EGC and EPL regarding potential strategic alternatives such as a refinancing or
restructuring of our indebtedness or capital structure or seeking to raise
additional capital through debt or equity financing to address our liquidity
issues and high debt levels. We cannot assure you that any refinancing or debt
or equity restructuring would be possible or that additional equity or debt
financing could be obtained on acceptable terms, if at all. Energy XXI is also
focused on long-term recurring cost reductions and the identification of
non-core assets for potential sale. We cannot assure that any of these efforts
will be successful or will result in cost reductions or additional cash flows or
the timing of any such cost reductions or additional cash flows.
As a result of the commodity price decline, we will continue to evaluate our
ability to make the debt payments in light of our liquidity constraints, but if
we are unable to generate sufficient cash flow to service our debt or meet our
debt obligations as they become due, we will have to take certain actions
described in greater detail elsewhere in this Quarterly Report and in our 2015
Annual Report in "Risk Factors - We may not be able to generate sufficient cash
flows to service all of our indebtedness and may be forced to take other actions
in order to satisfy our obligations under our indebtedness, which may not be
successful."
On February 16, 2016, we elected to enter into the 30-day grace period under the
terms of the indenture governing our outstanding 8.25% Senior Notes to extend
the timeline for making the cash interest payment to March 17, 2016. The
aggregate amount of the interest payments is approximately $8.8 million. During
the 30-day grace period, the Company, EGC and Energy XXI are working with their
debt holders regarding their ongoing effort to develop and implement a
comprehensive plan to restructure their balance sheets.
The election to enter into the 30-day grace period under the terms of the
indenture governing the 8.25% Senior Notes constitutes a default; however, it
does not constitute an Event of Default under the indenture governing the 8.25%
Senior Notes or the Revolving Credit Facility. As a result of this default,
certain restrictions have been placed on the Company, including but not limited
to, its ability to incur additional indebtedness, draw on the Revolving Credit
EPL Sub-Facility and issue additional letters of credit. The Company has 30 days
to cure the default by making the required interest payment that was due on
February 16, 2016. Alternatively, the Company may restructure the debt with its
creditors. On March 17, 2016, if the interest payment default is not cured, the
default would be considered an Event of Default and the trustee or the holders
of at least 25% in aggregate principal amount of then outstanding 8.25% Senior
Notes may declare the principal and accrued interest for all outstanding 8.25%
Senior Notes due and payable
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immediately. An Event of Default would also trigger cross defaults in the Company's other debt obligations. An Event of Default would have a material adverse effect on the Company's liquidity, financial condition and results of operations.
Absent a material improvement in oil and gas prices or a refinancing or some
restructuring of our debt obligations or other improvement in liquidity, we may
seek bankruptcy protection to continue our efforts to restructure our business
and capital structure and may have to liquidate our assets and may receive less
than the value at which those assets are carried on our consolidated financial
statements.
Our Indebtedness and Available Credit
Revolving Credit EPL Sub-Facility. The First Lien Credit Agreement, as amended,
has a maximum facility amount and borrowing base of $500 million, of which such
amount $150 million is the borrowing base under the Revolving Credit EPL
Sub-Facility, although we were required to maintain restricted cash of $30
million with respect to amounts outstanding under the Revolving Credit EPL
Sub-Facility. As of December 31, 2015, we had fully utilized amounts available
under our Revolving Credit EPL Sub-Facility. The maturity date of the First Lien
Credit Agreement is April 9, 2018, provided that certain conditions are met;
however, the maturity of the Revolving Credit Facility will accelerate if the
9.25% Senior Notes are not retired or refinanced by May 15, 2017 or the 8.25%
Senior Notes are not retired or refinanced by July 15, 2017. The Revolving
Credit Facility is comprised of a syndicate of large domestic and international
banks, with no single lender providing more than 5% of the overall commitment
amount.
On November 30, 2015, EGC and EPL entered into the Twelfth Amendment to the First Lien Credit Agreement, under which the following changes became effective:
• Modification of triggers that require EPL and its subsidiaries to provide
guarantees of the indebtedness of EGC and its subsidiaries and grant liens
on the assets of EPL and its subsidiaries to secure such guarantees. Under
such modifications, such guarantees and security will be required upon the
earlier of EPL's retirement of its obligations in respect of the 8.25%
Senior Notes and amendments to covenant restrictions under such notes that
eliminate restrictions on the ability of EPL and its subsidiaries to
guarantee the indebtedness of EGC and its subsidiaries and grant liens on
the assets of EPL and its subsidiaries to secure such guarantees (even if
such notes have not been refinanced or defeased).
