Contango Oil & Gas Company (NYSE MKT: MCF) (“Contango” or
the “Company”) announced today its financial results for the fourth
quarter and year ended December 31, 2014.
Fourth Quarter Highlights
- Production of 9.8 Bcfe for the
quarter
- Adjusted EBITDAX of $34.8 million for
the quarter
- Initiated pad drilling strategy on
Chalktown acreage to enhance recovery and achieve cost
efficiencies.
- Commenced initial production on Elm
Hill project in Fayette and Gonzales Counties, Texas
- Spud initial horizontal well on new
acreage in Natrona County, Wyoming, targeting the Mowry Shale.
- Spud vertical pilot well in South Texas
to evaluate the Eagle Ford.
Management Commentary
Allan D. Keel, the Company’s President and Chief Executive
Officer, said “We reduced our drilling activity in the fourth
quarter in response to the dramatic downturn in commodity prices.
We did, however, continue drilling to test new formations and
concepts and are optimistic about the initial results. We recently
began production from three wells on our first downspaced
multi-well pad drilling strategy at Chalktown, as well as from our
first three wells in our Elm Hill project in Fayette and Gonzales
Counties, Texas. We spud our initial well in our new FRAMS project
in Natrona County, Wyoming targeting the Mowry Shale and will
complete the well in March or April once the difficult winter
conditions subside. We recently spud our initial well targeting the
Muddy Sandstone formation in our North Cheyenne project in Weston
County, Wyoming. Additionally, during the fourth quarter we drilled
the Beeler Unit 24H as a vertical pilot well to evaluate the Eagle
Ford and other formations in Zavala and Dimmit Counties. We are
excited about the potential of our new plays, but will not embark
on any development programs until commodity prices improve.
Instead, we will limit our 2015 capital program to firm commitments
and to certain wells designed to test new plays or formations. We
anticipate that our capital program will be less than cash flow
generated; therefore, that excess will be used to improve our
already strong balance sheet. ”
Summary Fourth Quarter Financial Results
Net loss for the three months ended December 31, 2014 was $19.9
million, or $(1.05) per basic and diluted share, compared to net
income of $6.4 million, or $0.34 per basic and diluted share, for
the same period last year. Included in the current quarter figure
is a $24.4 million impairment charge related to unproved leases in
non-core areas and performance declines and lower prices at two
non-core producing fields. Other factors contributing to the
decrease in net income were lower revenues and higher depreciation,
depletion and amortization (“DD&A”) expense, partially offset
by a decrease in G&A costs. Average weighted shares outstanding
were approximately 19.0 million for the current and prior year
quarters.
The Company reported Adjusted EBITDAX, as defined below, of
approximately $34.8 million for the three months ended December 31,
2014, compared to $44.4 million for the same period last year, a
decrease mainly attributable to a $16.7 million decrease in
revenues, partially offset by a $5.3 million decrease in current
quarter cash G&A costs.
Revenues for the three months ended December 31, 2014 were
approximately $50.2 million compared to $66.9 million for the same
period last year. This decrease was primarily due to slightly lower
production and a 22% decrease in the weighted average equivalent
sales price received, partially offset by an increase in revenues
attributable to exercising a preferential right to purchase
additional interests in our Dutch wells in December 2013, and the
commencement of production from South Timbalier 17 in July
2014.
Production for the fourth quarter of 2014 was approximately 9.8
Bcfe, or 106.2 Mmcfe per day, approximately 4% less than production
for the fourth quarter of 2013 due to minimal new production being
added in the second half of 2014 as a result of our change to a
multi-well pad drilling strategy in our Chalktown area late in the
third quarter of 2014. The change to multi-well pad drilling
provides drilling cost efficiencies and overall recovery
enhancement; however, the related delay in initial production from
the two new three-well pads drilled in September through December
precluded us from reflecting an increase in production compared to
the prior year quarter. One pad began producing in mid-January and
the second pad is expected to begin production in early-March.
