Key Points: – Methanex to acquire OCI Global’s methanol business for $2.05 billion, boosting production capacity. – The acquisition is expected to increase Methanex’s free cash flow per share and add $275 million annually to EBITDA. – The deal strengthens Methanex’s position in low-carbon methanol production and expands into the ammonia market.
Methanex Corporation has announced its plan to acquire OCI Global’s international methanol business for $2.05 billion, marking a significant move to bolster its position in the global methanol industry. This acquisition aligns with Methanex’s strategic focus on enhancing value for shareholders while expanding its production capacity. The transaction, which includes two key methanol production facilities in North America, also strengthens Methanex’s access to abundant and competitively priced natural gas feedstock in the region.
The acquisition is expected to increase Methanex’s free cash flow per share immediately, making it a promising development for investors. The deal also includes a 50% stake in a second methanol facility operated by Natgasoline LLC, which will significantly increase Methanex’s production capacity. Once completed, the acquisition will boost Methanex’s global methanol production by more than 20%, giving it a competitive edge in the industry.
Methanex CEO Rich Sumner highlighted the strategic importance of this acquisition, emphasizing how OCI’s assets complement Methanex’s global operations. The Beaumont facilities included in the deal have undergone significant upgrades, positioning them as world-class production centers. The acquisition will also provide Methanex with an entry into ammonia production, a market that is increasingly important for low-carbon fuel solutions.
A key aspect of this transaction is Methanex’s acquisition of OCI’s low-carbon methanol production and marketing business. This move positions Methanex as a leader in the growing low-carbon solutions market, which is gaining traction as industries worldwide seek sustainable alternatives. By enhancing its capabilities in low-carbon methanol, Methanex is poised for long-term growth in this emerging sector.
Financially, the acquisition is projected to add $275 million annually to Methanex’s adjusted EBITDA, bringing the company’s total to $850 million based on a methanol price of $350 per metric ton. Methanex plans to maintain its financial flexibility and aims to reduce its debt-to-EBITDA ratio to its target range within 18 months of closing the deal. The acquisition is backed by financing from the Royal Bank of Canada, which ensures Methanex’s strong financial position throughout the transaction.
OCI, which will retain a 13% ownership interest in Methanex post-transaction, sees the deal as a mutually beneficial partnership. OCI Executive Chairman Nassef Sawiris expressed confidence in Methanex’s ability to generate long-term value for shareholders, citing the shared commitment to operational excellence and safety between the two companies.
This acquisition represents a major step for Methanex as it looks to expand its global footprint and diversify into low-carbon methanol and ammonia production. The transaction is expected to close in the first half of 2025, pending regulatory approvals and other conditions.
Calgary-based Tourmaline Oil Corp (TSX: TOU) has announced its acquisition of Crew Energy Inc. in a significant move that’s set to reshape the Canadian natural gas landscape. This strategic buyout, valued at approximately $1.3 billion, marks a pivotal moment in Tourmaline’s Northeast British Columbia (NEBC) consolidation strategy and solidifies its position as a dominant player in the Montney formation.
The deal, expected to close in early October 2024, will see Tourmaline issue 18.778 million common shares and assume Crew’s net debt of about $240 million. This acquisition brings substantial assets into Tourmaline’s portfolio, including a low-decline production base of 29,000 to 30,000 barrels of oil equivalent per day (boepd) and proved and probable (2P) reserves of 473.2 million boe.
One of the crown jewels in this acquisition is Crew’s extensive drilling inventory, featuring over 700 Tier 1 locations. This addition complements Tourmaline’s existing assets, potentially extending their Tier 1 inventory by four years based on a break-even natural gas price of $1.50/GJ.
Mike Rose, President & CEO of Tourmaline, expressed enthusiasm about the deal, stating, “Dale and his team at Crew have done a tremendous job over the past 21 years assembling one of the premier, concentrated Montney asset bases in NEBC, with significant upside.”
The acquisition is expected to be immediately accretive to Tourmaline’s key financial metrics, adding over $200 million to the company’s anticipated 2025 free cash flow. Tourmaline has also identified synergies with a net present value exceeding $0.6 billion at a 10% discount rate before tax.
This move aligns with Tourmaline’s broader strategy to evolve into Canada’s largest and most efficient Montney producer. The company is already the largest Alberta Deep Basin producer, and this acquisition furthers its goal of reaching 750,000 boepd production over the next five years.
In conjunction with the acquisition news, Tourmaline announced an increase in its quarterly base dividend from $0.33 to $0.35 per share, effective Q3 2024. This represents a 6% increase and continues the company’s trend of rewarding shareholders.
The transaction has received unanimous approval from both companies’ boards of directors. It’s subject to customary closing conditions, including court, Crew shareholder, and regulatory approvals. Notably, Crew’s officers, directors, and certain shareholders, representing 32% of fully diluted shares outstanding, have agreed to vote in favor of the arrangement.
As the Canadian energy sector continues to evolve, this acquisition positions Tourmaline to capitalize on the anticipated growth in North American LNG business and the increasing demand for natural gas-powered electrical generation across the continent.
