OTC:ALVOF | TSX:ALV.V
Alvopetro Energy (OTC:ALVOF) (TSX:ALV.V) achieved a highly significant, transformational milestone in 2020. After years of developing the Caburé natural gas field and completing the construction of supporting midstream infrastructure (a transfer pipeline and gas treatment facility), along with securing a gas sales agreement with Bahiagás, Alvopetro commenced natural gas deliveries on July 5, 2020. The company transformed into a profitable natural gas and condensate production company.
Recent Monthly Production Announcements
On June 3, 2021, Alvopetro Energy announced sales volumes for May. Based on field estimates, total sales volumes averaged 2,353 boepd. Natural gas sales averaged 13.4 MMCFPD while condensate sales averaged 109 BOPD.
On May 5, 2021, the company announced sales volumes for April. Based on field estimates, total sales volumes averaged 2,313 boepd. Natural gas sales averaged 13.3 MMCFPD while condensate sales averaged 99 BOPD.
Operationally, management focused on producing natural gas and condensate from the Caburé natural gas field and advancing the company’s Gomo natural gas project to production.
During 2021, management plans to drill two natural gas exploration prospects: 182-C1 and 183-B1. Drilling had been scheduled to start drilling at the end of June 2021; however, the drilling rig secured for these contracted projects failed to meet the company’s safety and performance acceptance standards. Management is evaluating alternatives that will permit both wells to be drilled by the end of 2021. Total drilling costs are anticipated to total $6.8 million for the two wells.
Management still expects to begin field construction for the 9-km flow line in July. The flow line will connect the 183-1 well to Alvopetro’s existing 11-km Caburé gas field transfer pipeline. The estimated cost, including field production facilities, is $2.1 million. During the first quarter of 2021, civil construction was completed at a cost of $0.3 million and long-lead items were purchased at a cost of $0.4 million.
Management anticipates that production from the Caburé natural gas field will continue at rates between 10.6 and 12.7 MMCFPD. Overall sales volumes (natural gas and associated condensate sales) are expected to average between 1,850 and 2,200 boepd for the remainder of 2021.
Due to the company’s improving operational performance, along with a strong pricing outlook, in early June, management raised 2021 EBITDA guidance to over $20 million, up from initial guidance of $17 million. Not only have sales volumes continue to rise month by month, but also the benchmark prices that contribute to the semi-annual price redetermination, namely Brent, Henry Hub and National Balancing Point) are also increasing. The floor and ceiling prices for natural gas price under the Gas Sales Agreement (GSA) with Bahiagás are re-set as of February 1st and August 1st.
Early Debt Repayment
In 2019, Alvopetro entered into a Senior Secured Credit Facility with Cordiant Capital with a cash interest rate of 9.5% per annum and a 3% PIK interest rate. The facility had an original maturity of October 8, 2022. The outstanding balance had risen to $15.4 million by the end of 2020.
During the first quarter of 2021, Alvopetro repaid $2.5 million of the Credit Facility, which reduced the balance to $13.0 million as of March 31, 2021. Then, on May 3, 2021, Alvopetro Energy restructured this debt through an amendment that extended the maturity date by one year to October 8, 2023. In addition, the amendment eliminated the facility’s 3% PIK interest as of April 15, 2021. The 9.5% cash interest rate was not altered.
Subsequently, on June 4, 2021, an additional $3.5 million was repaid since the capital spending on drilling 182-C1 and 183-B1 has been deferred to later in 2021. The balance of Credit Facility now ought to be $9.5 million.
First Quarter Results
On May 12, 2021, Alvopetro Energy reported results for the first quarter ending March 31, 2021. Natural gas and condensate sales were $6.94 million, a record for the company since just initiated deliveries of high pressure sales volume through its controlled midstream infrastructure. Year-over year (YOY) comparisons are meaningless since prior sales volumes from the Mãe-da-lua field during the first quarter of 2020 were de minimis (averaging averaged 6 BOPD).
Sequentially, natural gas and condensate sales increased 17.9% compared to $5.89 million in the fourth quarter of 2020, driven by a sequential 11.5% increase of overall sales volumes to 2,175 boepd, along with the an increase in sales prices through the re-set floor price of the GSA. Natural gas sales averaged 12.5 MMCFPD while condensate sales averaged 98 BOPD. Natural gas price realization was $5.68 per MCF, a 6.0% sequential increase from $5.37 per MCF in the fourth quarter. The realized condensate price was $64.41 per bbl.
Royalties and production taxes were 9.3% of natural gas and condensate sales. The Caburé natural gas field is subject to a 10% government royalty and a 1% landowner royalty while the Bom Lugar field is subject to a 5% government royalty and a 0.5% landowner royalty. The Mãe-da-lua field and Block 182 have an additional 2.5% gross-overriding royalty. However, royalties are determined at an inherent reference price attributable to production of raw natural gas produced , which is lower than the GSA contracted sales price, which results in a lower effective royalty rate. The reference price is also tied to current Henry Hub prices.
Sequentially, production expenses increased 16.8%, primarily due to higher fees associated with increased sales volumes. Most of Alvopetro’s production expenses are related to fees paid to Enerflex for the operation of the transfer pipeline and gas processing facility, along with unit operating costs on the Caburé upstream assets.
