Contango Oil & Gas Company (NYSE American: MCF) (“Contango” or
the “Company”) announced today that it is re-issuing its
previous release that was made on March 18, 2019 to include certain
disclosures that are required under the NYSE American Company
Guide. Other than this additional disclosure, the
content of this release is the same as the content of the release
issued on March 18, 2019.
Fourth Quarter 2018
Highlights
- Production of 3.7 Bcfe for the
quarter (39.8 Mmcfed, 42% liquids); within previously provided
guidance, despite late December weather related shut-ins
- Net loss of $33.8 million and
Adjusted EBITDAX of $7.5 million for the quarter
- Debt of $60 million at December 31,
2018, compared to $85.4 million at December 31, 2017
- $33.0 million in proceeds from
successful equity offering in November
- Acquisition of an additional 4,200
gross operated acres (1,700 net) and 4,000 gross non-operated acres
(200 net) in Pecos County, Texas adjacent to our current Southern
Delaware Basin position
- Over $6 million in cash proceeds
from non-core asset sales
Management Commentary
Wilkie S. Colyer, the Company’s President and
Chief Executive Officer, said, “We’ve been busy this quarter
executing on several strategic initiatives that we believe will
position the Company to deliver long term shareholder value,
beginning with the non-core asset sales and equity offering which
allowed us to be opportunistic in our purchase of high-quality,
bolt-on acreage in the Southern Delaware Basin that we call NE
Bullseye. We will be prudent in the use of our capital in
2019, spending only what we need to spend to preserve our asset
portfolio, which will largely be focused in NE Bullseye. With the
help of our financial advisors, we continue to evaluate strategic
alternatives available to the Company with the singular focus of
maximizing value for shareholders. In addition, we’ve continued to
focus on cost reduction by streamlining our organization and
reducing related administrative costs, resulting in a projected
$7.2 million, or 37%, decrease in cash G&A in 2019, increasing
well north of 40% on a run rate basis starting in Q2.”
Summary Fourth Quarter Financial
Results
Net loss for the three months ended December 31,
2018 was $33.8 million, or $(1.16) per basic and diluted share,
compared to a net loss of $5.6 million, or $(0.23) per basic and
diluted share, for the same period last year. This year’s quarter
was negatively impacted by impairment charges of $27.0 million
related to non-core asset sales and to price related reserve
revisions. Impairment charges for the same period last year
were $0.4 million. Average weighted shares outstanding were
approximately 29.0 million and 24.8 million for the current and
prior year quarters, respectively.
The Company reported Adjusted EBITDAX, as
defined below, of approximately $7.5 million for the three months
ended December 31, 2018, compared to $10.2 million for the same
period last year, a decrease attributable to a $1.3 million
decrease in revenues from lower production and a $1.1 million
realized loss from derivatives, compared to a $0.3 million gain for
the same period last year.
Revenues for the three months ended December 31,
2018 were approximately $18.7 million compared to $20.0 million for
the same period last year, a decrease attributable to lower
production during the current quarter and a 4% and 10% decrease in
crude oil and natural gas liquids prices, respectively, partially
offset by a 35% increase in natural gas prices.
Production for the fourth quarter of 2018 was
approximately 3.7 Bcfe, or 39.8 Mmcfe per day, compared to 51.8
Mmcfe per day for the fourth quarter of 2017, but within our
previously provided guidance. This decrease in production can be
attributed to our Vermilion 170 well ceasing production for the
entire month of November because of third-party pipeline issues,
cold weather shut-ins in some of our West Texas properties during
the month of December, a reduction in our drilling program in the
Southern Delaware Basin beginning in late 2018 in response to
declining oil prices and high Mid-Cushing oil differentials in West
Texas, and the divestiture of some non-core conventional
properties. Crude oil and natural gas liquids production
during the fourth quarter of 2018 was approximately 2,800 barrels
per day, or 42% of total production, compared to approximately
2,700 barrels per day, or 32% of total production, in the fourth
quarter of 2017, an increase attributable to bringing on new
production from our oil-based Southern Delaware Basin program and
normal decline in our natural gas-based offshore Gulf of Mexico
assets. Our first quarter 2019 production guidance is 34 – 39
Mmcfed.
The weighted average equivalent sales price
during the three months ended December 31, 2018 was $5.10 per Mcfe,
compared to $4.20 per Mcfe for the same period last year. As
previously noted, stronger natural gas prices were responsible for
the increase in the weighted average equivalent price.
Operating expenses for the three months ended
December 31, 2018 were approximately $5.8 million, or $1.57 per
Mcfe, compared to $7.0 million, or $1.47 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. Operating expenses
exclusive of production and ad valorem taxes for the three months
ended December 31, 2018 were approximately $5.1 million, or $1.39
per Mcfe, compared to approximately $6.4 million, or $1.34 per
Mcfe, for the same period last year, and below our previously
provided guidance for the quarter. This decrease is attributable to
routing substantially all of our offshore gas production through a
lower cost pipeline and the routing of substantially all of our
offshore condensate through a new pipeline we constructed in early
2018.
