CONTANGO OIL & GAS CO - 10-K - Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion and analysis of our financial condition and results of
operations should be read in conjunction with the financial statements and the
related notes and other information included elsewhere in this report. On
October 1, 2013 the Company's board of directors approved a change in fiscal
year end from June 30 to December 31. Unless otherwise noted, all references to
"years" in this report refer to the twelve-month period which ends on December
31 of each year. This Form 10-K covers the three year period ended December 31,
2015.
Overview
We are a
Houston, Texas
based independent oil and natural gas company. Our
business is to maximize production and cash flow from our offshore properties in
the shallow waters of the Gulf of Mexico ("GOM") and onshore properties in
various plays, and use that cash flow to explore, develop, exploit and acquire
crude oil and natural gas properties in the onshore Texas Gulf Coast and Rocky
Mountain regions of
the United States
.
On October 1, 2013, we completed a merger with Crimson Exploration Inc.
("Crimson") in an all-stock transaction pursuant to which Crimson became a
wholly-owned subsidiary of Contango (the "Merger"). The Merger gave us access to
high rate of return onshore prospects in known, prolific producing areas as well
as long-life resource plays. In 2015, our drilling activity focused primarily on
the Woodbine oil and liquids-rich play in
Madison
and
Grimes
counties,
Texas
(our
Southeast Texas Region
), in the Cretaceous Sands in
Fayette
and
Gonzales
counties,
Texas
(in our
South Texas Region
) and the late 2014/early 2015
commencement of drilling on our new acreage position in
Wyoming
where we are
targeting the Mowry Shale and the Muddy Sandstone formations. We believe these
areas could provide long-term growth potential from multiple formations that we
believe to be productive for oil and natural gas.
Additionally, we have (i) a 37% equity investment in Exaro Energy III LLC
("Exaro"), which is primarily focused on the development of proved natural gas
reserves in the Jonah Field in
Wyoming
; (ii) operated properties producing from
various conventional formations in various counties along the Texas Gulf Coast;
(iii) operated producing properties in the Denver Julesburg Basin ("DJ Basin")
in
Weld
and
Adams
counties in
Colorado
, which we believe may also be prospective
in the Niobrara Shale oil play; and (iv) operated producing properties in the
Haynesville Shale, Mid Bossier and James Lime formations in
East Texas
.
Natural gas and crude oil prices declined severely during 2015 and have declined
even further through 2016 to date. Due to the current challenging commodity
price environment, we focused our 2015 capital program on: (i) the preservation
of our strong and flexible financial position, including limiting our overall
capital expenditure budget; (ii) dedicating capital primarily to de-risking
and/or delineating strategic projects (i.e. versus field development); (iii) the
identification of opportunities for cost and production efficiencies in all
areas of our operations; and (iv) continuing to identify and, when appropriate,
pursue the expansion of our resource potential through opportunistic
acquisitions.
Our production for the year ended December 31, 2015 was approximately 34.0 Bcfe
(or 93.0 Mmcfe/d) and was 63% offshore and 37% onshore. Our production for the
three months ended December 31, 2015 was approximately 8.0 Bcfe (or 86.7
Mmcfe/d) and was 65% offshore and 35% onshore. As of December 31, 2015, our
proved reserves were approximately 61% offshore and 39% onshore and were 84%
proved developed, which were approximately 72% offshore and 28% onshore.
Revenues and Profitability
Our revenues, profitability and future growth depend substantially on our ability to find, develop and acquire natural gas and oil reserves that are economically recoverable, as well as prevailing prices for natural gas and oil.
Reserve Replacement
Generally, producing properties offshore in the Gulf of Mexico have high initial
production rates, followed by steep declines. Likewise, initial production rates
on new wells in the onshore resource plays start out at a relatively high rate
with a decline curve which results in 60% to 70% of the ultimate recovery of
present value occurring in the first eighteen months of the well's life. We
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must locate and develop, or acquire, new natural gas and oil reserves to replace
those being depleted by production. Substantial capital expenditures are
required to find, develop and/or acquire natural gas and oil reserves. 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. The Merger with Crimson allowed the
Company to add significant proved developed and undeveloped reserves (see "Item
2. Properties", for details of reserves acquired) and provided the Company with
access to several onshore resource plays which have substantial reserve growth
potential, including in oil and liquids rich plays that position us to move to a
more balanced oil/gas profile.
Use of Estimates
The preparation of our financial statements requires the use of estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from those estimates. Significant
estimates with regard to these financial statements include estimates of
remaining proved natural gas and oil reserves, the timing and costs of our
future drilling, development and abandonment activities, and income taxes.
Related Party Transactions
Effective as of the close of business on December 31, 2015, the Company and the
other members of Republic Exploration LLC ("REX") agreed to dissolve and
liquidate REX. REX's assets are being distributed proportionately to its
members. See Note 17 to our Financial Statements - "Related Party Transactions"
for a detailed description of our transactions with REX.
See "Item 1A. Risk Factors" for a more detailed discussion of a number of other factors that affect our business, financial condition and results of operations.
Results of Operations
The table below sets forth our average net daily production data in Mmcfe/d from our fields for each of the periods indicated:
Three Months Ended
March June March June
31, 30, September December 31, 30, September December
2014 2014 30, 2014 31, 2014 2015 2015 30, 2015 31, 2015
Offshore GOM
Dutch and Mary Rose 66.7 60.9 42.3 (5) 55.9 53.3 50.8 49.5 48.6
Vermilion 170 9.0 7.2 8.0 5.7 7.7 6.3 7.0 6.9
Other offshore (1) 0.4 0.6 5.2 6.5 3.2 1.6 0.5 0.5
Southeast Texas (2) 26.4 27.1 26.6 23.6 19.3 28.2 22.9 20.1
South Texas (3) 12.6 16.0 17.4 12.2 10.8 9.3 8.9 8.1
Other (4) 2.4 4.2 2.8 2.3 2.0 2.2 2.1 2.5
117.5 116.0 102.3 106.2 96.3 98.4 90.9 86.7
(1) Includes Ship Shoal 263 and South Timbalier 17.
(2) Includes
Madison
and
Grimes
counties, among others.
(3) Includes
Zavala
and
Dimmit
counties, among others.
(4) Includes onshore wells in
East Texas
,
Colorado
,
Wyoming
and Tuscaloosa Marine
Shale regions, among others.
(5) Lower mainly due to shut-in for approximately three weeks to install
compression.
Vermilion 170 Well
During December 2014, our Vermilion 170 well production was shut-in for fourteen days due to issues with the Sea Robin Pipeline, our third-party transporter.
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Other Offshore
Other offshore includes our Ship Shoal 263 well for all periods presented, except for periods after it was shut-in in September 2015 and for South Timbalier 17 for all quarters ended after June 30, 2014, as it commenced production in July 2014.
