Contango Oil & Gas Company (NYSE American: MCF) (“Contango” or
the “Company”) announced today its financial results for the fourth
quarter and twelve months ended December 31, 2020.
Fourth Quarter 2020 Highlights and
Recent Developments
- Production sales of 1,321 MBoe for
the quarter, or 14.4 MBoe per day, within guidance for the quarter.
Assuming we had owned MCEP and Silvertip during the fourth quarter,
our pro forma production sales would have been 24.5 MBoe per
day.
- Total operating expenses of $17.1
million for the quarter, and operating expenses exclusive of
production and ad valorem taxes of $15.5 million, at the lower end
of the guidance range for the quarter.
- Net loss of $25.2 million
(including $22.8 million in pre-tax impairments) compared to a net
loss of $138.4 million (including $124.7 million in pre-tax
impairments) in the prior year quarter.
- Recurring Adjusted EBITDAX (a
non-GAAP measure, as defined and presented herein) of $12.2
million, compared to $17.2 million in the prior year quarter.
- On October 25, 2020, the Company
entered into an Agreement and Plan of Merger with Mid-Con Energy
Partners, LP (“Mid-Con”) (NASDAQ:MCEP) and Mid-Con Energy GP, LLC,
the general partner of Mid-Con, pursuant to which Mid-Con merged
with and into a wholly-owned, direct subsidiary of the Company (the
“Mid-Con Acquisition”). The Mid-Con Acquisition closed on January
21, 2021, at which time the MSA terminated.
- On October 27, 2020, the Company
completed a private placement with a select group of institutional
and accredited investors for the sale of 26,451,988 shares of the
Company’s common stock for net proceeds of approximately $38.8
million.
- On October 30, 2020, the Company
entered into an amendment to its revolving credit agreement with
JPMorgan Chase Bank N.A., as administrative agent, and the lenders
party thereto (the “Credit Agreement”) under which, among other
things, the Company’s borrowing base increased from $75 million to
$130 million upon the closing of the Mid-Con Acquisition.
- On November 27, 2020, the Company
entered into a purchase and sale agreement with an undisclosed
seller to acquire certain oil and natural gas properties located in
the Big Horn Basin in Wyoming and Montana, in the Powder River
Basin in Wyoming, and in the Permian Basin in Texas and New Mexico
(the “Silvertip Acquisition”). The Silvertip Acquisition closed on
February 1, 2021.
- On December 1, 2020, the Company
completed another private placement of 14,193,903 shares of the
Company’s common stock for net proceeds of approximately $21.7
million.
- Pro forma for MCEP and Silvertip
acquisitions, the Company as of January 1, 2021 has increased
strip1 PDP PV-10 by a factor of 2.2x to $572 million compared to
the Company’s reserves as of January 1, 2020.
- Pro forma for MCEP and Silvertip
acquisitions, the Company’s 5 year PDP oil decline forecasted at a
peer leading < 10%, creating substantial cash flow to reinvest
in additional inorganic and organic opportunities.
- Debt outstanding as of March 1,
2021 was approximately $114 million, with $4 million cash on hand.
While we anticipate future inorganic growth, assuming strip1
pricing, no new acquisitions, and our current capital spending
budget, we anticipate the Company exiting 2021 at less than 0.5x
Debt/TTM EBITDA and anticipate being in a net cash position by the
end of Q3 next year.
- In the acquired Silvertip and MCEP
assets, we have identified a highly efficient capital budget for
2021 of approximately $4 million expected to create $46 million in
proved developed PV-10 at strip1 (a 9.2x PV/I) and is not inclusive
of potentially significant additional value from a well
reactivation initiative underway given the higher commodity price
environment.
(1) Strip prices run at March 3,2021.
Management Commentary
Wilkie S. Colyer, the Company’s Chief Executive
Officer, said, “As noted in this release, and our related SEC
filings, we had a very busy fourth quarter that has continued into
a good start to 2021. We signed two acquisition agreements in the
fourth quarter that we closed in the first quarter. Through these
long lived, lower decline acquisitions, we have increased our
current production to sales 24.5 MBoe/d based on fourth quarter
2020 sales, when compared to our fourth quarter average of 14.4
MBoe/d and have increased our reserves, cash flow, financial
strength, and flexibility. We believe this positions us well to
continue our consolidation strategy while the window of opportunity
to acquire PDP-heavy assets, with associated development potential
and at a discount to PDP PV-10 value, still exists. Our technical
team’s focus on operational efficiencies and cost improvements has
resulted in a 7.5 MMBoe addition to proved reserves in the form of
performance revisions at SEC pricing. We believe that we will be
equally successful in increasing the value of the reserves acquired
in the Mid-Con and Silvertip acquisitions, and we believe this
process to be repeatable on future acquisitions based on our
existing track record. Our diversified portfolio provides us an
inventory of very high return capital projects to execute on in
2021 and beyond.
“Maintaining a strong financial profile is also
a priority for us as we look to potentially take advantage of more
acquisition opportunities. We strive to maintain maximum
flexibility in our capital structure financing acquisitions, and we
protect our liquidity and cash flow through our aggressive hedging
program. For 2021, and pro forma for the MCEP and Silvertip
acquisitions, we have price protected approximately 67% of our
forecasted PDP oil production (from April through December) at an
average floor price of $54.87 per barrel and approximately 60% of
our forecasted 2021 PDP gas production (from April through
December) at an average floor price of $2.62 per MMBtu. For 2022,
we have price protected approximately 47% of our forecasted PDP oil
production at an average floor price of $50.24 per barrel and
approximately 57% of our forecasted PDP gas production at an
average floor price of $2.60 per MMBtu. We also have approximately
50% of forecasted PDP oil production for the first two months of
2023 hedged at an average floor price of $49.70 per barrel and
approximately 60% of forecasted PDP gas production for the first
two months of 2023 hedged at an average floor price $2.72. Lastly,
I’d like to thank our shareholders and lenders, led by JPMorgan,
for their continued support, along with our dedicated
employees.”