DD&A expense for the three months ended
December 31, 2018 was $8.8 million, or $2.41 per Mcfe, compared to
$11.5 million, or $2.42 per Mcfe, for the same period last year, a
decrease primarily attributable to lower production during the
quarter.
Impairment and abandonment expense from oil and
gas properties was $27.1 million for the three months ended
December 31, 2018. Of this amount, $12.1 million related to
the impairment of certain non-core conventional properties in South
Texas that were reduced to their fair value as a result of planned
sales during the current quarter, and $14.9 million was
attributable to price related reserve revisions primarily on our
Wyoming and certain South Texas assets. For the same period
last year, impairment and abandonment expense from oil and gas
properties was $0.9 million.
General and administrative (“G&A”) expenses
for the three months ended December 31, 2018 were $5.4 million, or
$1.46 per Mcfe, compared to $5.5 million, or $1.16 per Mcfe, for
the prior year quarter. G&A expenses for the current
quarter includes $1.0 million in non-cash stock compensation
expense and $0.2 million in non-cash bad-debt expense, while the
prior year quarter includes $1.5 million in non-cash stock
compensation expense. For the first quarter of 2019, we have
provided guidance of $4.0 million to $4.5 million for general and
administrative expenses, exclusive of non-cash stock compensation
(“Cash G&A”).
Loss from affiliates for the three months ended
December 31, 2018 was approximately $12.7 million which was
primarily related to impairment expenses, compared to a gain from
affiliates of $0.2 million for the same period last year, both
associated with our 37% equity interest in Exaro Energy
III.
2019 Capital Program
Capital costs incurred for the three months
ended December 31, 2018 were approximately $8.9 million, which was
primarily related to the acquisition our new NE Bullseye acreage in
the Southern Delaware Basin in Pecos County, Texas.
We currently forecast to spend approximately
$30.3 million on our 2019 capital expenditure program. Of
this amount, approximately $28.4 million has been allocated to the
Southern Delaware Basin. Our current plans call for us to drill
four gross wells and complete five in this area at a net cost to us
of $21.6 million. We have contracted a rig and plan to spud our
first well in NE Bullseye in late March 2019 and follow with two
additional NE Bullseye wells and our 14th well in Bullseye. All
wells are expected to be approximately 10,000’ laterals in the
Wolfcamp section. The fifth completion in 2019 is the Ripper State
2H, a Wolfcamp B well drilled in late 2018 with completion deferred
until it could be done in sequence with the 2019 wells. All
completions are expected to be designed similar to our previous
completions and other completions by operators in the area. In
addition, we have forecasted to spend $1.3 million in additional
lease hold costs and extensions on this acreage and $5.5 million in
infrastructure costs, primarily gathering facilities in NE
Bullseye.
In addition to our Southern Delaware Basin
activity in 2019, we have allocated an additional $1.9 million of
our 2019 capital budget to participate in two non-operated wells
targeting the Georgetown formation in our Booth-Tortuga area in
Zavala and Dimmit Counties of south Texas. We participated
for an approximate 20% working interest in two very successful
Georgetown horizontal wells in this area in 2017 and 2018. We
expect our 2019 capital expenditure program to be funded by
internally generated cash flow and temporary borrowings under our
revolving credit facility. We will continue to monitor commodity
prices, drilling results and service/supply costs during the year,
and if deemed appropriate, may make adjustments to our drilling
strategy as the year progresses.
Liquidity
Our debt at December 31, 2018 was approximately
$60.0 million, all of which is currently reflected as short-term
due to the fact that it matures in less than twelve months from the
December 31 balance sheet date. We are currently working
towards extending or replacing our revolving credit facility and
anticipate having that done prior to the October 1, 2019 facility
maturity date. Our credit facility currently provides for a
borrowing base of $90 million through May 1, 2019, and we are in
compliance with our bank facility covenants as of December 31,
2018. We will continue to investigate ways of prudently
increasing the availability of drilling capital during
2019.