Southeast Texas
During 2014, Contango drilled 18 gross (11.6 net) wells on acreage targeting the
Woodbine formation. During 2015, we brought seven gross wells (3.9 net) on
production which we initiated in late 2014 utilizing a pad drilling strategy on
500 foot spacing, plus an additional one gross well (0.9 net) in our
Iola
/
Grimes
area. We also drilled one gross (0.7 net) well in our Chalktown area to satisfy
a farm-in commitment and one gross (0.7 net) horizontal well testing a more
aggressive completion design in the Lower Lewisville formation in our
Grimes County
area, as we limited our 2015 capital expenditures to strategic projects
and to stay within internally generated cash flows.
South Texas
During 2014, Contango drilled 14 gross operated wells (6.8 net) in the
Buda
formation, which are all on production. We drilled one additional well during
the fourth quarter of 2014 as a vertical pilot well to test the viability of the
Eagle Ford and other formations in
Zavala
and
Dimmit
counties. Though core
analysis indicates the viability of the Eagle Ford formation in the area, no
drilling activity was conducted in this area in 2015, or is planned for 2016,
because of the low commodity price environment.
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Year Ended December 31, 2015 Compared to Year Ended December 31, 2014; and Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
The table below sets forth revenue, production data, average sales prices and
average production costs associated with our sales of natural gas, oil and
natural gas liquids ("NGLs") from continuing operations for the years ended
December 31, 2015, 2014 and 2013. Oil, condensate and NGLs are compared with
natural gas in terms of cubic feet of natural gas equivalents. One barrel of
oil, condensate or NGL is the energy equivalent of six Mcf of natural gas.
Reported lease operating expenses include production taxes, such as ad valorem
and severance. Information for the year ended December 31, 2013 includes twelve
months of Contango activity (January - December) and three months of post-merger
Crimson activity (October - December).
Year Ended December 31,
Year Ended December 31,
2015 2014 % 2014 2013 %
Revenues (thousands):
Oil and condensate sales $ 43,230 $ 130,238 (67) % $ 130,238 $ 59,608 118 %
Natural gas sales 59,058 112,695 (48) % 112,695 79,289 42 %
NGL sales 14,217 33,525 (58) % 33,525 25,224 33 %
Total revenues $ 116,505 $ 276,458 (58) % $ 276,458 $ 164,121 68 %
Production:
Oil and condensate (thousand
barrels)
Dutch and Mary Rose 164 220 (26) % 220 262 (16) %
Vermilion 170 22 37 (41) % 37 38 (3) %
Southeast Texas 493 734 (33) % 734 160 359 %
South Texas 178 337 (47) % 337 95 255 %
Other 67 73 (8) % 73 34 115 %
Total oil and condensate 924 1,401 (34) % 1,401 589 138 %
Natural gas (million cubic
feet)
Dutch and Mary Rose 14,736 16,257 (9) % 16,257 17,018 (4) %
Vermilion 170 2,050 2,108 (3) % 2,108 1,823 16 %
Southeast Texas 3,136 3,234 (3) % 3,234 875 270 %
South Texas 1,788 2,541 (30) % 2,541 623 308 %
Other 904 1,735 (48) % 1,735 285 509 %
Total natural gas 22,614 25,875 (13) % 25,875 20,624 25 %
Natural gas liquids (thousand
barrels)
Dutch and Mary Rose 454 501 (9) % 501 514 (3) %
Vermilion 170 60 68 (12) % 68 68 - %
Southeast Texas 359 304 18 % 304 66 361 %
South Texas 87 124 (30) % 124 26 377 %
Other 8 11 (27) % 11 3 267 %
Total natural gas liquids 968 1,008 (4) % 1,008 677 49 %
Total (million cubic feet
equivalent)
Dutch and Mary Rose 18,443 20,578 (10) % 20,578 21,674 (5) %
Vermilion 170 2,545 2,738 (7) % 2,738 2,459 11 %
Southeast Texas 8,249 9,461 (13) % 9,461 2,231 324 %
South Texas 3,379 5,309 (36) % 5,309 1,349 294 %
Other 1,345 2,237 (40) % 2,237 507 341 %
Total production 33,961 40,323 (16) % 40,323 28,220 43 %
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Year Ended December 31, Year Ended December 31,
2015 2014 % 2014 2013 %
Daily Production:
Oil and condensate (thousand
barrels per day)
Dutch and Mary Rose 0.4 0.6 (26) % 0.6 0.7 (14) %
Vermilion 170 0.1 0.1 (41) % 0.1 0.1 - %
Southeast Texas 1.4 2.0 (33) % 2.0 1.7 18 %
South Texas 0.5 0.9 (47) % 0.9 1.0 (10) %
Other 0.1 0.2 (8) % 0.2 0.1 100 %
Total oil and condensate 2.5 3.8 (34) % 3.8 3.6 6 %
Natural gas (million cubic
feet per day)
Dutch and Mary Rose 40.4 44.5 (9) % 44.5 46.6 (5) %
Vermilion 170 5.6 5.8 (3) % 5.8 5.0 16 %
Southeast Texas 8.6 8.9 (3) % 8.9 9.5 (6) %
South Texas 4.9 7.0 (30) % 7.0 6.8 3 %
Other 2.4 4.7 (48) % 4.7 1.8 161 %
Total natural gas 61.9 70.9 (13) % 70.9 69.7 2 %
Natural gas liquids (thousand
barrels per day)
Dutch and Mary Rose 1.2 1.4 (9) % 1.4 1.4 - %
Vermilion 170 0.2 0.2 (12) % 0.2 0.2 - %
Southeast Texas 1.0 0.8 18 % 0.8 0.7 14 %
South Texas 0.2 0.3 (30) % 0.3 0.3 - %
Other - 0.1 (27) % 0.1 - 100 %
Total natural gas liquids 2.6 2.8 (4) % 2.8 2.6 8 %
Total (million cubic feet
equivalent per day)
Dutch and Mary Rose 50.5 56.4 (10) % 56.4 59.4 (5) %
Vermilion 170 7.0 7.5 (7) % 7.5 6.7 12 %
Southeast Texas 22.6 25.9 (13) % 25.9 24.3 7 %
South Texas 9.3 14.5 (36) % 14.5 14.7 (1) %
Other 3.6 6.2 (40) % 6.2 2.7 130 %
Total production 93.0 110.5 (16) % 110.5 107.8 2 %
Average Sales Price:
Oil and condensate (per
barrel) $ 46.80 $ 92.98 (50) % $ 92.98 $ 101.21 (8) %
Natural gas (per thousand
cubic feet) $ 2.61 $ 4.36 (40) % $ 4.36 $ 3.84 13 %
Natural gas liquids (per
barrel) $ 14.68 $ 33.27 (56) % $ 33.27 $ 37.26 (11) %
Total (per thousand cubic
feet equivalent) $ 3.43 $ 6.86 (50) % $
6.86 $ 5.82 18 %
Expenses (thousands):
Operating expenses $ 37,840 $ 47,236 (20) % $ 47,236 $ 36,784 28 %
Exploration expenses $ 11,979 $ 33,387 (64) % $ 33,387 $ 1,811 **
Depreciation, depletion and
amortization $ 133,380 $ 156,117 (15) % $ 156,117 $ 65,529 138 %
Impairment and abandonment of
oil and gas
properties $ 285,877 $ 47,693 499 % $ 47,693 $ 776 **
General and administrative
expenses $ 26,402 $ 34,045 (22) % $ 34,045 $ 26,512 28 %
Gain (Loss) from investment
in affiliates
(net of taxes) $ (30,582) $ 6,923 (542) % $ 6,923 $ 2,310 200 %
