HOUSTON, March 30, 2020 (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, 2019.
Fourth Quarter 2019 HighlightsClosed on purchase agreements with Will Energy Corporation (“Will Energy”) and White Star Petroleum, LLC and certain affiliates (“White Star”) to acquire certain producing assets and undeveloped acreage, primarily in Oklahoma, for approximately $14.75 million in cash and 3.5 million common shares and approximately $95.9 million in cash, respectively, in each case after closing adjustments. The Will Energy and White Star acquisitions closed on October 25th and November 1st, respectively. Completed two equity private placements during the fourth quarter to partially fund the cash portion of the purchase price for the White Star and Will Energy acquisitions, selling 32.4 million common equivalent shares for net proceeds of $72.3 million.Entered into a joint development agreement with Juneau Oil & Gas, LLC (“Juneau”) in December 2019, which provides the Company the right to acquire an interest in up to six of Juneau’s exploratory prospects located in the Gulf of Mexico, for approximately $1.7 million in cash and 1.725 million common shares.Amended our senior credit facility in November to increase the number of bank`s in our facility and to increase the borrowing base from $65 million to $145 million. We had outstanding debt of $72.8 million at December 31, 2019.Production of 8.7 Bcfe for the quarter, or 94.2 Mmcfe per day, 237% of the average rate of 39.8 Mmcfe per day in the prior year quarter.Completed and initiated flowback on three wells in Pecos County, Texas, in the Southern Delaware Basin, with a fourth well initiating flow back in January 2020.
Completed and brought on production a Garfield County, Oklahoma well, which we acquired in connection with the White Star acquisition.
Appointed our largest shareholder and existing director, John Goff, as Chairman of the Board and added Farley Dakan to the management team as Senior Vice President – Corporate Development to lead our ongoing acquisition efforts.Net loss of $138.4 million (including $124.7 million in pre-tax impairments), compared to a net loss of $33.8 million in the prior year quarter (including $27.0 million in impairments).Recurring Adjusted EBITDAX (a non-GAAP measure, as defined and presented herein) of $17.2 million, compared to $7.4 million in the prior year quarter. This includes approximately two months of production and cash flow in the current quarter from the White Star and Will Energy acquisitions.Management CommentaryWilkie S. Colyer, the Company’s President and Chief Executive Officer, said, “As noted in the highlights section above, it was a very busy quarter for Contango. We were able to close on two very impactful PDP-rich acquisitions during the fourth quarter that allowed us to expand our credit facility and raise equity, prior to the recent drop in commodity prices. We anticipate this drop in prices will put immense pressure on our already distressed industry, and we will be on the lookout for ways to take advantage of the dislocation. The case for consolidation to rationalize excess costs, especially overhead, has never been stronger. We are also very encouraged by early performance in the NE Bullseye wells we completed during the fourth quarter, and we look forward to further development and production growth in that area when commodity prices improve. In the meantime, our 2020 strategy will be to use excess cash flow to repay debt and to undertake review of our producing areas to consider potential shut ins or curtailment of unhedged production in light of the commodity price environment. We are also evaluating the utilization of our excess oil storage capacity, especially in Cushing and our field storage in our Central Oklahoma region, given the steep contango that currently exists in the WTI futures curve. In the second quarter of 2020, we also plan to drill the Iron Flea Gulf of Mexico prospect we acquired from Juneau in December 2019, a high quality exploratory prospect which we believe could be very beneficial for the Company if successful. While our industry continues to be impacted by low commodity prices, we have been active in protecting our cash flow through an aggressive hedge program. We added hedges during the fourth quarter of 2019 and March of 2020, prior to the dramatic collapse in oil prices, and currently have approximately 70% of our total forecasted PDP oil production for 2020 hedged with swaps at an average floor price of $55.13 per barrel and 68% of our total forecasted PDP gas production for 2020 hedged at an average price of $2.57 per mmbtu. In 2021, we have approximately 67% of total forecasted PDP oil production hedged at $51.71 per barrel. The rest of our hedge book can be seen in the table below. As of the date of this release, the mark-to-market value of our total hedge position through the first quarter of 2022 is calculated at $42 million. We appreciate the support of our lenders and shareholders and look forward to continuing to execute our business plan in 2020.”Summary of Fourth Quarter Financial ResultsNet