Chesapeake Energy is making a massive bet on the future of natural gas with its just-announced $7.4 billion all-stock acquisition of rival Southwestern Energy. The deal, announced Thursday morning, will create a natural gas behemoth and make Chesapeake the largest natural gas producer in the United States.
The deal reflects Chesapeake’s bullish outlook on natural gas amid a wave of consolidation in the U.S. energy sector. Major players like Exxon and Chevron have recently snapped up Permian Basin leaders like Pioneer Natural Resources and Hess Corporation with multi-billion dollar deals. Now Chesapeake is looking to cement its dominance in natural gas production through its purchase of Southwestern’s assets primarily located in the Haynesville basin of Louisiana and the Appalachian shale formations.
Chesapeake itself emerged from bankruptcy just two years ago in 2021 and has been aggressively rebuilding under CEO Nick Dell’Osso. It has honed in on natural gas assets and production, believing gas will play an integral role in the global energy transition away from dirtier fossil fuels. Natural gas emits 50-60% less carbon dioxide when combusted compared to coal, but still faces criticism from environmentalists.
The Southwestern deal doubles down on this gas-focused strategy. The combined company will churn out a mammoth 7.9 billion cubic feet per day of natural gas production. That is enough to rocket Chesapeake past EQT Corporation as the top natural gas producer based on volume. Chesapeake already boosted its gas position last year with the $2.5 billion purchase of Chief E&D.
Chesapeake is offering Southwestern shareholders $6.69 per share, representing a slight 3% discount to Southwestern’s last closing share price. The deal values Southwestern at around $7.4 billion. Chesapeake shareholders will own approximately 60% of the merged entity, with Southwestern shareholders owning the remaining 40%.
Southwestern gives Chesapeake key positions in two of the most prolific U.S. natural gas plays. Its Marcellus Shale assets in Pennsylvania and West Virginia dovetail perfectly with Chesapeake’s existing Northeast presence. Southwestern also brings over 700,000 Haynesville acres, solidifying Chesapeake’s status as the dominant player in the basin.
The merger is expected to unlock $350-400 million in annual cost synergies within the first two years, a major boost to cash flows. Chesapeake predicts the deal will be accretive to all relevant 2023 per-share metrics. The combined company will retain Chesapeake’s investment grade credit rating and chop net debt to EBITDAX from 1.5x to under 1.3x in 2023.
Chesapeake CEO Dell’Osso will stay on as chief executive of the merged entity. He called the deal “highly compelling” and said it will “further enhance free cash flow growth and return of capital to shareholders.”
Natural gas prices face near-term headwinds, having plunged over 60% last year due to ballooning inventory levels and mild winter weather. But long-term projections remain bullish, especially if more coal generation is retired and replaced by gas. LNG export facilities continue expanding along the Gulf Coast, offering producers prime access to higher-priced global markets.
Chesapeake is betting big that natural gas will retain a substantial role in the global energy mix even as zero-carbon sources like wind and solar grow. If gas demand rises as expected, Chesapeake will be sitting pretty as the largest U.S. producer. But execution risks remain, as the two companies integrate operations and work through the challenges of joining two complex businesses.
The deal is expected to close in Q2 2024, pending shareholder and regulatory approval. But Chesapeake is already taking a victory lap, believing the tie-up cements its status as a premier U.S. natural gas producer for decades to come.
Chesapeake Utilities Corporation announced Monday that it has entered into an agreement to acquire Florida City Gas (FCG) from NextEra Energy for $923 million in cash. The acquisition will significantly expand Chesapeake’s presence in the growing Florida energy market.
FCG is the eighth largest natural gas local distribution company in Florida, serving around 120,000 residential and commercial customers across eight counties. Its infrastructure includes approximately 3,800 miles of distribution pipelines and 80 miles of transmission pipelines.
According to Jeff Householder, President and CEO of Chesapeake Utilities, natural gas demand in Florida continues to rise as consumers and businesses seek reliable, domestic, and affordable energy. With this acquisition, Chesapeake aims to capitalize on the robust growth opportunities across the state.
“This acquisition will more than double our natural gas business in Florida, one of the fastest growing states in the nation,” said Householder. “We see significant potential to continue pursuing long-term earnings growth.”
The deal is expected to close by the end of the fourth quarter of 2023, subject to regulatory approvals. Once completed, FCG will become a wholly owned subsidiary of Chesapeake Utilities.
Chesapeake has a strong track record of successfully integrating acquisitions to drive growth, as seen in its purchase of Florida Public Utilities in 2009. The company believes it can optimize FCG’s operations and execute on additional investments in gas distribution, transmission, and other energy platforms.
To finance the deal, Chesapeake plans to utilize a mix of equity and long-term debt to maintain balance sheet strength. The company has also obtained committed financing from Barclays.
Chesapeake has extended its earnings guidance through 2028 based on the increased scale and opportunities from FCG. It expects earnings per share growth of approximately 8% through 2028. The company also increased its 5-year capital expenditure guidance to $1.5-$1.8 billion.