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Year Ended December 31, Year Ended December 31,
2015 2014 % 2014
2013 % Other Income (Expense) $ (719) $ (2,687) (73) % $ (2,687) $ 29,482 (91) %
Selected data per Mcfe:
Operating expenses $ 1.11 $ 1.17 (5) % $ 1.17 $ 1.30 (10) %
General and administrative
expenses $ 0.78 $ 0.84 (7) % $ 0.84 $ 0.94 (10) %
Depreciation, depletion and
amortization $ 3.93 $ 3.87 2 % $ 3.87 $ 2.32 67 %
** Greater than 1,000%
Natural Gas, Oil and NGL Sales and Production
All of our revenues are from the sale of our natural gas, crude oil and natural
gas liquids production. Our revenues may vary significantly from year to year
depending on changes in commodity prices, which fluctuate widely, and production
volumes. Our production volumes are subject to wide swings as a result of new
discoveries, weather and mechanical related problems. In addition, the
production rate associated with our oil and gas properties declines over time as
we produce our reserves.
We reported revenues of approximately $116.5 million for the year ended December
31, 2015, compared to revenues of approximately $276.5 million for the year
ended December 31, 2014. This decrease in revenues was primarily attributable to
lower oil and natural gas prices in 2015 and lower production resulting from the
significant reduction in our capital program because of the dramatic decline in,
and uncertain outlook for, commodity prices.
Total production for the year ended December 31, 2015 was approximately 34.0
Bcfe, or 93.0 Mmcfe/d, compared to approximately 40.3 Bcfe, or 110.5 Mmcfe/d, in
the prior year, a decline attributable in large part to our limited drilling
activity in 2015 due to the low commodity price environment. Net natural gas
production for the year ended December 31, 2015 was approximately 61.9 Mmcf/d,
compared with approximately 70.9 Mmcf/d for the year ended December 31, 2014,
due to normal decline in production from our offshore properties. Net oil
production declined from 3,800 barrels per day to 2,500 barrels per day, while
NGL production decreased from approximately 2,800 barrels per day to 2,600
barrels per day, both decreases as a result of normal decline that was not
offset by new production from a limited 2015 capital program.
We reported revenues of approximately $276.5 million for the year ended December
31, 2014, compared to revenues of approximately $164.1 million for the year
ended December 31, 2013. This increase in revenues was primarily attributable to
our merger with Crimson, to additional interests purchased in our Dutch wells in
December 2013, to production from our South Timbalier 17 discovery which began
producing in July 2014, and to new natural gas, oil, condensate and NGL
production from our 2014 drilling program, partially offset by lower oil,
condensate and NGL prices. Revenue for 2013 was also negatively impacted by our
Vermilion 170 well shut-in for the first half of 2013 for workover.
Total production for the year ended December 31, 2014 was approximately 40.3
Bcfe, or 110.5 Mmcfe/d, compared to approximately 28.2 Bcfe, or 107.8 Mmcfe/d,
for the year ended December 31, 2013, an increase primarily attributable to our
merger with Crimson, new production from our 2014 drilling program, the
resumption of production at Vermilion 170 and the additional interests purchased
in our Dutch wells discussed above. This increase was partially offset by the
shut-in for approximately three weeks, and subsequent ramp up during the third
quarter 2014, to install compression for the Dutch and Mary Rose wells. Our net
natural gas production for the year ended December 31, 2014 was 70.9 Mmcf/d, up
from approximately 69.7 Mmcf/d for the year ended December 31, 2013.
Additionally, net oil production increased from 3,600 barrels per day to 3,800
barrels per day, while NGL production increased from approximately 2,600 barrels
per day to 2,800 barrels per day.
Average Sales Prices
The average equivalent sales price realized for the years ended December 31,
2015, 2014 and 2013 were $3.43 per Mcfe, $6.86 per Mcfe and $5.82 per Mcfe,
respectively. For the year ended December 31, 2015, the price of natural gas was
$2.61 per Mcf while the price for oil and NGLs was $46.80 per barrel and $14.68
per barrel, respectively. For the year ended December 31, 2014, the price of
natural gas was $4.36 per Mcf while the prices for oil and NGLs were $92.98 per
barrel and $33.27 per barrel, respectively.
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For the year ended December 31, 2013, the price of natural gas was $3.84 per Mcf while the prices for oil and NGLs were $101.21 per barrel and $37.26 per barrel, respectively.
Operating Expenses (including production taxes)
Operating expenses for the year ended December 31, 2015 were approximately $37.8
million, or $1.11 per Mcfe, compared to approximately $47.2 million, or $1.17
per Mcfe, for the year ended December 31, 2014. Operating expenses for the year
ended December 31, 2013 were approximately $36.8 million, or $1.30 per Mcfe. The
table below provides additional detail of operating expenses for the years ended
December 31, 2015, 2014 and 2013.
Twelve Months Ended December 31,
2015 2014 2013
(in thousands) (per Mcfe) (in thousands) (per Mcfe) (in thousands) (per Mcfe)
Lease operating expenses $ 25,124 $ 0.74 $ 27,271 $ 0.68 $ 15,682 $ 0.55
Production & ad valorem 4,747 0.14 11,513 0.29 4,693 0.17
taxes
Transportation & 4,714 0.13 5,855 0.14 4,336 0.15
processing costs
Workover costs 3,255 0.10 2,597 0.06 12,073 0.43
Total operating expenses $ 37,840 $ 1.11 $ 47,236 $ 1.17 $ 36,784 $ 1.30
Lease operating expenses decreased by 8% for the year ended December 31, 2015,
compared to the year ended December 31, 2014, as a direct result of our efforts
to reduce costs during the second half of 2015 during this challenging commodity
price environment. Production and ad valorem taxes decreased by 59% for the year
ended December 31, 2015, compared to the prior year, primarily due to the
decrease in revenues for the same period.