loss for the three months ended December 31, 2019 was $138.4 million, or $(1.32) per basic and diluted share, compared to a net loss of $33.8 million, or $(1.16) per basic and diluted share, for the prior year quarter. Impacting earnings in the current and prior year quarters were $124.7 million and $27.0 million, respectively, in pre-tax, non-cash, impairment charges explained below. Excluding total impairment and abandonment charges of $125.1 million and $27.1 million for the respective current and prior year quarters, our pre-tax net loss for the current quarter would have been $13.5 million, compared to a pre-tax loss of $6.9 million for the prior year quarter.Average weighted shares outstanding were approximately 105.2 million and 29.0 million for the current and prior year quarters, respectively. The Company reported Adjusted EBITDAX, as defined below, of approximately $12.3 million for the three months ended December 31, 2019, compared to $7.5 million for the same period last year, an increase attributable primarily to the incremental revenues from the properties we acquired from White Star and Will Energy. Recurring Adjusted EBITDAX (defined below as Adjusted EBITDAX exclusive of non-recurring business combination expenses, strategic advisory fees and legal judgments) was $17.2 million for the current quarter, compared to $7.5 million for the prior year quarter.Revenues for the current quarter were approximately $37.2 million compared to $18.7 million for the prior year quarter, an increase attributable to the addition of the Will Energy and White Star properties for the months of November and December 2019.Production for the fourth quarter was approximately 8.7 Bcfe, or 94.2 Mmcfe per day, compared to 3.7 Bcfe, or 39.8 Mmcfe per day for the fourth quarter of 2018. The properties acquired from White Star and Will Energy produced at an average rate of approximately 90.6 Mmcfe/d for November and December 2019, which contributed 60.0 Mmcfe/d to the fourth quarter of 2019.The weighted average equivalent sales price during the three months ended December 31, 2019 was $4.29 per Mcfe, compared to $5.10 per Mcfe for the same period last year, as we experienced a 47% decline in natural gas prices and a 44% decline in natural gas liquids prices.Operating expenses for the three months ended December 31, 2019 were approximately $16.9 million, compared to $5.8 million for the same period last year. 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 were approximately $15.0 million for the current quarter, compared to approximately $5.1 million for the prior year quarter. The properties acquired from White Star and Will Energy added an additional $12.8 million in operating expenses for the three months ended December 31, 2019.DD&A expense for the three months ended December 31, 2019 was $16.2 million, or $1.87 per Mcfe, compared to $8.8 million, or $2.41 per Mcfe, for the prior year quarter. The Will Energy and White Star acquisitions contributed an additional $5.4 million ($0.98 per associated Mcfe produced) in depreciation, depletion and amortization expense.Impairment and abandonment expense was $125.1 million for the current quarter, of which $124.7 million related to non-cash impairment. We recorded a $34.5 million impairment of our Gulf of Mexico properties as a result of performance revisions associated with the re-evaluation of the projected field costs and recoverable condensate volumes and a $83.1 million impairment of onshore proved properties, primarily related to our Bullseye area in West Texas due to performance and price revisions, which led to the re-evaluation of the future drilling plans for the proved undeveloped locations in this area, and resulted in the elimination of certain proved undeveloped locations due to the Securities and Exchange Commission’s (“SEC”) five year development rule for such locations. The current year quarter also included $7.2 million in impairment expense related to unproved lease expirations and near-term lease expirations in the Bullseye area of our West Texas region. The prior year quarter included $27.1 million of impairment and abandonment expense, of which $27.0 million related to non-cash impairment.Total G&A expenses were $9.6 million for the three months ended December 31, 2019, compared to $5.4 million for the prior year quarter. Recurring G&A expenses (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) were $4.6 million, or $0.53 per Mcfe for the current quarter, compared to $5.4 million, or $1.46 per Mcfe for the prior year quarter, an approximate 14% decline. Recurring cash G&A (defined as Recurring G&A expenses exclusive of non-cash stock-based compensation of $0.2 million and $1.0 million for the respective current and prior-year quarters) were $4.5 million for the current quarter, compared to $4.4 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, 2019 was approximately $0.9 million, compared to a $12.7 million loss for the same period last year, due to 2018 year-end impairments at Exaro.Loss on derivatives for the three months ended December 31, 2019 was approximately $4.4 