The FCG acquisition demonstrates Chesapeake’s strategy of consolidating natural gas assets and positioning itself for growth in key geographies. As energy markets evolve, strategic deals allow companies like Chesapeake to enhance their competitive position.
Oil markets and energy stocks often get painted with a broad brush. But within the sector, offshore drilling stocks offer upside that many investors are overlooking. Despite cries of peak oil demand, fundamentals for rig owners point to gains ahead.
The oil services sector has rocketed over 50% higher in the last year, soundly beating the S&P 500. Yet offshore drilling stocks remain unloved. This creates an opportunity for investors willing to take a contrarian bet.
The bull case lies in constrained supply and rapidly rising prices. ESG considerations have limited capital investment in new oil production. But robust demand has returned as pandemic impacts recede. This supply/demand imbalance has sent oil above $80 per barrel.
Day rates for offshore rigs are soaring as utilization rates stick near 90%. However, shipyards are focused on liquefied natural gas, not building fresh drilling ships. That means supply can’t catch up to growing demand in a hurry.
This grants pricing power to rig owners. Valaris, Noble, and Weatherford have emerged from bankruptcy with pristine balance sheets. Meanwhile Transocean boasts the most high-specification rigs, positioning it to profit from climbing day rates.
Yet valuations look disconnected from fundamentals. Offshore drillers trade at up to an 80% discount to replacement value, signaling the market doubts their potential. But conditions point to further gains.
Why Energy Could Shine for Investors
Beyond compelling fundamentals, two key reasons make energy stocks stand out right now:
Inflation hedge – Energy equities have historically held up well during inflationary periods. With prices still running hot, oil stocks may offer protection if high inflation persists.
Contrarian bet – Energy is the most hated sector this year, with heavy net outflows from funds. That sets up a chance to buy low while others are selling.
To be clear, the long-term peak oil argument holds merits. The global energy transition will likely constrain fossil fuel demand over time. But that shift will take decades to play out.
In the meantime, diminished investment and stiff demand creates room for shares like offshore drillers to run higher. For investors willing to make a contrarian bet, the neglected energy space offers rare value.
ESG Sours Sentiment But Oil Remains Key
What about the ESG push away from fossil fuels? Shift is clearly underway. But hydrocarbons still supply 80% of global energy needs. Realistically, oil and gas will remain vital to powering the world for years to come.
Market sentiment has soured on all things oil. But investors should remember that supply/demand, not narrative, ultimately drives commodity prices. Offshore drillers look primed to benefit from that dynamic.
While oil markets face uncertainty beyond the next decade, conditions now point to upside in left-behind niches like offshore drilling stocks. For investors who see value where others only see headwinds, forgotten energy corners may hold diamonds in the rough.
Enbridge Inc.’s agreement to acquire three natural gas utilities from Dominion Energy for $14 billion presents opportunities for smaller companies in the sector.
The Canadian pipeline giant will dramatically expand its regulated gas distribution business in the U.S. through the purchase of Questar Gas, East Ohio Gas and Public Service Company of North Carolina.
But the deal also creates an opening for nimble smaller utilities to grow amidst consolidation. Regulators may require certain assets to be divested as conditions for merger approval.
Smaller players could potentially gain customers, infrastructure and new geographies by acquiring these divested assets. Companies in the energy sector may be well positioned.
The agreement comes as Dominion reviews its business mix. Other major utilities are also rationalizing assets, setting the stage for smaller competitors.
Small operators boast strong community ties and localized expertise. They have advantages in customer service and responsiveness.
While lacking scale, these firms can thrive by focusing resources on targeted markets and infrastructure modernization. Many also offer renewable natural gas and other next-gen offerings.
Western Midstream Partners, LP (NYSE: WES) is set to expand its footprint in the Powder River Basin through the acquisition of Meritage Midstream Services II, LLC (Meritage). This all-cash transaction comes with a price tag of $885 million and is expected to close in the fourth quarter of 2023, subject to regulatory approvals.
Meritage, headquartered in Denver, Colorado, operates a substantial natural gas gathering and processing business in Wyoming’s Powder River Basin. The acquisition will significantly increase WES’s natural gas processing capacity, taking it to 440 MMcf/d. Additionally, it will diversify WES’s customer base with long-term contracts and acreage dedications from reputable counterparties.
The Powder River Basin has attracted considerable investment due to its multi-stacked pay horizon potential, making it an appealing prospect for energy companies. As part of this acquisition, WES aims to enhance its position in the basin and pursue additional acreage dedications and business development opportunities.
Upon completing the transaction, WES anticipates recommending a Base Distribution increase of $0.0125 per unit, providing a potential boost for its investors.
This strategic move represents a significant step for WES in expanding its presence in a region with promising energy prospects.
Alvopetro Energy Ltd.’s vision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.
Michael Heim, Senior Vice President, Equity Research Analyst, Energy & Transportation, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
2023-1Q results continued a steady upward production trend and biannual gas price resetting that has lead to higher revenues, fund flow from operations, and earnings. Results were generally in line with expectations. Although gas sales and prices were previously disclosed, total revenues were slightly below expectations due to lower natural gas liquid pricing. Royalty rates fell sharply due to a restructuring and lower natural gas prices.