Lease operating expenses increased for the year ended December 31, 2014,
compared to the year ended December 31, 2013, primarily due to the incremental
operational activity associated with the expanded asset base as a result of our
merger with Crimson. Production and ad valorem taxes increased for the year
ended December 31, 2014, compared to the prior year, primarily due to the
increase in revenues related to the Merger. The $12.0 million in workover costs
for the year ended December 31, 2013, was associated with the tubing and casing
replacement at Vermilion 170.
Exploration Expenses
We reported approximately $12.0 million of exploration expenses for the year
ended December 31, 2015, which included $6.7 million in dry-hole costs related
to our State #1H well in
Natrona County, Wyoming
, and $2.8 million related to
the early termination of a drilling rig contract, compared to $33.4 million for
the year ended December 31, 2014. The 2014 costs include $31.5 million related
to our exploratory dry hole at Ship Shoal 255 and $1.9 million for geological
and geophysical activities, seismic data and delay rentals. We reported
approximately $1.8 million of exploration expenses for the year ended December
31, 2013.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for the year ended December 31, 2015
was approximately $133.4 million, or $3.93 per Mcfe, compared with
approximately $156.1 million, or $3.87 per Mcfe, for the year ended December 31,
2014, a decrease primarily attributable to lower production during 2015. The
rate was reduced substantially for the fourth quarter 2015 as a result of the
impairment recorded in the quarter ended September 30, 2015, as discussed below.
Depreciation, depletion and amortization for the year ended December 31, 2014
was approximately $156.1 million, or $3.87 per Mcfe, compared to approximately
$65.5 million, or $2.32 per Mcfe, for the year ended December 31, 2013, an
increase primarily attributable to the expanded asset base and production levels
subsequent to our merger with Crimson.
Impairment and Abandonment of Oil and Gas Properties
Impairment and abandonment expenses for the year ended December 31, 2015
included producing property impairment of $269.6 million related to the decline
in commodity prices and the resulting impact on estimated future net cash flows
from associated reserves. Approximately $235.8 million of the total producing
property impairment for the year ended December 31, 2015 is
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attributable to the
Madison
/
Grimes
counties and
Zavala
/
Dimmit
/
Karnes
counties
properties, our highest valued properties stemming from the Merger with Crimson.
Impairment expenses for the year ended December 31, 2015 included a $16.3
million impairment of certain unproved properties and onshore prospects due
primarily to the sustained low commodity price environment and expiring leases.
Approximately $9.3 million of the total for the year ended December 31, 2015 is
related to unproved lease cost amortization of the Elm Hill project in
Fayette
and
Gonzales
counties,
Texas
.
Impairment and abandonment expenses for the year ended December 31, 2014
included producing property impairments of $7.7 million for South Timbalier 17
and $3.7 million for the Tuscaloosa Marine Shale ("TMS") proved properties due
to performance and commodity price declines in 2014, $3.5 million impairment of
unproved leasehold cost related to the dry hole on our Ship Shoal 255 block and
$12.1 million for impairment of an existing platform which was expected to be
used by the Ship Shoal 255 well if it had been successful. Impairment expenses
for the year ended December 31, 2014 also included a $20.1 million impairment
charge for certain unproved prospects due to expiring leases and leases not
likely to be drilled, primarily related to GOM leases and unproved TMS leases.
For the year ended December 31, 2013, the Company recorded impairment expense of approximately $0.8 million, related to expiring leasehold costs in our Ship Shoal 83 and Brazos 543 prospects.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2015 were
approximately $26.4 million, compared to $34.0 million for the year ended
December 31, 2014. Included in our current year expense was approximately $0.6
million in cash severance costs resulting from an August 2015 reduction in force
and $6.5 million in non-cash stock based compensation. Included in the prior
year expense was approximately $4.5 million in non-cash stock based compensation
and $2.6 million in merger-related costs. Exclusive of the stock compensation
and severance related costs, cash general and administrative expenses for the
current year were $19.3 million, compared to cash expenses of $29.5 million for
the prior year. The 2015 reduction in force was a major step in our ongoing cost
cutting efforts necessitated by the current challenging commodity price
environment.
General and administrative expenses for the year ended December 31, 2014 were
approximately $34.0 million, compared to $26.5 million for the year ended
December 31, 2013. General and administrative expenses for the year ended
December 31, 2014 included approximately $4.5 million in non-cash stock based
compensation and $2.6 million in merger-related costs. General and
administrative expenses for the year ended December 31, 2013 included
approximately $3.2 million in non-cash stock based compensation and $3.9 million
attributable to the merger with Crimson.
Gain (loss) from Affiliates
For the year ended December 31, 2015, the Company recorded a loss from
affiliates of approximately $30.6 million, net of tax benefit of $16.5 million,
related to our equity investment in Exaro, compared with a gain from affiliates
of approximately $6.9 million, net of taxes of $3.8 million, for the year ended
December 31, 2014. The decline in 2015 was related primarily to an impairment of
Exaro's oil and gas properties as a result of the recent dramatic decline in
commodity prices.
For the year ended December 31, 2013, the Company recorded a gain from affiliates of approximately $2.3 million, net of taxes of $1.2 million, related to our investment in Exaro.
Other Income (Expense)
Other expense for the year ended December 31, 2015 was approximately $0.7
million, which is primarily related to $5.6 million of costs incurred in pursuit
of an unsuccessful acquisition in the fourth quarter and interest expense of
$3.2 million, partially offset by $6.1 million in proceeds related to favorable
outcomes in two lawsuits and realized gains on derivatives of $2.3 million.
Other expense for the year ended December 31, 2014 was approximately $2.7 million, which is primarily related to interest expense.
Other income for the year ended December 31, 2013 was approximately $29.5
million, which included a $15.3 million gain on the sale of assets related to
our equity investment in Alta Resources, Inc., a $6.6 million gain related to
the disposition of a minority working interest in all developed and undeveloped
properties in
Madison
and
Grimes
counties, and the proceeds from a $10 million
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key-man life insurance policy on the Company's former Chairman, President and Chief Executive Officer, Mr. Kenneth Peak, who passed away on April 19, 2013.
Capital Resources and Liquidity
Our primary cash requirements are for capital expenditures, working capital,
operating expenses, acquisitions and principal and interest payments on
indebtedness. Our primary sources of liquidity are cash generated by operations,
net of the realized effect of our hedging agreements, and amounts available to
be drawn under our credit facility.
The table below summarizes certain measures of liquidity and capital expenditures, as well as our sources of capital from internal and external sources, for the periods indicated, in thousands.