Further impacting fourth quarter production, and expected
production for 2015, was our reduction in drilling activity
associated with the dramatic downturn in crude oil and natural gas
prices during the fourth quarter. Partially offsetting this
decrease in production was incremental production from additional
interests in our Dutch wells acquired in December 2013 and new
production from our 2013 discovery at South Timbalier 17 which
began producing in July 2014. Crude oil and natural gas liquids
production during the fourth quarter of 2014 was approximately
5,600 barrels per day, or 32% of total production, compared to
approximately 6,300 barrels per day, or 34% of total production, in
the fourth quarter of 2013, a decline related to lower capital
expenditures in the fourth quarter and the deferral of initial
production from fourth quarter drilling at Chalktown. Our first
quarter 2015 production guidance of 95-105 Mmcfed reflects the
impact of the reduced fourth quarter 2014 and first quarter 2015
capital program (as described herein) due to the low and uncertain
commodity price environment.
The weighted average equivalent sales price during the three
months ended December 31, 2014 was $5.14 per Mcfe, compared to
$6.60 per Mcfe for the same period last year, a decrease due to the
decline in all commodity prices over the past few months and a
slight decrease in the percentage that oil and liquids represented
of total production for the quarter.
Operating expenses for the three months ended December 31, 2014
were approximately $10.8 million, or $1.11 per Mcfe, compared to
$10.8 million, or $1.06 per Mcfe, for the same period last year.
Included in operating expenses are lease operating expenses,
transportation and processing costs, workover expenses and
production and ad valorem taxes.
Lease operating expenses (“LOE”), transportation and processing
costs and workover expenses for the three months ended December 31,
2014 were approximately $8.6 million, or $0.88 per Mcfe, compared
to approximately $8.5 million, or $0.84 per Mcfe, for the same
period last year, a slight increase attributable to incremental
costs associated with compression added at Eugene Island 11 and the
addition of South Timbalier 17.
DD&A expense for the three months ended December 31, 2014
was $41.3 million, or $4.22 per Mcfe, compared to $33.3 million, or
$3.29 per Mcfe, for the same period last year. This increase is
primarily attributable to additional wells brought on-line during
the year, including the additional interests purchased in our Dutch
wells and the commencement of production on South Timbalier 17.
Impairment and abandonment expense from oil and gas properties
was $24.4 million for the three months ended December 31, 2014. Of
this amount, $13.0 million was due to the impairment of certain
unproved properties due to the estimated decline in the value of
leases expiring in the near term and/or not likely to be drilled
prior to expiration. The impairment relates primarily to certain
portions of our Tuscaloosa Marine Shale acreage position and to our
Gulf of Mexico exploratory acreage. Also recorded in the fourth
quarter of 2014 was an impairment charge of $11.4 million related
to producing properties at South Timbalier 17 and in the Tuscaloosa
Marine Shale area, a charge necessitated by performance declines
and lower oil and gas prices.
G&A expenses for the three months ended December 31, 2014
were $7.6 million, or $0.77 per Mcfe, compared to $14.9 million, or
$1.47 per Mcfe, for the prior year quarter. G&A expenses for
the current and prior year quarter, exclusive of $1.2 million and
$3.2 million, respectively, in non-cash stock compensation expense,
were $6.4 million and $11.7 million, respectively, as the prior
year quarter included merger-related costs and costs related to the
post-merger combination of staff and facilities of both companies.
For the first quarter of 2015, we have provided guidance of $7.3
million to $7.8 million for general and administrative expenses,
exclusive of non-cash stock compensation (“Cash G&A”).
2014 Capital Program
Capital expenditures incurred for the three months ended
December 31, 2014 were approximately $46.0 million, of which $24.9
million was spent drilling in the Woodbine formation in Madison and
Grimes Counties, Texas; $12.1 million spent drilling the Buda
formation in Dimmit County, Texas; $4.4 million spent in Wyoming;
$3.6 million invested in acreage positions primarily in new areas;
and $1.0 million for other capital expenditures. We have previously
provided guidance of a reduced 2015 capital budget of approximately
$51 million; a budget that is focused on limiting capital
expenditures to that determined to be warranted from a strategic
perspective and improving our already strong financial position.
See our release on February 17, 2015.
As of December 31, 2014, we had approximately $63.4 million of
debt outstanding under our credit facility with Royal Bank of
Canada and other lenders. The credit facility has a borrowing base
of $275 million, which was reaffirmed on October 28, 2014 and
through May 1, 2015.