2018 Year End Reserves
As of December 31, 2018, the Standardized
Measure of Discounted Future Net Cash Flows (“Standardized
Measure”) value of our proved reserves was approximately $218.9
million and the SEC PV-10 value of our proved reserves was
approximately $220.5 million, compared to the Standardized Measure
value of $255.9 million and SEC PV-10 value of $257.3 million as of
December 31, 2017, a decrease attributable to production,
performance revisions, divestitures and expired proved undeveloped
reserves (“PUD”) as a result of the failure to drill those PUDs
within five years of the initial booking as proved, as required by
the SEC’s five-year rule. This decrease was offset, in part,
by the value of reserves added through our Southern Delaware Basin
drilling program and price-related revisions attributable to the
increase in commodity prices. The SEC-mandated prices used in
determining our December 31, 2018 proved reserves and PV-10 value
were $62.90/Bbl for oil and condensate, $3.02/Mmbtu for natural gas
and $27.89/Bbl for natural gas liquids, compared with SEC prices of
$47.41/Bbl for oil and condensate, $2.92/Mmbtu for natural gas and
$18.59/Bbl for natural gas liquids used in estimating proved
reserves as of December 31, 2017.
As of December 31, 2018, our independent
third-party engineering firms estimated our proved oil and natural
gas reserves to be approximately 131.9 Bcfe compared with 189.3
Bcfe of proved reserves as of December 31, 2017, a decline
attributable to 16 Bcfe of production during the year, 25.2 Bcfe of
divestitures and 51.7 Bcfe of negative revisions, the majority of
which were related to a revision to our West Texas type curve
resulting from analysis of longer term decline experience and our
previously disclosed Eugene Island field as a result of new bottom
hole pressure data gathered during the planned installation of
compression. Partially offsetting those decreases were 35.5 Bcfe of
additions from our Southern Delaware Basin drilling program, our
Georgetown drilling program participation, and price-related
revisions resulting from the impact of higher commodity prices on
the volume and value of our proved reserves. The impact of our
oil-weighted drilling program in the Southern Delaware is also
reflected in the more balanced commodity profile of our reserve
base at year-end 2018. At the end of 2018, the composition of
our proved reserves, volumetrically, was 41% natural gas, 43% oil
and condensate and 16% natural gas liquids, compared to 48% natural
gas, 34% oil and condensate and 18% natural gas liquids at December
31, 2017. These estimates were prepared in accordance with reserve
reporting guidelines mandated by the Securities and Exchange
Commission (“SEC”).
Our proved developed reserves for the year ended
December 31, 2018 were estimated at 79.2 Bcfe, compared to 123.9
Bcfe in the prior year. The decline in proved developed reserves
can be attributed to approximately 16 Bcfe of production during the
year, 17.7 Bcfe in property sales and 26.7 Bcfe in negative
revisions, the majority of which were related to our Eugene Island
field as described above. Partially offsetting those declines were
9.0 Bcfe in extensions and new discoveries, 3.9 Bcfe of reserves
that were converted from proved undeveloped reserves and 2.8 Bcfe
in positive price revisions due to the increase in commodity
prices.
Our proved undeveloped reserves (“PUD”) for the
year ended December 31, 2018 were 52.7 Bcfe, compared to 65.4 Bcfe
at December 31, 2017. The decrease in PUD reserves can be
attributed to 7.6 Bcfe related to property sales, 3.9 Bcfe of PUDs
converted to proved developed reserves, the reclassification of 5.6
Bcfe to unproved reserves as a result of the failure to drill those
PUDs within five years of the initial booking as proved, as
required by the SEC’s five-year rule and 19.3 Bcfe in negative
revisions, the majority of which were associated with a revision to
our West Texas type curve as discussed above. These decreases were
offset, in part, by 22.5 Bcfe in extensions and new discoveries and
1.2 Bcfe price-related revisions resulting from the increase in
commodity prices.
The above estimates do not include net proved
reserves of approximately 26.6 Bcfe and 30.7 Bcfe attributable to
our 37% equity ownership interest in Exaro Energy III LLC (“Exaro”)
as of December 31, 2018 and 2017, respectively. The PV-10 value of
the proved reserves attributable to our 37% interest in Exaro was
approximately $21.0 million and $24.4 million at December 31, 2018
and 2017, respectively.
The following table summarizes Contango’s total proved reserves
as of December 31, 2018 (1):
|
|
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|
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|
|
|
|
|
|
|
|
|
Present Value |
|
|
OIL |
|
NGL |
|
Gas |
|
Total |
|
Discounted |
Category |
|
(MBbl) |
|
(MBbl) |
|
(Mmcf) |
|
(Mmcfe) |
|
at 10% ($000) |
Developed |
|
3,103 |
|
2,297 |
|
46,840 |
|
79,234 |
|
176,298 |
Undeveloped |
|
6,331 |
|
1,220 |
|
7,366 |
|
52,677 |
|
44,209 |
Total Proved |
|
9,434 |
|
3,517 |
|
54,206 |
|
131,911 |
|
220,507 |
- These estimates do not include net reserves of approximately
26.6 Bcfe (PV-10 of approximately $21.0 million attributable to our
37% equity ownership investment in Exaro as of December 31,
2018).