Year ended December 31,
2015 2014 2013
Net cash provided by operating
activities $ 24,955 $ 209,960 $
105,037
Net cash used in investing activities $ (76,806) $ (175,057) $ (34,795)
Net cash provided by (used in)
financing activities $ 51,851 $ (34,903) $
(149,729)
Cash and cash equivalents at the end of
the period $ - $ - $ -
Cash flow from operating activities, including changes in working capital,
provided approximately $25.0 million in cash for the year ended December 31,
2015 compared to $210.0 million for the year ended December 31, 2014. The
deficit in working capital was reduced by approximately $27.2 million during
2015, compared to an increase in 2014 of approximately $16.7 million. Cash flow
from operating activities, excluding changes in working capital, provided
approximately $52.2 million in cash for the year ended December 31, 2015
compared to $193.3 million for the year ended December 31, 2014. This decrease
in cash provided by operating activities was primarily attributable to lower oil
and natural gas prices for 2015, as well as a decline attributable to our
reduced drilling activity in 2015 due to the low commodity price environment.
Cash flow from operating activities provided approximately $210.0 million in
cash for the year ended December 31, 2014 compared to $105.0 million for the
year ended December 31, 2013. This increase in cash provided by operating
activities was primarily attributable to our merger with Crimson.
Cash used in investing activities was approximately $76.8 million for the year
ended December 31, 2015, which included approximately $77.8 million for capital
expenditures, partially offset by approximately $1.0 million in distributions
from REX as a result the dissolution of that entity.
Cash used in investing activities was approximately $175.1 million for the year
ended December 31, 2014, which included approximately $180.4 million for capital
expenditures, partially offset by approximately $5.4 million related to the sale
of assets and distributions from affiliates.
Cash used in investing activities was approximately $34.8 million for the year
ended December 31, 2013, which included approximately $62.6 million for capital
expenditures and approximately $15.4 million for investments in affiliates,
partially offset by approximately $43.2 million related to the sale of assets
and distributions from affiliates.
Cash provided by financing activities was approximately $51.9 million for the
year ended December 31, 2015 compared to $34.9 million used in financing
activities in 2014. The cash provided by financing activities in 2015 was
primarily attributable to net borrowings under our RBC Credit Facility (defined
below) used to reduce the working capital deficit at December 31, 2014, while
the cash used in financing activities in 2014 reflected the net repayment of
borrowings under the RBC Credit Facility that existed at the beginning of that
year.
Cash used in financing activities was approximately $34.9 million for the year
ended December 31, 2014 compared to $149.7 million used in financing activities
in 2013, a change primarily attributable to the retirement of a portion of
Crimson's debt assumed upon closing of the Merger, partially offset by
post-merger borrowings under our RBC Credit Facility.
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Credit Facility
In connection with the Merger, the Company assumed and immediately repaid
Crimson's $175.0 million second lien term loan with Barclays Bank PLC
("Barclays") and other lenders, and Crimson's $58.6 million balance under its
senior secured revolving credit facility with Wells Fargo and other lenders, and
$1.8 million in accrued interest and prepayment premiums. In order to refinance
the assumed debt, the Company entered into a $500 million four-year revolving
credit facility with Royal Bank of Canada and other lenders (the "RBC Credit
Facility"), which matures on October 1, 2017, with an initial
hydrocarbon-supported borrowing base of $275 million. As part of the regular
redetermination schedule, the borrowing base was redetermined at $225 million
effective May 8, 2015, and $190 million effective November 13, 2015 due
primarily to lower commodity prices and the impact of the significant reduction
in the Company's drilling program in 2015. The borrowing base under our RBC
Credit Facility is redetermined each November 1 and May 1. Since the last
regularly scheduled redetermination of our borrowing base, effective through May
1, 2016, commodity prices have continued to decline. The decline in prices will
likely negatively impact the price decks utilized by banks in their calculation
of the Company's borrowing base at May 1, 2016. If our next borrowing base
redetermination results in a lower borrowing base, we may be unable to obtain
financing otherwise currently available under the RBC Credit Facility.
The Company incurred $2.2 million of arrangement and upfront fees in connection
with the RBC Credit Facility. Proceeds of the RBC Credit Facility were, or may
be used (i) to finance working capital and for general corporate purposes, (ii)
for permitted acquisitions, and (iii) to finance transaction expenses in
connection with the RBC Credit Facility and the Merger. The RBC Credit Facility
is collateralized by substantially all of the producing assets of the Company
and its subsidiaries. Borrowings under the RBC Credit Facility bear interest at
a rate that is dependent upon LIBOR or the
U.S.
prime rate of interest, plus a
0.50% to 2.50% margin dependent upon the amount of borrowings outstanding.
On October 28, 2014, the Company entered into a second amendment to the RBC
Credit Facility, which reduced the effective interest rate on borrowings and
provided for the repurchase by the Company of common shares under its 2011 Share
Repurchase Plan, subject to certain limitations. As of December 31, 2015, we had
$115.4 million outstanding under the RBC Credit Facility, compared with $63.4
million outstanding under the RBC Credit Facility at the end of 2014.
The RBC Credit Facility requires us to maintain a Current Ratio of greater than
or equal to 1.0 and a Leverage Ratio of less than or equal to 3.50, both as
defined in the RBC Credit Facility Agreement. Our compliance with these
covenants is tested each quarter. At December 31, 2015, we were in compliance
with the covenants under the RBC Credit Facility, and at current commodity
prices, we do not except any covenant compliance issues over the next twelve
months. See Note 13 to our Financial Statements -"Long-Term Debt" for a more
detailed description of terms and provisions of our credit agreement.
Future Capital Requirements
Our future crude oil, natural gas and natural gas liquids reserves and
production, and therefore our cash flow and results of operations, are highly
dependent on our success in efficiently developing and exploiting our current
reserves and economically finding or acquiring additional recoverable reserves.
We intend to grow our reserves and production by further exploiting our existing
property base through drilling opportunities in our resource plays and in our
conventional onshore inventory in the Texas Gulf Coast, with activity in any
particular area and period of time to be a function of market and field
economics. We anticipate that acquisitions, including those of undeveloped
leasehold interests, will continue to play a role in our business strategy as
those opportunities arise from time to time; however, there can be no assurance
that we will be successful in consummating any acquisitions, or that any such
acquisition entered into will be successful. These potential acquisitions are
not part of our current capital budget and would require additional capital.
Natural gas and oil prices continue to be volatile and our financial resources
may be insufficient to fund any of these opportunities. While there are
currently no unannounced agreements for the acquisition of any material
businesses or assets, such transactions can be effected quickly and could occur
at any time.