2014 Year End Reserves
As previously disclosed in our February 17, 2015 operations
update, proved reserves at December 31, 2014, as estimated by
William M. Cobb & Associates, Inc. and Netherland,
Sewell & Associates, Inc., Contango’s independent
petroleum engineering firms, in accordance with reserve reporting
guidelines mandated by the Securities and Exchange Commission
(“SEC”), were 275.2 Bcfe, a 12% decrease over our proved reserves
as of December 31, 2013, consisting of 179.7 billion cubic
feet of natural gas, 8.4 million barrels of crude oil, and 7.5
million barrels of natural gas liquids, with a present value of
proved reserves discounted at 10% (“PV-10”) of $796.9 million.
Exclusive of an approximate 22.4 Bcfe negative revision of proved
developed producing reserves at our Eugene Island 11 field,
reserves would have been approximately 5% lower than the prior year
reserves, mainly attributable to normal production decline and
limited reserve adds during the latter half of 2014 due to a
reduction in drilling activity. As of December 31, 2014, 65%
of our proved reserves were natural gas and 76% were proved
developed. These estimates do not include net reserves of
approximately 70.2 Bcfe (PV-10 of approximately $100.6 million)
attributable to our 37% equity ownership investment in Exaro Energy
III LLC ("Exaro") as of December 31, 2014.
The following table summarizes Contango’s total proved reserves
as of December 31, 2014:
Present Value OIL NGL Gas Total
Discounted Category (MBbl) (MBbl) (Mmcf) (Mmcfe) at 10% ($000)
Developed 4,114 5,637 150,235 208,734 657,989 Undeveloped 4,301
1,872 29,416 66,459 138,882 Total Proved 8,415 7,509 179,651
275,193 796,871
Selected Financial and Operating
Data
The following table reflects certain comparative financial and
operating data for the three and twelve month periods ended
December 31, 2014 and 2013:
Three Months Ended Year Ended December 31, December
31, 2014 2013 % 2014
2013 (1)
% Offshore Volumes Sold: Oil and condensate (Mbbls) 57 76 -25 % 269
331 -19 % Natural gas (Mmcf) 5,140 5,010 3 % 19,442 18,994 2 %
Natural gas liquids (Mbbls) 132 155 -15
% 571 584 -2 % Natural gas
equivalents (Mmcfe) 6,273 6,396 -2 % 24,474 24,489 0 %
Onshore Volumes Sold: Oil and condensate (Mbbls) 214 258 -17 %
1,132 258 340 % Natural gas (Mmcf) 1,536 1,630 -6 % 6,433 1,630 295
% Natural gas liquids (Mbbls) 113 93 22
% 437 93 371 % Natural gas
equivalents (Mmcfe) 3,498 3,736 -6 % 15,849 3,731 325 %
Total Volumes Sold: Oil and condensate (Mbbls) 271 334 -19 % 1,401
589 138 % Natural gas (Mmcf) 6,676 6,640 1 % 25,875 20,624 25 %
Natural gas liquids (Mbbls) 245 248 -1
% 1,008 677 49 % Natural gas
equivalents (Mmcfe) 9,771 10,132 -4 % 40,323 28,220 43 %
Daily Sales Volumes: Oil and condensate (Mbbls) 2.9 3.6 -19 % 3.8
3.6 6 % Natural gas (Mmcf) 72.6 72.2 1 % 70.9 69.7 2 % Natural gas
liquids (Mbbls) 2.7 2.7
0
% 2.8 2.6 8 % Natural gas
equivalents (Mmcfe) 106.2 110.2 -4 % 110.5 107.8 2 % Average
sales prices: Oil and condensate (per Bbl) $ 70.71 $ 94.78 -25 % $
92.98 $ 101.21 -8 % Natural gas (per Mcf) $ 3.77 $ 3.91 -4 % $ 4.36
$ 3.84
14
% Natural gas liquids (per Bbl) $ 24.26 $ 37.40 -35 % $ 33.27 $
37.26 -11 % Total (per Mcfe) $ 5.14 $ 6.60 -22 % $ 6.86 $ 5.82 18 %
(1) Results for the twelve months ended December 31, 2013
include nine months (January-September) of Contango prior to the
Merger with Crimson, and three months (October-December) of
post-merger Contango.
