U.S. Treasury Secretary Janet Yellen escalated trade tensions with China over its massive subsidies for green industries like electric vehicles, solar panels and batteries. During her recent four-day visit to Beijing, Yellen bluntly warned that the Biden administration “will not accept” American industries being decimated by a flood of cheap Chinese exports – a repeat of the “China shock” that hollowed out U.S. manufacturing in the early 2000s.
At the heart of the dispute are allegations that China has massively overinvested in renewable energy supply chains, building factory capacity far exceeding domestic demand. This excess output is then exported at artificially low prices due to Beijing’s subsidies, undercutting firms in the U.S., Europe and elsewhere.
“Over a decade ago, massive Chinese government support led to below-cost Chinese steel that flooded the global market and decimated industries across the world and in the United States,” Yellen said. “I’ve made it clear that President Biden and I will not accept that reality again.”
While not threatening immediate tariffs or trade actions, the stark warning shows Washington is seriously considering punitive measures if Beijing does not rein in subsidies and overcapacity. Yellen said U.S. concerns are shared by allies like Europe and Japan fearing a glut of unfairly cheap Chinese green tech imports.
For its part, China is pushing back hard. Officials argue the U.S. is unfairly portraying its renewable energy firms as subsidized, understating their innovation. They claim restricting Chinese electric vehicle imports would violate WTO rules and deprive global markets of key climate solutions.
Escalating tensions over green tech subsidies could disrupt trade flows and supply chains for renewable energy developers, electric automakers, battery manufacturers and more across multiple continents. Some key impacts for investors:
Rising Costs: Potential tariffs on Chinese solar panels, wind turbines, EV batteries and other components could increase costs for green energy projects in the U.S. and allied countries, slowing roll-out.
Shifting Competitive Landscape: Non-Chinese exporters of renewable hardware like solar from countries like South Korea, Vietnam or India may benefit from U.S. trade actions against China, increasing overall competition.
Consumer Prices: Green tech price inflation could be passed through to consumers for products like rooftop solar systems, home batteries and EVs if tariffs increase costs.
Strategic Decoupling: If tensions escalate towards a full “decoupling”, it could accelerate efforts by the U.S., Europe and others to secure their supply chains by bringing more critical green industries in-house through domestic investments and subsidies.
Stock Impacts: Depending on how tensions unfold, stocks of firms exposed to U.S.-China green tech trade flows could face volatility and disruptions in both directions. Tariffs would likely create clear winners and losers.
For now, Yellen says new forums for discussions have been created to potentially resolve overcapacity concerns. However, her blunt warnings suggest the U.S. will not hesitate to take tougher actions to protect America’s fledgling renewable energy and electric vehicle industries from alleged unfair Chinese trade practices.
Ford Motor Company has pumped the brakes on its plans to rapidly electrify its vehicle lineup, announcing delays for two hotly anticipated all-electric models – a three-row SUV and a pickup truck. The automaker cited the need to allow more time for consumer demand and new battery technologies to develop further before committing to these capital-intensive vehicle programs.
The multi-row electric SUV initially targeted for production in 2025 at Ford’s Oakville, Canada plant has been pushed back to at least 2027. And the electric pickup previously slated for late 2025 is now not expected until 2026. This recalibrated roadmap represents a significant detour from Ford’s earlier aggressive EV roadmap, and has notable implications both for Ford and the overall electric vehicle market trajectory.
For Ford, the delays allow the company to be more judicious with its investments at a time when EV adoption has been slower and more costly than many projected. Ford lost $4.7 billion on its electric vehicle efforts in 2023 alone. By taking a more measured approach, Ford can hopefully time these program launches better with consumer readiness and technological advancements that could make the vehicles more compelling and profitable.
However, the setbacks also risk Ford falling behind leaders like Tesla, Hyundai/Kia, and Chinese EV makers BYD and Xiaomi in the fierce electric vehicle battle. Both Tesla and Hyundai/Kia outsold Ford’s EV lineup in the first quarter of 2024, while BYD is gearing up to launch its first electric pickup truck to challenge Ford in that key segment.
For investors, Ford’s pulled-back EV plans could be seen as a prudent way to limit the staggering losses in that part of the business for now. But it also injects more uncertainty around Ford’s long-term EV positioning and market share outlook. Competition is intensifying rapidly with new electric offerings from virtually every major automaker, including emerging players like Xiaomi looking to grab a piece of the EV pie.
Tesla maintains a clear lead, but its growth has slowed as rivals have released more compelling electric models across more vehicle segments. If companies like Hyundai, GM, Volkswagen, BYD and others can continue gaining traction, Ford could find itself scrambling if it is late to market with mainstream electric SUV and truck options that are so pivotal to its product mix.
The EV delays underscore the challenging transitions legacy automakers face in balancing investments for the electric future while still deriving most of their profits from sales of internal combustion engine vehicles today. Stock investors seem to be giving Ford the benefit of the doubt for now, with shares trading close to 52-week highs. But delivering on execution with these postponed electric models has become even more crucial for Ford to remain relevant and profitable over the long haul as new EV competitors emerge.
Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.
Refer to the bottom of the report for important disclosures
Energy stocks outpaced the general overall market in the March quarter due to a rise in oil prices. Higher oil prices reflect improving global economics and Middle East concerns. Natural gas prices continued to fall due to warm weather and high storage levels.