We believe that our internally generated cash flow, combined with availability
under our RBC Credit Facility will be sufficient to meet the liquidity
requirements necessary to fund our daily operations and planned capital
development and to meet our debt service requirements for the next twelve
months. We currently plan to limit our 2016 capital expenditures to a level
within our forecasted cash flow from operations for the year; however, we do
possess the capacity, through forecasted excess cash flow and through our RBC
Credit Facility, to increase and/or accelerate drilling on any particular area
should we determine that market and project economics so warrant. Our ability to
execute on our growth strategy will be determined, in large part, by our cash
flow and the
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availability of debt and equity capital at that time. Any decision regarding a financing transaction, and our ability to complete such a transaction, will depend on prevailing market conditions and other factors.
Our 2016 capital budget is expected to be funded from internally generated cash
flow, exclusive of acquisitions, if any, and due to the current commodity price
environment will be focused primarily on: (i) the preservation of our strong and
flexible financial position by limiting our overall capital expenditure budget
to no more than internally generated cash flow; (ii) focusing expenditures on
strategic projects only, and (iii) identification of opportunities for cost
efficiencies in all areas of our operations. Our current capital budget for 2016
should allow us to meet our contractual requirements, remain in position to
preserve our term acreage where appropriate and maintain our already healthy
financial profile during this challenging period for our industry. We will
continuously monitor the commodity price environment, and if warranted, make
adjustments to our investment strategy as the year progresses.
Inflation and Changes in Prices
While the general level of inflation affects certain costs associated with the
energy industry, factors unique to the industry result in independent price
fluctuations. Such price changes have had, and will continue to have, a material
effect on our operations; however, we cannot predict these fluctuations.
Income Taxes
During the year ended December 31, 2015, we received a refund of approximately
$0.2 million in federal and state income taxes. During the years ended December
31, 2014 and 2013, we paid approximately $0.2 million and $0.3 million,
respectively, in federal and state income taxes, net of cash refunds received.
Contractual Obligations
The following table summarizes our known contractual obligations as of December
31, 2015:
Payment due by period (thousands)
Less than More than
Total 1 year 1 - 3 years 3 - 5 years 5 years
Long term debt and
interest (1) $ 121,446 $ 2,839 $ 118,607 $ - $ -
Delay rentals 1,068 345 308 205 210
Asset retirement
obligations 27,109 4,603 2,636 1,291 18,579
Employment agreements 2,088 2,088 - - -
Operating leases (2) 7,182 3,182 3,584 416 -
Hardware/software 203 113 90 - -
Uncertain income tax
positions (3) 360 - - - 360
Total $ 159,456 $ 13,170 $ 125,225 $ 1,912 $ 19,149
(1) Estimated interest is based on the outstanding debt at December 31, 2015
using the interest rate in effect at that time.
(2) Operating leases include contracts related to office space, compressors,
vehicles, office equipment and other. Operating lease commitments from our
previous office space are expected to be substantially recovered by the
subleases that we have entered into for the remainder of our lease term.
(3) We cannot predict at this time when, or if, this obligation may be required
to be paid.
In addition to the above, we have also committed to invest up to an additional $20.6 million in Exaro.
Application of Critical Accounting Policies and Management's Estimates
The discussion and analysis of the Company's financial condition and results of
operations is based upon the consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in
the United States
. The preparation of these consolidated financial statements
requires the Company to make estimates and judgments that affect the reported
amounts of assets, liabilities, revenues and expenses. The Company's significant
accounting policies are described in Note 2 of Notes to Consolidated Financial
Statements included as part of this Form 10-K. We have identified below the
policies that are of particular importance to the portrayal of our financial
position and results of operations and which require the application of
significant
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judgment by management. The Company analyzes its estimates, including those
related to natural gas and oil reserve estimates, on a periodic basis and bases
its estimates on historical experience, independent third party reservoir
engineers and various other assumptions that management believes to be
reasonable under the circumstances. Actual results may differ from these
estimates under different assumptions or conditions. The Company believes the
following critical accounting policies affect its more significant judgments and
estimates used in the preparation of the Company's consolidated financial
statements:
Oil and Gas Properties - Successful Efforts
Our application of the successful efforts method of accounting for our natural
gas and oil exploration and production activities requires judgments as to
whether particular wells are developmental or exploratory, since exploratory
costs and the costs related to exploratory wells that are determined to not have
proved reserves must be expensed whereas developmental costs are capitalized.
The results from a drilling operation can take considerable time to analyze, and
the determination that commercial reserves have been discovered requires both
judgment and application of industry experience. Wells may be completed that are
assumed to be productive and actually deliver natural gas and oil in quantities
insufficient to be economic, which may result in the abandonment of the wells at
a later date. On occasion, wells are drilled which have targeted geologic
structures that are both developmental and exploratory in nature, and in such
instances an allocation of costs is required to properly account for the
results. Delineation seismic costs incurred to select development locations
within a productive natural gas and oil field are typically treated as
development costs and capitalized, but often these seismic programs extend
beyond the proved reserve areas and therefore management must estimate the
portion of seismic costs to expense as exploratory. The evaluation of natural
gas and oil leasehold acquisition costs included in unproved properties requires
management's judgment of exploratory costs related to drilling activity in a
given area. Drilling activities in an area by other companies may also
effectively condemn leasehold positions.
Reserve Estimates
While we are reasonably certain of recovering our reported reserves, the
Company's estimates of natural gas and oil reserves are, by necessity,
projections based on geologic and engineering data, and there are uncertainties
inherent in the interpretation of such data as well as the projection of future
rates of production and the timing of development expenditures. Reserve
engineering is a subjective process of estimating underground accumulations of
natural gas and oil that are difficult to measure. The accuracy of any reserve
estimate is a function of the quality of available data, engineering and
geological interpretation and judgment. Estimates of economically recoverable
natural gas and oil reserves and future net cash flows necessarily depend upon a
number of variable factors and assumptions, such as historical production from
the area compared with production from other producing areas, the assumed effect
of regulations by governmental agencies, and assumptions governing future
natural gas and oil prices, future operating costs, severance taxes, development
costs and workover costs, all of which may in fact vary considerably from actual
results. The future development costs associated with reserves assigned to
proved undeveloped locations may ultimately increase to the extent that these
reserves are later determined to be uneconomic. For these reasons, estimates of
the economically recoverable quantities of expected natural gas and oil
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future net cash flows
may vary substantially. Any significant variance in the assumptions could
materially affect the estimated quantity and value of the reserves, which could
affect the carrying value of the Company's natural gas and oil properties and/or
the rate of depletion of such natural gas and oil properties.
Actual production, revenues and expenditures with respect to the Company's
reserves will likely vary from estimates, and such variances may be material.
