|
HOUSTON--(BUSINESS WIRE)--
Contango Oil & Gas Company (NYSE MKT: MCF) (“Contango”) announced today
its financial results for the three months ended September 30, 2014 and
provided an operational update.
Third Quarter 2014 Highlights
-
Production of 9.4 Bcfe for the quarter
-
Net income of $3.7 million and Adjusted EBITDAX of $47.7 million for
the quarter
-
Commenced initial production at South Timbalier 17, our 2013 offshore
discovery
-
Installed compression at Eugene Island Block 11 for our Dutch and Mary
Rose wells
-
Spud initial horizontal well in newly acquired 53,200 gross (23,700
net) acre position in our Elm Hill project in Fayette County, Texas
-
Acquisition of the right to earn approximately 49,000 gross (44,000
net) acres in our North Cheyenne project in Weston County, Wyoming,
targeting multiple formations, including the Muddy Sandstone formation
-
Reaffirmed our borrowing base of $275 million, through May 1, 2015
Management Commentary
Allan D. Keel, the Company’s President and Chief Executive Officer, said
“We are excited to begin drilling in our new prospective resource plays.
To date we have spud two wells in our new Elm Hill project in Fayette
County, Texas and have just spud our initial well in our new FRAMS
project in Natrona County, Wyoming targeting the Mowry Shale. We expect
to spud our initial well targeting the Muddy Sandstone formation in our
North Cheyenne project in Weston County, Wyoming in late December or
early January 2015. We are excited about the potential from these plays
as a complement to our liquids-focused resource strategy currently
focused on the Woodbine and Buda in Madison and Dimmit Counties, Texas,
respectively. Since the beginning of the quarter we have brought two
wells on-line in the Woodbine and have initiated a downspaced pad
concept at Chalktown, where an additional four wells are in various
stages of drilling or completion. In the Buda, we have brought five
wells on-line since the beginning of the quarter, while an additional
two are in various stages of drilling or completion.”
Summary Financial Results for the Quarter Ended September 30, 2014
The results for the three months ended September 30, 2014 include the
effect of the Company’s October 1, 2013 merger with Crimson Exploration
Inc. (“Crimson”), while the results for the three months ended September
30, 2013 include only the results of Contango.
Net income for the three months ended September 30, 2014 was $3.7
million, or $0.19 per basic and diluted share, compared to net income of
$19.7 million, or $1.30 per basic and diluted share, for the same period
last year. Included in the prior year figure is a $15.6 million pre-tax
gain from our investment in Alta Resources. The remaining decrease in
net income was primarily attributable to a $29.0 million pre-tax
increase in depreciation, depletion and amortization (“DD&A”), an $8.2
million increase in operating expenses and a $4.2 million increase in
general and administrative (“G&A”) costs associated with our expanded
asset base and organization subsequent to our merger with Crimson,
partially offset by a $32.8 million increase in revenues. Revenues for
the current 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. Average weighted shares outstanding were
approximately 19.1 million and 15.2 million for the current and prior
year quarters, respectively.
The Company reported Adjusted EBITDAX, as defined below, of
approximately $47.7 million for the three months ended September 30,
2014, compared to $26.6 million for the same period last year. Crimson’s
field operations contributed $33.8 million to the current quarter,
offset in part by the above mentioned impact of the shut-in at Eugene
Island 11 and higher post-merger G&A costs.
Revenues for the three months ended September 30, 2014 were
approximately $67.6 million compared to $34.7 million for the same
period last year. This increase was primarily due to the addition of
Crimson’s operations which contributed $41.9 million in additional
revenues, partially offset by the estimated $12.1 million decrease in
Contango’s revenues due to the shut-in at Eugene Island 11.
