Contango Announces Third Quarter 2015 Financial Results and Provides Operations Update
Contango Oil & Gas Company (NYSE MKT: MCF) (“Contango”) announced today
its financial results for the three months ended September 30, 2015 and
provided an operational update.
Third Quarter 2015 Summary
-
Production of 8.4 Bcfe for the quarter (90.9 Mmcfed), within guidance.
-
24% reduction in recurring direct lease operating expenses for the
quarter (i.e. excluding workovers), 15% decrease in per unit costs.
-
20% reduction in recurring cash G&A costs for the quarter.
-
Adjusted EBITDAX of $20.7 million for the quarter.
-
Two wells in progress to further delineate our June 2015 discovery in
the Muddy Sandstone formation in Weston County, Wyoming.
Management Commentary
Allan D. Keel, the Company’s President and Chief Executive Officer,
said, “We continued to pursue a very conservative strategy during the
third quarter due to the challenging commodity price environment. We
limited our capital program to completing wells in process at the end of
the second quarter and the drilling of strategic wells in our Muddy
Sandstone play in Wyoming. That strategy allowed us to keep our debt
level relatively flat and preserve our balance sheet to potentially
capitalize on acquisition opportunities that may surface in this
environment. We also continue to find ways to cut costs in the field,
and implemented a meaningful and painful reduction in force in our
corporate office in August 2015. We believe that it is important for us
to remain conservative, i.e. limit capital expenditures, reduce costs
and focus on maintaining our financial flexibility, during this period
of commodity price uncertainty.”
Summary Financial Results for the Quarter Ended September 30, 2015
Net loss for the three months ended September 30, 2015 was $185.7
million, or $9.79 per basic and diluted share, compared to net income of
$3.7 million, or $0.19 per basic and diluted share, for the prior year
quarter. Impacting our earnings this quarter was a $235.1 million
pre-tax, non-cash impairment mandated by U.S. GAAP as a result of the
impact of the decline in commodity prices on the value of the Company’s
reserve base. Other factors contributing to the decrease in net income
period over period were the impact of lower commodity prices on our
revenue stream and lower production resulting from our strategically
reduced capital drilling program. Offsetting the impact of these items,
in part, were decreases in operating expenses and cash G&A costs
compared with the 2014 third quarter. Included in the prior year quarter
results was a $5.2 million credit in exploration expense for an
adjustment to estimated final costs for our unsuccessful Ship Shoal 255
exploratory well drilled in the second quarter of 2014. Average weighted
shares outstanding were approximately 19.0 million for the current
quarter and 19.1 million for the prior year quarter.
The Company reported Adjusted EBITDAX, as defined below, of
approximately $20.7 million for the three months ended September 30,
2015, compared to $47.7 million for the same period last year, a
decrease mainly attributable to the decrease in revenues, partially
offset by a decrease in lease operating costs and cash G&A, and an
increase in other income.
Revenues for the three months ended September 30, 2015 were $29.0
million compared to $67.6 million for the same period last year, a
decrease attributable to lower commodity prices and lower production
resulting from our decision to reduce our capital drilling program in
the latter half of 2014 and in 2015 during the dramatic decline in
commodity prices. Revenues for the prior year quarter were negatively
impacted by an estimated $12.1 million related to the shut-in of our
Eugene Island 11 platform for compressor installation.
Production for the three months ended September 30, 2015 was
approximately 8.4 Bcfe, or 90.9 Mmcfed, less than the 9.4 Bcfe, or 102.3
Mmcfed, for the same period last year, but within our previously
provided guidance. As previously disclosed, due to the low and uncertain
commodity price environment, we strategically reduced our capital
activity level dramatically in the latter half of 2014 and in 2015 and
focused on confirmation of our exploratory prospects. This approach
emphasizes strategic confirmation of unproved plays and ultimate
recovery and further delineation of new discoveries, rather than
production growth. For the fourth quarter of 2015, we estimate our
production will be between 85,000 – 90,000 Mcfed.