The United States is ramping up the export of oil and liquified natural gas. Oil exports have helped offset a reduction in OPEC exports. The United States, once a large importer of LNG, is now the largest exporter. LNG exports have helped European countries replace gas from Russia.
Balance sheets have improved and management has become more disciplined. Most energy companies used the recent strength in energy prices to pay down debt and repurchase shares instead of expanding operations. This new-found discipline leaves the companies in a good position to make investments quickly should energy prices rise, which we believe could happen with an improvement in global economic conditions.
We remain positive on the sector. We look for energy companies, especially those focused on oil, to continue to outpace the overall market should energy prices rise.
Energy stocks, as measured by the Energy Select Sector SPDR Fund (XLE), rose 12.9% during the quarter ended March 31, 2024. The increase was slightly higher than the 10.2% increase in the S&P Composite index. Energy stocks were boosted by a 16.1% increase in the May oil futures prices, which more than offset a 29.9% decrease in the May natural gas futures price.
At current oil prices, domestic producers are able to produce oil at profitable levels. Oil production has grown from 5 million barrels of oil per day (mmboe/d) in 2008 to the current level above 12 mmboe/d. Most of the production has come from increased drilling in the Permian Basin. Rig count has risen steadily in recent years to a level above 500 rigs but remains well below the 1600 rig level seen as recently as 2012. Increase production from fewer rigs demonstrated productivity gains in recent years as well as an increased focus on drilling in the Permian Basin, an area with high initial flow rates.
Figure #1
As domestic production grows, the United States has taken on an increased role supplying oil across the world. Oil exports have grown steadily in recent years. U.S. production has largely replaced the import of oil from OPEC which has declined from 0.20 million barrels of oil per day in 2008 to 0.03 million mmboe/d in January 2024.
Figure #2
An even more dramatic story can be told regarding natural gas production. Production continues to rise even as natural gas prices remain weak. Higher production comes despite a reduction in natural gas rigs from a peak level near 1600 in 2008 to the current level of 112. Once again, increased productivity comes due to a focus on drilling in areas with shale formations where horizontal drilling and fracking greatly increase initial production rates.
Figure #3
The United States has been steadily increasing the amount of liquified natural gas it exports. In fact, the United States has recently become the largest exporter of LNG. This transformation from being the largest importer of LNG to becoming the largest exporter has taken place in less than 20 years. Much of the increase in exports reflects increased deliveries to European countries in response to a decrease in natural gas from Russia.
Figure #4
The increased involvement in the global energy trade has improved the profitability of domestic producers. Most producers are receiving high netbacks at current energy prices. This is especially true for producers focused on oil. With strong balance sheets and a new-found management discipline that focuses on rewarding shareholders over expanding operations, we believe most energy companies are well positioned to grow earnings and cash flow at current prices. At the same time, they are able to expand operations should prices rise, as we believe could happen as global economic conditions improve. We look for energy stocks to continue their strength and maintain our favorable outlook on the group.
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Senior Equity Analyst focusing on Basic Materials & Mining. 20 years of experience in equity research. BA in Business Administration from Westminster College. MBA with a Finance concentration from the University of Missouri. MA in International Affairs from Washington University in St. Louis. Named WSJ ‘Best on the Street’ Analyst and Forbes/StarMine’s “Best Brokerage Analyst.” FINRA licenses 7, 24, 63, 87
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In a major boost to its ambitious renewable energy growth plans, Aemetis, Inc. has received approval from U.S. immigration authorities for $200 million in low-cost funding from foreign investors through the EB-5 Immigrant Investor Visa Program. This influx of capital will support construction of several key initiatives at the forefront of Aemetis’ drive to replace petroleum-based products with renewable alternatives.
The $200 million EB-5 investment will primarily fund three transformative projects – the development of a cutting-edge sustainable aviation fuel (SAF) production plant in Riverbank, California, a vast network of dairy farms generating renewable natural gas, and systems to capture and sequester carbon emissions.
At the centerpiece is Aemetis’ newly permitted Riverbank SAF refinery, designed to produce a staggering 78 million gallons of the low-carbon fuel annually to meet skyrocketing demand from airlines. The company has already secured over $3 billion worth of SAF supply contracts with major carriers desperate to reduce their environmental footprint and comply with tightening regulations.
“This $200 million of EB-5 funding provides us with attractive low-interest capital to construct our sustainable aviation fuel plant and build out other negative carbon intensity projects like dairy biogas and CO2 sequestration,” said Eric McAfee, CEO of Aemetis. “These investments will be transformative for our company’s growth.”
The EB-5 program, created in 1990, allows foreign investors to obtain U.S. permanent residency through investing substantial funds into domestic projects that create full-time jobs in high unemployment areas or rural regions. Aemetis’ projects qualified by being located at the company’s existing ethanol production facility in Keyes and the new Riverbank plant site, both classified as high unemployment zones by authorities.
In total, 245 foreign investors were approved to participate by providing $800,000 each, joining 8 others who had previously invested $4 million. The $200 million sum represents a considerable capital raise for Aemetis on highly attractive terms, enabling the company to expand its suite of renewable offerings.
In addition to the SAF refinery, funds will go towards building out the company’s dairy renewable natural gas operations across California’s Central Valley. Aemetis plans to construct biodigesters to capture methane from cattle waste at numerous dairy farms, which will then be processed into pipeline-quality renewable natural gas (RNG) as an ultra-low carbon substitute for fossil gas. The funding will cover new gas pipelines, biofuel conversion facilities, and RNG fueling stations to service this rapidly growing market.