Derivative Instruments
As of December 31, 2018, we have the following
financial derivative contracts in place with members of our bank
group. These contracts represent approximately 72% of our
currently forecasted 2019 proved developed reserves (“PDP”) natural
gas production and 68% of our currently forecasted 2019 PDP crude
oil production.
|
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|
|
|
|
Commodity |
|
Period |
|
Derivative |
|
Volume/Month |
|
|
Price/Unit |
Natural Gas |
|
Jan
2019 - March 2019 |
|
Swap |
|
600,000 MMBtus |
|
$ |
3.21
(1) |
Natural Gas |
|
April
2019 - July 2019 |
|
Swap |
|
600,000 MMBtus |
|
$ |
2.75
(1) |
Natural Gas |
|
Aug
2019 - Oct 2019 |
|
Swap |
|
100,000 MMBtus |
|
$ |
2.75
(1) |
Natural Gas |
|
Nov
2019 - Dec 2019 |
|
Swap |
|
500,000 MMBtus |
|
$ |
2.75
(1) |
|
|
|
|
|
|
|
|
|
|
Oil |
|
Jan
2019 - Dec 2019 |
|
Collar |
|
7,000
Bbls |
|
$ |
50.00
- 58.00 (2) |
Oil |
|
Jan
2019 - Dec 2019 |
|
Collar |
|
4,000
Bbls |
|
$ |
52.00
- 59.45 (3) |
Oil |
|
Jan
2019 - June 2019 |
|
Collar |
|
12,000
Bbls |
|
$ |
70.00
- 76.25 (3) |
|
|
|
|
|
|
|
|
|
|
Oil |
|
Jan
2019 - July 2019 |
|
Swap |
|
6,000
Bbls |
|
$ |
66.10
(3) |
|
|
|
|
|
|
|
|
|
|
Oil |
|
July
2019 |
|
Swap |
|
12,000
Bbls |
|
$ |
72.10
(3) |
Oil |
|
Aug
2019 - Oct 2019 |
|
Swap |
|
9,000
Bbls |
|
$ |
72.10
(3) |
Oil |
|
Nov
2019 - Dec 2019 |
|
Swap |
|
12,000
Bbls |
|
$ |
72.10
(3) |
- Based on Henry Hub NYMEX natural gas prices.
- Based on Argus Louisiana Light Sweet crude oil prices.
- Based on West Texas Intermediate crude oil prices.
Selected Financial and Operating DataThe
following table reflects certain comparative financial and
operating data for the three and twelve months ended December 31,
2018 and 2017:
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|
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Three Months Ended |
|
Year ended |
|
|
December 31, |
|
December 31, |
|
|
2018 |
|
2017 |
|
% |
|
2018 |
|
2017 |
|
% |
Offshore Volumes
Sold: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate
(Mbbls) |
|
|
17 |
|
|
21 |
|
-19 |
% |
|
|
73 |
|
|
99 |
|
-26 |
% |
Natural
gas (Mmcf) |
|
|
1,769 |
|
|
2,571 |
|
-31 |
% |
|
|
7,704 |
|
|
11,189 |
|
-31 |
% |
Natural
gas liquids (Mbbls) |
|
|
76 |
|
|
76 |
|
0 |
% |
|
|
287 |
|
|
330 |
|
-13 |
% |
Natural
gas equivalents (Mmcfe) |
|
|
2,327 |
|
|
3,154 |
|
-26 |
% |
|
|
9,865 |
|
|
13,762 |
|
-28 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Volumes
Sold: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
condensate (Mbbls) |
|
|
123 |
|
|
109 |
|
13 |
% |
|
|
496 |
|
|
419 |
|
18 |
% |
Natural
gas (Mmcf) |
|
|
358 |
|
|
689 |
|
-48 |
% |
|
|
2,075 |
|
|
2,721 |
|
-24 |
% |
Natural
gas liquids (Mbbls) |
|
|
41 |
|
|
44 |
|
-7 |
% |
|
|
187 |
|
|
187 |
|
0 |
% |
Natural
gas equivalents (Mmcfe) |
|
|
1,339 |
|
|
1,610 |
|
-17 |
% |
|
|
6,174 |
|
|
6,361 |
|
-3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Volumes
Sold: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
condensate (Mbbls) |
|
|
140 |
|
|
130 |
|
8 |
% |
|
|
569 |
|
|
518 |
|
10 |
% |
Natural