Production for the three months ended September 30, 2014 was
approximately 9.4 Bcfe, or 102.3 Mmcfed, which was within our previously
provided guidance. This 42% increase over production for the same period
last year, despite the shut in at Eugene Island 11 (estimated 17.9
Mmcfed impact for the quarter), was attributable primarily to the
addition of Crimson’s operations, new production from our 2014 drilling
program, additional interests in our Dutch wells acquired in December
2013 and new production from our 2013 discovery at South Timbalier 17
that began producing in the current year quarter. Our Dutch and Mary
Rose wells at Eugene Island were shut in completely for approximately
three weeks during the current quarter to install compression, with
reduced production rates over several days as the area was restored to
full production at 99% of pre-shut in rates. Crude oil and natural gas
liquids production during the third quarter was approximately 6,900
barrels per day, or 40% of total production, up from approximately 2,600
barrels per day, or 22% of total production for the same period last
year, an increase attributable to the addition of the Crimson properties
and the subsequent focus on the development of our oil and liquids-rich
onshore resource plays. For the fourth quarter of 2014, we estimate our
production will be 105 - 115 Mmcfed. Guidance for the fourth quarter is
less than the shut-in adjusted actual production for the third quarter
due to drilling-related interference in three wells in our Buda play and
due to the Company initiating a pad drilling strategy in the fourth
quarter in our Chalktown area, thereby resulting in no new production
during the quarter from that drilling. When drilling from pads, three
wells are drilled in succession, those wells are then completed in
succession, and then all three are put on production simultaneously to
maximize recovery. It is anticipated that initial production will occur
in January 2015.
The weighted average equivalent sales price during the three months
ended September 30, 2014 was $7.17 per Mcfe, compared to $5.24 per Mcfe
for the same period last year. The increase in the weighted average
equivalent prices resulted from a higher percentage mix of crude and
liquids production to total production, as well as from an increase in
natural gas prices, which accounted for 60% of our volumes. The impact
from the increase in liquids mix and higher gas prices was partially
offset by lower oil and condensate prices during the current quarter.
Operating expenses for the three months ended September 30, 2014 were
approximately $13.8 million, or $1.47 per Mcfe, compared to $5.6
million, or $0.84 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,
all of which increased as a result of our expanded operations and
increased production subsequent to our merger with Crimson.
Lease operating expenses (“LOE”), transportation and processing costs
and workover expenses for the three months ended September 30, 2014 were
approximately $10.6 million, or $1.13 per Mcfe, compared to
approximately $4.8 million, or $0.72 per Mcfe, for the same period last
year. Current quarter expense was slightly outside of our previously
provided guidance due to higher than expected offshore transportation
costs.
Exploration costs for the three months ended September 30, 2014 included
a $5.2 million credit related to the adjustment of estimated costs
accrued in the previous quarter for our unsuccessful Ship Shoal 255
well, including credits negotiated with certain service providers.
DD&A expenses for the three months ended September 30, 2014 were $40.6
million, or $4.31 per Mcfe, compared to $11.5 million, or $1.71 per
Mcfe, for the same period last year. This increase is primarily
attributable to the incremental production from Crimson’s properties,
and an increase in the DD&A rate resulting from higher costs associated
with onshore oil plays and the impact of purchase price accounting
related to the merger.
Impairment and abandonment expense from oil and gas properties was $6.7
million for the three months ended September 30, 2014 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 prospects.
G&A expenses for the three months ended September 30, 2014 were $6.8
million, or $0.72 per Mcfe, compared to $2.7 million, or $0.40 per Mcfe,
for the prior year quarter. G&A expenses for the quarter, exclusive of
$1.2 million in non-cash stock compensation expense were $5.6 million,
compared to $2.7 million for the same period last year, an increase due
to the post-merger combination of the staffs and facilities of both
companies. This was below our previously provided guidance due to lower
than projected legal and compensation costs. For the fourth quarter of
2014, we have provided guidance of $6.5 million to $7.5 million for
general and administrative expenses, exclusive of non-cash stock
compensation (“Cash G&A”).
Drilling Activity Update
Onshore Activity
Southeast Texas (Woodbine)
Chalktown Area, Madison County, Texas
Our drilling efforts in Madison and Grimes counties this quarter were
concentrated in the Chalktown Area and focused on the
Woodbine/Lewisville. Our quarterly results and current activity in the
Chalktown Area consist of the following. We anticipate keeping two rigs
in this area for the remainder of the year, and have commenced a pad
drilling strategy on 500 foot spacing:
Well
|
|
WI%
|
|
Total Measured Depth (ft.)
|
|
Lateral (ft.)