Holding all other factors constant, a reduction in the Company's proved reserve
estimate at December 31, 2015 of 5%, 10% and 15% would affect depreciation,
depletion and amortization expense by approximately $1.0 million, $2.2 million
and $3.4 million, respectively.
Impairment of Natural Gas and Oil Properties
The Company reviews its proved natural gas and oil properties for impairment
whenever events and circumstances, such as the current low commodity price
environment, indicate a potential decline in the recoverability of their
carrying value. An impairment loss associated with an asset group is the amount
by which the carrying amount of a long-lived asset is not recoverable and
exceeds its fair value. An asset's fair value is preferably indicated by a
quoted market price in the asset's principal market. Unlike many businesses
where independent appraisals can be obtained for items such as equipment, oil
and gas proved reserves are unique assets. Most oil and gas valuations are based
on a combination of the income approach and market approach methodologies. We
utilize the
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income approach also known as the discounted cash flow ("DCF") approach. Under the DCF method in determining fair value, there are specific guidelines and ranges within the evaluation that we can consider and estimate.
The Company compares expected undiscounted future net cash flows from each field
to the unamortized capitalized cost of the asset. If the future undiscounted net
cash flows, based on the Company's estimate of future natural gas and oil prices
and operating costs and anticipated production from proved reserves, are lower
than the unamortized capitalized cost, then the capitalized cost is reduced to
fair market value. The factors used to determine fair value include, but are not
limited to, estimates of reserves, future commodity pricing, future production
estimates, and anticipated capital expenditures. Unproved properties are
reviewed quarterly to determine if there has been impairment of the carrying
value, with any such impairment charged to expense in the period. Drilling
activities in an area by other companies may also effectively impair leasehold
positions. Given the complexities associated with natural gas and oil reserve
estimates and the history of price volatility in the natural gas and oil
markets, events may arise that will require the Company to record an impairment
of its natural gas and oil properties and there can be no assurance that such
impairments will not be required in the future nor that they will not be
material. Assuming strip pricing as of March 1, 2016 through 2020 and keeping
pricing flat thereafter, instead of 2015 SEC pricing, while leaving all other
parameters unchanged, the Company's proved reserves would have been 185.4 Bcfe
and the PV-10 value of proved reserves would have been $226.3 million.
Derivative Instruments
At the end of each reporting period we record on our balance sheet the
mark-to-market valuation of our derivative instruments. The estimated change in
fair value of the derivatives, along with the realized gain or loss for settled
derivatives, is reported in Other Income (Expense) as Gain (loss) on
derivatives, net.
Income Taxes
Income taxes are provided for the tax effects of transactions reported in the
financial statements and consist of taxes currently payable plus deferred income
taxes related to certain income and expenses recognized in different periods for
financial and income tax reporting purposes. Deferred income taxes are measured
by applying currently enacted tax rates to the differences between financial
statements and income tax reporting. Numerous judgments and assumptions are
inherent in the determination of deferred income tax assets and liabilities as
well as income taxes payable in the current period. We are subject to taxation
in several jurisdictions, and the calculation of our tax liabilities involves
dealing with uncertainties in the application of complex tax laws and
regulations in various taxing jurisdictions.
Accounting for uncertainty in income taxes prescribes a recognition threshold
and a measurement attribute for the financial statement recognition and
measurement of income tax positions taken or expected to be taken in an income
tax return. For those benefits to be recognized, an income tax position must be
more-likely-than-not to be sustained upon examination by taxing authorities.
In assessing the realizability of deferred tax assets, we consider whether it is
more likely than not that some portion or all of the deferred tax assets will
not be realized. As of December 31, 2015, we had federal net operating loss
("NOL") carryforwards of $140.4 million which occurred due to the Merger, and
subsequent taxable losses in 2014 and 2015 due to lower commodity prices and
impairment of oil and gas property. Generally, these NOLs are available to
reduce future taxable income and the related income tax liability subject to the
limitations set forth in Internal Revenue Code Section 382. Given the
uncertainty of our ability to generate taxable income, a valuation allowance of
$57.5 million has been recorded for the year ended December 31, 2015 against the
deferred tax assets, reduced by the amount of the deferred tax liability.
Our federal and state income tax returns are generally not filed before the
consolidated financial statements are prepared. Therefore, we estimate the tax
basis of our assets and liabilities at the end of each period as well as the
effects of tax rate changes, tax credits and net operating and capital loss
carryforwards and carrybacks. Adjustments related to differences between the
estimates we used and actual amounts we reported are recorded in the period in
which we file our income tax returns. See Note 16 - "Income Taxes" to our
consolidated financial statements.
Business Combinations
Accounting for business combinations requires that the various assets acquired
and liabilities assumed in a business combination be recorded at their
respective acquisition date fair values. The most significant estimates to us
typically relate to the
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value assigned to future recoverable oil and gas reserves and unproved
properties. Deferred taxes are recorded for any differences between fair value
and tax basis of assets acquired and liabilities assumed. To the extent the
purchase price plus the liabilities assumed (including deferred income taxes
recorded in connection with the transaction) exceeds the fair value of the net
assets acquired, we are required to record the excess as goodwill. As the fair
value of assets acquired and liabilities assumed is subject to significant
estimates and subjective judgments, the accuracy of this assessment is
inherently uncertain. The value assigned to recoverable oil and gas reserves is
subject to the impairment test when facts or circumstances indicate that the
value of the properties may be impaired, and the value assigned to unproved
properties is assessed at least annually to ascertain whether impairment has
occurred. If the initial accounting for the business combination is not
complete, the amounts recognized for assets acquired and liabilities assumed in
the financial statements may be adjusted during the measurement period of up to
one year as specified by Accounting Standards Codification ("ASC") 805, Business
Combinations.
Recent Accounting Pronouncements
In February 2016, the FASB issued Accounting Standards Update No. 2016-02:
Leases (Topic 842) (ASU 2016-02). The main objective of ASU 2016-02 is to
increase transparency and comparability among organizations by recognizing lease
assets and lease liabilities on the balance sheet and disclosing key information
about leasing arrangements. The main difference between previous GAAP and Topic
842 is the recognition of lease assets and lease liabilities by lessees for
those leases classified as operating leases. ASU 2016-02 requires lessees to
recognize assets and liabilities arising from leases on the balance sheet. ASU
2016-02 further defines a lease as a contract that conveys the right to control
the use of identified property, plant, or equipment for a period of time in
exchange for consideration. Control over the use of the identified asset means
that the customer has both (1) the right to obtain substantially all of the
economic benefit from the use of the asset and (2) the right to direct the use
of the asset. ASU 2016-02 requires disclosures by lessees and lessors to meet
the objective of enabling users of financial statements to assess the amount,
timing, and uncertainty of cash flows arising from leases. In transition,
lessees and lessors are required to recognize and measure leases at the
beginning of the earliest period presented using a modified retrospective
approach. For public entities, ASU 2016-02 is effective for financial statements
issued for fiscal years beginning after December 15, 2018, including interim
periods within those fiscal years; early application is permitted. The Company
will continue to assess the impact this may have on its financial position,
results of operations, and cash flows.