Impact of the COVID-19
Pandemic
The COVID-19 pandemic has resulted in a severe
worldwide economic downturn, significantly disrupting the demand
for oil throughout the world, and has created significant
volatility, uncertainty and turmoil in the oil and natural gas
industry. This led to a significant global oversupply of oil and a
subsequent substantial decrease in oil prices. While global oil
producers, including the Organization of Petroleum Exporting
Countries (“OPEC”) and other oil producing nations recently have
shown a willingness to exercise more restraint on production
levels, and there has been a decline in U.S. production due to a
reduction in drilling activity, general downward pressure on, and
volatility in, commodity prices has remained and could continue for
the foreseeable future. We have commodity derivative instruments in
place to mitigate the effects of such price declines; however,
derivatives will not entirely mitigate lower oil and natural gas
prices. While there has been modest recovery in oil prices, the
length of this demand disruption is still unknown, and there is
significant uncertainty regarding the long-term impact to global
oil demand, which will ultimately depend on various factors and
consequences beyond the Company’s control, such as the duration and
scope of the pandemic, the length and severity of the worldwide
economic downturn, additional actions by businesses and governments
in response to both the pandemic and the decrease in oil prices,
the speed and effectiveness of responses to combat the virus, and
the time necessary to equalize oil supply and demand to restore oil
pricing. In response to these developments, we have continued to
implement measures to mitigate the impact of the COVID-19 pandemic
on our employees, operations and financial position. These measures
include, but are not limited to, the following:
- work from home initiatives for all but critical staff and the
implementation of social distancing measures;
- a company-wide effort to cut costs
throughout our operations;
- utilization of our available
storage capacity to temporarily store a portion of our production
for later sale at higher prices when advantageous to do so (such as
the approximate 50,000 barrels of second quarter 2020 oil
production we stored and sold during the third quarter of 2020 at
higher oil prices);
- suspension of any further plans for
operated onshore and offshore drilling in 2020;
- pursuit of additional “fee for
service” opportunities similar to the Management Services Agreement
entered into in June 2020 with Mid-Con (the “MSA”), which was
terminated at the closing of the Mid-Con Acquisition on January 21,
2021; and
- potential acquisitions of PDP-heavy
assets, with attractive, discounted valuations, in
stressed/distressed scenarios or from non-industry owners, such as
our Silvertip Acquisition.
Summary of Fourth Quarter Financial
Results
Net loss for the three months ended December 31,
2020 was $24.8 million, or $(0.16) per basic and diluted share,
compared to a net loss of $138.4 million, or $(1.32) per basic and
diluted share, for the prior year quarter. Pre-tax net loss for the
three months ended December 31, 2020 was $25.9 million, compared to
a pre-tax net loss of $138.6 million for the prior year
quarter.
Average weighted shares outstanding were
approximately 155.5 million and 105.2 million for the current and
prior year quarters, respectively.
The Company reported Adjusted EBITDAX, a
non-GAAP measure defined below, of approximately $11.3 million for
the three months ended December 31, 2020, compared to $12.2 million
for the same period last year, a decrease attributable primarily to
lower commodity prices. Recurring Adjusted EBITDAX (defined below
as Adjusted EBITDAX exclusive of non-recurring business combination
expenses, strategic advisory fees and legal judgments) was $12.2
million for the current quarter, compared to $17.2 million for the
prior year quarter.
Revenues for the current quarter were
approximately $29.2 million compared to $37.2 million for the prior
year quarter, a decrease primarily attributable to a 17% decrease
in the weighted average equivalent sales price in production period
over period primarily as a result of a 32% decline in oil prices
period over period. Current quarter revenues also included $1.0
million related to our since-terminated fee for service agreement
with Mid-Con.
Production sales for the fourth quarter were
approximately 1,321 MBoe, or 14.4 MBoe per day, compared to 1,444
MBoe, or 15.7 MBoe per day for the fourth quarter of 2019. The
decrease in the current year quarter was primarily attributable to
a 0.7 MBoe/d decline from our Gulf of Mexico properties due to the
year over year natural decline in production and to downtime
related to Hurricane Delta in October 2020.
The weighted average equivalent sales price
during the three months ended December 31, 2020 was $21.32 per Boe,
compared to $25.75 per Boe for the same period last year, a decline
primarily attributable to the decrease in oil prices in the current
year quarter as a result of the decrease in demand for commodity
products due to the COVID-19 pandemic and the ongoing disruptions
to the global energy markets. In comparison to the fourth quarter
of 2019, we experienced a 32% decline in oil prices, a 7% increase
in natural gas prices and a 16% increase in natural gas liquids
prices in the fourth quarter of 2020.
Operating expenses for the three months ended
December 31, 2020 were approximately $17.1 million, compared to
$16.9 million for the same period last year, a minimal increase
considering the 2019 fourth quarter included expenses related to
the White Star and Will Energy properties for only the months of
November and December. Although lease operating expenses increased
quarter over quarter, we were able to reduce 2020 expenses related
to utilities and generators by approximately $3.9 million compared
to the prior year, due to cost-saving initiatives implemented in
2020. Included in operating expenses are direct lease operating
expenses, transportation and processing costs, workover expenses
and production and ad valorem taxes. Operating expenses (exclusive
of production and ad valorem taxes of $1.6 million and $1.9
million, respectively) were approximately $15.5 million for the
current quarter, at the low end of guidance, compared to
approximately $15.0 million for the prior year quarter.
DD&A expense for the three months ended
December 31, 2020 was $5.9 million, or $4.47 per Boe, compared to
$16.2 million, or $11.22 per Boe, for the prior year quarter. The
lower depletion expense and rate in the current quarter was related
to lower depletable property cost as a result of the proved
property impairment recorded during the fourth quarter of 2019 and
first quarter of 2020.
Impairment and abandonment expense was $22.9
million for the current quarter, of which $22.8 million related to
non-cash impairment. We recorded $21.1 million for proved property
impairment in the current quarter, of which $15.6 million related
to our offshore properties as a result of performance revisions in
reserves and the decline in gas prices and production yield. We
recorded $1.7 million for unproved property impairment due to
leases expiring in 2021, which we have no plan to extend or develop
as a result of the current commodity price environment and our
continued focus on cost saving and production enhancing
initiatives. The prior year quarter included $125.1 million of
impairment and abandonment expense, of which $124.7 million related
to non-cash impairment.
Total G&A expenses were $7.7 million, or
$5.81 per Boe, for the three months ended December 31, 2020,
compared to $9.6 million, or $6.61 per Boe, for the prior year
quarter. Recurring G&A expenses (Non-GAAP, defined as G&A
expenses exclusive of business combination expenses and
non-recurring strategic advisory fees of $1.8 million and legal
judgments of ($0.8) million) for the current quarter were $6.7
million, or $5.09 per Boe. Recurring G&A expenses (Non-GAAP,
defined as G&A expenses exclusive of business combination
expenses and non-recurring strategic advisory fees of $2.1 million
and legal judgments of $2.8 million) for the prior year quarter
were $4.6 million, or $3.20 per Boe. The increase from the prior
year is primarily due to the costs of additional personnel, systems
costs and other administrative expenses added in conjunction with
the properties we acquired from Will Energy and White Star, which
more than tripled our production base. Recurring Cash G&A
expenses (defined as Recurring G&A expenses exclusive of
non-cash stock-based compensation of $1.9 million and $0.2 million
for the respective current and prior-year quarters) were $4.8
million for the current quarter, compared to $4.5 million for the
prior year quarter.
Gain from our investment in affiliates (i.e.,
Exaro Energy III (“Exaro”)) for the three months ended December 31,
2020 was approximately $40,000, compared to $0.9 million for the
three months ended December 31, 2019.
Loss on derivatives for the three months ended
December 31, 2020 was approximately $2.9 million. Of this amount,
$5.8 million was non-cash, unrealized mark-to-market losses
attributable to improvement in benchmark commodity prices at the
end of the current quarter compared to the benchmark prices at the
end of the third quarter of 2020, offset in part by $2.9 million in
realized gains on derivative settlements during the current
quarter. Loss on derivatives for the three months ended December
31, 2019 was approximately $4.4 million, of which $4.9 million was
non-cash, unrealized mark-to-market losses, while the remaining
$0.5 million were realized gains.