Three Months Ended
Year Ended December 31, December 31, 2014 2013 % 2014
2013 (1)
% Offshore Selected Costs ($ per Mcfe): Lease Operating
Expenses (2) $ 0.55 $ 0.59 -7 % $ 0.55 $ 1.12 -51 % Production and
ad valorem taxes $ 0.10 $ 0.08 25 % $ 0.10 $ 0.12 -17 %
Depreciation and depletion expense $ 2.39 $ 1.74 37 % $ 2.01 $ 1.77
14 % Onshore Selected Costs ($ per Mcfe): Lease Operating
Expenses (2) $ 1.45 $ 1.27 14 % $ 1.41 $ 1.27 11 % Production and
ad valorem taxes $ 0.46 $ 0.46 0 % $ 0.57 $ 0.46 24 % Depreciation
and depletion expense $ 7.51 $ 5.95 26 % $ 6.74 $ 5.95 13 %
Average Selected Costs ($ per Mcfe): Lease Operating Expenses (2) $
0.88 $ 0.84 5 % $ 0.89 $ 1.14 -22 % Production and ad valorem taxes
$ 0.23 $ 0.22 5 % $ 0.28 $ 0.16 75 % Depreciation and depletion
expense $ 4.22 $ 3.29 28 % $ 3.87 $ 2.32 67 % General and
administrative expense (cash) $ 0.65 $ 1.16 -44 % $ 0.73 $ 0.83 -12
% Interest expense $ 0.06 $ 0.12 -50 % $ 0.07 $ 0.04 75 %
Adjusted EBITDAX (3) (thousands) $ 34,808 $ 44,431 $ 197,275 $
113,493 Weighted Average Shares Outstanding (thousands)
Basic 19,016 19,007 19,059 16,156 Diluted 19,016 19,015 19,059
16,158
(1) Results for the twelve months ended December 31, 2013
include nine months (January-September) of Contango prior to the
Merger with Crimson, and three months (October-December) of
post-merger Contango.
(2) LOE includes transportation and workover expenses.
(3) Adjusted EBITDAX is a non-GAAP financial measure. See below
for reconciliation to net income (loss).
CONTANGO OIL & GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
December 31, December 31, 2014 2013
ASSETS
Cash and cash equivalents $ — $ — Accounts receivable, net 25,309
60,613 Other current assets 5,731 5,504 Net property and equipment
748,623 791,023 Investments in affiliates and other non-current
assets 63,752 53,164
TOTAL ASSETS
$ 843,415 $ 910,304
LIABILITIES AND
SHAREHOLDERS' EQUITY
Accounts payable and accrued liabilities 92,892 96,833 Other
current liabilities 4,123 2,446 Long-term debt 63,359 90,000
Deferred tax liability 93,952 105,956 Asset retirement obligations
21,623 22,019 Total shareholders’ equity 567,466
593,050 TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY $
843,415 $ 910,304
CONTANGO OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
Three Months Ended Year Ended December 31, December 31, 2014
2013 2014 2013 (1) REVENUES Oil and condensate sales $
19,136 $ 31,655 $ 130,238 $ 59,608 Natural gas sales 25,148 25,973
112,695 79,289 Natural gas liquids sales 5,946 9,275
33,525 25,224 Total revenues 50,230
66,903 276,458 164,121 EXPENSES Operating
expenses 10,810 10,761 47,236 36,784 Exploration expenses 316 1,642
33,387 1,811 Depreciation, depletion and amortization 41,264 33,284
156,117 65,529 Impairment and abandonment of oil and gas properties
24,434 - 47,693 776 General and administrative expenses
7,560 14,891 34,045 26,512 Total expenses
84,384 60,578 318,478 131,412
OTHER INCOME (EXPENSE) Gain from investment in affiliates (net of
income taxes) 2,536 907 6,923 2,310 Interest expense (581) (1,197)
(2,658) (1,171) Gain (loss) on derivatives, net 1,335 (1,132) (153)
(1,132) Other income (loss) 272 6,323 124
31,785 Total other income (expense) 3,562
4,901 4,236 31,792 NET INCOME (LOSS) BEFORE
INCOME TAXES (30,592) 11,226 (37,784)
64,501 Income tax benefit (provision) 10,666
(4,830) 15,910 (23,139) NET INCOME (LOSS) $
(19,926) $ 6,396 $ (21,874) $ 41,362
(1) Results for the twelve months ended December 31, 2013
include nine months (January-September) of Contango prior to the
Merger with Crimson, and three months (October-December) of
post-merger Contango.