Sale decline further explained. April volumes averaged 1,972 boepd vs. 2023-1Q production of 2,767 boepd. Management cited reduced demand and higher nominated volumes from its partner in the Cabure unit. Sales in the Cabure field are subject to a partnership agreement based on reserves in the ground. Alvopetro’s partner can then nominate the amount of reserves that are sold from its “piggy bank.” Bahia Gas, the consumer of Alvopetro’s gas supply, can take gas on a firm or interruptible basis. For a 7-10 day period, it took gas primarily from firm customers decreasing the demand for other customers.
Equity Research is available at no cost to Registered users of Channelchek. Not a Member? Click ‘Join’ to join the Channelchek Community. There is no cost to register, and we never collect credit card information.
This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).
*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
Alvopetro Energy Ltd.’s vision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.
Michael Heim, Senior Vice President, Equity Research Analyst, Energy & Transportation, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Production growth combined with price increases is leading to rising revenues. 2023-1Q production rose to 2,767 boepd (up 11% annually and 2% sequentially). Monthly production had been reported, so results were in line with expectations. Realized gas prices were $12.06/mcf (up 20% annually and 8% sequentially). A biannual price adjustment in February resulted in higher rates. This was also disclosed previously, so pricing was in line with our expectations. Energy sales revenues were $18.2 million slightly below our $18.8 million estimate due to lower-than-expected oil and NGL sales.
Top line growth is flowing through to the bottom line. The company reported record Funds Flow From Operations of $15.0 million versus $10.9 million for the same period last year and above our $11.4 million estimate. Net income was $12.8 million ($0.33 per diluted share) versus $15.1 million ($0.30) also above our $9.1 million ($0.24) estimate.
Equity Research is available at no cost to Registered users of Channelchek. Not a Member? Click ‘Join’ to join the Channelchek Community. There is no cost to register, and we never collect credit card information.
This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).
*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
Alvopetro Energy Ltd.’s vision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.
Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Production running ahead of our modeling. January sales volumes averaged 2,754 boepd ahead of our 2023-1Q quarterly estimate of 2,710 boepd. This represents a 1% increase over 2022-4Q volumes and a 10% increase over 2022-1Q volumes. The year-over-year increase reflects an increase in processing volumes last summer to 3,000 boepd. Alvopetro will be bringing two new wells to production in the next few months which could further increase sales.
Prices rise again under semi-annual price redetermination. Realized natural gas prices will increase to an expected level of $12.40/mcf (includes price redetermination and various adjustments). Redeterminations are based on a variety of factors including oil prices, gas prices, and exchange rates subject to price adjustment floors and ceilings that rise each period. New prices reflect a 3.6% increase from the previous determination. As we have discussed in the past, current redeterminations would be as high as $15/mcf absent a ceiling and will most likely continue to rise each period even if energy prices decline.
Equity Research is available at no cost to Registered users of Channelchek. Not a Member? Click ‘Join’ to join the Channelchek Community. There is no cost to register, and we never collect credit card information.
This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).
*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
CALGARY, AB, Dec. 7, 2022 /CNW/ – Alvopetro Energy Ltd. (TSXV: ALV) (OTCQX: ALVOF) announces November 2022 sales volumes and an operational update.
November 2022 sales volumes
November sales volumes averaged 2,667 boepd, including natural gas sales of 15.2 MMcfpd and associated natural gas liquids sales from condensate of 135 bopd, based on field estimates, a decrease of 2% from the October 2022 average daily volumes and an increase of 1% from our Q3 2022 average.
Operational Update
We have now moved the service rig to our 182-C2 well on our 100% owned and operated Block 182 and expect to commence testing operations shortly. We completed drilling the 182-C2 well in October to a total measured depth (“MD”) of 3,185 metres. Testing of the 182-C2 well will begin with the Sergi Formation, the deepest of two formations with hydrocarbons shows during drilling. As previously announced, the well encountered a 223.7-metre-thick section with 121.3 metres of sand estimated above 6% porosity in the sand-dominated interval between 2,704.1 and 2,927.8 metres total vertical depth in the Sergi Formation. Caliper logs indicate that a significant amount of the wellbore in the Sergi interval contains washouts from drilling and is out of gauge, making open-hole log analysis challenging. As such, hydrocarbon potential in the Sergi will be validated through formation testing. Following testing of the Sergi Formation, testing will proceed up-hole to the Agua Grande Formation where, based on open-hole wireline logs, the well encountered 10.9 metres of potential net hydrocarbon pay, with an average porosity of 8.9% and average water saturation of 25.1%, using a 6% porosity cut-off, 50% Vshale cut-off and 50% water saturation cut-off. This testing will assess the extent, if any, of commercial hydrocarbons associated with the well, the productive capability of the well and will help define the field development plan.
Alvopetro Energy Ltd.’svision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
All amounts contained in this new release are in United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.