A portion of the EB-5 investment is also earmarked for carbon capture and sequestration systems at Aemetis’ biorefineries, furthering efforts to shrink the company’s carbon footprint to negative levels. By safely storing emissions underground, Aemetis aims to produce some of the most environmentally friendly and low carbon-intensity biofuels, bioenergy, and biomaterials in the world.
“The EB-5 funding, combined with our other financing sources like 20-year USDA loans, provide the growth capital for Aemetis to construct large-scale projects in line with our bold Five Year Plan,” McAfee stated. “We deeply appreciate the confidence shown by these investors in our vision for revolutionizing the renewable fuels landscape.”
As global demand for sustainable energy solutions continues rising, the $200 million EB-5 infusion positions Aemetis at the forefront of this transition, paving the way for its pioneering dairy biogas, carbon-negative biofuels, and other low-carbon innovations to scale up rapidly in the coming years.
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.
Hemisphere announced an independent evaluation of its reserves highlighting a 5% increase in NPV10 value for proved reserves. The estimated value for total proved reserves (PR) when discounted back at a 10% rate was $325 million ($3.27 per share) versus $308 million in the reserve from last year. The increase reflects higher West Canada Select oil prices in future years with the completion of the Trans Mountain Pipeline running from Alberta to the Pacific Coast. The value of proved developed producing (PDP) reserves rose 9% as the company was active drilling in 2023 and moving reserves into the PDP category.
The company was able to replace reserves reduced by production through drilling and acquisition. Hemisphere produced 1.1 mmboe in 2023 and added 1.0 mmboe of reserves through the drillbit or from acquisition. As a result, proved reserves were 12.1 mmboe in the most recent report versus 12.2 mmboe last year. The company spent $16 million to drill eight wells in addition to purchasing land and seismic. Just two years ago, capital expenditures were only $8 million. Finding, Development and Acquisition costs per proved reserve added in 2023 were $14.82/boe, an attractive price given current oil prices.
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InPlay Oil is a junior oil and gas exploration and production company with operations in Alberta focused on light oil production. The company operates long-lived, low-decline properties with drilling development and enhanced oil recovery potential as well as undeveloped lands with exploration possibilities. The common shares of InPlay trade on the Toronto Stock Exchange under the symbol IPO and the OTCQX Exchange under the symbol IPOOF.
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.
Quarterly production in line with recently reduced guidance. InPlay reported 2023 production volume of 9,025 boe/day consistent with guidance of 9,000-9,100 boe/day. We had expressed concern that the previous decline in guidance reflected a sharper production decline curve than previously expected. Management assures that the decline curve has not changed and the decline reflects a shift towards drilling oil wells which have a lower initial production rate than gas wells.
InPlay released a reserve report for the 2023 year end. The reserve report shows a modest reduction in reserves and reserve value implying a reserve replacement rate slightly below 1.0 times. The calculation is somewhat complicated by changing assumptions regarding assumed energy pricing and recoverability. The report indicated a finding, development and acquisition cost of $23.36/boe which is attractive compared to current prices.
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*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.
Motorists across the nation are once again feeling the pinch at the gas pump as oil prices have climbed sharply in recent months. After a brief reprieve earlier this year, the national average price for a gallon of regular gasoline has risen over 18 cents in just the last month to around $3.40 according to AAA data. Experts warn that prices could jump another 10-15 cents over the next couple of weeks alone.
The primary culprit behind the surge is the rising cost of crude oil. Both the U.S. benchmark West Texas Intermediate and the global Brent crude have seen prices spike, with WTI crude now hovering around $79 per barrel and Brent north of $83 per barrel. Just a few months ago, WTI started 2024 just over $70 a barrel.
As crude gets more expensive for refiners to purchase, the costs get passed along to consumers in the form of higher gasoline prices. Tighter supplies and seasonal factors are also contributing to price increases at the pump.
“This week, Gulf Coast refiners began transitioning to more expensive summer blend gasoline, which accounts for nearly 50% of the nation’s refining capacity,” said Andy Lipow of Lipow Oil Associates. “That switch means higher prices are ahead.”
California drivers are being hit particularly hard, with the statewide average price per gallon already at a lofty $4.88 as of Wednesday. Refinery maintenance, lower inventory levels, and the changeover to summer blends have caused California gas prices to jump around 25 cents in recent weeks according to Lipow.
The overall lower supply situation is being exacerbated by disruptions at some key refineries. For example, BP’s massive Whiting refinery in Indiana, the largest in the Midwest, is still recovering from a recent power outage caused by cold weather that impacted production.
Historically, spring represents the start of the annual rise in gas prices as refiners transition to summer blends and demand picks up with more drivers hitting the road after the winter months. Consumer demand typically peaks during summer’s peak driving season.
While higher energy costs were one of the main factors driving an unexpected increase in inflation in February, rising gas prices take an oversized toll on household budgets. The latest Consumer Price Index data showed the gasoline index spiked 3.8% last month alone after declining in January.
Analysts caution there is likely more pain at the pump on the horizon with the summer driving season still ahead. Unless crude oil prices reverse course or refining capacity increases, American drivers can expect gasoline to remain unusually expensive compared to this time last year.