The weighted average equivalent sales price during the three months
ended September 30, 2015 was $3.47 per Mcfe, compared to $7.17 per Mcfe
for the same period last year. The decrease in the weighted average
equivalent prices quarter over quarter was attributable to a 54%
decrease in average oil and condensate prices, a 25% decline in natural
gas prices, a 59% decrease in natural gas liquids prices, and a lower
percentage of total production coming from crude oil and natural gas
liquids.
Total operating expenses for the three months ended September 30, 2015
were approximately $9.0 million, or $1.08 per Mcfe, compared to $13.8
million, or $1.47 per Mcfe, for the same period last year. Included in
total operating expenses are direct lease operating expenses (“LOE”),
transportation and processing costs, workover expenses and production
and ad valorem taxes.
Direct operating expenses (i.e. total operating expenses, excluding
production and ad valorem taxes) for the three months ended September
30, 2015 were approximately $8.2 million, or $0.98 per Mcfe, which was
below our previously provided guidance, compared to approximately $10.6
million, or $1.13 per Mcfe, for the same period last year. This
improvement resulted from our ongoing efforts to reduce field costs
during this challenging commodity price environment. Direct lease
operating costs, exclusive of expense workovers, declined 24% period
over period. We are pleased to have been able to reduce recurring costs
in total, but it is notable that we were also able to reduce our per
unit cost despite lower production and given that a large majority of
field operating costs are essentially fixed costs.
Production and ad valorem tax expense for the three months ended
September 30, 2015 was $0.8 million, or $0.10 per Mcfe, compared to $3.2
million, or $0.34 per Mcfe, for the same period last year, a decrease
associated with lower revenues.
Exploration expense for the three months ended September 30, 2015 were
$0.4 million, compared to a credit of $4.7 million for the same period
last year. The prior year quarter included a $5.2 million credit related
to a downward adjustment to estimated costs for our unsuccessful Ship
Shoal 255 exploratory well drilled in the second quarter of 2014.
DD&A expenses for the three months ended September 30, 2015 were $38.4
million, or $4.59 per Mcfe, compared to $40.6 million, or $4.31 per
Mcfe, for the same period last year. The higher overall per unit charge
in 2015 is primarily a result of specific field rate increases
associated with price-related year-end 2014 reserve revisions.
Impairment expenses for the three months ended September 30, 2015
included a $225.6 million impairment of proved properties related to the
decline in commodity prices and the resulting impact on estimated future
net cash flows from associated reserves compared to the carrying value
of our properties on the balance sheet. Approximately $196.5 million of
the total proved property impairment for the current quarter is
attributable to the Madison/Grimes counties and Zavala/Dimmit/Karnes
counties properties. No impairment of proved properties was recognized
for the three months ended September 30, 2014.
Impairment expenses for the three months ended September 30, 2015 also
included a $9.5 million impairment of certain unproved properties,
including approximately $8.2 million related to amortization of unproved
lease cost associated with our Elm Hill project in Fayette and Gonzales
counties Texas. Impairment expense for the three months ended September
30, 2014 included a $6.7 million impairment of certain unproved
prospects due to expiring leases and leases not likely to be drilled.
G&A expenses for the three months ended September 30, 2015 were $7.5
million, or $0.90 per Mcfe, compared to $6.8 million, or $0.72 per Mcfe,
for the prior year quarter. Cash G&A expenses for the current and prior
year quarters, i.e. exclusive of $2.4 million and $1.2 million,
respectively, in non-cash stock compensation expense, were $5.1 million
and $5.6 million, respectively, for the two quarters. Also included in
cash G&A for the current quarter is approximately $600,000 in cash
severance costs incurred in implementing a reduction in force in August
2015. The reduction in force (30% of the personnel count in our
corporate office) is a major part of our ongoing cost cutting efforts
necessitated by the current commodity price environment and related
reduction in capital activity. For the fourth quarter of 2015, we have
provided guidance of $4.5 million to $5.0 million for general and
administrative expenses, exclusive of non-cash stock compensation.
