FORT WORTH, Texas, March 10, 2021 (GLOBE NEWSWIRE) — 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.
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):
|Category||(MBbl)||(MMcf)||(MBbl)||(MBoe)||at 10% ($000) (2)|
|(2)||The above estimates do not include net proved reserves of approximately 2.6 MMBoe attributable to our 37% equity ownership investment in Exaro as of December 31, 2020.|
|(3)||PV-10 is a non-GAAP measure. Please see below for a definition and reconciliation to Standardized Measure.|
As of December 31, 2020, we had the following financial derivative contracts in place with members of our bank group or third-party counterparties under an unsecured line of credit with no margin call provisions.
|Oil||Jan 2021 – March 2021||Swap||19,000||Bbls||$||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||$||3.149||(2)|
(1) Based on West Texas Intermediate crude oil prices.
(2) Based on Henry Hub NYMEX natural gas prices.
In conjunction with the closing of the Mid-Con Acquisition in January 2021, we acquired the following additional derivative contracts via novation from Mid-Con:
(1) Based on West Texas Intermediate crude oil prices.
In the first quarter of 2021, we entered into the following additional derivative contracts:
|Oil||March 2021 – Oct 2021||Swap||25,000||Bbls||$||54.77||(1)|
|Oil||Nov 2021 – Dec 2021||Swap||15,000||Bbls||$||54.77||(1)|
|Natural Gas||March 2021||Swap||100,000||MMBtus||$||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||$||2.72||(2)|
(1) Based on West Texas Intermediate crude oil prices.
(2) Based on Henry Hub NYMEX natural gas prices.
Selected Financial and Operating Data
The following table reflects certain comparative financial and operating data for the three and twelve months ended December 31, 2020 and 2019:
|Three Months Ended||Year ended|
|December 31,||December 31,|
|Offshore Volumes Sold:|
|Oil and condensate (MBbls)||7||11||(36||)%||32||43||(26||)%|
|Natural gas (MMcf)||1,113||1,402||(21||)%||4,962||5,908||(16||)%|
|Natural gas liquids (MBbls)||39||46||(15||)%||127||210||(40||)%|
|Thousand barrels of oil equivalent (MBoe)||232||290||(20||)%||986||1,237||(20||)%|
|Onshore Volumes Sold:|
|Oil and condensate (MBbls)||358||396||(10||)%||1,642||748||120||%|
|Natural gas (MMcf)||2,786||2,741||2||%||14,005||3,615||287||%|
|Natural gas liquids (MBbls)||267||301||(11||)%||1,135||402||182||%|
|Thousand barrels of oil equivalent (MBoe)||1,089||1,154||(6||)%||5,111||1,753||192||%|
|Total Volumes Sold:|
|Oil and condensate (MBbls)||365||407||(10||)%||1,674||791||112||%|
|Natural gas (MMcf)||3,899||4,143||(6||)%||18,967||9,523||99||%|
|Natural gas liquids (MBbls)||306||347||(12||)%||1,262||612||106||%|
|Thousand barrels of oil equivalent (MBoe)||1,321||1,444||(9||)%||6,097||2,990||104||%|
|Daily Sales Volumes:|
|Oil and condensate (MBbls)||4.0||4.4||(5||)%||4.6||2.2||113||%|
|Natural gas (MMcf)||42.4||45.0||(7||)%||51.8||26.1||99||%|
|Natural gas liquids (MBbls)||3.3||3.8||8||%||3.4||1.7||98||%|
|Thousand barrels of oil equivalent (MBoe)||14.4||15.7||(9||)%||16.7||8.2||100||%|
|Average sales prices:|
|Oil and condensate (per Bbl)||$||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||$||25.59||(29||)%|
|Three Months Ended||Year Ended|
|December 31,||December 31,|
|Offshore Selected Costs ($ 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||)%|
|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)|
(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 COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
|December 31,||December 31,|
|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|
|LIABILITIES AND SHAREHOLDERS’ EQUITY|
|Accounts payable and accrued liabilities||83,970||104,593|
|Other current liabilities||5,566||5,954|
|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 COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
|Three Months Ended||Year Ended|
|December 31,||December 31,|
|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||—|
|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|
|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|
|Gain (loss) on derivatives, net||(2,941||)||(4,425||)||27,585||(3,357||)|
|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||)|
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,|
|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|
|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||)|
|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 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):
|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.
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.
|Contango Oil & Gas Company|
|E. Joseph Grady – 713-236-7400|
|Senior Vice President and Chief Financial and Accounting Officer|