gas (Mmcf) |
|
|
2,127 |
|
|
3,260 |
|
-35 |
% |
|
|
9,779 |
|
|
13,910 |
|
-30 |
% |
Natural
gas liquids (Mbbls) |
|
|
117 |
|
|
120 |
|
-3 |
% |
|
|
474 |
|
|
517 |
|
-8 |
% |
Natural
gas equivalents (Mmcfe) |
|
|
3,666 |
|
|
4,764 |
|
-23 |
% |
|
|
16,039 |
|
|
20,123 |
|
-20 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily Sales
Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
condensate (Mbbls) |
|
|
1.5 |
|
|
1.4 |
|
8 |
% |
|
|
1.6 |
|
|
1.4 |
|
10 |
% |
Natural
gas (Mmcf) |
|
|
23.1 |
|
|
35.4 |
|
-35 |
% |
|
|
26.8 |
|
|
38.1 |
|
-30 |
% |
Natural
gas liquids (Mbbls) |
|
|
1.3 |
|
|
1.3 |
|
-3 |
% |
|
|
1.3 |
|
|
1.4 |
|
-8 |
% |
Natural
gas equivalents (Mmcfe) |
|
|
39.8 |
|
|
51.8 |
|
-23 |
% |
|
|
43.9 |
|
|
55.1 |
|
-20 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales
prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
condensate (per Bbl) |
|
$ |
53.25 |
|
$ |
55.30 |
|
-4 |
% |
|
$ |
60.43 |
|
$ |
48.90 |
|
24 |
% |
Natural
gas (per Mcf) |
|
$ |
3.87 |
|
$ |
2.87 |
|
35 |
% |
|
$ |
3.05 |
|
$ |
2.97 |
|
3 |
% |
Natural
gas liquids (per Bbl) |
|
$ |
25.78 |
|
$ |
28.59 |
|
-10 |
% |
|
$ |
27.04 |
|
$ |
22.97 |
|
18 |
% |
Total
(per Mcfe) |
|
$ |
5.10 |
|
$ |
4.20 |
|
21 |
% |
|
$ |
4.80 |
|
$ |
3.90 |
|
23 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Year Ended |
|
|
December 31, |
|
December 31, |
|
|
2018 |
|
2017 |
|
% |
|
2018 |
|
2017 |
|
% |
Offshore Selected Costs
($ per Mcfe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
(1) |
|
$ |
0.80 |
|
$ |
0.61 |
|
31 |
% |
|
$ |
0.84 |
|
$ |
0.72 |
|
17 |
% |
Production and ad valorem taxes |
|
$ |
0.06 |
|
$ |
0.06 |
|
0 |
% |
|
$ |
0.07 |
|
$ |
0.06 |
|
17 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Selected Costs
($ per Mcfe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expenses (1) |
|
$ |
2.43 |
|
$ |
2.78 |
|
-13 |
% |
|
$ |
2.30 |
|
$ |
2.32 |
|
-1 |
% |
Production and ad valorem taxes |
|
$ |
0.39 |
|
$ |
0.25 |
|
56 |
% |
|
$ |
0.39 |
|
$ |
0.28 |
|
39 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selected Costs
($ per Mcfe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expenses (1) |
|
$ |
1.39 |
|
$ |
1.34 |
|
4 |
% |
|
$ |
1.40 |
|
$ |
1.22 |
|
15 |
% |
Production and ad valorem taxes |
|
$ |
0.18 |
|
$ |
0.12 |
|
50 |
% |
|
$ |
0.19 |
|
$ |
0.13 |
|
46 |
% |
General
and administrative expense (cash) |
|
$ |
1.19 |
|
$ |
0.83 |
|
43 |
% |
|
$ |
1.21 |
|
$ |
0.90 |
|
34 |
% |
Interest
expense |
|
$ |
0.40 |
|
$ |
0.27 |
|
48 |
% |
|
$ |
0.35 |
|
$ |
0.20 |
|
75 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX (2)
(thousands) |
|
$ |
7,450 |
|
$ |
10,213 |
|
|
|
$ |
29,400 |
|
$ |
35,087 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares
Outstanding (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
29,018 |
|
|
24,757 |
|
|
|
|
25,945 |
|
|
24,686 |
|
|
Diluted |
|
|
29,018 |
|
|
24,757 |
|
|
|
|
25,945 |
|
|
24,686 |
|
|
__________________________
- LOE includes transportation and workover expenses.
- Adjusted EBITDAX is a non-GAAP financial measure. See below for
reconciliation to net income.