Abbreviations:
bbls = barrelsboepd = barrels of oil equivalent (“boe”) per daybopd = barrels of oil and/or natural gas liquids (condensate) per dayMMcf = million cubic feetMMcfpd = million cubic feet per day
BOE Disclosure. The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this news release are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
Testing and Well Results. Data obtained from the 182-C2 well identified in this press release, including hydrocarbon shows, open-hole logging, net pay and porosities and initial testing data, should be considered to be preliminary until detailed pressure transient and other analysis and interpretation has been completed. Hydrocarbon shows can be seen during the drilling of a well in numerous circumstances and do not necessarily indicate a commercial discovery or the presence of commercial hydrocarbons in a well. There is no representation by Alvopetro that the data relating to the 182-C2 well contained in this press release is necessarily indicative of long-term performance or ultimate recovery. The reader is cautioned not to unduly rely on such data as such data may not be indicative of future performance of the well or of expected production or operational results for Alvopetro in the future.
Forward-Looking Statements and Cautionary Language. This news release contains “forward-looking information” within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward‐looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning potential hydrocarbon pay in the 182-C2 well, exploration and development prospects of Alvopetro and the expected timing of certain of Alvopetro’s testing and operational activities. The forward‐looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to expectations and assumptions concerning testing results of the 183-B1 well and the 182-C2 well, equipment availability, the timing of regulatory licenses and approvals, the success of future drilling, completion, testing, recompletion and development activities, the outlook for commodity markets and ability to access capital markets, the impact of the COVID-19 pandemic, the performance of producing wells and reservoirs, well development and operating performance, foreign exchange rates, general economic and business conditions, weather and access to drilling locations, the availability and cost of labour and services, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, expectations regarding Alvopetro’s working interest and the outcome of any redeterminations, the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our annual information form which may be accessed on Alvopetro’s SEDAR profile at www.sedar.com. The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
CALGARY, AB, Nov. 15, 2022 /CNW/ – Alvopetro Energy Ltd. (TSXV:ALV); (OTCQX: ALVOF) is pleased to announce a 50% increase in our quarterly dividend, to US$0.12 per common share, an intention to launch a share buyback program under a normal course issuer bid (“NCIB”) and operating and financial results for the third quarter of 2022 including another record quarter of funds flow from operations of $13.3 million. We will host a live webcast to discuss Q3 2022 results on Wednesday November 16, 2022, beginning at 9:00 am Mountain time.
President & CEO, Corey C. Ruttan commented:
“With continued strong operating and financial results, and with our debt now fully repaid, we are pleased to announce a 50% increase in our quarterly dividend following on the 33% increase earlier this year. Our dividend program and the proposed NCIB will provide us with maximum flexibility to meet our strategy to maintain a balanced organic growth and stakeholder return model.”
All references herein to $ refer to United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.
Quarterly Dividend Increased 50% to $0.12 per Share
Alvopetro is pleased to announce that our Board of Directors has approved a 50% increase in our quarterly dividend, to $0.12 per common share, payable in cash on January 13, 2023, to shareholders of record at the close of business on December 30, 2022. This dividend is designated as an “eligible dividend” for Canadian income tax purposes.
Dividend payments to non-residents of Canada will be subject to withholding taxes at the Canadian statutory rate of 25%. Shareholders may be entitled to a reduced withholding tax rate under a tax treaty between their country of residence and Canada. For further information, see Alvopetro’s website at https://alvopetro.com/Dividends-Non-resident-Shareholders.
Normal Course Issuer Bid
In connection with our long-standing balanced and disciplined stakeholder return and organic growth model, our Board has provided approval to submit an application to launch a share buyback program under a NCIB, subject to securities law and customary approvals. Once approved, the NCIB, combined with our quarterly dividends, will provide us with flexibility in managing our returns to stakeholders.
Financial and Operating Highlights – Third Quarter of 2022
Daily sales averaged 2,642 boepd in Q3 2022, a 7% increase from the Q3 2021 average of 2,459 boepd and a 12% increase from the Q2 2022 average of 2,359 boepd. The expansion of our gas processing facility was completed at the end of July and available processing capacity has now increased to 500,000 m3/d (18 MMcfpd) contributing to higher volumes in the quarter.
As of August 1, 2022, Alvopetro’s natural gas price has been reset to the new ceiling price of $10.22/MMBtu. Due to the appreciation of the BRL in the first half of 2022 compared to second half of 2021, the BRL contracted price remained consistent at BRL1.94/m3. With all natural gas sales in Q3 2022 at the ceiling price, our average realized natural gas price increased to $11.18/Mcf compared to the Q3 2021 average price of $7.07/Mcf. Higher commodity prices and higher daily sales volumes resulted in a 67% increase in our natural gas, condensate and oil revenue compared to Q3 2021.
Our operating netback was $59.83 per boe in Q3 2022, an improvement of $23.45 per boe from Q3 2021 (+64%). Despite consistent BRL denominated natural gas pricing, our operating netback decreased $4.13 per boe from Q2 2022 (-6%) due to the devaluation of the BRL relative to the USD and lower Brent pricing on condensate.