|
|
Frac Stages
|
|
Status/First Production
|
|
30 Day Avg IP (boed)
|
|
% Oil
|
|
Dean 1H
|
|
70%
|
|
16,194
|
|
6,737
|
|
29
|
|
July 2014
|
|
927
|
|
79%
|
*
|
Heath Unit A 1H
|
|
70%
|
|
16,358
|
|
7,050
|
|
30
|
|
Evaluating
|
|
not yet available
|
|
Vick Trust B 2H
|
|
68%
|
|
TBD
|
|
TBD
|
|
TBD
|
|
Drilled
|
|
TBD
|
|
TBD
|
|
Barr Unit A 2H
|
|
50%
|
|
TBD
|
|
TBD
|
|
TBD
|
|
Drilling - 9,300'
|
|
TBD
|
|
TBD
|
|
Vick Trust B 5H
|
|
68%
|
|
TBD
|
|
TBD
|
|
TBD
|
|
Drilling - 9,200'
|
|
TBD
|
|
TBD
|
|
* Previously reported
Iola/Grimes Area, Grimes County, Texas
We brought one well online in Grimes County during the quarter that was
spud during the second quarter. We currently expect the arrival of a
third rig (in addition to the two rigs in Chalktown) late in the fourth
quarter that will target an extended lateral in the Woodbine in Grimes
County.
Well
|
|
WI%
|
|
Total Measured Depth (ft.)
|
|
Lateral (ft.)
|
|
Frac Stages
|
|
Status/First Production
|
|
30 Day Avg IP (boed)
|
|
% Oil
|
|
Tommie Carroll 2H
|
|
46%
|
|
14,950
|
|
5,221
|
|
22
|
|
July 2014
|
|
648
|
|
81%
|
*
|
* Previously reported
South Texas (Buda), Zavala
and Dimmit Counties
Our recent and current activity in the Buda in South Texas consists of
the following:
Well
|
|
WI%
|
|
Total Measured Depth
(ft.)
|
|
Lateral (ft.)
|
|
Frac Stages
|
|
Status/First Production
|
|
30 Day Avg IP (boed)
|
|
% Oil
|
|
Beeler 19H
|
|
50%
|
|
14,290
|
|
7,096
|
|
n/a
|
|
July 2014
|
|
1,198
|
|
73%
|
*
|
Beeler C 20H
|
|
50%
|
|
16,574
|
|
9,474
|
|
n/a
|
|
July 2014
|
|
835
|
|
65%
|
*
|
Bruce Weaver 2H
|
|
12.5% (Non-Op)
|
|
13,290
|
|
6,386
|
|
n/a
|
|
July 2014
|
|
1,047
|
|
57%
|
*
|
Dunlap 4H
|
|
100%
|
|
12,570
|
|
5,518
|
|
n/a
|
|
August 2014
|
|
235
|
|
12%
|
|
Bruce Weaver 1H
|
|
12.5% (Non-Op)
|
|
10,530
|
|
3,918
|
|
n/a
|
|
August 2014
|
|
684
|
|
80%
|
|
Beeler Unit 26H
|
|
50%
|
|
TBD
|
|
TBD
|
|
TBD
|
|
Completing
|
|
TBD
|
|
TBD
|
|
Beeler Unit J 24H
|
|
50%
|
|
TBD
|
|
TBD
|
|
TBD
|
|
Drilling
|
|
TBD
|
|
TBD
|
|
* Previously reported
Since May of 2013, we have drilled or participated in 19 wells within
the Buda trend and believe that we have defined the optimum spacing and
productive sweet spot. Additional drilling into the Buda will be limited
going forward as our attention will focus on the Eagle Ford’s
prospectivity over our 9,500 net acre position in Zavala and Dimmit
Counties. We have drilled a pilot with whole core into the Eagle Ford
and expect results in Q1 2015 from that analysis. Operators continue to
drill wells with excellent productivity in the immediate area of our
leasehold.