|
CONTANGO OIL & GAS COMPANYCONDENSED CONSOLIDATED
BALANCE SHEETS(in thousands) |
|
|
|
|
|
|
|
|
|
December 31, |
|
December 31, |
|
|
2018 |
|
2017 |
|
|
|
|
|
ASSETS |
|
(unaudited) |
Cash
and cash equivalents |
|
$ |
— |
|
$ |
— |
Accounts receivable, net |
|
|
11,531 |
|
|
13,059 |
Other
current assets |
|
|
5,903 |
|
|
2,714 |
Net
property and equipment |
|
|
233,174 |
|
|
345,957 |
Investment in affiliates and other non-current assets |
|
|
6,524 |
|
|
19,723 |
|
|
|
|
|
|
|
TOTAL ASSETS |
|
$ |
257,132 |
|
$ |
381,453 |
|
|
|
|
|
|
|
LIABILITIES AND
SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
Accounts payable and
accrued liabilities |
|
|
39,506 |
|
|
46,755 |
Current portion of
long-term debt |
|
|
60,000 |
|
|
— |
Other
current liabilities |
|
|
1,751 |
|
|
3,782 |
Long-term debt |
|
|
— |
|
|
85,380 |
Asset
retirement obligations |
|
|
12,168 |
|
|
20,388 |
Other
non-current liabilities |
|
|
3,318 |
|
|
548 |
Total
shareholders’ equity |
|
|
140,389 |
|
|
224,600 |
|
|
|
|
|
|
|
TOTAL LIABILITIES &
SHAREHOLDERS’ EQUITY |
|
$ |
257,132 |
|
$ |
381,453 |
|
|
|
|
|
|
|
|
CONTANGO OIL & GAS COMPANYCONSOLIDATED STATEMENTS
OF OPERATIONS(in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Year Ended |
|
|
December 31, |
|
December 31, |
|
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited) |
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate
sales |
|
$ |
7,437 |
|
|
$ |
7,213 |
|
|
$ |
34,413 |
|
|
$ |
25,347 |
|
Natural
gas sales |
|
|
8,239 |
|
|
|
9,361 |
|
|
|
29,824 |
|
|
|
41,317 |
|
Natural
gas liquids sales |
|
|
3,018 |
|
|
|
3,441 |
|
|
|
12,850 |
|
|
|
11,881 |
|
Total
revenues |
|
|
18,694 |
|
|
|
20,015 |
|
|
|
77,087 |
|
|
|
78,545 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
Operating
expenses |
|
|
5,765 |
|
|
|
6,980 |
|
|
|
25,552 |
|
|
|
27,183 |
|
Exploration expenses |
|
|
349 |
|
|
|
416 |
|
|
|
1,637 |
|
|
|
1,106 |
|
Depreciation, depletion and amortization |
|
|
8,821 |
|
|
|
11,537 |
|
|
|
41,657 |
|
|
|
47,215 |
|
Impairment and abandonment of oil and gas properties |
|
|
27,104 |
|
|
|
880 |
|
|
|
103,732 |
|
|
|
2,395 |
|
General
and administrative expenses |
|
|
5,353 |
|
|
|
5,513 |
|
|
|
24,157 |
|
|
|
24,161 |
|
Total
expenses |
|
|
47,392 |
|
|
|
25,326 |
|
|
|
196,735 |
|
|
|
102,060 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME
(EXPENSE) |
|
|
|
|
|
|
|
|
|
|
|
|
Gain
(loss) from investment in affiliates, net of income taxes |
|
|
(12,683 |
) |
|
|
222 |
|
|
|
(12,721 |
) |
|
|
2,697 |
|
Gain
(loss) from sale of assets |
|
|
1,909 |
|
|
|
(56 |
) |
|
|
13,224 |
|
|
|
2,280 |
|
Interest
expense |
|
|
(1,466 |
) |
|
|
(1,278 |
) |
|
|
(5,548 |
) |
|
|
(4,100 |
) |
Gain
(loss) on derivatives, net |
|
|
6,900 |
|
|
|
(1,249 |
) |
|
|
1,939 |
|
|
|
3,325 |
|
Other
income |
|
|
67 |
|
|
|
1,302 |
|
|
|
1,306 |
|
|
|
1,275 |
|
Total
other income (expense) |
|
|
(5,273 |
) |
|
|
(1,059 |
) |
|
|
(1,800 |
) |
|
|
5,477 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS BEFORE INCOME
TAXES |
|
|
(33,971 |
) |
|
|
(6,370 |
) |
|
|
(121,448 |
) |
|
|
(18,038 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit
(provision) |
|
|
168 |
|
|
|
792 |
|
|
|
(120 |
) |
|
|
395 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS |
|
$ |
(33,803 |
) |
|
$ |
(5,578 |
) |
|
$ |
(121,568 |
) |
|
$ |
(17,643 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP Financial Measures
This news release includes certain non-GAAP
financial information as defined by Securities and Exchange
Commission rules. Pursuant to SEC requirements, reconciliations of
non-GAAP financial measures to the most directly comparable
financial measures calculated and presented in accordance with
generally accepted accounting principles (GAAP) are included in
this press release.
Adjusted EBITDAX represents net income (loss)
before interest expense, taxes, depreciation, depletion and
amortization, and oil and gas exploration expenses (“EBITDAX”) as
further adjusted to reflect the items set forth in the table below
and is a measure required to be used in determining our compliance
with financial covenants under our credit facility.