We generated cash flows from operating activities of $13.8 million ($0.40 per basic share and $0.37 per diluted share) and funds flows from operations of $13.3 million ($0.39 per basic share and $0.36 per diluted share), increases of $6.6 million and $5.4 million, respectively compared to Q3 2021.
We reported net income of $8.8 million in Q3 2022 compared to a loss of $0.02 million in Q3 2021.
Capital expenditures totaled $8.7 million, and included drilling costs for our 183-B1, 182-C2 and Unit-C wells, testing costs on our 182-C1 well, long lead purchases and development costs on our Murucututu project.
All outstanding warrants were exercised in the quarter, with 1,342,978 warrants exercised by way of cashless exercise and 1,342,978 warrants exercised at a strike price of $1.80 per share. Alvopetro received cash proceeds of $2.4 million and issued a total of 2,081,616 common shares on the exercise.
We repaid the final $2.5 million outstanding on the credit facility and the facility has now been cancelled. As at September 30, 2022, we had a net working capital surplus of $12.2 million, including $17.4 million in cash and cash equivalents.
Our October 2022 sales volumes averaged 2,720 boepd based on field estimates, with natural gas sales of 15.6MMcfpd and natural gas liquids from condensate of 124 bopd.
The following table provides a summary of Alvopetro’s financial and operating results for three and nine months ended September 30, 2022 and September 30, 2021. The consolidated financial statements with the Management’s Discussion and Analysis (“MD&A) are available on our website at www.alvopetro.com and will be available on the System for Electronic Document Analysis and Retrieval (SEDAR) website at www.sedar.com.
Notes:
The 2021 comparative periods in the table above have been restated. See “Restatement of the 2021 Comparative Period” section within the MD&A and Note 14 of the unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2022 for further details.
Per share amounts are based on weighted average shares outstanding other than dividends per share, which is based on the number of common shares outstanding at each dividend record date. The weighted average number of diluted common shares outstanding in the computation of funds flow from operations and cash flows from operating activities per share is the same as for net income per share.
See “Non-GAAP and Other Financial Measures” section within this news release.
Third Quarter 2022 Results Webcast
Alvopetro will host a live webcast to discuss Q3 2022 financial results at 9:00 am Mountain time on November 16, 2022. Details for joining the event are as follows:
The webcast will include a question-and-answer period. Online participants will be able to ask questions through the Zoom portal. Dial-in participants can email questions directly to socialmedia@alvopetro.com.
Long-term Incentive Compensation Grants
In connection with our long-term incentive compensation program, Alvopetro’s Board of Directors (the “Board”) has approved the annual rolling grants to officers, directors and certain employees under Alvopetro’s Omnibus Incentive Plan. A total of 536,000 stock options, 122,000 restricted share units (“RSUs”) and 40,000 deferred share units (“DSUs”) were approved by the Board and are expected to be granted on November 24, 2022. Of the total grants, 248,000 stock options, 101,000 RSUs and 40,000 DSUs were granted to directors and officers. Each stock option, RSU and DSU entitles the holder to purchase one common share. Each stock option granted will have an exercise price based on the volume weighted average trading price of Alvopetro’s shares on the TSX Venture Exchange for the five (5) consecutive trading days up to and including November 24, 2022. All stock options, RSUs and DSUs granted expire five (5) years from the date of the grant.
Alvopetro Energy Ltd.’svision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
Abbreviations:
bbls
=
barrels
boepd
=
barrels of oil equivalent (“boe”) per day
bopd
=
barrels of oil and/or natural gas liquids (condensate) per day
BRL
=
Brazilian Real
m3
=
cubic metre
Mcf
=
thousand cubic feet
Mcfpd
=
thousand cubic feet per day
MMcf
=
million cubic feet
MMcfpd
=
million cubic feet per day
NGLs
=
natural gas liquids
Q2 2022
=
three months ended June 30, 2022
Q3 2021
=
three months ended September 30, 2021
Q3 2022
=
three months ended September 30, 2022
Non-GAAP and Other Financial Measures
This news release contains references to various non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures as such terms are defined in National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure. Such measures are not recognized measures under GAAP and do not have a standardized meaning prescribed by IFRS and might not be comparable to similar financial measures disclosed by other issuers. While these measures may be common in the oil and gas industry, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. The non-GAAP and other financial measures referred to in this report should not be considered an alternative to, or more meaningful than measures prescribed by IFRS and they are not meant to enhance the Company’s reported financial performance or position. These are complementary measures that are used by management in assessing the Company’s financial performance, efficiency and liquidity and they may be used by investors or other users of this document for the same purpose. Below is a description of the non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures used in this news release. For more information with respect to financial measures which have not been defined by GAAP, including reconciliations to the closest comparable GAAP measure, see the “Non-GAAP Measures and Other Financial Measures” section of the Company’s MD&A which may be accessed through the SEDAR website at www.sedar.com.