“With the industry having less refining capacity and the economy remaining relatively strong, I expect retail gasoline prices to set new records across the nation in the coming months,” Lipow stated.
Whether taking a road trip for spring break or commuting to and from work and activities, consumers have little choice but to absorb the impact of elevated gas prices cutting into other spending. Budgets will be further squeezed if crude oil costs remain stubbornly high and gasoline supply remains tight.
CALGARY AB, March 13, 2024 /CNW/ – InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) announces its financial and operating results for the three and twelve months ended December 31, 2023, and the results of its independent oil and gas reserves evaluation effective December 31, 2023 (the “Reserve Report”) prepared by Sproule Associates Limited (“Sproule”). InPlay’s audited annual financial statements and notes, as well as Management’s Discussion and Analysis (“MD&A”) for the year ended December 31, 2023 will be available at “www.sedarplus.ca” and our website at “www.inplayoil.com“. An updated presentation will be available soon on our website.
2023 Financial and Operations Highlights:
Achieved average annual production of 9,025 boe/d(1) (58% light crude oil and NGLs) and average quarterly production of 9,596 boe/d(1) (59% light crude oil and NGLs) in the fourth quarter, an increase of 7% compared to 9,003 boe/d(1) (57% light crude oil and NGLs) in the third quarter of 2023.
Achieved a quarterly record for light oil production of 4,142 bbl/d in the fourth quarter of 2023.
Generated strong adjusted funds flow (“AFF”)(2) of $91.8 million ($1.03 per basic share(3)), the second highest level ever achieved by the Company, despite WTI prices decreasing 18% and AECO natural gas prices decreasing 50% compared to 2022.
Realized strong operating income profit margins of 58% during 2023 notwithstanding the significant benchmark commodity price decreases.
Returned $16.5 million to shareholders through our monthly base dividend and normal course issuer bid (“NCIB”) share repurchases, representing an annual yield of 8.2% relative to year-end market capitalization. Since November 2022 InPlay has distributed $22.8 million in dividends, or $0.255 per share including dividends declared to date in 2024.
Recorded net income of $32.7 million ($0.37 per basic share; $0.36 per diluted share). InPlay has now returned to a positive retained earnings position on the balance sheet demonstrating that the Company has generated positive earnings since inception (net of dividends paid).
Invested $84.5 million to drill, complete and equip 12 (10.5 net) Extended Reach Horizontal (“ERH”) wells in Willesden Green, five (5.0 net) ERH wells in Pembina, one (1.0 net) multilateral Belly River well and three (0.6 net) non-operated ERH wells in Willesden Green, in addition to capital spent on two major natural gas facility upgrades to increase operated natural gas takeaway capacity for future growth.
Exited 2023 at 0.5x net debt to earnings before interest, taxes and depletion (“EBITDA”)(2) which is among the lower leverage ratios amongst our peers.
Renewed our revolving Senior Credit Facility with a total lending capacity and borrowing base of $110 million, providing significant liquidity to be used for tactical capital investment and strategic acquisitions.
Dedicated $3.3 million to the successful abandonment of 29 (23.1 net) wellbores, 114 (103.3 net) pipelines and the reclamation of 35 (29.3) wellsites.
2023 Reserve Highlights:
An organic 2023 capital program without acquisition/disposition (“A&D”) activity resulted in:
Proved developed producing (“PDP”) reserves of 17,293 mboe (56% light and medium crude oil & NGLs)
Proved developed non-producing (“PDNP”) reserves of 1,002 mboe (76% light and medium crude oil & NGLs) are expected to move to the PDP reserve category throughout the year, with over 60% of the related wells expected to be finished and on production in the first half of 2024.
Total proved (“TP”) reserves of 45,919 mboe (62% light and medium crude oil & NGLs)
Total proved plus probable (“TPP”) reserves of 61,594 mboe (63% light and medium crude oil & NGLs)
On a year-over-year basis, PDP, TP and TPP reserves remained relatively unchanged.
Reserves life index (“RLI”)(6) for PDP, TP and TPP of approximately 5.2 years, 13.9 years and 18.7 years, respectively highlight a sizable drilling inventory for InPlay to sustainably develop over time.
Delivered TPP Finding, Development and Acquisition (“FD&A”) costs (including changes in future development costs) of $23.36/boe notwithstanding $7 million in capital expenditures spent on non-recurring facility projects in 2023 to enhance our natural gas takeaway capacity. This generated a recycle ratio of 1.4x based on an operating netback of $31.61/boe.
Achieved healthy NPV BT10 reserve values(5):
NPV BT10:
PDP: $242 million
PDP+PDNP: $261 million
TP: $571 million
TPP: $824 million
Message to Shareholders:
InPlay had another year of solid operational and financial performance in 2023 while continuing to deliver strong returns to shareholders and maintaining a solid balance sheet. The continued development of our drilling inventory has yielded consistent and sustainable results, with our team constantly evaluating options to provide further shareholder returns.
Average 2023 production of 9,025 boe/d(1) generated AFF of $91.8 million ($1.03 per share). InPlay returned $16.5 million to shareholders through our monthly base dividend and normal course issuer bid (“NCIB”) share repurchases. The Company maintained its balance sheet strength with a net debt to EBITDA ratio of 0.5x and total debt capacity of $110 million, allowing the financial flexibility to take advantage of strategic opportunities and weather periods of market volatility.