Non-GAAP Financial Measures
EBITDAX represents net income (loss) before interest expense,
taxes, and depreciation, depletion and amortization, and oil &
gas expenses. Adjusted EBITDAX represents EBITDAX as further
adjusted to reflect the items set forth in the table below, all of
which will be required in determining our compliance with financial
covenants under the RBC Credit Facility.
We have included EBITDAX and Adjusted EBITDAX in this release to
provide investors with a supplemental measure of our operating
performance and information about the calculation of some of the
financial covenants that are contained in our credit agreements. We
believe EBITDAX is an important supplemental measure of operating
performance because it eliminates items that have less bearing on
our operating performance and so highlights trends in our core
business that may not otherwise be apparent when relying solely on
GAAP financial measures. We also believe that securities analysts,
investors and other interested parties frequently use EBITDAX in
the evaluation of companies, many of which present EBITDAX when
reporting their results. Adjusted EBITDAX is a material component
of the covenants that are imposed on us by our credit agreements.
We are subject to financial covenant ratios that are calculated by
reference to Adjusted EBITDAX. Non-compliance with the financial
covenants contained in these credit agreements could result in a
default, an acceleration in the repayment of amounts outstanding
and a termination of lending commitments. Our management and
external users of our financial statements, such as investors,
commercial banks, research analysts and others, also use EBITDAX
and Adjusted EBITDAX to assess:
- the financial performance of our assets
without regard to financing methods, capital structure or
historical cost basis;
- the ability of our assets to generate
cash sufficient to pay interest costs and support our
indebtedness;
- our operating performance and return on
capital as compared to those of other companies in our industry,
without regard to financing or capital structure; and
- the feasibility of acquisitions and
capital expenditure projects and the overall rates of return on
alternative investment opportunities.
EBITDAX and Adjusted EBITDAX are not presentations made in
accordance with generally accepted accounting principles, or GAAP.
As discussed above, we believe that the presentation of EBITDAX and
Adjusted EBITDAX in this release is appropriate. However, when
evaluating our results, you should not consider EBITDAX and
Adjusted EBITDAX in isolation of, or as a substitute for, measures
of our financial performance as determined in accordance with GAAP,
such as net income (loss). EBITDAX and Adjusted EBITDAX have
material limitations as performance measures because they exclude
items that are necessary elements of our costs and operations.
Because other companies may calculate EBITDAX and Adjusted EBITDAX
differently than we do, EBITDAX may not be, and Adjusted EBITDAX as
presented in this release is not, comparable to similarly-titled
measures reported by other companies.
The following table reconciles net income to EBITDAX and
Adjusted EBITDAX for the periods presented:
Three Months Ended Year Ended December
31, December 31, 2014 2013 2014 2013 (1) Net income (loss) $
(19,926) $ 6,396 $ (21,874) $ 41,362 Interest expense 581 1,197
2,658 1,171 Income tax provision (benefit) (10,666) 4,830 (15,910)
23,139 Depreciation, depletion and amortization 41,264 33,284
156,117 65,529 Exploration expenses 316 1,642
33,387 1,811 EBITDAX $ 11,569 $ 47,349 $ 154,378 $ 133,012
Unrealized gain on derivative instruments $ 363 $ 1,132 $
(1,131) $ 1,132 Non-cash equity-based compensation charges 1,182
3,180 4,515 3,180 Impairment of oil and gas properties 24,386 -
46,396 767 Loss (gain) on sale of assets and investment in
affiliates (2,692) (7,230) (6,883)
(24,598) Adjusted EBITDAX $ 34,808 $ 44,431 $ 197,275 $ 113,493
(1) Results for the twelve months ended December 31, 2013
include nine months (January-September) of Contango prior to the
Merger with Crimson, and three months (October-December) of
post-merger Contango.