million. Of this amount, $4.9 million were non-cash, unrealized mark-to-market charges, while the remaining $0.5 million were realized gains. Gain on derivatives for the three months ended December 31, 2018 was approximately $6.9 million, of which $8.0 million were non-cash, unrealized mark-to-market gains, while the remaining $1.1 million were realized losses.2019/2020 Capital ProgramCapital costs incurred for the three months ended December 31, 2019 were approximately $129.8 million, of which $112.1 was related to the White Star and Will Energy acquisitions and the joint development agreement with Juneau. Also included in capital costs for the current quarter was $9.3 million for our drilling and completion activity in the Southern Delaware Basin in Pecos County, Texas.Our 2020 capital budget will be focused primarily on: (i) preserving our financial position, including limiting capital expenditures to internally generated cash flow and proceeds from the sale of non-core assets; (ii) focusing drilling expenditures on strategic projects that provide good investment returns in the current price environment; and (iii) identifying opportunities for cost efficiencies in all areas of our operations. Our 2020 capital expenditure budget is currently estimated at approximately $13.1 million and is expected to include the following:Offshore GOM: the Iron Flea prospect in the Grand Isle Block 45/46 area in the shallow waters off of the Louisiana coast will require $6.3 million to drill and $0.8 million to abandon in the case of dry hole. We expect that capital expenditures will exceed this amount if the prospect is a success due to evaluation and completions costs and the possibility of a second well and /or facilities.
West Texas: $3.3 million to drill and complete one salt water disposal well and $0.4 million for infrastructure costs in our NE Bullseye area.Central Oklahoma: $2.3 million to complete three previously drilled wells, which we acquired from White Star.We may revise our 2020 capital expenditure budget if deemed appropriate in light of changes in commodity prices or economic conditions.As of December 31, 2019, the Company had approximately $72.8 million outstanding under the Company’s credit facility and $1.9 million in an outstanding letter of credit, with a borrowing availability of $70.3 million.Operations Activity UpdateWe brought three wells online in the Southern Delaware Basin during the quarter, the Iron Snake #1H, the Breakthrough State #1H and the Old Ironside #1H, all of which are located in our NE Bullseye project area. In January 2020, we brought an additional NE Bullseye well online, the State Spearhead #1H. NE Bullseye is expected to be a more productive and higher oil cut area than our Bullseye area and is projected to be the focus of future capital spending in the area, if and when we determine it to be appropriate to be more aggressive in allocating capital to our drilling program.We also completed and brought on production the Margaret 35-23N-5W #1MH, a Garfield County, Oklahoma well located in our Central Oklahoma area, which was acquired in the White Star acquisition.2019 Year End ReservesAs of December 31, 2019, the Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) value of our proved reserves was approximately $257.8 million and the SEC PV-10 value (Non-GAAP) of our proved reserves was approximately $286.6 million, compared to the Standardized Measure value of $218.9 million and SEC PV-10 value of $220.5 million as of December 31, 2018, an increase primarily attributable to the reserves added from the White Star and Will Energy acquisitions and new producing wells and proved undeveloped locations added in our NE Bullseye area in West Texas, partially offset by performance revisions, production and a reduction in our proved undeveloped reserves (“PUD”) in our Bullseye Area in West Texas. The SEC-mandated prices used in determining our December 31, 2019 proved reserves and PV-10 value were $55.69/Bbl for oil and condensate and $2.52/Mmbtu for natural gas, compared with SEC prices of $64.80/Bbl for oil and condensate and $3.10/Mmbtu for natural gas used in estimating proved reserves as of December 31, 2018.As of December 31, 2019, our independent third-party engineering firms estimated our proved oil and natural gas reserves to be approximately 316.4 Bcfe compared with 131.9 Bcfe of proved reserves as of December 31, 2018, an increase primarily attributable to the 192.7 Bcfe acquired in the White Star and Will Energy acquisitions, as well as an increase in total reserves related to our recently drilled wells in the NE Bullseye area of West Texas, offset by 2019 production and a downward revision related to a reduction in Bullseye PUDs in West Texas in the current low price environment. At the end of 2019, the composition of our proved reserves, volumetrically, was 42% natural gas, 36% oil and condensate and 22% natural gas liquids, compared to 41% natural gas, 43% oil and condensate and 16% natural gas liquids at December 31, 2018. These estimates were prepared in accordance with reserve reporting guidelines mandated