Derivative Instruments
We have the following derivative contract in place for the remainder of
the year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
|
|
|
Period
|
|
|
Derivative
|
|
|
Volume/Month
|
|
|
Price/Unit (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
|
|
|
Oct 2015 - Dec 2015
|
|
|
Collar
|
|
|
35,000 Bbls
|
|
|
$55.00 - $65.15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Commodity derivative based on NYMEX West Texas Intermediate
crude oil prices.
|
|
|
Drilling Activity Update
Our drilling activity during the quarter ended September 30, 2015 was
designed to keep our debt level flat and focus on delineating our
Wyoming and Fayette County plays.
Muddy Sandstone - Weston County, Wyoming
In June 2015, we announced the discovery and successful completion of
the Elliot #1H well (80% WI) in the Muddy Sandstone formation in Weston
County, Wyoming (referred to as our North Cheyenne Project). Based on
the encouraging results from this well, we spud two more wells in
September 2015, the WC 45N-66W-35 1H and the WC 44N-66W-9 1H. Both wells
are currently in various stages of drilling or completion. We have
approximately 49,000 gross acres (35,000 net) in this area. Our 2016
drilling program for this area will be developed based on results of the
wells in process and the commodity price environment. Approximately 200
to 300 Muddy horizontal well locations may be prospective on the acreage
based on a drilling density of three to four wells per 640 acres.
Additional prospective horizons in this area will be evaluated during
the delineation phase with additional log and core data and could also
add significantly to the total number of potential horizontal locations.
Elm Hill Project – Fayette and Gonzales
Counties, Texas
In 2014, we acquired approximately 25,000 net acres primarily in Fayette
and Gonzales counties, Texas (referred to as our Elm Hill Project), to
pursue horizontal drilling in this multiple formation area. As of
September 30, 2015, we had drilled and completed five gross (2.5 net)
wells in the Navarro, Buda and Austin Chalk formations, and were
producing from two of these wells; the other three wells were not
commercial successes. We have recovered four whole cores to further
evaluate six hydrocarbon bearing formations that we believe might have
potential for development. We and our partner are discussing future
plans for this area.
2015 Capital Program & Liquidity
Capital expenditures incurred for the three months ended September 30,
2015 were $7.9 million, including $1.2 million for final testing on two
non-commercial wells in our Elm Hill Project in Fayette and Gonzales
counties; $3.7 million on the two delineation wells in Weston County
Wyoming; and $4.3 million for the acquisition of leases and other rights
in these and other areas. We currently anticipate that our total capital
expenditure program for 2015 will be approximately $58 million, which
will be funded primarily from internally generated cash flow. We are in
the process of developing our capital program for 2016, and similar to
our strategy for 2015, that program will likely be focused more on
strategic projects and delineation of recent success, with the goal of
maintaining or reducing debt and/or working capital obligations in this
low commodity price environment. We will continually reassess that
strategy during the year based on forecasted commodity prices and
service costs.
As of September 30, 2015, we had approximately $114.6 million of debt
outstanding under our credit facility compared to approximately $63.4
million at the end of 2014, an increase due to having incurred the vast
majority of our 2015 capital expenditures during the first half of the
year, as planned, and the reduction in the beginning of the year working
capital deficit associated with a more active capex program. We
currently project that our debt level at year-end 2015 will be similar
to our current level with a simultaneous decrease expected in overall
current trade payables and accruals.
Our borrowing base was redetermined at $225 million effective May 7,
2015 with the next regular scheduled redetermination expected to be
completed in mid-November. Due to the lower commodity price environment
and the reduced capital program, we expect some reduction in the
borrowing base from that level. Based on preliminary discussions with
our agent bank, and their borrowing base recommendation currently being
considered by the remaining lenders under the facility, we expect that
the proposed borrowing base will not impact our liquidity position in a
material adverse way.