Fayette County, Texas (Elm Hill Project)
We commenced our drilling program in this area during the quarter, and
our current activity in the Elm Hill project consists of the following:
Well
|
|
WI%
|
|
Total Measured Depth (ft.)
|
|
Lateral (ft.)
|
|
Frac Stages
|
|
Status/First Production
|
|
30 Day Avg IP (boed)
|
|
% Oil
|
Janecka 1H
|
|
50%
|
|
11,758
|
|
6,000
|
|
25
|
|
Flowing back
|
|
not yet available
|
Vinklarek 1H
|
|
50%
|
|
TBD
|
|
TBD
|
|
TBD
|
|
Drilling - 9,800'
|
|
TBD
|
|
TBD
|
We anticipate drilling a total of four wells in this area by the end of
the year, will evaluate results at that time, and then decide on a rig
and development strategy for 2015. We and our partner have approximately
53,200 gross acres (23,700, net to the Company) in the area on which we
may pursue a number of formations horizontally.
Wyoming (FRAMS Project and N. Cheyenne Project)
Last week we spud our initial well targeting the Mowry Shale in Natrona
County, Wyoming. We originally acquired in May 2014 the right to earn an
80% working interest in approximately 119,500 gross acres (93,000 net
acres) in the area on which to pursue the Mowry and other potential
formations. We expect to spud our initial well targeting the Muddy
Sandstone formation in Weston County, Wyoming in late December or early
January 2015. We originally acquired in September 2014 the right to earn
a 100% working interest in approximately 49,000 gross acres (44,000 net
acres), where the prospect generator retains an option to participate
for a 10% working interest, in the area on which to pursue the Muddy
Sandstone and other potential formations.
2014 Capital Program & Liquidity
Capital expenditures incurred for the three months ended September 30,
2014 were $25.8 million, of which $8.6 million was spent drilling in the
Woodbine formation in Madison and Grimes Counties, Texas; $9.1 million
was spent drilling the Buda formation in Dimmit County, Texas; and $7.3
million was invested in acreage positions primarily in new areas.
We currently anticipate that our total capital expenditure program for
2014 will be in the $215 - $225 million range, funded primarily from
internally generated cash flow.
As of September 30, 2014, we had approximately $54.4 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.
Selected Financial and Operating Data
The following table reflects certain comparative financial and operating
data for the three and nine month periods ended September 30, 2014 and
2013:
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2014
|
|
2013(1)
|
|
%
|
|
2014
|
|
2013(1)
|
|
%
|
Offshore Volumes Sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (Mbbls)
|
|
|
57
|
|
|
91
|
|
|
-37
|
%
|
|
|
211
|
|
|
255
|
|
|
-17
|
%
|
Natural gas (Mmcf)
|
|
|
4,039
|
|
|
5,190
|
|
|
-22
|
%
|
|
|
14,302
|
|
|
13,985
|
|
|
2
|
%
|
Natural gas liquids (Mbbls)
|
|
|
121
|
|
|
148
|
|
|
-18
|
%
|
|
|
439
|
|
|
431
|
|
|
2
|
%
|
Natural gas equivalents (Mmcfe)
|
|
|
5,104
|
|
|
6,623
|
|
|
-23
|
%
|
|
|
18,201
|
|
|
18,100
|
|
|
1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Volumes Sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (Mbbls)
|
|
|
335
|
|
|
-
|
|
|
n/a
|
|
|
|
919
|
|
|
-
|
|
|
n/a
|
|
Natural gas (Mmcf)
|
|
|
1,598
|
|
|
-
|
|
|
n/a
|
|
|
|
4,896
|
|
|
-
|
|
|
n/a
|
|
Natural gas liquids (Mbbls)
|
|
|
117
|
|
|
-
|
|
|
n/a
|
|
|
|
323
|
|
|
-
|
|
|
n/a
|
|
Natural gas equivalents (Mmcfe)
|
|
|
4,312
|
|
|
-
|
|
|
n/a
|
|
|
|
12,352
|
|
|
-
|
|
|
n/a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Volumes Sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (Mbbls)
|
|
|
392
|
|
|
91
|
|
|
331
|
%
|