Non-GAAP Financial Measures
Operating netback
Operating netback is calculated as natural gas, oil and condensate revenues less royalties and production expenses. This calculation is provided in the “Operating Netback” section of the Company’s MD&A using our IFRS measures. The Company’s MD&A may be accessed through the SEDAR website at www.sedar.com. Operating netback is a common metric used in the oil and gas industry used to demonstrate profitability from operations.
Non-GAAP Financial Ratios
Operating netback per boe
Operating netback is calculated on a per unit basis, which is per barrel of oil equivalent (“boe”). It is a common non-GAAP measure used in the oil and gas industry and management believes this measurement assists in evaluating the operating performance of the Company. It is a measure of the economic quality of the Company’s producing assets and is useful for evaluating variable costs as it provides a reliable measure regardless of fluctuations in production. Alvopetro calculated operating netback per boe as operating netback divided by total sales volumes (barrels of oil equivalent). This calculation is provided in the “Operating Netback” section of the Company’s MD&A using our IFRS measures. The Company’s MD&A may be accessed through the SEDAR website at www.sedar.com. Operating netback is a common metric used in the oil and gas industry used to demonstrate profitability from operations on a per unit basis (boe).
Operating netback margin
Operating netback margin is calculated as operating netback per boe divided by the realized sales price per boe. Operating netback margin is a measure of the profitability per boe relative to natural gas, oil and condensate sales revenues per boe and is calculated as follows:
Funds Flow from Operations Per Share
Funds flow from operations per share is a non-GAAP ratio that includes all cash generated from operating activities and is calculated before changes in non-cash working capital, divided by the weighted the weighted average shares outstanding for the respective period. For the periods reported in this news release the cash flows from operating activities per share and funds flow from operations per share is as follows:
Capital Management Measures
Funds Flow from Operations
Funds flow from operations is a non-GAAP capital management measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. The most comparable GAAP measure to funds flow from operations is cash flows from operating activities. Management considers funds flow from operations important as it helps evaluate financial performance and demonstrates the Company’s ability to generate sufficient cash to fund future growth opportunities. Funds flow from operations should not be considered an alternative to, or more meaningful than, cash flows from operating activities however management finds that the impact of working capital items on the cash flows reduces the comparability of the metric from period to period. A reconciliation of funds flow from operations to cash flows from operating activities is as follows:
Net Working Capital
Net working capital is computed as current assets less current liabilities. Net working capital is a measure of liquidity, is used to evaluate financial resources, and is calculated as follows:
Working Capital Net of Debt
Working capital net of debt is computed as net working capital surplus decreased by the carrying amount of the Credit Facility. Working capital net of debt is used by management to assess the Company’s overall financial position.
Supplementary Financial Measures
“Average realized natural gas price – $/Mcf” is comprised of natural gas sales as determined in accordance with IFRS, divided by the Company’s natural gas sales volumes.
“Average realized NGL – condensate price – $/bbl” is comprised of condensate sales as determined in accordance with IFRS, divided by the Company’s NGL sales volumes from condensate.
“Average realized oil price – $/bbl” is comprised of oil sales as determined in accordance with IFRS, divided by the Company’s oil sales volumes.
“Average realized price – $/boe” is comprised of natural gas, condensate and oil sales as determined in accordance with IFRS, divided by the Company’s total natural gas, condensate and oil sales volumes (barrels of oil equivalent).
“Royalties per boe” is comprised of royalties, as determined in accordance with IFRS, divided by the total natural gas, condensate and oil sales volumes (barrels of oil equivalent).
“Production expenses per boe” is comprised of production expenses, as determined in accordance with IFRS, divided by the total natural gas, condensate and oil sales volumes (barrels of oil equivalent).
BOE Disclosure
The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6 Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this MD&A are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
Forward-Looking Statements and Cautionary Language
This news release contains forward-looking information within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward‐looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning the Company’s dividend policy, plans for dividends in the future, and the timing and taxation of such dividends, the Company’s intention to proceed with an NCIB, plans relating to the Company’s operational activities, the expected natural gas price, gas sales and gas deliveries under Alvopetro’s long-term gas sales agreement, exploration and development prospects of Alvopetro, the expected timing of certain of Alvopetro’s testing and operational activities, future results from operations, and the Company’s plans for dividends in the future. Forward-looking statements are necessarily based upon assumptions and judgments with respect to the future including, but not limited to, expected approvals and timing thereof with respect to an NCIB, equipment availability, the timing and results of testing the 183-B1 well, the 182-C2 well and the Unit C well, the success of future drilling, completion, recompletion and development activities, foreign exchange rates, expectations regarding Alvopetro’s working interest and the outcome of any redeterminations, the outlook for commodity markets and ability to access capital markets, the impact of the COVID-19 pandemic, the performance of producing wells and reservoirs, well development and operating performance, the timing of regulatory licenses and approvals, general economic and business conditions, forecasted demand for oil and natural gas, weather and access to drilling locations, the availability and cost of labour and services, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. In addition, the declaration, timing, amount and payment of future dividends remain at the discretion of the Board of Directors. Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our restated annual information form which may be accessed on Alvopetro’s SEDAR profile at www.sedar.com. The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
SOURCE Alvopetro Energy Ltd.