Selected Financial and Operating Data
The following tables reflect certain comparative financial and operating
data as of, and for the three and nine month periods ended, September
30, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
|
|
|
September 30,
|
|
|
|
|
2015
|
|
|
2014
|
|
|
%
|
|
|
|
2015
|
|
|
2014
|
|
|
%
|
|
Offshore Volumes Sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (Mbbls)
|
|
|
|
42
|
|
|
|
57
|
|
|
-26
|
%
|
|
|
|
|
149
|
|
|
|
211
|
|
|
-29
|
%
|
|
Natural gas (Mmcf)
|
|
|
|
4,191
|
|
|
|
4,039
|
|
|
4
|
%
|
|
|
|
|
13,117
|
|
|
|
14,302
|
|
|
-8
|
%
|
|
Natural gas liquids (Mbbls)
|
|
|
|
133
|
|
|
|
121
|
|
|
10
|
%
|
|
|
|
|
392
|
|
|
|
439
|
|
|
-11
|
%
|
|
Natural gas equivalents (Mmcfe)
|
|
|
|
5,244
|
|
|
|
5,104
|
|
|
3
|
%
|
|
|
|
|
16,367
|
|
|
|
18,201
|
|
|
-10
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Volumes Sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (Mbbls)
|
|
|
|
171
|
|
|
|
335
|
|
|
-49
|
%
|
|
|
|
|
581
|
|
|
|
919
|
|
|
-37
|
%
|
|
Natural gas (Mmcf)
|
|
|
|
1,389
|
|
|
|
1,598
|
|
|
-13
|
%
|
|
|
|
|
4,043
|
|
|
|
4,896
|
|
|
-17
|
%
|
|
Natural gas liquids (Mbbls)
|
|
|
|
117
|
|
|
|
117
|
|
|
0
|
%
|
|
|
|
|
348
|
|
|
|
323
|
|
|
8
|
%
|
|
Natural gas equivalents (Mmcfe)
|
|
|
|
3,115
|
|
|
|
4,312
|
|
|
-28
|
%
|
|
|
|
|
9,615
|
|
|
|
12,352
|
|
|
-22
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Volumes Sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (Mbbls)
|
|
|
|
213
|
|
|
|
392
|
|
|
-46
|
%
|
|
|
|
|
730
|
|
|
|
1,130
|
|
|
-35
|
%
|
|
Natural gas (Mmcf)
|
|
|
|
5,580
|
|
|
|
5,637
|
|
|
-1
|
%
|
|
|
|
|
17,160
|
|
|
|
19,198
|
|
|
-11
|
%
|
|
Natural gas liquids (Mbbls)
|
|
|
|
250
|
|
|
|
238
|
|
|
5
|
%
|
|
|
|
|
740
|
|
|
|
762
|
|
|
-3
|
%
|
|
Natural gas equivalents (Mmcfe)
|
|
|
|
8,359
|
|
|
|
9,416
|
|
|
-11
|
%
|
|
|
|
|
25,982
|
|
|
|
30,553
|
|
|
-15
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily Sales Volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (Mbbls)
|
|
|
|
2.3
|
|
|
|
4.3
|
|
|
-46
|
%
|
|
|
|
|
2.7
|
|
|
|
4.1
|
|
|
-35
|
%
|
|
Natural gas (Mmcf)
|
|
|
|
60.7
|
|
|
|
61.3
|
|
|
-1
|
%
|
|
|
|
|
62.9
|
|
|
|
70.3
|
|
|
-11
|
%
|
|
Natural gas liquids (Mbbls)
|
|
|
|
2.7
|
|
|
|
2.6
|
|
|
5
|
%
|
|
|
|
|
2.7
|
|
|
|
2.8
|
|
|
-3
|
%
|
|
Natural gas equivalents (Mmcfe)
|
|
|
|
90.9
|
|
|
|
102.3
|
|
|
-11
|
%
|
|
|
|
|
95.2
|
|
|
|
111.9
|
|
|
-15
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (per Bbl)
|
|
|
$
|
44.56
|