2020/2021 Capital Program & Capital
Resources
Capital costs for the three months ended
December 31, 2020 were approximately $0.4 million, of which $0.3
million was related to costs and evaluations of potential offshore
exploratory prospects.
Our 2021 capital expenditure budget is currently
planned to be between $13 - $16 million for capital workovers,
facility upgrades, waterflood development and selected new well
drills; however, due to our ongoing evaluation of future
development for our recently acquired properties from the Mid-Con
Acquisition and the Silvertip Acquisition, and the regulatory and
operational factors being considered in developing a timeline for
our next well in our GOM program, our capital expenditure program
will continue to be evaluated for revision during the year. We
believe that we will have the financial resources to increase the
currently planned 2021 capital expenditure budget, when and if
deemed appropriate, including as a result of changes in commodity
prices, economic conditions or operational factors.
As of December 31, 2020, we had approximately
$9.0 million outstanding under the Company’s Credit Agreement, $1.9
million in an outstanding letter of credit and $1.4 million in
cash. The borrowing base was $75 million as of December 31, 2020,
with a borrowing availability of $64.1 million.
On October 25, 2020, the Company and Mid-Con
entered into the Agreement and Plan of Merger for the Mid-Con
Acquisition providing for the Company’s acquisition of Mid-Con in
an all-stock merger transaction in which Mid-Con became a direct,
wholly owned subsidiary of Contango. The Mid-Con Acquisition closed
on January 21, 2021 at which time the MSA with Mid-Con was
terminated. A total of 25,409,164 shares of Contango common stock
were issued at the closing of the Mid-Con acquisition. Concurrently
with the announcement of the Mid-Con Acquisition, we announced the
execution of an agreement with a select group of institutional and
accredited investors to sell 26,451,988 shares of the Company’s
common stock. On October 27, 2020, we completed the private
placement offering for net proceeds of approximately $38.8 million.
The proceeds were used for the Mid-Con Acquisition and for general
corporate purposes, including the repayment of debt outstanding
under our Credit Agreement. See Note 1 – “Organization and
Business” and Note 4 – “Acquisitions and Dispositions” in our
recently filed Form 10-K for the year ended December 31, 2020 for
further information.
On October 30, 2020, we entered into the Third
Amendment to the Credit Agreement (the “Third Amendment”) under
which the Company’s borrowing base was increased from $75 million
to $130 million, effective upon the closing of the Mid-Con
Acquisition. The Third Amendment provides for, among other things,
a $10 million automatic reduction in the borrowing base on March
31, 2021. The next regularly scheduled borrowing base
redetermination is on or before May 1, 2021. The borrowing base may
also be adjusted by certain events, including the incurrence of any
senior unsecured debt, material asset dispositions or liquidation
of hedges in excess of certain thresholds. The Credit Agreement
matures on September 17, 2024. See Note 13 – “Long-Term Debt”
in our recently filed Form 10-K for the year ended December 31,
2020 for further information.
On November 27, 2020, we entered into a Purchase
and Sale Agreement with an undisclosed seller for the Silvertip
Acquisition providing for the acquisition of certain oil and
natural gas properties located in the Big Horn Basin in Wyoming and
Montana, on the Powder River Basin in Wyoming, and in the Permian
Basin in Texas and New Mexico. The acquisition closed on February
1, 2021. See Note 4 – “Acquisitions and Dispositions” in our
recently filed Form 10-K for the year ended December 31, 2020 for
further information.
On December 1, 2020, we completed another
private placement of 14,193,903 shares of the Company’s common
stock for net proceeds of approximately $21.7 million. The net
proceeds were used to fund the Silvertip Acquisition and for
general corporate purposes, including the repayment of debt
outstanding under our Credit Agreement. See Note 1 – “Organization
and Business” in our recently filed Form 10-K for the year ended
December 31, 2020 for further information.
2020 Year End Reserves
As of December 31, 2020, the Standardized
Measure of Discounted Future Net Cash Flows (“Standardized
Measure”) of our proved reserves was approximately $115.6 million,
and the PV-10 value (Non-GAAP) of our proved reserves was
approximately $126.4 million, compared to the Standardized Measure
value of $257.8 million and PV-10 value of $286.6 million as of
December 31, 2019, a decrease primarily attributable to lower
commodity prices and the sales of non-core producing assets The
Securities and Exchange Commission (“SEC”) mandated prices used in
determining our December 31, 2020 proved reserves and PV-10 value
were $39.57 per Bbl of oil and condensate and $2.14 per MMBtu for
natural gas, compared with SEC prices of $55.69 per Bbl for oil and
condensate and $2.52 per MMMbtu for natural gas used in estimating
proved reserves as of December 31, 2019.
As of December 31, 2020, our independent
third-party engineering firms estimated our proved oil and natural
gas reserves to be approximately 34.2 MMBoe compared with 52.7
MMBoe of proved reserves as of December 31, 2019. The decrease in
proved reserves is primarily due to a 21.1 MMBoe decrease related
to negative revisions related to lower commodity prices, a 1.0
MMBoe decrease related to property sales in our Central Oklahoma
and Western Anadarko regions and 2020 production of 6.1 MMBoe,
partially offset by a 7.5 MMBoe increase related to positive
performance revisions primarily in our Central Oklahoma and West
Texas regions and a 2.3 MMBoe increase attributable to new PUD
locations in our West Texas area.
At the end of 2020, the composition of our
proved reserves, volumetrically, was 38% oil and condensate, 41%
natural gas and 21% natural gas liquids, compared to 36% oil and
condensate, 42% natural gas and 22% natural gas liquids at December
31, 2019. These estimates were prepared in accordance with reserve
reporting guidelines mandated by the SEC.
Our proved developed reserves for the year ended
December 31, 2020 were estimated at 27.6 MMBoe, compared to 40.8
MMBoe in the prior year. The decrease in proved developed reserves
is primarily attributable to negative revisions related to lower
commodity prices of 9.8 MMBoe and 2020 production of 6.1 MMBoe,
partially offset by positive performance-related revisions related
in our Central Oklahoma properties.
Our proved undeveloped reserves (“PUD”) for the
year ended December 31, 2020 were 6.7 MMBoe, compared to 12.0 MMBoe
at December 31, 2019. The decrease in PUD reserves was primarily
attributable to 11.4 MMBoe in negative price-related revisions,
partially offset by a 4.3 MMBoe positive performance revision and
2.3 MMBoe of new additions, both of which relate to properties in
our West Texas region.