InPlay achieved strong before tax estimated net present values (“NPV”) of future net revenues associated with our 2023 year-end reserves and discounted at 10% (“NPV BT10”) although impacted by weaker future commodity prices in comparison to December 31, 2022. Forecasted WTI and AECO prices used in the Reserve Report decreased by 8% and 48% in year one and 4% and 23% in year two respectively. The Company achieved NPV BT10 reserve values of $242 million (PDP), $571 million (TP) and $824 million (TPP) based on a three independent reserve evaluator average pricing, cost forecast and foreign exchange rates as at December 31, 2023 as used in the Reserve Report.
InPlay remains focused on disciplined development of our high rate of return assets with a focus on maximizing free adjusted funds flow alongside a reasonable production growth profile while maintaining conservative leverage ratios, with the ultimate goal of maximizing returns to shareholders. The Company will remain disciplined and flexible and can quickly adjust capital activity to respond to changing market conditions.
Outlook and Operations Update:
InPlay’s capital program for the first quarter of 2024 started with a two (1.9 net) ERH well pad in Willesden Green which came on production at the end of February and is in the early stages of cleanup. Drilling of three (3.0 net) Pembina Cardium ERH wells has been completed with completion operations currently underway. These wells are expected to come on production by the end of March and offset five successful wells drilled in 2023 characterized by low decline rates and high light oil and liquids weightings. An additional two (0.3 net) non-operated Willesden Green ERH wells have recently been drilled, are being completed, and are expected to come online in mid-March with another one (0.35 net) non-operated Willesden Green ERH well drilled in March and expected to be on production in the second quarter.
The Company’s first (1.0 net) multilateral Belly River horizontal well was brought on production in December. The well has been on production with no decline and is meeting internal expectations with initial production (“IP”) rates of 84 boe/d (96% light crude oil and liquids) and 89 boe/d (97% light crude oil and liquids) over its first 30 and 60 days respectively. The Belly River is characterized by high quality sweet light oil that receives premium pricing to our realized benchmark MSW commodity price. We are encouraged by the results that we are seeing from this well and will continue to evaluate expanding the use of this technology on further potential areas in our Belly River play.
WTI prices remained volatile early in 2024 but have improved throughout the quarter to approximately US $78/bbl, exceeding the US $75/bbl assumption utilized in our previously released 2024 budget. Future differentials to WTI, including MSW , are forecasted to significantly improve by 55% – 60% throughout the balance of the year compared to the fourth quarter of 2023 and first quarter of 2024 as new pipeline capacity comes online in the second quarter. The relatively weak Canadian dollar is supportive of the Canadian crude oil price environment and is expected to continue throughout the year. Natural gas prices have been challenged with warmer than average temperatures impacting winter demand resulting in weak AECO prices forecasted through to the end of the summer. InPlay has implemented crude oil and natural gas hedges at favorable pricing levels to mitigate risk and add stability during periods of market volatility.
As previously announced, InPlay’s Board of Directors approved a 2024 capital budget of $64 – $67 million which is forecast to result in annual average production of 9,000 – 9,500 boe/d(1) (59% – 61% light crude oil and NGLs). InPlay has taken a measured and disciplined approach to capital allocation for 2024 with a program focused on high return oil weighted locations driving annual oil production growth at the midpoint of guidance of approximately 7% over 2023 despite a 20% to 25% reduction in capital spending year over year. The capital program is designed to responsibly manage the pace of development, maintain operational and financial flexibility and remain focused on delivering return of capital to shareholders. The Company achieved record quarterly light oil production of 4,142 bbl/d and increased our light oil and NGLs weighting to 59% in the fourth quarter of 2023. This higher weighting of light oil and NGLs is expected to continue in 2024 as a result of our oil focused drilling program, allowing the Company to take advantage of the strong oil price environment which is the Company’s main revenue and AFF driver.
Production averaged 9,025 boe/d(1) (58% light crude oil & NGLs) in 2023 compared to 9,105 boe/d(1) (57% light crude oil & NGLs) in 2022. Production averaged 9,596 boe/d(1) (59% light crude oil & NGLs) in the fourth quarter of 2023, a 7% increase in comparison to the third quarter of 2023. Production for 2023 was impacted by approximately 650 boe/d over the year due to extraordinary curtailments experienced from third party capacity constraints and turnarounds, Alberta wildfires, and delays in starting up our natural gas facility in the third quarter as discussed in our prior press releases.
In 2023, commodity prices decreased over 2022 levels. WTI oil prices decreased 18% predominantly as a result of increased supply and sentiment on future demand. Natural gas prices weakened due to production growth in North America with higher than normal inventory levels in North America and Europe, resulting in a 50% decrease in AECO pricing compared to 2022. These lower commodity prices resulted in a 24% decline in our realized sales price driving a decrease to AFF and netbacks compared to 2022, which was partially offset by realized hedging gains.
InPlay’s capital program for 2023 consisted of $84.5 million of development capital. The Company drilled, completed and brought on production 12 (10.5 net) Extended Reach Horizontal (“ERH”) wells in Willesden Green, five (5.0 net) ERH wells in Pembina, one (1.0 net) multilateral Belly River well and three (0.6 net) non-operated ERH well in Willesden Green. This activity amounted to the drilling of 21 gross (17.1 net) wells. Capital activity in 2023 was also focused on expanding and upgrading our natural gas facility infrastructure to accommodate future growth. InPlay completed two major facility upgrades in 2023 to increase operated natural gas takeaway capacity and to mitigate potential production issues arising from third party outages and capacity constraints. These projects have already shown value by reducing back pressure on wells and lowering declines while improving our liquids weighting with higher natural gas liquids recovery. After the completion of these projects, more consistent run times and the transportation of associated natural gas to our lower cost operated facilities has resulted in operating costs trending downward in the last quarter of 2023 which is expected to continue into 2024.