For further information: Corey C. Ruttan, President, Chief Executive Officer and Director, or Alison Howard, Chief Financial Officer, Phone: 587.794.4224, Email: info@alvopetro.com, www.alvopetro.com, TSX-V: ALV, OTCQX: ALVOF
CALGARY, AB, Nov. 7, 2022 /CNW/ – Alvopetro Energy Ltd. (TSXV: ALV) (OTCQX: ALVOF) announces initial results from the first interval tested in our 183-B1 well on our 100% owned and operated Block 183 and October 2022 sales volumes.
In July 2022, we completed drilling the 183-B1 exploration well to a total measured depth (“MD”) of 2,917 metres. Based on open-hole wireline logs and fluid samples confirming hydrocarbons, the well discovered hydrocarbons in multiple formations with a total of 34.3 metres of potential net hydrocarbon pay, with an average porosity of 10.6% and average water saturation of 29.0% using a 6% porosity cut-off, 50% Vshale cut-off and 50% water saturation cut-off.
Alvopetro has completed the 183-B1 formation test in the Sergi formation, the deepest of three formations with hydrocarbons shows during drilling of the well. We perforated a total of 26.5 metres in the Sergi formation at various intervals between 2,811 metres MD and 2,886 metres MD. We initially swabbed 63 bbls of oil and 7 bbls of completions fluid during the initially clean-up period. After a short shut-in we then initiated the production test. Cumulatively, over the duration of the 72-hour production test, we recovered 59 bbls of 43°API oil, 7 bbls of water identified as completion fluid, and 0.28 MMcf of associated gas. The daily oil rate recovered during swabbing operations averaged 20 bopd.
The 183-B1 well has now been shut-in to measure reservoir pressure and obtain pressure build‑up data to undertake a pressure transient analysis, which will help predict productivity of this first zone. After completing the pressure build-up test, the first interval will be suspended temporarily with a bridge plug and the test will proceed up-hole to test the Agua Grande formation.
October Sales Volumes
October sales volumes averaged 2,720 boepd, including natural gas sales of 15.6 MMcfpd and associated natural gas liquids sales from condensate of 124 bopd, based on field estimates, an increase of 3% over our average daily sales volumes in the third quarter. October sales volumes include initial sales volumes from our 183(1) well on our Murucututu project where we commenced production in mid-October following completion of the commissioning of field production facility. Our team continues to optimize the field production facility at the wellsite. Since coming on production, the well has averaged approximately 0.42 MMcfpd based on field estimates.
Q3 2022 Results Webcast
Alvopetro anticipates announcing Q3 2022 results on November 15, 2022 after markets close and will host a live webcast to discuss the results at 9:00 am Mountain time on November 16, 2022. Details for joining the event are as follows:
The webcast will include a question-and-answer period. Online participants will be able to ask questions through the Zoom portal. Dial-in participants can email questions directly to socialmedia@alvopetro.com.
Alvopetro Energy Ltd.’svision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
All amounts contained in this new release are in United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.
Abbreviations:
API
=
American Petroleum Institute
°API
=
an indication of the specific gravity of crude oil measured on the API gravity scale.
bbls
=
barrels
boepd
=
barrels of oil equivalent (“boe”) per day
bopd
=
barrels of oil and/or natural gas liquids (condensate) per day
MMcf
=
million cubic feet
MMcfpd
=
million cubic feet per day
BOE Disclosure. The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this news release are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
Testing and Well Results. Data obtained from the 183-B1 well identified in this press release, including hydrocarbon shows, open-hole logging, net pay and porosities and initial testing data, should be considered to be preliminary until detailed pressure transient and other analysis and interpretation has been completed. Hydrocarbon shows can be seen during the drilling of a well in numerous circumstances and do not necessarily indicate a commercial discovery or the presence of commercial hydrocarbons in a well. There is no representation by Alvopetro that the data relating to the 183-B1 well contained in this press release is necessarily indicative of long-term performance or ultimate recovery. The reader is cautioned not to unduly rely on such data as such data may not be indicative of future performance of the well or of expected production or operational results for Alvopetro in the future.
Forward-Looking Statements and Cautionary Language. This news release contains “forward-looking information” within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward‐looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning potential hydrocarbon pay in the 183-B1 well, anticipated production from our Murucututu project, exploration and development prospects of Alvopetro and the expected timing of certain of Alvopetro’s testing and operational activities. The forward‐looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to expectations and assumptions concerning testing results of the 183-B1 well and the 182-C2 well, equipment availability, the timing of regulatory licenses and approvals, the success of future drilling, completion, testing, recompletion and development activities, the outlook for commodity markets and ability to access capital markets, the impact of the COVID-19 pandemic, the performance of producing wells and reservoirs, well development and operating performance, foreign exchange rates, general economic and business conditions, weather and access to drilling locations, the availability and cost of labour and services, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, expectations regarding Alvopetro’s working interest and the outcome of any redeterminations, the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our annual information form which may be accessed on Alvopetro’s SEDAR profile at www.sedar.com. The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