The following table summarizes Contango’s total
proved reserves as of December 31, 2020 (1):
|
|
|
|
|
|
|
|
|
|
|
Present Value |
|
|
Oil |
|
Gas |
|
NGL |
|
Total |
|
|
Discounted |
Category |
|
(MBbl) |
|
(MMcf) |
|
(MBbl) |
|
(MBoe) |
|
|
at 10% ($000) (2) |
Developed |
|
7,166 |
|
82,788 |
|
6,595 |
|
27,558 |
|
$ |
112,103 |
Undeveloped |
|
5,838 |
|
1,694 |
|
559 |
|
6,680 |
|
|
14,273 |
Total Proved |
|
13,004 |
|
84,482 |
|
7,154 |
|
34,238 |
|
$ |
126,376 |
(2) |
The above estimates do not include net proved reserves of
approximately 2.6 MMBoe attributable to our 37% equity ownership
investment in Exaro as of December 31, 2020. |
(3) |
PV-10 is a non-GAAP measure. Please see below for a definition and
reconciliation to Standardized Measure. |
Derivative Instruments
As of December 31, 2020, we had the following
financial derivative contracts in place with members of our bank
group or third-party counterparties under an unsecured line of
credit with no margin call provisions.
Commodity |
|
Period |
|
Derivative |
|
Volume/Month |
|
Price/Unit |
Oil |
|
Jan 2021 - March 2021 |
|
Swap |
|
19,000 |
|
Bbls |
|
$ |
50.00 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
April 2021 - July 2021 |
|
Swap |
|
12,000 |
|
Bbls |
|
$ |
50.00 |
(1) |
Oil |
|
Aug 2021 - Sept 2021 |
|
Swap |
|
10,000 |
|
Bbls |
|
$ |
50.00 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
Jan 2021 - July 2021 |
|
Swap |
|
62,000 |
|
Bbls |
|
$ |
52.00 |
(1) |
Oil |
|
Aug 2021 - Sept 2021 |
|
Swap |
|
55,000 |
|
Bbls |
|
$ |
52.00 |
(1) |
Oil |
|
Oct 2021 - Dec 2021 |
|
Swap |
|
64,000 |
|
Bbls |
|
$ |
52.00 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
April 2022 - Oct 2022 |
|
Swap |
|
25,000 |
|
Bbls |
|
$ |
42.04 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
Jan 2021 - March 2021 |
|
Swap |
|
185,000 |
|
MMBtus |
|
$ |
2.505 |
(2) |
Natural Gas |
|
April 2021 - July 2021 |
|
Swap |
|
120,000 |
|
MMBtus |
|
$ |
2.505 |
(2) |
Natural Gas |
|
Aug 2021 - Sept 2021 |
|
Swap |
|
10,000 |
|
MMBtus |
|
$ |
2.505 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
Jan 2021 - March 2021 |
|
Swap |
|
185,000 |
|
MMBtus |
|
$ |
2.508 |
(2) |
Natural Gas |
|
April 2021 - July 2021 |
|
Swap |
|
120,000 |
|
MMBtus |
|
$ |
2.508 |
(2) |
Natural Gas |
|
Aug 2021 - Sept 2021 |
|
Swap |
|
10,000 |
|
MMBtus |
|
$ |
2.508 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
Jan 2021 - March 2021 |
|
Swap |
|
650,000 |
|
MMBtus |
|
$ |
2.508 |
(2) |
Natural Gas |
|
April 2021 - Oct 2021 |
|
Swap |
|
400,000 |
|
MMBtus |
|
$ |
2.508 |
(2) |
Natural Gas |
|
Nov 2021 - Dec 2021 |
|
Swap |
|
580,000 |
|
MMBtus |
|
$ |
2.508 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
April 2021 - Nov 2021 |
|
Swap |
|
70,000 |
|
MMBtus |
|
$ |
2.36 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
Dec 2021 |
|
Swap |
|
350,000 |
|
MMBtus |
|
$ |
2.36 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
Jan 2022 - March 2022 |
|
Swap |
|
780,000 |
|
MMBtus |
|
$ |
2.542 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
April 2022 - July 2022 |
|
Swap |
|
650,000 |
|
MMBtus |
|
$ |
2.515 |
(2) |
Natural Gas |
|
Aug 2022 - Oct 2022 |
|
Swap |
|
350,000 |
|
MMBtus |
|
$ |
2.515 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
Jan 2022 - March 2022 |
|
Swap |
|
250,000 |
|
MMBtus |
|
$ |
3.149 |
(2) |
______________________(1) Based on West Texas Intermediate crude
oil prices.(2) Based on Henry Hub NYMEX natural gas prices.
In conjunction with the closing of the Mid-Con
Acquisition in January 2021, we acquired the following additional
derivative contracts via novation from Mid-Con:
Commodity |
|
Period |
|
Derivative |
|
Volume/Month |
|
Price/Unit |
Oil |
|
Jan 2021 |
|
Swap |
|
20,883 |
|
Bbls |
|
$ |
55.78 |
(1) |
Oil |
|
Feb 2021 |
|
Swap |
|
20,804 |
|
Bbls |
|
$ |
55.78 |
(1) |
Oil |
|
March 2021 |
|
Swap |
|
20,725 |
|
Bbls |
|
$ |
55.78 |
(1) |
Oil |
|
April 2021 |
|
Swap |
|
20,647 |
|
Bbls |
|
$ |
55.78 |
(1) |
Oil |
|
May 2021 |
|
Swap |
|
20,563 |
|
Bbls |
|
$ |
55.78 |
(1) |
Oil |
|
June 2021 |
|
Swap |
|
20,487 |
|
Bbls |
|
$ |
55.78 |
(1) |
Oil |
|
July 2021 |
|
Swap |
|
20,412 |
|
Bbls |
|
$ |
55.78 |
(1) |
Oil |
|
Aug 2021 |
|
Swap |
|
20,301 |
|
Bbls |
|
$ |
55.78 |
(1) |
Oil |
|
Sept 2021 |
|
Swap |
|
20,228 |
|
Bbls |
|
$ |
55.78 |
(1) |
Oil |
|
Oct 2021 |
|
Swap |
|
20,155 |
|
Bbls |
|
$ |
55.78 |
(1) |
Oil |
|
Nov 2021 |
|
Swap |
|
20,084 |
|
Bbls |
|
$ |
55.78 |
(1) |
Oil |
|
Dec 2021 |
|
Swap |
|
20,012 |
|
Bbls |
|
$ |
55.78 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
Jan 2021 |
|
Collar |
|
20,883 |
|
Bbls |
|
$ |
52.00 |
- |
58.80 |
(1) |
Oil |
|
Feb 2021 |
|
Collar |
|
20,804 |
|
Bbls |
|
$ |
52.00 |
- |
58.80 |
(1) |
Oil |
|
March 2021 |
|
Collar |
|
20,725 |
|
Bbls |
|
$ |
52.00 |
- |
58.80 |
(1) |
Oil |
|
April 2021 |
|
Collar |
|
20,647 |
|
Bbls |
|
$ |
52.00 |
- |
58.80 |
(1) |
Oil |
|
May 2021 |
|
Collar |
|
20,563 |
|
Bbls |
|
$ |
52.00 |
- |
58.80 |
(1) |
Oil |
|
June 2021 |
|
Collar |
|
20,487 |
|
Bbls |
|
$ |
52.00 |
- |
58.80 |
(1) |
Oil |
|
July 2021 |
|
Collar |
|
20,412 |
|
Bbls |
|
$ |
52.00 |
- |
58.80 |
(1) |
Oil |
|
Aug 2021 |
|
Collar |
|
20,301 |
|
Bbls |
|
$ |
52.00 |
- |
58.80 |
(1) |
Oil |
|
Sept 2021 |
|
Collar |
|
20,228 |
|
Bbls |
|
$ |
52.00 |
- |
58.80 |
(1) |
Oil |
|
Oct 2021 |
|
Collar |
|
20,155 |
|
Bbls |
|
$ |
52.00 |
- |
58.80 |
(1) |
Oil |
|
Nov 2021 |
|
Collar |
|
20,084 |
|
Bbls |
|
$ |
52.00 |
- |
58.80 |
(1) |
Oil |
|
Dec 2021 |
|
Collar |
|
20,012 |
|
Bbls |
|
$ |
52.00 |
- |
58.80 |
(1) |
__________________(1) Based on West Texas Intermediate crude oil
prices.