|
|
1,130
|
|
|
255
|
|
|
343
|
%
|
Natural gas (Mmcf)
|
|
|
5,637
|
|
|
5,190
|
|
|
9
|
%
|
|
|
19,198
|
|
|
13,985
|
|
|
37
|
%
|
Natural gas liquids (Mbbls)
|
|
|
238
|
|
|
148
|
|
|
61
|
%
|
|
|
762
|
|
|
431
|
|
|
77
|
%
|
Natural gas equivalents (Mmcfe)
|
|
|
9,416
|
|
|
6,623
|
|
|
42
|
%
|
|
|
30,553
|
|
|
18,100
|
|
|
69
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily Sales Volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (Mbbls)
|
|
|
4.3
|
|
|
1.0
|
|
|
331
|
%
|
|
|
4.1
|
|
|
0.9
|
|
|
343
|
%
|
Natural gas (Mmcf)
|
|
|
61.3
|
|
|
56.4
|
|
|
9
|
%
|
|
|
70.3
|
|
|
51.2
|
|
|
37
|
%
|
Natural gas liquids (Mbbls)
|
|
|
2.6
|
|
|
1.6
|
|
|
61
|
%
|
|
|
2.8
|
|
|
1.6
|
|
|
77
|
%
|
Natural gas equivalents (Mmcfe)
|
|
|
102.3
|
|
|
72.0
|
|
|
42
|
%
|
|
|
111.9
|
|
|
66.3
|
|
|
69
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (per Bbl)
|
|
$
|
96.05
|
|
$
|
110.37
|
|
|
-13
|
%
|
|
$
|
98.32
|
|
$
|
109.65
|
|
|
-10
|
%
|
Natural gas (per Mcf)
|
|
$
|
3.85
|
|
$
|
3.64
|
|
|
6
|
%
|
|
$
|
4.56
|
|
$
|
3.81
|
|
|
20
|
%
|
Natural gas liquids (per Bbl)
|
|
$
|
34.55
|
|
$
|
39.01
|
|
|
-11
|
%
|
|
$
|
36.17
|
|
$
|
37.02
|
|
|
-2
|
%
|
Total (per Mcfe)
|
|
$
|
7.17
|
|
$
|
5.24
|
|
|
37
|
%
|
|
$
|
7.40
|
|
$
|
5.37
|
|
|
38
|
%
|
|
|
|
(1)
|
|
Results for the three and nine months ended September 30, 2013
include only the results of Contango, prior to the merger with
Crimson.
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2014
|
|
2013(1)
|
|
%
|
|
2014
|
|
2013(1)
|
|
%
|
Offshore Selected Costs ($ per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
LOE (including transportation and workovers)
|
|
$
|
0.83
|
|
$
|
0.72
|
|
|
15
|
%
|
|
$
|
0.57
|
|
$
|
1.31
|
|
|
-57
|
%
|
Production and ad valorem taxes
|
|
$
|
0.11
|
|
$
|
0.12
|
|
|
-12
|
%
|
|
$
|
0.10
|
|
$
|
0.13
|
|
|
-26
|
%
|
Depreciation and depletion expense
|
|
$
|
2.39
|
|
$
|
1.71
|
|
|
40
|
%
|
|
$
|
1.88
|
|
$
|
1.78
|
|
|
6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Selected Costs ($ per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
LOE (including transportation and workovers)
|
|
$
|
1.48
|
|
$
|
-
|
|
|
n/a
|
|
|
$
|
1.36
|
|
$
|
-
|
|
|
n/a
|
|
Production and ad valorem taxes
|
|
$
|
0.62
|
|
$
|
-
|
|
|
n/a
|
|
|
$
|
0.61
|
|
$
|
-
|
|
|
n/a
|
|
Depreciation and depletion expense
|
|
$
|
6.58
|
|
$
|
-
|
|
|
n/a
|
|
|
$
|
6.53
|
|
$
|
-
|
|
|
n/a
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selected Costs ($ per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
LOE (including transportation and workovers)
|
|
$
|
1.13
|
|
$
|
0.72
|
|
|
57
|
%
|
|
$
|
0.89
|
|
$
|
1.31
|
|
|
-32
|
%
|
Production and ad valorem taxes
|
|
$
|
0.34
|
|
$
|
0.12
|
|
|
181
|
%
|
|
$
|
0.30
|
|
$
|
0.13
|
|
|
129
|
%
|
Depreciation and depletion expense
|
|
$
|
4.31
|
|
$
|
1.71
|
|
|
152
|
%
|
|
$
|
3.76
|
|
$
|
1.78
|
|
|
110
|
%
|
General and administrative expense (cash)
|
|
$
|
0.60
|
|
$
|
0.40
|
|
|
49
|
%
|
|
$
|
0.76
|
|
$
|
0.64
|
|
|
18
|
%
|
Interest expense
|
|
$
|
0.07
|
|
$
|
-
|
|
|
100
|
%
|
|
$
|
0.07
|
|
$
|
-
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX (2) (thousands)
|
|
$
|
47,694
|
|
$
|
26,565
|
|
|
|
|
$
|
162,467
|
|
$
|
69,674
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares Outstanding (thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
19,077
|
|
|
15,195
|
|
|
|
|
|
19,074
|
|
|
15,195
|
|
|
|
Diluted
|
|
|
19,122
|
|
|
15,195
|
|
|
|
|
|
19,074
|
|
|
15,195
|
|
|
|
|
|
|
(1)
|
|
Results for the three and nine months ended September 30, 2013
include only the results of Contango, prior to the merger with
Crimson.