|
|
$
|
96.05
|
|
|
-54
|
%
|
|
|
|
$
|
49.14
|
|
|
$
|
98.32
|
|
|
-50
|
%
|
|
Natural gas (per Mcf)
|
|
|
$
|
2.87
|
|
|
$
|
3.85
|
|
|
-25
|
%
|
|
|
|
$
|
2.80
|
|
|
$
|
4.56
|
|
|
-39
|
%
|
|
Natural gas liquids (per Bbl)
|
|
|
$
|
14.05
|
|
|
$
|
34.55
|
|
|
-59
|
%
|
|
|
|
$
|
14.86
|
|
|
$
|
36.17
|
|
|
-59
|
%
|
|
Total (per Mcfe)
|
|
|
$
|
3.47
|
|
|
$
|
7.17
|
|
|
-52
|
%
|
|
|
|
$
|
3.66
|
|
|
$
|
7.40
|
|
|
-51
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
Nine Months Ended
|
|
|
|
|
|
September 30,
|
|
|
|
September 30,
|
|
|
|
|
|
2015
|
|
|
2014
|
|
|
%
|
|
|
|
2015
|
|
|
2014
|
|
|
%
|
|
Offshore Selected Costs ($ per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses (1)
|
|
|
|
$
|
0.69
|
|
|
$
|
0.83
|
|
|
-17
|
%
|
|
|
|
$
|
0.64
|
|
|
$
|
0.57
|
|
|
12
|
%
|
|
Production and ad valorem taxes
|
|
|
|
$
|
0.07
|
|
|
$
|
0.11
|
|
|
-36
|
%
|
|
|
|
$
|
0.08
|
|
|
$
|
0.10
|
|
|
-20
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Selected Costs ($ per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses (1)
|
|
|
|
$
|
1.47
|
|
|
$
|
1.48
|
|
|
-1
|
%
|
|
|
|
$
|
1.63
|
|
|
$
|
1.36
|
|
|
20
|
%
|
|
Production and ad valorem taxes
|
|
|
|
$
|
0.14
|
|
|
$
|
0.62
|
|
|
-77
|
%
|
|
|
|
$
|
0.25
|
|
|
$
|
0.61
|
|
|
-59
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Selected Costs ($ per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses (1)
|
|
|
|
$
|
0.98
|
|
|
$
|
1.13
|
|
|
-13
|
%
|
|
|
|
$
|
1.01
|
|
|
$
|
0.89
|
|
|
13
|
%
|
|
Production and ad valorem taxes
|
|
|
|
$
|
0.10
|
|
|
$
|
0.34
|
|
|
-71
|
%
|
|
|
|
$
|
0.14
|
|
|
$
|
0.30
|
|
|
-53
|
%
|
|
General and administrative expense (cash)
|
|
|
|
$
|
0.61
|
|
|
$
|
0.60
|
|
|
2
|
%
|
|
|
|
$
|
0.68
|
|
|
$
|
0.76
|
|
|
-11
|
%
|
|
Interest expense
|
|
|
|
$
|
0.09
|
|
|
$
|
0.07
|
|
|
29
|
%
|
|
|
|
$
|
0.09
|
|
|
$
|
0.07
|
|
|
29
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX (2) (thousands)
|
|
|
|
$
|
20,701
|
|
|
$
|
47,694
|
|
|
|
|
|
|
$
|
54,646
|
|
|
$
|
162,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares Outstanding (thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
18,966
|
|
|
|
19,077
|
|
|
|
|
|
|
|
18,948
|
|
|
|
19,074
|
|
|
|
|
Diluted
|
|
|
|
|
18,966
|
|
|
|
19,122
|
|
|
|
|
|
|
|
18,948
|
|
|
|
19,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) LOE includes transportation and workover expenses.
|
|
(2) Adjusted EBITDAX is a non-GAAP financial measure. See below
for a reconciliation to net income (loss).