In the first quarter of 2021, we entered into the following
additional derivative contracts:
Commodity |
|
Period |
|
Derivative |
|
Volume/Month |
|
Price/Unit |
Oil |
|
March 2021 - Oct 2021 |
|
Swap |
|
25,000 |
|
Bbls |
|
$ |
54.77 |
(1) |
Oil |
|
Nov 2021 - Dec 2021 |
|
Swap |
|
15,000 |
|
Bbls |
|
$ |
54.77 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
March 2021 |
|
Swap |
|
50,000 |
|
Bbls |
|
$ |
63.31 |
(1) |
Oil |
|
April 2021 |
|
Swap |
|
50,000 |
|
Bbls |
|
$ |
63.13 |
(1) |
Oil |
|
May 2021 |
|
Swap |
|
50,000 |
|
Bbls |
|
$ |
62.71 |
(1) |
Oil |
|
June 2021 |
|
Swap |
|
50,000 |
|
Bbls |
|
$ |
62.17 |
(1) |
Oil |
|
July 2021 |
|
Swap |
|
50,000 |
|
Bbls |
|
$ |
61.50 |
(1) |
Oil |
|
Aug 2021 |
|
Swap |
|
50,000 |
|
Bbls |
|
$ |
60.94 |
(1) |
Oil |
|
Sep 2021 |
|
Swap |
|
50,000 |
|
Bbls |
|
$ |
60.38 |
(1) |
Oil |
|
Oct 2021 |
|
Swap |
|
50,000 |
|
Bbls |
|
$ |
59.89 |
(1) |
Oil |
|
Nov 2021 |
|
Swap |
|
50,000 |
|
Bbls |
|
$ |
59.46 |
(1) |
Oil |
|
Dec 2021 |
|
Swap |
|
50,000 |
|
Bbls |
|
$ |
59.01 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
Jan 2022 |
|
Swap |
|
60,000 |
|
Bbls |
|
$ |
52.94 |
(1) |
Oil |
|
Feb 2022 |
|
Swap |
|
60,000 |
|
Bbls |
|
$ |
52.65 |
(1) |
Oil |
|
March 2022 |
|
Swap |
|
60,000 |
|
Bbls |
|
$ |
52.29 |
(1) |
Oil |
|
April 2022 |
|
Swap |
|
47,500 |
|
Bbls |
|
$ |
51.98 |
(1) |
Oil |
|
May 2022 |
|
Swap |
|
45,000 |
|
Bbls |
|
$ |
51.71 |
(1) |
Oil |
|
June 2022 |
|
Swap |
|
45,000 |
|
Bbls |
|
$ |
51.41 |
(1) |
Oil |
|
July 2022 |
|
Swap |
|
45,000 |
|
Bbls |
|
$ |
51.13 |
(1) |
Oil |
|
Aug 2022 |
|
Swap |
|
45,000 |
|
Bbls |
|
$ |
50.89 |
(1) |
Oil |
|
Sep 2022 |
|
Swap |
|
45,000 |
|
Bbls |
|
$ |
50.65 |
(1) |
Oil |
|
Oct 2022 |
|
Swap |
|
45,000 |
|
Bbls |
|
$ |
50.45 |
(1) |
Oil |
|
Nov 2022 |
|
Swap |
|
55,000 |
|
Bbls |
|
$ |
50.26 |
(1) |
Oil |
|
Dec 2022 |
|
Swap |
|
55,000 |
|
Bbls |
|
$ |
50.22 |
(1) |
Oil |
|
Jan 2023 |
|
Swap |
|
57,500 |
|
Bbls |
|
$ |
49.81 |
(1) |
Oil |
|
Feb 2023 |
|
Swap |
|
57,500 |
|
Bbls |
|
$ |
49.63 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
Jan 2022 |
|
Swap |
|
60,000 |
|
Bbls |
|
$ |
52.96 |
(1) |
Oil |
|
Feb 2022 |
|
Swap |
|
60,000 |
|
Bbls |
|
$ |
52.66 |
(1) |
Oil |
|
March 2022 |
|
Swap |
|
60,000 |
|
Bbls |
|
$ |
52.27 |
(1) |
Oil |
|
April 2022 |
|
Swap |
|
47,500 |
|
Bbls |
|
$ |
51.96 |
(1) |
Oil |
|
May 2022 |
|
Swap |
|
45,000 |
|
Bbls |
|
$ |
51.72 |
(1) |
Oil |
|
June 2022 |
|
Swap |
|
45,000 |
|
Bbls |
|
$ |
51.42 |
(1) |
Oil |
|
July 2022 |
|
Swap |
|
45,000 |
|
Bbls |
|
$ |
51.13 |
(1) |
Oil |
|
Aug 2022 |
|
Swap |
|
45,000 |
|
Bbls |
|
$ |
50.90 |
(1) |
Oil |
|
Sep 2022 |
|
Swap |
|
45,000 |
|
Bbls |
|
$ |
50.66 |
(1) |
Oil |
|
Oct 2022 |
|
Swap |
|
45,000 |
|
Bbls |
|
$ |
50.47 |
(1) |
Oil |
|
Nov 2022 |
|
Swap |
|
55,000 |
|
Bbls |
|
$ |
50.26 |
(1) |
Oil |
|
Dec 2022 |
|
Swap |
|
55,000 |
|
Bbls |
|
$ |
50.01 |
(1) |
Oil |
|
Jan 2023 |
|
Swap |
|
57,500 |
|
Bbls |
|
$ |
49.79 |
(1) |
Oil |
|
Feb 2023 |
|
Swap |
|
57,500 |
|
Bbls |
|
$ |
49.62 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
March 2021 |
|
Swap |
|
100,000 |
|
MMBtus |
|
$ |
2.96 |
(2) |
Natural Gas |
|
April 2021 - July 2021 |
|
Swap |
|
350,000 |
|
MMBtus |
|
$ |
2.96 |
(2) |
Natural Gas |
|
Aug 2021 - Oct 2021 |
|
Swap |
|
500,000 |
|
MMBtus |
|
$ |
2.96 |
(2) |
Natural Gas |
|
Nov 2021 |
|
Swap |
|
450,000 |
|
MMBtus |
|
$ |
2.96 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
April 2022 |
|
Swap |
|
175,000 |
|
MMBtus |
|
$ |
2.51 |
(2) |
Natural Gas |
|
May 2022 - July 2022 |
|
Swap |
|
150,000 |
|
MMBtus |
|
$ |
2.51 |
(2) |
Natural Gas |
|
Aug 2022 - Oct 2022 |
|
Swap |
|
400,000 |
|
MMBtus |
|
$ |
2.51 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
Nov 2022 - Feb 2023 |
|
Swap |
|
750,000 |
|
MMBtus |
|
$ |
2.72 |
(2) |
________________________(1) Based on West Texas Intermediate
crude oil prices.(2) Based on Henry Hub NYMEX natural gas
prices.