|
(2)
|
|
Adjusted EBITDAX is a non-GAAP financial measure. See below for a
reconciliation to net income (loss).
|
|
|
|
CONTANGO OIL & GAS COMPANY
|
CONDENSED CONSOLIDATED BALANCE SHEETS
|
(in thousands)
|
|
|
|
September 30,
|
|
December 31,
|
|
|
2014
|
|
2013
|
ASSETS
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
-
|
|
$
|
-
|
Accounts receivable
|
|
|
35,990
|
|
|
60,613
|
Other current assets
|
|
|
7,940
|
|
|
5,504
|
Net property and equipment
|
|
|
767,637
|
|
|
791,023
|
Investments in affiliates and other non-current assets
|
|
|
59,885
|
|
|
53,164
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
871,452
|
|
$
|
910,304
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS' EQUITY
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
|
93,133
|
|
|
96,833
|
Other current liabilities
|
|
|
4,176
|
|
|
2,446
|
Long-term debt
|
|
|
54,415
|
|
|
90,000
|
Deferred tax liability
|
|
|
103,849
|
|
|
105,956
|
Asset retirement obligations
|
|
|
21,325
|
|
|
22,019
|
Total shareholders’ equity
|
|
|
594,554
|
|
|
593,050
|
|
|
|
|
|
TOTAL LIABILITIES & SHAREHOLDERS’ EQUITY
|
|
$
|
871,452
|
|
$
|
910,304
|
|
CONTANGO OIL & GAS COMPANY
|
CONSOLIDATED STATEMENTS OF OPERATIONS
|
(in thousands)
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
|
2014
|
|
|
|
2013
|
|
|
|
2014
|
|
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
REVENUES
|
|
|
|
|
|
|
|
|
Oil and condensate sales
|
|
$
|
37,662
|
|
|
$
|
10,044
|
|
|
$
|
111,102
|
|
|
$
|
27,961
|
|
Natural gas sales
|
|
|
21,676
|
|
|
|
18,914
|
|
|
|
87,547
|
|
|
|
53,308
|
|
Natural gas liquids sales
|
|
|
8,214
|
|
|
|
5,764
|
|
|
|
27,579
|
|
|
|
15,948
|
|
Total revenues
|
|
|
67,552
|
|
|
|
34,722
|
|
|
|
226,228
|
|
|
|
97,217
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
13,797
|
|
|
|
5,553
|
|
|
|
36,426
|
|
|
|
26,025
|
|
Exploration expenses
|
|
|
(4,713
|
)
|
|
|
89
|
|
|
|
33,071
|
|
|
|
223
|
|
Depreciation, depletion and amortization
|
|
|
40,550
|
|
|
|
11,518
|
|
|
|
114,853
|
|
|
|
32,242
|
|
Impairment and abandonment of oil and gas properties
|
|
|
6,693
|
|
|
|
-
|
|
|
|
23,259
|
|
|
|
767
|
|
General and administrative expenses
|
|
|
6,821
|
|
|
|
2,657
|
|
|
|
26,485
|
|
|
|
11,622
|
|
Total expenses
|
|
|
63,148
|
|
|
|
19,817
|
|
|
|
234,094
|
|
|
|
70,879
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
Gain from investment in affiliates (net of income taxes)
|
|
|
1,287
|
|
|
|
669
|
|
|
|
4,387
|
|
|
|
1,402
|
|
Interest expense
|
|
|
(672
|
)
|
|
|
(13
|
)
|
|
|
(2,077
|
)
|
|
|
(38
|
)
|
Gain (loss) on derivatives, net
|
|
|
1,734
|
|
|
|
-
|
|
|
|
(1,488
|
)
|
|
|
-
|
|
Other income (loss)
|
|
|
48
|
|
|
|
15,698
|
|
|
|
(148
|
)
|
|
|
25,573
|
|
Total other income (expense)
|
|
|
2,397
|
|
|
|
16,354
|
|