• Suspending the maximum net secured leverage ratio covenant with respect to
EGC and its subsidiaries (other than EPL and its subsidiaries) to begin on
the fiscal quarter ending March 31, 2017 rather than March 31, 2015.
• Suspending the maximum net secured leverage ratio covenant with respect to
EPL and its subsidiaries to begin on the fiscal quarter ending March 31,
2017 rather than March 31, 2015.
• Modifying the maximum net secured leverage covenant with respect to EGC and
its subsidiaries to be 3.75:1.00 as of the end of each fiscal quarter
beginning with the fiscal quarter ended September 30, 2015, increasing to
4.75:1.00 starting March 31, 2016 and to 5.25:1.00 starting June 30, 2016,
and decreasing to 5.00:1.00 beginning June 30, 2017 and thereafter.
As amended, the First Lien Credit Agreement requires EGC and EPL to maintain
certain financial covenants separately for so long as the 8.25% Senior Notes
remain outstanding. EGC is subject to the following financial covenants on a
consolidated basis: (a) a minimum current ratio of no less than 1.0 to 1.0 and
(b) a consolidated maximum net secured leverage ratio of no more than 3.75 to
1.0 as of the end of the fiscal quarter ended December 31, 2015, and increasing
to 4.75 to 1.0 starting March 31, 2016, and to 5.25 to 1.00 starting June 30,
2016 and decreasing to 5.00 to 1.0 beginning June 30, 2017 and thereafter. In
addition, EGC is subject to the following financial covenants on a stand-alone
basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0
and (b) a consolidated maximum net secured leverage ratio of no more than 3.75
to 1.0 beginning with the fiscal quarter ending March 31, 2017. In addition, EPL
is subject to the following financial covenants on a stand-alone basis: (a) a
consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a
consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0
beginning with the fiscal quarter ending March 31, 2017. If the 8.25% Senior
Notes are no longer outstanding and certain other conditions are met, EGC and
EPL will be subject to the following financial covenants on a
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consolidated basis: (a) a consolidated maximum net first lien leverage ratio of
1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more
than 4.75 to 1.0 as of the end of each fiscal quarter beginning with the fiscal
quarter ending March 31, 2016, increasing to 5.25 to 1.0 starting June 30, 2016
and decreasing to 5.00 to 1.0 beginning June 30, 2017 and thereafter, and (c) a
minimum current ratio of no less than 1.0 to 1.0.
Since required lender consent to the specific terms of the transaction with respect to the sale of the East Bay field had not been obtained, EGC and EPL were in technical default under the First Lien Credit Agreement at June 30, 2015. On July 14, 2015, we obtained a waiver to this event of default.
8.25% Senior Notes. The 8.25% Senior Notes consist of $510.0 million in
aggregate principal amount issued under the 2011 Indenture. Subsequent to
December 31, 2015, we repurchased approximately $266.6 million in aggregate
principal amount (carrying value of approximately $279.4 million) of our 8.25%
Senior Notes in open market transactions at a total price of approximately $11.4
million, including accrued interest of $10.4 million. The 8.25% Senior Notes
bear interest from the date of their issuance at an annual rate of 8.25% with
interest due semi-annually, in arrears, on February 15th and August 15th of each
year. The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly
and severally, on an unsecured senior basis initially by each of our existing
direct and indirect domestic subsidiaries (other than immaterial subsidiaries).
The 8.25% Senior Notes will mature on February 15, 2018. As of December 31,
2015, we were in compliance with all of the covenants under the 2011 Indenture;
however, based on current market conditions and depressed commodity prices, if
Energy XXI is unable to execute on one of the strategic alternatives discussed
above and adequately address liquidity concerns, we will not be in compliance
with the consolidated net secured leverage ratio covenant under the Revolving
Credit Facility for the quarter ending March 31, 2016.
Promissory Note. On March 12, 2015, in connection with EGC's issuance of the
11.0% Notes, we entered into the $325.0 million secured second lien Promissory
Note between us, as the maker, and EGC, as the payee. The Promissory Note bears
interest at an annual rate of 10%, has a maturity date of October 9, 2018, and
is secured by a second priority lien on certain of our assets that secure the
obligations under the First Lien Credit Agreement.
For more information regarding our outstanding indebtedness, see Note 6 - Indebtedness in the Notes to Consolidated Financial Statements contained in this Quarterly Report.