G&A expenses increased 14.4% sequentially, mainly due to increased professional fees and higher general corporate costs, including higher insurance costs.
Interest expense declined 0.2% sequentially to approximately $994,000, primarily due to the balance of the Credit Facility being reduced from $15.5 million to $13 million by the end of the first quarter. The other major component of interest expense is related to interest on the capital lease with Enerflex. Looking forward, interest expense in the second quarter should decline given that the balance of the Credit Facility was $9.5 million in the first week of May. In addition, the 3% interest-in-kind (PIK) on the Credit Facility was eliminated as of April 15, 2021.
The company’s tax expense of $1.07 million in the first quarter is an anomaly since it reflects both Brazil’s statutory corporate tax rate of 34% (15% corporate tax, 10% surtax and a 9% social contribution tax) and the deferred tax expense that relates to tax deductions recognized in 2021 in excess of accounting deductions. In the future, a regional tax incentive is expected to lower the company’s effective tax rate to 15.25%.
The reported quarterly loss was $1.088 million (or $0.0109 per diluted share) versus a loss of $2.363 million (or $0.0240 per diluted share) in the comparable quarter last year. The first quarter’s earnings were negatively impacted by an unrealized foreign exchange loss of $2.065 million. Without the recognition of the unrealized foreign exchange loss, earnings for the first quarter would have been $0.977 million (or $0.0098 per diluted share).
With the realized sales price at $35.45 per BOE, royalties at $3.30 per BOE and production expenses at $3.63 per BOE, the operating netback was $28.52 per BOE.
As of March 31, 2021, working capital was $5.77 million, a $236,000 improvement from $5.54 million at the end of 2020. During the first quarter, the $15.0 million Senior Secured Credit Facility was reduced to $13.0 million through a $2.5 million principal repayment. Management believes that the positive cash flows from natural gas and condensate sales are sufficient to fund the company’s operational activities and planned capital projects.
The Board of Directors has formally adopted a dividend policy and strategy, which includes the expectation of initiating the payment of dividends (denominated in US$) as soon as the first quarter of 2022. The dividend will be determined after the 2021 exploration drilling campaign is completed and the 2022 capital budget is finalized.
To facilitate the payment of dividends, the company plans to conduct a one-time, small-lot common share repurchase program, which may be implemented through a buyback or by a share consolidation, all subject to shareholder approval. The cost is expected to be less than $1.0 million.
Expectations for 2021
Management expects that the production from the Caburé natural gas field will continue at rates between 10.6 and 12.7 MMCFPD. Overall sales volumes (natural gas and associated condensate sales) are expected to average between 1,850 and 2,200 boepd for the remainder of 2021.
In February 2021, management raised its EBITDA forecast from the $17 million to US$18 million for 2021. Subsequently in June, management raised 2021 EBITDA guidance again to over $20 million.
At the Gomo Natural Gas Project, with the successful completion of the production test of the 183-1 well in March 2021, management is proceeding with plans to commence construction of a 9-km tie-in pipeline that will connect well 183-1 to the 11-km Caburé transfer pipeline. The environmental approval has been already received for this pipeline. The estimated cost is $2.1 million.
Also at the Gomo Project, stimulation of additional net pay in 183-1 well and stimulation of 197-1 well are expected during 2021.
Furthermore, management plans on drilling two natural gas exploration prospects (182-C1 and 183-B1). The civil construction on both these well sites has been completed at a cost of $0.3 million. Drilling had been scheduled to start drilling at the end of June 2021; however, the drilling rig secured for these contracted projects failed to meet the company’s safety and performance standards. Management is evaluating alternatives that will permit both wells to be drilled by the end of 2021. Total drilling costs are anticipated to total $6.8 million for the two wells. Moreover, in late-2021 or 2022, management plans to drill additional developmental wells at Gomo.
Management’s vision is to make Alvopetro Energy a leading independent upstream and midstream gas company in Brazil. Phase 1 consisted of becoming commercial producer of on-shore natural gas producer in the state of Bahia in Brazil, which was achieved in July 2020. The cash flow from the production is expected to help fund additional developmental initiatives and return a healthy dividend to shareholders.
Based on the development of the company’s Caburé’s P2 reserves, management has forecasted an EBITDA profile at the floor price in the sales agreement with Bahiagás (light green bars in the above chart). In 2020, the company generated EBITDA of US$6.22 million, most of which has been either utilized to reduced debt or added to working capital. For 2021, projected EBITDA is over US$20 million, including the impact of forecasted G&A expenses. In 2021, almost all of the projected EBITDA is anticipated to be consumed by capital expenditures (grey bar), debt principal repayment and interest costs on debt (blue bar), a UPGN fee to Enerflex for the gas facility (yellow bar) and taxes (red bar). By the end of 2023, it is assumed that the entire amount of debt will have been repaid.
The P/S valuation range for comparable small-cap, producing oil & gas companies is between 13.6 and 3.36. Utilizing comparable analysis, the target price for Alvopetro Energy is $1.34 per share, which is based on an expected mid-second quartile price-to-sales multiple.
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