Selected Financial and Operating Data
The following table reflects certain comparative
financial and operating data for the three and twelve months ended
December 31, 2020 and 2019:
|
Three Months Ended |
|
Year ended |
|
December 31, |
|
December 31, |
|
2020 |
|
2019 |
|
% |
|
2020 |
|
2019 |
|
% |
Offshore Volumes Sold: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (MBbls) |
|
7 |
|
|
11 |
|
(36 |
)% |
|
|
32 |
|
|
43 |
|
(26 |
)% |
Natural gas (MMcf) |
|
1,113 |
|
|
1,402 |
|
(21 |
)% |
|
|
4,962 |
|
|
5,908 |
|
(16 |
)% |
Natural gas liquids (MBbls) |
|
39 |
|
|
46 |
|
(15 |
)% |
|
|
127 |
|
|
210 |
|
(40 |
)% |
Thousand barrels of oil equivalent (MBoe) |
|
232 |
|
|
290 |
|
(20 |
)% |
|
|
986 |
|
|
1,237 |
|
(20 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Volumes Sold: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (MBbls) |
|
358 |
|
|
396 |
|
(10 |
)% |
|
|
1,642 |
|
|
748 |
|
120 |
% |
Natural gas (MMcf) |
|
2,786 |
|
|
2,741 |
|
2 |
% |
|
|
14,005 |
|
|
3,615 |
|
287 |
% |
Natural gas liquids (MBbls) |
|
267 |
|
|
301 |
|
(11 |
)% |
|
|
1,135 |
|
|
402 |
|
182 |
% |
Thousand barrels of oil equivalent (MBoe) |
|
1,089 |
|
|
1,154 |
|
(6 |
)% |
|
|
5,111 |
|
|
1,753 |
|
192 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Volumes Sold: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (MBbls) |
|
365 |
|
|
407 |
|
(10 |
)% |
|
|
1,674 |
|
|
791 |
|
112 |
% |
Natural gas (MMcf) |
|
3,899 |
|
|
4,143 |
|
(6 |
)% |
|
|
18,967 |
|
|
9,523 |
|
99 |
% |
Natural gas liquids (MBbls) |
|
306 |
|
|
347 |
|
(12 |
)% |
|
|
1,262 |
|
|
612 |
|
106 |
% |
Thousand barrels of oil equivalent (MBoe) |
|
1,321 |
|
|
1,444 |
|
(9 |
)% |
|
|
6,097 |
|
|
2,990 |
|
104 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily Sales Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (MBbls) |
|
4.0 |
|
|
4.4 |
|
(5 |
)% |
|
|
4.6 |
|
|
2.2 |
|
113 |
% |
Natural gas (MMcf) |
|
42.4 |
|
|
45.0 |
|
(7 |
)% |
|
|
51.8 |
|
|
26.1 |
|
99 |
% |
Natural gas liquids (MBbls) |
|
3.3 |
|
|
3.8 |
|
8 |
% |
|
|
3.4 |
|
|
1.7 |
|
98 |
% |
Thousand barrels of oil equivalent (MBoe) |
|
14.4 |
|
|
15.7 |
|
(9 |
)% |
|
|
16.7 |
|
|
8.2 |
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (per Bbl) |
$ |
39.30 |
|
$ |
57.93 |
|
(32 |
)% |
|
$ |
37.31 |
|
$ |
56.55 |
|
(34 |
)% |
Natural gas (per Mcf) |
$ |
2.22 |
|
$ |
2.07 |
|
7 |
% |
|
$ |
1.65 |
|
$ |
2.35 |
|
(30 |
)% |
Natural gas liquids (per Bbl) |
$ |
16.86 |
|
$ |
14.50 |
|
16 |
% |
|
$ |
13.54 |
|
$ |
15.39 |
|
(12 |
)% |
Total (per Boe) |
$ |
21.32 |
|
$ |
25.75 |
|
(17 |
)% |
|
$ |
18.19 |
|
$ |
25.59 |
|
(29 |
)% |
|
Three Months Ended |
|
Year Ended |
|
December 31, |
|
December 31, |
|
2020 |
|
|
2019 |
|
|
% |
|
2020 |
|
|
2019 |
|
|
% |
Offshore Selected Costs ($ per
Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses (1) |
$ |
4.50 |
|
|
$ |
5.22 |
|
|
(14 |
)% |
|
$ |
5.68 |
|
|
$ |
5.13 |
|
|
11 |
% |
Production and ad valorem taxes |
$ |
0.47 |
|
|
$ |
0.36 |
|
|
31 |
% |
|
$ |
0.38 |
|
|
$ |
0.43 |
|
|
(12 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Selected Costs ($ per
Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses (1) |
$ |
13.24 |
|
|
$ |
11.67 |
|
|
13 |
% |
|
$ |
12.04 |
|
|
$ |
13.26 |
|
|
(9 |
)% |
Production and ad valorem taxes |
$ |
1.37 |
|
|
$ |
1.56 |
|
|
(12 |
)% |
|
$ |
1.04 |
|
|
$ |
1.75 |
|
|
(41 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Selected Costs ($ per
Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses (1) |
$ |
11.72 |
|
|
$ |
10.38 |
|
|
13 |
% |
|
$ |
11.01 |
|
|
$ |
9.91 |
|
|
11 |
% |
Production and ad valorem taxes |
$ |
1.22 |
|
|
$ |
1.32 |
|
|
(8 |
)% |
|
$ |
0.94 |
|
|
$ |
1.21 |
|
|
(22 |
)% |
General and administrative expense (cash) |
$ |
4.38 |
|
|
$ |
6.54 |
|
|
(33 |
)% |
|
$ |
3.39 |
|
|
$ |
7.55 |
|
|
(55 |
)% |
Interest expense |
$ |
0.45 |
|
|
$ |
3.76 |
|
|
(88 |
)% |
|
$ |
0.82 |
|
|
$ |
2.87 |
|
|
(71 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss (thousands) |
$ |
(25,248 |
) |
|
$ |
(138,379 |
) |
|
|
|
$ |
(165,342 |
) |
|
$ |
(159,796 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX (2)
(thousands) |
$ |
11,270 |
|
|
$ |
12,270 |
|
|
|
|
$ |
48,206 |
|
|
$ |
23,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares
Outstanding (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
155,480 |
|
|
|
105,215 |
|
|
|
|
|
137,522 |
|
|
|
54,136 |
|
|
|
Diluted |
|
155,480 |
|
|
|
105,215 |
|
|
|
|
|
137,522 |
|
|
|
54,136 |
|
|
|
_____________________________(1) Operating expense includes
direct lease operating expenses, transportation and workover
expenses.(2) Adjusted EBITDAX is a non-GAAP financial measure. See
below for reconciliation to net loss.