We have included 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
agreement. We believe Adjusted EBITDAX is an important
supplemental measure of operating performance because it eliminates
items that have less bearing on our operating performance and
therefore 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 Adjusted EBITDAX in the
evaluation of companies, many of which present Adjusted EBITDAX
when reporting their results. Adjusted EBITDAX is a material
component of the covenants that are imposed on us by our credit
agreement. We are subject to financial covenant ratios that
are calculated by reference to Adjusted EBITDAX.
Non-compliance with the financial covenants contained in our credit
agreement 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 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.
The following table reconciles net income to
EBITDAX and Adjusted EBITDAX for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Year Ended |
|
|
December 31, |
|
December 31, |
|
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
Net loss |
|
$ |
(33,803 |
) |
|
$ |
(5,578 |
) |
|
$ |
(121,568 |
) |
|
$ |
(17,643 |
) |
Interest
expense |
|
|
1,466 |
|
|
|
1,278 |
|
|
|
5,548 |
|
|
|
4,100 |
|
Income
tax provision (benefit) |
|
|
(168 |
) |
|
|
(792 |
) |
|
|
120 |
|
|
|
(395 |
) |
Depreciation, depletion and amortization |
|
|
8,821 |
|
|
|
11,537 |
|
|
|
41,657 |
|
|
|
47,215 |
|
Exploration expense |
|
|
349 |
|
|
|
416 |
|
|
|
1,637 |
|
|
|
1,106 |
|
EBITDAX |
|
$ |
(23,335 |
) |
|
$ |
6,861 |
|
|
$ |
(72,606 |
) |
|
$ |
34,383 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss (gain) on derivative instruments |
|
$ |
(7,972 |
) |
|
$ |
1,593 |
|
|
$ |
(5,421 |
) |
|
$ |
(2,204 |
) |
Non-cash
stock-based compensation charges |
|
|
994 |
|
|
|
1,540 |
|
|
|
4,766 |
|
|
|
6,100 |
|
Impairment of oil and gas properties |
|
|
26,989 |
|
|
|
385 |
|
|
|
103,164 |
|
|
|
1,785 |
|
Loss
(gain) on sale of assets and investment in affiliates |
|
|
10,774 |
|
|
|
(166 |
) |
|
|
(503 |
) |
|
|
(4,977 |
) |
Adjusted
EBITDAX |
|
$ |
7,450 |
|
|
$ |
10,213 |
|
|
$ |
29,400 |
|
|
$ |
35,087 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10 at year-end is a non-GAAP financial
measure and represents the present value, discounted at 10% per
year, of estimated future cash inflows from proved natural gas and
crude oil reserves, less future development and production costs
using pricing assumptions in effect at the end of the period. PV-10
differs from Standardized Measure of Discounted Net Cash Flows
because it does not include the effects of income taxes on future
net revenues. Neither PV-10 nor Standardized Measure of Discounted
Net Cash Flows represents an estimate of fair market value of our
natural gas and crude oil properties. PV-10 is used by the industry
and by our management as an arbitrary reserve asset value measure
to compare against past reserve bases and the reserve bases of
other business entities that are not dependent on the taxpaying
status of the entity.
The following table provides a reconciliation of
our Standardized Measure to PV‑10 (in thousands):
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2018 |
|
2017 |
Standardized measure of
discounted future net cash flows |
|
$ |
218,944 |
|
$ |
255,907 |
Future income taxes, discounted at 10% |
|
|
1,563 |
|
|
1,376 |
Pre-tax net present
value, discounted at 10% |
|
$ |
220,507 |
|
$ |
257,283 |
|
|
|
|
|
|
|
In addition to Adjusted EBITDAX and PV-10, we
may provide additional non-GAAP financial measures because our
management believes providing investors with this information gives
additional insights into our profitability, cash flows and
expenses.
Adjusted EBITDAX, PV-10 and other non-GAAP
measures in this release are not presentations made in accordance
with generally accepted accounting principles, or GAAP. As
discussed above, we believe that the presentation of non-GAAP
financial measures in this release is appropriate. However,
when evaluating our results, you should not consider the non-GAAP
financial measures in isolation of, or as a substitute for,
measures of our financial performance as determined in accordance
with GAAP, such as net income (loss). For example, Adjusted
EBITDAX have material limitations as performance measures because
it excludes items that are necessary elements of our costs and
operations. Because other companies may calculate Adjusted
EBITDAX differently than we do, Adjusted EBITDAX as presented in
this release is not, comparable to similarly-titled measures
reported by other companies.
