Contango Announces 4th Quarter &Full Year 2020 Financial Results

Source: www.gulfoilandgas.com 3/10/2021, Location: North America

Contango Oil & Gas Company announced 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.

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.

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.

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.

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.


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