CONTANGO OIL & GAS COMPANYCONDENSED
CONSOLIDATED BALANCE SHEETS(in thousands)
|
December 31, |
|
December 31, |
|
2020 |
|
2019 |
ASSETS |
|
|
|
|
|
Cash and cash equivalents |
$ |
1,383 |
|
$ |
1,624 |
Accounts receivable, net |
|
37,862 |
|
|
39,567 |
Current derivative asset |
|
2,996 |
|
|
3,819 |
Other current assets |
|
4,565 |
|
|
1,377 |
Net property and equipment |
|
101,903 |
|
|
291,120 |
Non-current assets |
|
21,558 |
|
|
16,319 |
|
|
|
|
|
|
TOTAL ASSETS |
$ |
170,267 |
|
$ |
353,826 |
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS’
EQUITY |
|
|
|
|
|
Accounts payable and accrued
liabilities |
|
83,970 |
|
|
104,593 |
Other current liabilities |
|
5,566 |
|
|
5,954 |
Long-term debt |
|
12,369 |
|
|
72,768 |
Asset retirement obligations |
|
2,624 |
|
|
49,662 |
Other non-current liabilities |
|
50,171 |
|
|
4,809 |
Total shareholders’ equity |
|
15,567 |
|
|
116,040 |
|
|
|
|
|
|
TOTAL LIABILITIES &
SHAREHOLDERS’ EQUITY |
$ |
170,267 |
|
$ |
353,826 |
CONTANGO OIL & GAS COMPANYCONSOLIDATED
STATEMENTS OF OPERATIONS(in thousands)
|
Three Months Ended |
|
Year Ended |
|
December 31, |
|
December 31, |
|
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited) |
REVENUES |
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales |
$ |
14,334 |
|
|
$ |
23,579 |
|
|
$ |
62,461 |
|
|
$ |
44,705 |
|
Natural gas sales |
|
8,663 |
|
|
|
8,588 |
|
|
|
31,381 |
|
|
|
22,380 |
|
Natural gas liquids sales |
|
5,160 |
|
|
|
5,025 |
|
|
|
17,078 |
|
|
|
9,427 |
|
Fee for service revenues |
|
1,000 |
|
|
|
— |
|
|
|
2,000 |
|
|
|
— |
|
Total revenues |
|
29,157 |
|
|
|
37,192 |
|
|
|
112,920 |
|
|
|
76,512 |
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
17,071 |
|
|
|
16,884 |
|
|
|
72,847 |
|
|
|
33,205 |
|
Exploration expenses |
|
250 |
|
|
|
312 |
|
|
|
11,594 |
|
|
|
1,003 |
|
Depreciation, depletion and amortization |
|
5,901 |
|
|
|
16,204 |
|
|
|
30,032 |
|
|
|
39,807 |
|
Impairment and abandonment of oil and gas properties |
|
22,877 |
|
|
|
125,120 |
|
|
|
168,802 |
|
|
|
128,290 |
|
General and administrative expenses |
|
7,672 |
|
|
|
9,598 |
|
|
|
24,940 |
|
|
|
24,938 |
|
Total expenses |
|
53,771 |
|
|
|
168,118 |
|
|
|
308,215 |
|
|
|
227,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE) |
|
|
|
|
|
|
|
|
|
|
|
Gain from investment in affiliates, net of income taxes |
|
40 |
|
|
|
893 |
|
|
|
27 |
|
|
|
742 |
|
Gain (loss) from sale of assets |
|
30 |
|
|
|
(83 |
) |
|
|
4,501 |
|
|
|
518 |
|
Interest expense |
|
(601 |
) |
|
|
(5,428 |
) |
|
|
(5,022 |
) |
|
|
(8,596 |
) |
Gain (loss) on derivatives, net |
|
(2,941 |
) |
|
|
(4,425 |
) |
|
|
27,585 |
|
|
|
(3,357 |
) |
Other income |
|
2,154 |
|
|
|
1,326 |
|
|
|
3,609 |
|
|
|
1,848 |
|
Total other income (expense) |
|
(1,318 |
) |
|
|
(7,717 |
) |
|
|
30,700 |
|
|
|
(8,845 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS BEFORE INCOME
TAXES |
|
(25,932 |
) |
|
|
(138,643 |
) |
|
|
(164,595 |
) |
|
|
(159,576 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision
(benefit) |
|
684 |
|
|
|
264 |
|
|
|
(747 |
) |
|
|
(220 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS |
$ |
(25,248 |
) |
|
$ |
(138,379 |
) |
|
$ |
(165,342 |
) |
|
$ |
(159,796 |
) |
Non-GAAP Financial Measures
This news release includes certain non-GAAP
financial information as defined by SEC 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. Recurring
Adjusted EBITDAX represents Adjusted EBITDAX exclusive of
non-recurring business combination and strategic advisory fees and
legal judgments.
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 loss to
EBITDAX and Adjusted EBITDAX and Recurring Adjusted EBITDAX for the
periods presented:
|
Three Months Ended |
|
Year Ended |
|
December 31, |
|
December 31, |
|
2020 |
|
|
2019 |
|
|
2020 |
|
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
Net loss |
$ |
(25,248 |
) |
|
$ |
(138,379 |
) |
|
$ |
(165,342 |
) |
|
$ |
(159,796 |
) |
Interest expense |
|
601 |
|
|
|
5,428 |
|
|
|
5,022 |
|
|
|
8,596 |
|
Income tax provision (benefit) |
|
(684 |
) |
|
|
(264 |
) |
|
|
747 |
|
|
|
220 |
|
Depreciation, depletion and amortization |
|
5,901 |
|
|
|
16,204 |
|
|
|
30,032 |
|
|
|
39,807 |
|
Impairment of oil and gas properties |
|
22,794 |
|
|
|
124,718 |
|
|
|
168,732 |
|
|
|
126,964 |
|
Exploration expense |
|
250 |
|
|
|
312 |
|
|
|
11,594 |
|
|
|
1,003 |
|
EBITDAX |
$ |
3,614 |
|
|
$ |
8,019 |
|
|
$ |
50,785 |
|
|
$ |
16,794 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss (gain) on derivative instruments |
$ |
5,834 |
|
|
$ |
4,905 |
|
|
$ |
(2,321 |
) |
|
$ |
5,973 |
|
Non-cash stock-based compensation charges |
|
1,892 |
|
|
|
158 |
|
|
|
4,270 |
|
|
|
2,352 |
|
Loss (gain) on sale of assets and investment in affiliates |
|
(70 |
) |
|
|
(812 |
) |
|
|
(4,528 |
) |
|
|
(1,260 |
) |
Adjusted EBITDAX |
$ |
11,270 |
|
|
$ |
12,270 |
|
|
$ |
48,206 |
|
|
$ |
23,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-recurring business combination expenses and strategic fees |
$ |
1,752 |
|
|
$ |
2,347 |
|
|
$ |
4,380 |
|
|
$ |
4,177 |
|
Non-recurring legal judgments |
|
(806 |
) |
|
|
2,839 |
|
|
|
(560 |
) |
|
|
4,973 |
|
Recurring Adjusted EBITDAX |
$ |
12,216 |
|
|
$ |
17,456 |
|
|
$ |
52,026 |
|
|
$ |
33,009 |
|
In addition to Adjusted EBITDAX and Recurring
Adjusted EBITDAX, we may provide additional non-GAAP financial
measures, including Operating expenses exclusive of production and
ad valorem taxes, Recurring G&A expenses and Recurring Cash
G&A expenses, because our management believes providing
investors with this information gives additional insights into our
profitability, cash flows and expenses.