BOEM Bonding Requirements
The cost of compliance with our existing supplemental bonding requirements or
any other changes to the BOEM's current NTL supplemental bonding requirements or
supplemental bonding regulations applicable to us or our subsidiaries'
properties could materially and adversely affect our financial condition, cash
flows, and results of operations. In addition, we may be required to provide
cash collateral or letters of credit to support the issuance of such bonds or
other surety. Such letters of credit would likely be issued under our Revolving
Credit Facility and would reduce the amount of borrowings available under such
facility in the amount of any such letter of credit obligations. We can provide
no assurance that we can continue to obtain bonds or other surety in all cases
or that we will have sufficient availability under our Revolving Credit Facility
to support such supplemental bonding requirements. If we are unable to obtain
the additional required bonds or assurances as requested, the BOEM may require
any of our operations on federal leases to be suspended or cancelled or
otherwise impose monetary penalties, and any one or more of such actions could
have a material adverse effect on our business, prospects, results of
operations, financial condition, and liquidity. For more information about
BOEM's supplement bonding requirements, see "- Known Trends and
Uncertainties - BOEM Supplemental Financial Assurance and/or Bonding
Requirements."
Capital Expenditures
For the six months ended December 31, 2015, our capital expenditures totaled
approximately $67 million including expenditures for plugging, abandonment and
other decommissioning activities. Our current capital expenditures are allocated
to development activities, which are geared toward the improvement of existing
production and the performance of necessary plugging, abandonment and other
decommissioning activities. We intend to fund our capital expenditures and
contractual commitments with cash flows from operating
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activities and borrowings and equity investments from EGC. If oil and natural
gas prices remain at current levels or continue to decline and our cash flows
from operating activities and availability of funding from EGC are not
sufficient to fund our capital program, we will further reduce our capital
spending or otherwise fund our capital needs with proceeds from the sale of
non-core assets. There is no guarantee that we can access debt and equity
capital markets or sell non-core assets at attractive terms. Our capital
expenditures and the scope of our drilling activities for fiscal year 2016 may
change as a result of several factors, including, but not limited to, changes in
oil and natural gas sales prices, costs of drilling and completion operations
and drilling results and available funding from EGC.
Disposition
On June 30, 2015, we sold our interest in the East Bay field for cash
consideration of $21 million plus the assumption of asset retirement obligations
totaling approximately $55.1 million. The cash consideration was payable in two
installments with $5 million received at closing and the remainder received
during the quarter ended December 31, 2015. We retained a 5% overriding royalty
interest (applicable only during calendar months if and when the WTI for such
month averages over $65) on these assets for a period not to exceed 5 years from
the closing date or $7 million whichever occurs first, and we also retained 50%
of the deep rights associated with the East Bay field.
We may decide to divest of certain non-core assets from time to time. There can
be no assurance any such potential transactions will prove successful. We cannot
provide any assurance that we will be able to sell these assets on satisfactory
terms, if at all.
Cash Flows
The following table sets forth selected historical information from our
statements of cash flows:
[[Image Removed]] [[Image Removed]] [[Image Removed]]
Six Months Ended
December 31,
2015 2014
(In thousands)
Net cash provided by operating activities $ 27,463 $
98,901
Net cash used in investing activities (16,122 ) (239,498 )
Net cash provided by (used in) financing
activities (11,558 )
135,480
The decrease in our net cash provided by operating activities for the first six
months of fiscal 2016 as compared to the same period in the prior fiscal year
primarily reflects decreases in revenues due to lower oil and natural gas
prices.
Net cash used in investing activities decreased for the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to the reduction in cash used for capital expenditures.
Net cash used in financing activities for the first six months of fiscal 2016
primarily reflects $30.0 million in restricted cash related to the Revolving
Credit Facility and $3.4 million in payments on derivative instruments premium
financing, partially offset by $22.0 million in advances from EGC. Net cash
provided by financing activities for the first six months of fiscal year 2015
reflects $135.5 million in advances from EGC.
We have not paid any cash dividends in the past on our common stock. The
covenants in certain debt instruments to which we are a party, including the
2011 Indenture governing the 8.25% Senior Notes, place certain restrictions and
conditions on our ability to pay dividends. Any future cash dividends would
depend on contractual limitations, future earnings, capital requirements, our
financial condition and other factors determined by our board of directors.
Contractual Obligations
Our contractual obligations at December 31, 2015 did not change materially from
those disclosed in Item 7 of our 2015 Annual Report, other than as disclosed in
Note 6 - Indebtedness and Note 5 - Asset Retirement Obligations of Notes to
Consolidated Financial Statements in this Quarterly Report.
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TABLE OF CONTENTS
Critical Accounting Policies
Our significant accounting policies are summarized in Note 1 - Organization and
Summary of Significant Accounting Policies of Notes to Consolidated Financial
Statements included in our 2015 Annual Report.
Recent Accounting Pronouncements
For information regarding new accounting pronouncements, see the information in
Note 1 - Organization and Summary of Significant Accounting Policies - Recent
Accounting Pronouncements of Notes to Consolidated Financial Statements in this
Quarterly Report.
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