Notes:
1.
See “Production Breakdown by Product Type” at the end of this press release.
2.
Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures” contained within this press release and in our most recently filed MD&A.
3.
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
4.
Supplementary financial measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
5.
See “Corporate Reserves Information” for detailed information from the Reserve Report and associated NPV calculations.
6.
“FD&A”, “recycle ratio”, “reserve life index” and “capital efficiency” do not have standardized meanings and therefore may not be comparable to similar measures presented for other entities. Refer to section “Performance Measures” for the determination and calculation of these measures.
7.
Based on a current share price of $2.30.
Corporate Reserves Information:
The following summarizes certain information contained in the Reserve Report. The Reserve Report was prepared in accordance with the definitions, standards and procedures contained in the COGE Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form (“AIF”) which will be filed on SEDAR by the end of March 2024.
Net Present Values of Reserves:
December 31, 2023
BTAX NPV 5%
BTAX NPV 10%
($000’s)
($000’s)
PDP NPV(1)(2)
271,987
242,298
TP NPV(1)(2)
744,150
571,097
TPP NPV(1)(2)
1,098,195
823,589
Notes:
1.
Evaluated by Sproule as at December 31, 2023. The estimated NPV does not represent fair market value of the reserves.
2.
Based on an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2023.
Future Development Costs (“FDCs”):
The following FDCs are included in the 2023 Reserve Report:
($millions)
TP
TPP
2024
55.9
55.9
2025
97.5
106.6
2026
91.8
112.2
2027
105.6
115.2
Remainder
79.8
118.6
Total undiscounted FDC
430.7
508.5
Total discounted FDC at 10% per year
338.6
394.6
Note: FDC as per Reserve Report based on forecast pricing as outlined in the table herein entitled “Pricing Assumptions”
The $509 million of total FDC in the Reserve Report generates approximately $521 million in future net present value discounted at 10%.
Performance Measures:
2021
2022
2023
3 Year Avg
Average WTI crude oil price (US$/bbl)
67.91
94.23
77.62
79.92
FD&A Costs(1)
70,486
76,081
83,085
76,551
Production boe/d – FY(3)
5,768
9,105
9,025
7,966
Operating netback $/boe – FY(2)
34.63
45.90
31.61
37.78
Proved Developed Producing
Total Reserves mboe
15,890
17,653
17,293
16,945
Reserves additions mboe
8,318
5,086
2,935
5,446
FD&A (including FDCs) $/boe(1)
8.47
14.96
28.31
14.06
FD&A (excluding FDCs) $/boe(1)
8.47
14.96
28.31
14.06
Recycle Ratio(4)
4.1
3.1
1.1
2.7
RLI (years)(5)
7.5
5.3
5.2
5.8
Total Proved
Total Reserves mboe
45,891
46,464
45,919
46,091
Reserves additions mboe
26,372
3,897
2,748
11,006
FD&A (including FDCs) $/boe(1)
12.03
24.04
28.92
14.86
FD&A (excluding FDCs) $/boe(1)
2.67
19.52
30.23
6.96
Recycle Ratio(4)
2.9
1.9
1.1
2.5
RLI (years)(5)
21.8
14.0
13.9
15.9
Proved Plus Probable
Total Reserves mboe
60,640
61,842
61,594
61,359
Reserves additions mboe
29,929
4,525
3,047
12,500
FD&A (including FDCs) $/boe(1)
9.56
27.02
23.36
12.79
FD&A (excluding FDCs) $/boe(1)
2.36
16.81
27.27
6.12
Recycle Ratio(4)
3.6
1.7
1.4
3.0
RLI (years)(5)
28.8
18.6
18.7
21.1
Notes:
1.
Finding, Development & Acquisition (“FD&A”) costs are used as a measure of capital efficiency. The calculation includes the period’s capital expenditures, including Exploration and Development (“E&D”) and Acquisition and Disposition (“A&D”) expended in the year, less capitalized G&A expenses and undeveloped land expenditures acquired with no reserves. This total of capital expenditures, including the change in the FDC over the period, is then divided by the change in reserves, other than from production, for the period incorporating additions/reductions from extensions, infill drilling, technical revisions, acquisitions/dispositions and economic factors. For example: 2023 TPP = ($84.5 million capital expenditures – PP&E and E&E – $1.7 million capitalized G&A – $nil of land acquisitions + $0.3 property acquisitions – $11.9 million change in FDCs) / (61,594 mboe – 61,842 mboe + 3,294 mboe) = $23.36 per boe. Finding and Development Costs (“F&D”) are calculated the same as FD&A costs, however adjusted to exclude the capital expenditures and reserve additions/reductions from acquisition/disposition activity. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
2.
Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures” contained within this press release and our most recently filed MD&A.
3.
See “Reader Advisories – Production Breakdown by Product Type”
4.
Recycle Ratio is calculated by dividing the year’s operating netback per boe by the FD&A costs for that period. For example: 2023 TPP = ($31.61/$23.36) = 1.4. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
5.