|
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
December 31,
|
|
|
|
|
2015
|
|
2014
|
|
ASSETS
|
|
|
(in thousands)
|
|
Cash and cash equivalents
|
|
|
$
|
-
|
|
$
|
-
|
|
Accounts receivable, net
|
|
|
|
21,335
|
|
|
25,309
|
|
Other current assets
|
|
|
|
8,679
|
|
|
5,731
|
|
Net property and equipment
|
|
|
|
444,775
|
|
|
748,623
|
|
Investments in affiliates and other non-current assets
|
|
|
|
62,583
|
|
|
63,752
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
|
$
|
537,372
|
|
$
|
843,415
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
|
|
47,445
|
|
|
92,892
|
|
Other current liabilities
|
|
|
|
6,417
|
|
|
4,123
|
|
Long-term debt
|
|
|
|
114,569
|
|
|
63,359
|
|
Deferred tax liability
|
|
|
|
-
|
|
|
93,952
|
|
Asset retirement obligations
|
|
|
|
20,314
|
|
|
21,623
|
|
Total shareholders’ equity
|
|
|
|
348,627
|
|
|
567,466
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY
|
|
|
$
|
537,372
|
|
$
|
843,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
|
2015
|
|
2014
|
|
|
2015
|
|
2014
|
|
|
|
|
(in thousands)
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales
|
|
|
$
|
9,500
|
|
|
$
|
37,662
|
|
|
|
$
|
35,882
|
|
|
$
|
111,102
|
|
|
Natural gas sales
|
|
|
|
16,020
|
|
|
|
21,676
|
|
|
|
|
48,130
|
|
|
|
87,547
|
|
|
Natural gas liquids sales
|
|
|
|
3,515
|
|
|
|
8,214
|
|
|
|
|
11,004
|
|
|
|
27,579
|
|
|
Total revenues
|
|
|
|
29,035
|
|
|
|
67,552
|
|
|
|
|
95,016
|
|
|
|
226,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
9,036
|
|
|
|
13,797
|
|
|
|
|
29,919
|
|
|
|
36,426
|
|
|
Exploration expenses
|
|
|
|
407
|
|
|
|
(4,713
|
)
|
|
|
|
11,814
|
|
|
|
33,071
|
|
|
Depreciation, depletion and amortization
|
|
|
|
38,386
|
|
|
|
40,550
|
|
|
|
|
112,271
|
|
|
|
114,853
|
|
|
Impairment and abandonment of oil and gas properties
|
|
|
|
235,150
|
|
|
|
6,693
|
|
|
|
|
237,667
|
|
|
|
23,259
|
|
|
General and administrative expenses
|
|
|
|
7,504
|
|
|
|
6,821
|
|
|
|
|
22,683
|
|
|
|
26,485
|
|
|
Total expenses
|
|
|
|
290,483
|
|
|
|
63,148
|
|
|
|
|
414,354
|
|
|
|
234,094
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) from investment in affiliates (net of income taxes)
|
|
|
|
(375
|
)
|
|
|
1,287
|
|
|
|
|
(562
|
)
|
|
|
4,387
|
|
|
Interest expense
|
|
|
|
(785
|
)
|
|
|
(672
|
)
|
|
|
|
(2,315
|
)
|
|
|
(2,077
|
)
|
|
Loss on derivatives, net
|
|
|
|
2,011
|
|
|
|
1,734
|
|
|
|
|
2,001
|
|
|
|
(1,488
|
)
|
|
Other income (expense)
|
|
|
|
4,288
|
|
|
|
48
|
|
|
|
|
5,278
|
|
|
|
(148
|
)
|
|
Total other income (expense)
|
|
|
|
5,139
|
|
|
|
2,397
|
|
|
|
|
4,402
|
|
|
|
674
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) BEFORE INCOME TAXES
|
|
|
|
(256,309
|
)
|
|
|
6,801
|
|
|
|
|
(314,936
|
)
|
|
|
(7,192
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit (provision)
|
|
|
|
70,624
|
|
|
|
(3,137
|
)
|
|
|
|
91,159
|
|
|
|
5,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
|
$
|
(185,685
|
)
|
|
$
|
3,664
|
|
|
|
$
|
(223,777
|
)
|
|
$
|
(1,948