Guidance for First Quarter 2015
The Company is providing the following guidance for the first
calendar quarter of 2015.
First quarter 2015 production
95,000 – 105,000 Mcfe per day LOE (including transportation
and workovers) $8.3 million – $8.8 million Production and ad
valorem taxes 4.7%
(% of Revenue)
Cash G&A $7.3 million – $7.8 million DD&A
rate $4.00 – $4.25
Teleconference Call
Contango management will hold a conference call to discuss the
information described in this press release on Tuesday, March 3,
2015 at 9:30am CST. Those interested in participating in the
earnings conference call may do so by calling the following phone
number: 1-888-389-5997, (International 1-719-325-2332) and entering
the following participation code: 7092162. A replay of the
call will be available from Tuesday, March 3, 2015 at 12:30pm CST
through Tuesday, March 10, 2015 at 12:30pm CDT by dialing toll free
1-888-203-1112, (International 1-719-457-0820) and asking for
replay ID code 7092162.
Contango Oil & Gas Company is a Houston, Texas based,
independent energy company engaged in the acquisition, exploration,
development, exploitation and production of crude oil and natural
gas offshore in the shallow waters of the Gulf of Mexico and in the
onshore Texas Gulf Coast and Rocky Mountain regions of the United
States. Additional information is available on the Company's
website at http://contango.com.
This press release contains forward-looking statements regarding
Contango that are intended to be covered by the safe harbor
"forward-looking statements" provided by the Private Securities
Litigation Reform Act of 1995, based on Contango’s current
expectations and includes statements regarding acquisitions and
divestitures, estimates of future production, future results of
operations, quality and nature of the asset base, the assumptions
upon which estimates are based and other expectations, beliefs,
plans, objectives, assumptions, strategies or statements about
future events or performance (often, but not always, using words
such as "expects," “projects,” "anticipates," "plans," "estimates,"
"potential," "possible," "probable," or "intends," or stating that
certain actions, events or results "may," "will," "should," or
"could" be taken, occur or be achieved). Statements concerning oil
and gas reserves also may be deemed to be forward-looking
statements in that they reflect estimates based on certain
assumptions that the resources involved can be economically
exploited. Forward-looking statements are based on current
expectations, estimates and projections that involve a number of
risks and uncertainties, which could cause actual results to differ
materially from those, reflected in the statements. These risks
include, but are not limited to: the risks of the oil and gas
industry (for example, operational risks in exploring for,
developing and producing crude oil and natural gas; risks and
uncertainties involving geology of oil and gas deposits; the
uncertainty of reserve estimates; the uncertainty of estimates and
projections relating to future production, costs and expenses;
potential delays or changes in plans with respect to exploration or
development projects or capital expenditures; health, safety and
environmental risks and risks related to weather such as hurricanes
and other natural disasters); uncertainties as to the availability
and cost of financing; fluctuations in oil and gas prices; risks
associated with derivative positions; inability to realize expected
value from acquisitions, inability of our management team to
execute its plans to meet its goals, shortages of drilling
equipment, oil field personnel and services, unavailability of
gathering systems, pipelines and processing facilities and the
possibility that government policies may change or governmental
approvals may be delayed or withheld. Additional information on
these and other factors which could affect Contango’s operations or
financial results are included in Contango’s other reports on file
with the Securities and Exchange Commission. Investors are
cautioned that any forward-looking statements are not guarantees of
future performance and actual results or developments may differ
materially from the projections in the forward-looking statements.
Forward-looking statements are based on the estimates and opinions
of management at the time the statements are made. Contango does
not assume any obligation to update forward-looking statements
should circumstances or management's estimates or opinions change.
Initial production rates are subject to decline over time and
should not be regarded as reflective of sustained production
levels.
Contango Oil & Gas CompanyE. Joseph Grady,
713-236-7400Senior Vice President and Chief Financial OfficerSergio
Castro, 713-236-7400Vice President and Treasurer
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