RLI is calculated by dividing the reserves in each category by the 2023 average annual production. For example 2023 TPP = (61,594 mboe) / (9,025 boe/d) = 18.7 years. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
Pricing Assumptions:
The following tables set forth the benchmark reference prices, as at December 31, 2023, reflected in the Reserve Report. These price and cost assumptions were an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast and Sproule’s foreign exchange rate forecast at the effective date of the Reserve Report.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS (1) as of December 31, 2023 FORECAST PRICES AND COSTS
Year
WTICushingOklahoma($US/Bbl)
CanadianLight Sweet40o API($Cdn/Bbl)
CromerLSB 35o API($Cdn/Bbl)
Natural Gas AECO- C Spot($Cdn/MMBtu)
NGLsEdmonton Propane($Cdn/Bbl)
NGLs Edmonton Butanes($Cdn/Bbl)
EdmontonPentanesPlus($Cdn/Bbl)
Operating Cost Inflation Rates%/Year
Capital Cost Inflation Rates%/Year
Exchange Rate (2)($Cdn/$US)
Forecast(3)
2024
73.67
92.91
93.57
2.20
29.65
47.69
96.79
0.0 %
0.0 %
0.75
2025
74.98
95.04
95.86
3.37
35.13
48.83
98.75
2.0 %
2.0 %
0.75
2026
76.14
96.07
96.46
4.05
35.43
49.36
100.71
2.0 %
2.0 %
0.76
2027
77.66
97.99
98.39
4.13
36.14
50.35
102.72
2.0 %
2.0 %
0.76
2028
79.22
99.95
100.36
4.21
36.86
51.35
104.78
2.0 %
2.0 %
0.76
2029
80.80
101.94
102.36
4.30
37.60
52.38
106.87
2.0 %
2.0 %
0.76
2030
82.42
103.98
104.41
4.38
38.35
53.43
109.01
2.0 %
2.0 %
0.76
2031
84.06
106.06
106.50
4.47
39.12
54.50
111.19
2.0 %
2.0 %
0.76
2032
85.74
108.18
108.63
4.56
39.90
55.58
113.41
2.0 %
2.0 %
0.76
2033
87.46
110.35
110.80
4.65
40.70
56.70
115.67
2.0 %
2.0 %
0.76
Thereafter Escalation rate of 2.0%
Notes:
1.
This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
2.
The exchange rate used to generate the benchmark reference prices in this table.
3.
As at December 31, 2023.
The payment date for InPlay’s March 2024 dividend declared on March 1, 2024 has been amended to March 28, 2024 due to Canadian banks being closed on the previously disclosed payment date of March 29, 2024.
On behalf of our employees, management team and Board of Directors, we would like to thank our shareholders for their support and look forward to an exciting 2024 and beyond.
For further information please contact:
Doug Bartole President and Chief Executive Officer InPlay Oil Corp. Telephone: (587) 955-0632
Throughout this press release and other materials disclosed by the Company, InPlay uses certain measures to analyze financial performance, financial position and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed under GAAP and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered alternatives to, or more meaningful than, financial measures that are determined in accordance with GAAP as indicators of the Company performance. Management believes that the presentation of these non-GAAP and other financial measures provides useful information to shareholders and investors in understanding and evaluating the Company’s ongoing operating performance, and the measures provide increased transparency and the ability to better analyze InPlay’s business performance against prior periods on a comparable basis.
Non-GAAP Financial Measures and Ratios
Included in this document are references to the terms “free adjusted funds flow”, “operating income”, “operating netback per boe”, “operating income profit margin”, “Net Debt to EBITDA”, “Net corporate acquisitions”, “Production per debt adjusted share” and “EV / DAAFF”. Management believes these measures and ratios are helpful supplementary measures of financial and operating performance and provide users with similar, but potentially not comparable, information that is commonly used by other oil and natural gas companies. These terms do not have any standardized meaning prescribed by GAAP and should not be considered an alternative to, or more meaningful than “profit (loss) before taxes”, “profit (loss) and comprehensive income (loss)”, “adjusted funds flow”, “capital expenditures”, “corporate acquisitions, net of cash acquired”, “net debt”, “weighted average number of common shares (basic)” or assets and liabilities as determined in accordance with GAAP as a measure of the Company’s performance and financial position.
Free Adjusted Funds Flow (“FAFF”)
Management considers FAFF an important measure to identify the Company’s ability to improve its financial condition through debt repayment and its ability to provide returns to shareholders. FAFF should not be considered as an alternative to or more meaningful than AFF as determined in accordance with GAAP as an indicator of the Company’s performance. FAFF is calculated by the Company as AFF less exploration and development capital expenditures and property dispositions (acquisitions) and is a measure of the cashflow remaining after capital expenditures before corporate acquisitions that can be used for additional capital activity, corporate acquisitions, repayment of debt or decommissioning expenditures or potentially return of capital to shareholders. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast FAFF.