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 our credit
facility with the Royal Bank of Canada and other lenders (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 loss to EBITDAX and Adjusted EBITDAX
for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
|
2015
|
|
2014
|
|
|
2015
|
|
2014
|
|
|
|
|
(in thousands)
|
|
Net income (loss)
|
|
|
$
|
(185,685
|
)
|
|
$
|
3,664
|
|
|
|
$
|
(223,777
|
)
|
|
$
|
(1,948
|
)
|
|
Interest expense
|
|
|
|
785
|
|
|
|
672
|
|
|
|
|
2,315
|
|
|
|
2,077
|
|
|
Income tax provision (benefit)
|
|
|
|
(70,624
|
)
|
|
|
3,137
|
|
|
|
|
(91,159
|
)
|
|
|
(5,244
|
)
|
|
Depreciation, depletion and amortization
|
|
|
|
38,386
|
|
|
|
40,550
|
|
|
|
|
112,271
|
|
|
|
114,853
|
|
|
Exploration expenses
|
|
|
|
407
|
|
|
|
(4,713
|
)
|
|
|
|
11,814
|
|
|
|
33,071
|
|
|
EBITDAX
|
|
|
$
|
(216,731
|
)
|
|
$
|
43,310
|
|
|
|
$
|
(188,536
|
)
|
|
$
|
142,809
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain on derivative instruments
|
|
|
$
|
(1,009
|
)
|
|
$
|
(1,963
|
)
|
|
|
$
|
(999
|
)
|
|
$
|
(1,494
|
)
|
|
Non-cash stock-based compensation charges
|
|
|
|
2,430
|
|
|
|
1,217
|
|
|
|
|
5,008
|
|
|
|
3,333
|
|
|
Impairment of oil and gas properties
|
|
|
|
235,112
|
|
|
|
6,417
|
|
|
|
|
237,656
|
|
|
|
22,010
|
|
|
Loss (gain) on sale of assets and investment in affiliates
|
|
|
|
899
|
|
|
|
(1,287
|
)
|
|
|
|
1,517
|
|
|
|
(4,191
|
)
|
|
Adjusted EBITDAX
|
|
|
$
|
20,701
|
|
|
$
|
47,694
|
|
|
|
$
|
54,646
|
|
|
$
|
162,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guidance for Fourth Quarter 2015
The Company is providing the following guidance for the fourth calendar
quarter of 2015.
|
|
|
|
|
|
|
|
Fourth quarter 2015 production
|
|
|
|
|
85,000 – 90,000 Mcfe per day
|
|
|
|
|
|
|
|
|
LOE (including transportation and workovers)
|
|
|
|
|
$7.8 million - $8.3 million
|
|
|
|
|
|
|
|
|
Production and ad valorem taxes
|
|
|
|
|
4.0%
|
|
(% of Revenue)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash G&A
|
|
|
|
|
$4.5 million - $5.0 million
|
|
|
|
|
|
|
|
|
DD&A rate
|
|
|
|
|
$2.50 - $2.75
|
|
|
|
|
|
|
|
Teleconference Call
Contango management will hold a conference call to discuss the
information described in this press release on Wednesday, November 4,
2015 at 9:30am CST. Those interested in participating in the earnings
conference call may do so by calling the following phone number:
1-800-756-4697, (International 1-913-312-0398) and entering the
following participation code: 824286. A replay of the call will be
available from Wednesday, November 4, 2015 at 12:30pm CST through
Wednesday, November 11, 2015 at 12:30pm CST by dialing toll free
1-888-203-1112, (International 1-719-457-0820) and asking for replay ID
code 824286.
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 properties
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.
View source version on businesswire.com: http://www.businesswire.com/news/home/20151103007040/en/
Copyright Business Wire 2015