Guidance for First Quarter 2019
The Company is providing the following guidance for the first
calendar quarter of 2019.
|
|
|
Production |
|
34,000 - 39,000 Mcfe per day |
|
|
|
LOE
(including transportation and workovers) |
|
$4.7
million - $5.3 million |
|
|
|
Production and ad valorem taxes (% of Revenue) |
|
3.75 - 4.25% |
|
|
|
G&A, exclusive of non-cash stock compensation |
|
$4.0
million - $4.5 million |
|
|
|
DD&A Rate |
|
$2.40
- $2.65 |
|
|
|
Teleconference Call
Contango management will hold a conference call
to discuss the information described in this press release on
Tuesday, March 19, 2019 at 8:00 am Central Time. Those
interested in participating in the earnings conference call may do
so by calling 1-800-230-1085, (International 1-612-234-9959) and
entering participation code 465432. A replay of the call
will be available from Tuesday, March 19, 2019 at 10:00am CDT
through Tuesday, March 26, 2019 at 11:59pm CDT by calling
1-800-475-6701, (International 1-320-365-3844) and entering
participation code 465432.
About Contango Oil & Gas Company
Contango Oil & Gas Company is a
Houston, Texas based, independent oil and natural gas company whose
business is to maximize production and cash flow from its offshore
properties in the shallow waters of the Gulf of Mexico and onshore
properties in Texas and Wyoming and to use that cash flow to
explore, develop, exploit, increase production from and acquire
crude oil and natural gas properties in West Texas, the Texas Gulf
Coast and the Rocky Mountain regions of the United States.
Additional information is available on the Company's website at
http://contango.com.
Receipt of Audit Opinion with Going Concern
Emphasis
As previously disclosed in its Annual Report on
Form 10-K for the fiscal year ended December 31, 2018, which was
filed with the Securities and Exchange Commission on March 18,
2019, the Company’s audited financial statements contained a going
concern explanatory paragraph in the audit opinion from its
independent registered public accounting firm. This announcement
does not represent any change or amendment to the Company’s
financial statements or to its Annual Report on Form 10-K for the
fiscal year ended December 31, 2018. Please read our Annual Report
on Form 10-K for the year ended December 31, 2018 for more
information.
Forward-Looking Statements and
Cautionary Statements
This press release contains forward-looking
statements within the meaning of Section 27A of the Securities Act
of 1933, and Section 21E of the Securities Exchange Act of 1934, as
amended. These statements are, based on Contango’s current
expectations and includes statements regarding our estimates of
future production, and other guidance (including information
regarding lease operating expenses, cash G&A expenses, and
DD&A Rate), acquisitions and divestitures, 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. Words and phrases used to identify
our forward-looking statements include terms such as “guidance”,
"expects", “projects”, "anticipates", "plans", "estimates",
"potential", "possible", "probable", or "intends", or words and
phrases 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; our ability to comply with financial
covenants in our debt instruments, repay indebtedness and access
new sources of indebtedness, including our ability to refinance
and/or replace the existing RBC Credit Facility, provide additional
liquidity for future capital expenditures and/or continue as a
going concern; fluctuations in oil and gas prices; risks associated
with derivative positions; our ability to realize expected value
from acquisitions and to complete strategic dispositions of assets
and realize the benefits of such dispositions; the need to take
impairments on properties due to lower commodity prices; the
limited trading volume of our common stock and general market
volatility; ability of our management team to execute its
plans or to meet its goals; shortages of drilling equipment, oil
field personnel and services; unavailability of gathering systems,
pipelines and processing facilities; the possibility that
government policies may change or governmental approvals may be
delayed or withheld; and the other factors discussed under the
“Risk Factors” heading in our annual report on Form 10-K for the
year ended December 31, 2018 and our quarterly reports on Form 10-Q
filed with or furnished to the Securities and Exchange Commission.
Additional information on these and other factors which could
affect Contango’s operations or financial results are included in
Contango’s 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 speak
only as of the date they were made and 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.
Cautionary Statements Regarding Reserves
The estimates and guidance presented in this
release are based on assumptions of capital expenditure levels,
prices for oil, natural gas and NGLs, current indications of supply
and demand for oil, well results and operating costs. IP and other
production rates included in this release might not be indicative
of production over longer periods in the life of the well. The
guidance provided in this release does not constitute any form of
guarantee or assurance that the matters indicated will be achieved.
While we believe these estimates and the assumptions on which they
are based are reasonable, they are inherently uncertain and are
subject to, among other things, significant business, economic,
operational and regulatory risks and uncertainties and are subject
to material revision. Actual results may differ materially from our
estimates and guidance, and we undertake no duty to update these
statements.
|
|
Contact: |
|
Contango Oil & Gas Company |
|
E.
Joseph Grady – 713-236-7400 |
Sergio Castro – 713-236-7400 |
Senior Vice President and Chief Financial Officer |
Vice
President and Treasurer |
|
|
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