In January 2016, the Financial Accounting Standards Board (the "FASB") issued
Accounting Standards Update No. 2016-01: Financial Instruments - Overall
(Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial
Liabilities (ASU 2016-01). The main objective of ASU 2016-01 is enhancing the
reporting model for financial instruments to provide users of financial
statements with more decision-useful information. The amendments in ASU 2016-01
make targeted improvements to GAAP by: (i) requiring equity investments (except
those accounted for under the equity method of accounting or those that result
in consolidation of the investee) be measured at fair value with changes in fair
value recognized in net income; (ii) simplifying the impairment assessment of
equity investments without readily determinable fair values by requiring a
qualitative assessment to identify impairment; (iii) exempting all non-public
business entities from disclosing fair value information for financial
instruments measured at amortized cost; (iv) eliminating requirement for public
business entities to disclose the methods and significant assumptions used to
estimate the fair value for financial instruments measured at amortized cost on
the balance sheet: (v) requiring public business entities to use the exit price
notion when measuring the fair value of financial instruments for disclosure
purposes; (vi) requiring separate presentation in other comprehensive income the
portion of the total change in fair value of a liability resulting from a change
in the instrument-specific credit risk when the entity has elected to measure
the liability at fair value in accordance with the fair value option for
financial instruments; (vii) requiring separate presentation of financial assets
and financial liabilities by measurement category and form of financial asset;
and (viii) clarifying that an entity should evaluate the need for a valuation
allowance on a deferred tax asset related to available-for-sale securities in
combination with the entity's other deferred tax assets. For public entities,
ASU 2016-01 is effective for financial statements issued for fiscal years
beginning after December 15, 2017, including interim periods within those fiscal
years; early application is permitted. The provisions of this accounting update
are not expected to have a material impact on the Company's financial position
or results of operations.
In November 2015, the FASB issued Accounting Standards Update No. 2015-17:
Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU
2015-17). ASU 2015-17 is part of an initiative to reduce complexity in
accounting standards. Current GAAP requires an entity to separate deferred
income tax liabilities and assets into current and noncurrent amounts in a
classified statement of financial position. However, this classification does
not generally align with the time period in which the
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recognized deferred tax amounts are expected to be recovered or settled. To
simplify the presentation of the deferred income taxes, ASU 2015-17 requires
that deferred tax liabilities and assets be classified as noncurrent in a
classified statement of financial position. The current requirement that
deferred tax liabilities and assets of an entity be offset and presented as a
single amount is not affected by the amendments of ASU 2015-17. For public
entities, ASU 2015-17 is effective for financial statements issued for fiscal
years beginning after December 15, 2016, and interim periods within those fiscal
years; early application is permitted. The Company has selected early
application starting with the financial statements issued for the year ended
December 31, 2015. The provisions of this accounting update do not have a
material impact on the Company's financial position or results of operations.
Accordingly, the deferred tax liability and the valuation allowance are
classified as non-current.
In September 2015, the FASB issued Accounting Standards Update No. 2015-16:
Business Combinations (Topic 805): Simplifying the Accounting for
Measurement-Period Adjustments (ASU 2015-16). ASU 2015-16 is part of an
initiative to reduce complexity in accounting standards, and requires that an
acquirer recognize adjustments to provisional amounts that are identified during
the measurement period in the reporting period in which the adjustment amounts
are determined. In addition, the amendments of this update require that the
acquirer record, in the same period's financial statements, the effect on
earnings of changes in depreciation, amortization, or other income effects, if
any, as a result of the changes to the provisional amounts, calculated as if the
accounting had been completed at the acquisition date. Furthermore, ASU 2015-16
requires an entity to present separately on the face of the income statement or
disclose in the notes the portion of the amount recorded in current-period
earnings by line item that would have been recorded in previous reporting
periods if the adjustments to the provisional amounts had been recognized as of
the acquisition date. For public entities, ASU 2015-16 is effective for fiscal
years beginning after December 15, 2015, including interim periods within those
fiscal years. The provisions of this accounting update are not expected to have
a material impact on the Company's financial position or results of operations.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15:
Presentation of Financial Statements - Going Concern (Subtopic 205-40):
Disclosure of Uncertainties about an Entity's Ability to Continue as a Going
Concern (ASU 2014-15). ASU 2014-15 asserts that management should evaluate
whether there are relevant condition or events that are known and reasonably
knowable that raise substantial doubt about the entity's ability to continue as
a going concern within one year after the date the financial statements are
issued or are available to be issued when applicable. If conditions or events at
the date the financial statements are issued raise substantial doubt about an
entity's ability to continue as a going concern, disclosures are required which
will enable users of the financial statements to understand the conditions or
events as well as management's evaluation and plan. ASU 2014-15 is effective for
the annual period ending after December 15, 2016, and for annual and interim
periods thereafter; early application is permitted. The provisions of this
accounting update are not expected to have a material impact on our financial
position or results of operations.
In May 2014, the FASB and the International Accounting Standards Board jointly
issued new accounting guidance for recognition of revenue Accounting Standards
Update No. 2014-09: Revenue from Contracts with Customers (Topic 606) (ASU
2014-09). This new guidance replaces virtually all existing US GAAP and
International Financial Reporting Standards guidance on revenue recognition. ASU
2014-09 is effective for fiscal years beginning after December 15, 2017. This
new guidance applies to all periods presented. Therefore, when the Company
issues its financial statements on Forms 10-Q and 10-K for periods included in
its year ended December 31, 2017, its comparative periods that are presented
from the years ended December 31, 2015 and 2016, must be retrospectively
presented in compliance with this new guidance. Early adoption is not allowed
for US GAAP. The new guidance requires companies to make more estimates and use
more judgment than under current accounting guidance. The Company does not
anticipate that this new guidance will have a material impact on the Company's
consolidated financial position or results of operations for the periods
presented.
Off Balance Sheet Arrangements
We may enter into off-balance sheet arrangements that can give rise to
off-balance sheet obligations. As of December 31, 2015, the primary off-balance
sheet arrangements that we have entered into included short-term drilling rig
contracts and operating lease agreements, all of which are customary in the oil
and gas industry. Other than the off-balance sheet arrangements shown under
operating leases and drilling rig in the commitments and contingencies table, we
have no other arrangements that are reasonably likely to materially affect our
liquidity or availability of or requirements for capital resources.
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