Adjusted EBITDAX, Recurring Adjusted EBITDAX 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 loss. For example, Adjusted
EBITDAX has material limitations as a performance measure 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.
PV 10
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 oil and natural
gas 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
oil and natural gas 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, |
|
2020 |
|
2019 |
Standardized measure of
discounted future net cash flows |
$ |
115,587 |
|
$ |
257,842 |
Future income taxes, discounted at 10% |
|
10,789 |
|
|
28,711 |
Pre-tax net present value,
discounted at 10% |
$ |
126,376 |
|
$ |
286,553 |
Guidance for the First Quarter 2021
Production sales |
19,000 - 21,000 Boe per day |
|
|
LOE (including transportation and workovers) |
$22.0 million - $25.0 million |
|
|
Recurring Cash G&A (non-GAAP) |
$6.0 million - $7.0 million |
|
|
The first quarter guidance includes properties
acquired in the Mid-Con Acquisition and Silvertip Acquisition,
prorated from the closing dates of January 21, 2021 and February 1,
2021, respectively.
We do not provide a reconciliation of Recurring
Cash G&A expense guidance to the corresponding GAAP measure
because we are unable to predict with reasonable certainty the
non-cash stock based compensation expense and non-recurring
expenses associated with our strategic initiatives without
unreasonable effort. These items are uncertain and depend on
various factors and are not expected to be material to the results
computed in accordance with GAAP.
Teleconference Call
Contango management will hold a conference call
to discuss the information described in this press release on
Wednesday, March 10, 2021 at 8:00 am Central Standard Time. A brief
presentation related to certain items to be discussed on the call
will be posted to the Company’s website at ir.contango.com prior to
the call. Those interested in participating in the earnings
conference call may do so by clicking here to join and entering
your information to be connected. The link becomes active 15
minutes prior to the scheduled start time, and the conference will
call you. If you are not at a computer, you can join by dialing +1
(323)-347-3622 (International 800-309-1256) and entering
participation code 898661. A replay of the call will be available
Thursday, March 11, 2021 through Thursday, March 18, 2021 by
clicking here.
About Contango Oil & Gas Company
Contango Oil & Gas Company is a Fort
Worth, 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 primarily located in Oklahoma, Texas, Wyoming and
Louisiana and, when determined appropriate, to use that cash flow
to explore, develop, and increase production from its existing
properties, to acquire additional PDP-heavy crude oil and natural
gas properties or to pay down debt. Additional information is
available on the Company’s website at http://contango.com.
Information on our website is not part of this release.
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 include statements regarding our estimates of
future production and other guidance (including information
regarding production, lease operating expenses, cash G&A
expenses, and DD&A Rate), the Company’s integration of and
future plans for its recently closed Mid-Con Acquisition and
Silvertip Acquisition, the Company’s drilling program and capital
expenditures and the potential success related to those
expenditures, our liquidity and access to capital, expected
reduction in overall drilling costs, lease operating cost and
G&A costs, the potential impact of the COVID-19 pandemic
including reduced demand for oil and natural gas, the low and
volatile commodity price environment, the Company’s new fee for
services platform, the impact of our derivative instruments, the
accuracy of our projections of future production, future results of
operations, ability to identify and complete acquisitions, ability
to realize expected benefits of acquisitions the 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”,
“believes”, “plans”, “estimates”, “potential”, “possible”,
“probable”, “intends”, “forecasts”, “view”, “efforts”, “goal”,
“positions” 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); risks related to our recent Silvertip
Acquisition and Mid-Con Acquisition, including the risk that the
anticipated benefits from those acquisitions may not be fully
realized or may take longer to realize than expected, and that
management attention will be diverted to integration-related
issues; risks related to the impact of the climate change
initiative by President Biden’s administration and Congress,
including, as an example, the January 2021 executive order imposing
a moratorium on new oil and natural gas leasing on federal lands
and offshore waters pending completion of a comprehensive review
and reconsideration of federal oil and natural gas permitting and
leasing practices; uncertainties as to the availability and cost of
financing; our relationships with lenders; our ability to comply
with financial covenants in our debt instruments, repay
indebtedness and access new sources of indebtedness and/or provide
additional liquidity for future capital expenditures; any reduction
in our borrowing base and our ability to avoid or repay excess
borrowings as a result of such reduction; our ability to execute on
our strategy, including execution of acquisitions, any changes in
our strategy or our fee for service platform; fluctuations in or
sustained low commodity prices; availability and effect of storage
of production; expected benefits of and risks associated with
derivative positions; our ability to realize cost savings; our
ability to execute on and 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 trading market volatility;
outbreaks and pandemics, even outside our areas of operation,
including COVID-19; the impact of the COVID-19 pandemic, including
reduced demand for oil and natural gas, economic slowdown,
governmental and societal actions taken in response to the COVID-19
pandemic, stay-at-home orders and interruptions to our operations;
the 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 in our reports filed or furnished with
the SEC, including under the “Risk Factors” heading in our annual
report on Form 10-K for the year ended December 31, 2020 and our
quarterly reports on Form 10-Q filed with the SEC. Additional
information on these and other factors, many of which may be
unknown or unpredictable at this time, which could affect
Contango’s operations or financial results are included in
Contango’s reports on file with the SEC. 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, except
as required by law. Initial production rates are subject to decline
over time and should not be regarded as reflective of sustained
production levels. Initial production rates of wells and initial
indications of formation performance or the benefits of any
transaction are not necessarily indicative of future or long-term
results. Reserves and PV-10 are not necessarily representative of
future cash flows and production.
|
Contact: |
Contango Oil & Gas Company |
E. Joseph Grady – 713-236-7400 |
Senior Vice President and Chief Financial and Accounting
Officer |
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