by the SEC. Our proved developed reserves for the year ended December 31, 2019 were estimated at 244.5 Bcfe, compared to 79.2 Bcfe in the prior year. The increase in proved developed reserves is primarily attributable to 188.3 Bcfe related to the Will Energy and White Star acquisitions and to additions of 5.6 Bcfe related primarily to wells drilled and put on production in 2019 in our NE Bullseye area of West Texas. Partially offsetting the noted 2019 increases were 2019 production and downward performance revisions of 9.7 Bcfe related to our offshore properties and Bullseye properties in West Texas.Our proved undeveloped reserves (“PUD”) for the year ended December 31, 2019 were 71.9 Bcfe, compared to 52.7 Bcfe at December 31, 2018. The increase in PUD reserves was primarily attributable to 65.9 Bcfe in new PUD locations resulting from our 2019 drilling program in our NE Bullseye area in West Texas and in our other onshore region. This increase was partially offset by a downward revision of 41.0 Bcfe related to the reduction in PUDs in our Bullseye area in West Texas due to the impact of lower performance and prices on the planned timeline for development of PUDs in this area within the SEC’s five year requirement.The above estimates do not include net proved reserves of approximately 23.0 Bcfe and 26.6 Bcfe attributable to our 37% equity ownership interest in Exaro as of December 31, 2019 and 2018, respectively. The PV-10 value of the proved reserves attributable to our 37% interest in Exaro was approximately $15.3 million and $21.0 million at December 31, 2019 and 2018, respectively.The following table summarizes Contango’s total proved reserves as of December 31, 2019 (1):(1) These estimates do not include net reserves of approximately 23.0 Bcfe (PV-10 of approximately $15.3 million attributable to our 37% equity ownership investment in Exaro as of December 31, 2019).Derivative InstrumentsWe currently have hedges in place for 70% and 67% of currently forecasted PDP oil production for 2020 and 2021, respectively, at average floor prices of $55.13 and $51.71 per barrel, respectively. We also have 68% and 57% of currently forecasted PDP natural gas production for 2020 and 2021, respectively, hedged at average floor prices of $2.57 and $2.49 per mmbtu, and 76% of forecasted PDP production for the first quarter of 2022 hedged with swaps at $2.54 per mmbtu. Approximately 98% of our hedges are swaps, and we have no three way collars or short puts.As of December 31, 2019, 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. (1) Based on Henry Hub NYMEX natural gas prices.
(2) Based on West Texas Intermediate crude oil prices.In addition to the above financial derivative instruments, as of December 31, 2019, we had a costless swap agreement with a Midland WTI – Cushing oil differential swap price of $0.05 per barrel of crude oil. The agreement fixes the Company’s exposure to that differential on 12,000 barrels of crude oil per month for January 2020 through June 2020 and 10,000 barrels per month for July 2020 through December 2020.In March 2020 the Company entered into the following additional derivative contracts: (1) Based on Henry Hub NYMEX natural gas prices.Selected Financial and Operating DataThe following table reflects certain comparative financial and operating data for the three and twelve months ended December 31, 2019 and 2018:
__________________________(1) LOE includes transportation and workover expenses.
(2) Adjusted EBITDAX is a non-GAAP financial measure. See below for reconciliation to net loss.
Non-GAAP Financial MeasuresThis 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 income to EBITDAX and Adjusted EBITDAX and Recurring Adjusted EBITDAX for the periods presented:In addition to Adjusted EBITDAX and Recurring Adjusted EBITDAX, we may provide additional non-GAAP financial measures because our management believes providing investors with this information gives additional insights into our profitability, cash flows and expenses.Adjusted EBITDAX, 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 natural gas and oil reserves, less future development and production costs using pricing assumptions in effect at the end of the period. PV-10 differs from Standardized Measure of Discounted Net Cash Flows because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure of Discounted Net Cash Flows represents an estimate of fair market value of our natural gas and oil properties. PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.The following table provides a reconciliation of our Standardized Measure to PV-10 (in thousands):Guidance for the First Quarter 2020Teleconference CallThose interested in participating in the earnings conference call may do so by clicking Here to Join and enter 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 1-800-309-1256, (International 1-323-347-3622) and entering participation code 6038572. A replay of the call will be available from Tuesday, March 31, 2020 at 11:00am CDT through Tuesday, April 7, 2020 at 11:00am CDT by clicking here.
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