|
|
674
|
|
|
|
26,937
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) BEFORE INCOME TAXES
|
|
|
6,801
|
|
|
|
31,259
|
|
|
|
(7,192
|
)
|
|
|
53,275
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit (provision)
|
|
|
(3,137
|
)
|
|
|
(11,519
|
)
|
|
|
5,244
|
|
|
|
(18,310
|
)
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$
|
3,664
|
|
|
$
|
19,740
|
|
|
$
|
(1,948
|
)
|
|
$
|
34,965
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
|
2014
|
|
|
|
2013
|
|
|
|
2014
|
|
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
3,664
|
|
|
$
|
19,740
|
|
|
$
|
(1,948
|
)
|
|
$
|
34,965
|
|
Interest expense
|
|
|
672
|
|
|
|
13
|
|
|
|
2,077
|
|
|
|
38
|
|
Income tax provision (benefit)
|
|
|
3,137
|
|
|
|
11,519
|
|
|
|
(5,244
|
)
|
|
|
18,310
|
|
Depreciation, depletion and amortization
|
|
|
40,550
|
|
|
|
11,518
|
|
|
|
114,853
|
|
|
|
32,242
|
|
Exploration expenses
|
|
|
(4,713
|
)
|
|
|
89
|
|
|
|
33,071
|
|
|
|
223
|
|
EBITDAX
|
|
$
|
43,310
|
|
|
$
|
42,879
|
|
|
$
|
142,809
|
|
|
$
|
85,778
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain on derivative instruments
|
|
$
|
(1,963
|
)
|
|
$
|
-
|
|
|
$
|
(1,494
|
)
|
|
$
|
-
|
|
Non-cash equity-based compensation charges
|
|
|
1,217
|
|
|
|
-
|
|
|
|
3,333
|
|
|
|
-
|
|
Impairment of oil and gas properties
|
|
|
6,417
|
|
|
|
-
|
|
|
|
22,010
|
|
|
|
767
|
|
Loss (gain) on sale of assets and investment in affiliates
|
|
|
(1,287
|
)
|
|
|
(16,314
|
)
|
|
|
(4,191
|
)
|
|
|
(16,871
|
)
|
Adjusted EBITDAX
|
|
$
|
47,694
|
|
|
$
|
26,565
|
|
|
$
|
162,467
|
|
|
$
|
69,674
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guidance for Fourth Quarter 2014
The Company is providing the following guidance for the fourth calendar
quarter of 2014.
|
|
|
Fourth quarter 2014 production
|
|
|
105,000 – 115,000 Mcfe per day
|
|
|
|
|
|
|
|
|
|
|
LOE (including transportation and workovers)
|
|
|
$9.5 million - $10.0 million
|
|
|
|
|
|
|
|
|
|
|
Production and ad valorem taxes
|
|
|
4.7%
|
|
|
|
(% of Revenue)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash G&A
|
|
|
$6.5 million - $7.5 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, November 11,
2014 at 8:00am CST. Those interested in participating in the earnings
conference call may do so by calling the following phone number:
1-888-337-8192, (International 1-719-325-2332) and entering the
following participation code: 6281005. A replay of the call will be
available from Tuesday, November 11, 2014 at 11:00am CST through
Tuesday, November 18, 2014 at 11:00am CST by dialing toll free
1-888-203-1112, (International 1-719-457-0820) and asking for replay ID
code 6281005.
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 State. 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.
|
|