Operating Income/Operating Netback per boe/Operating Income Profit Margin
InPlay uses “operating income”, “operating netback per boe” and “operating income profit margin” as key performance indicators. Operating income is calculated by the Company as oil and natural gas sales less royalties, operating expenses and transportation expenses and is a measure of the profitability of operations before administrative, share-based compensation, financing and other non-cash items. Management considers operating income an important measure to evaluate its operational performance as it demonstrates its field level profitability. Operating income should not be considered as an alternative to or more meaningful than net income as determined in accordance with GAAP as an indicator of the Company’s performance. Operating netback per boe is calculated by the Company as operating income divided by average production for the respective period. Management considers operating netback per boe an important measure to evaluate its operational performance as it demonstrates its field level profitability per unit of production. Operating income profit margin is calculated by the Company as operating income as a percentage of oil and natural gas sales. Management considers operating income profit margin an important measure to evaluate its operational performance as it demonstrates how efficiently the Company generates field level profits from its sales revenue. Refer below for a calculation of operating income, operating netback per boe and operating income profit margin. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast operating income, operating netback per boe and operating income profit margin.
(thousands of dollars)
Three Months Ended December 31
Year Ended December 31
2023
2022
2023
2022
Revenue
47,631
58,161
179,366
238,590
Royalties
(6,339)
(10,375)
(22,516)
(38,392)
Operating expenses
(13,233)
(13,081)
(49,576)
(43,740)
Transportation expenses
(940)
(1,118)
(3,130)
(3,920)
Operating income
27,119
33,587
104,144
152,538
Sales volume (Mboe)
882.8
885.3
3,294.1
3,323.4
Per boe
Revenue
53.95
65.69
54.45
71.79
Royalties
(7.18)
(11.72)
(6.84)
(11.55)
Operating expenses
(14.99)
(14.78)
(15.05)
(13.16)
Transportation expenses
(1.06)
(1.26)
(0.95)
(1.18)
Operating netback per boe
30.72
37.93
31.61
45.90
Operating income profit margin
57 %
58 %
58 %
64 %
Net Debt to EBITDA
Management considers Net Debt to EBITDA an important measure as it is a key metric to identify the Company’s ability to fund financing expenses, net debt reductions and other obligations. EBITDA is calculated by the Company as adjusted funds flow before interest expense. When this measure is presented quarterly, EBITDA is annualized by multiplying by four. When this measure is presented on a trailing twelve month basis, EBITDA for the twelve months preceding the net debt date is used in the calculation. This measure is consistent with the EBITDA formula prescribed under the Company’s Senior Credit Facility. Net Debt to EBITDA is calculated as Net Debt divided by EBITDA. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast Net Debt to EBITDA.
Net Corporate Acquisitions
Management considers Net corporate acquisitions an important measure as it is a key metric to evaluate the corporate acquisition in comparison to other transactions using the negotiated consideration value and ignoring changes to the fair value of the share consideration between the signing of the definitive agreement and the closing of the transaction. Net corporate acquisitions should not be considered as an alternative to or more meaningful than “Corporate acquisitions, net of cash acquired” as determined in accordance with GAAP as an indicator of the Company’s performance. Net corporate acquisitions is calculated as total consideration with share consideration adjusted to the value negotiated with the counterparty, less working capital balances assumed on the corporate acquisition. Refer below for a calculation of Net corporate acquisitions and reconciliation to the nearest GAAP measure, “Corporate acquisitions, net of cash acquired”.
(thousands of dollars)
Three Months Ended December 31
Year Ended December 31
2023
2022
2023
2022
Corporate acquisitions, net of cash acquired
–
(321)
–
180
Share consideration(1)
–
–
–
–
Non-cash working capital acquired
–
–
–
–
Derivative contracts
–
–
–
–
Net Corporate acquisitions
–
(321)(1)
–
180(1)
(1)
During the year ended December 31, 2022, the acquired amount of Property, plant and equipment was adjusted by $0.2 million as a result of adjustments relating to the acquisition, with a corresponding increase in the recognized amounts of Accounts payable and accrued liabilities.
Production per Debt Adjusted Share
InPlay uses “Production per debt adjusted share” as a key performance indicator. Debt adjusted shares should not be considered as an alternative to or more meaningful than common shares as determined in accordance with GAAP as an indicator of the Company’s performance. Debt adjusted shares is a non-GAAP measure used in the calculation of Production per debt adjusted share and is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company’s current trading price on the TSX, converting net debt to equity. Debt adjusted shares should not be considered as an alternative to or more meaningful than weighted average number of common shares (basic) as determined in accordance with GAAP as an indicator of the Company’s performance. Management considers Debt adjusted share to be a key performance indicator as it adjusts for the effects of capital structure in relation to the Company’s peers. Production per debt adjusted share is calculated by the Company as production divided by debt adjusted shares. Management considers Production per debt adjusted share to be a key performance indicator as it adjusts for the effects of changes in annual production in relation to the Company’s capital structure. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast Production per debt adjusted share.
EV / DAAFF
InPlay uses “enterprise value to debt adjusted AFF” or “EV/DAAFF” as a key performance indicator. EV/DAAFF is calculated by the Company as enterprise value divided by debt adjusted AFF for the relevant period. Debt adjusted AFF (“DAAFF”) is calculated by the Company as adjusted funds flow plus financing costs. Enterprise value is a capital management measure that is used in the calculation of EV/DAAFF. Enterprise value is calculated as the Company’s market capitalization plus net debt. Management considers enterprise value a key performance indicator as it identifies the total capital structure of the Company. Management considers EV/DAAFF a key performance indicator as it is a key metric used to evaluate the sustainability of the Company relative to other companies while incorporating the impact of differing capital structures. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast EV/DAAFF.
Capital Management Measures
Adjusted Funds Flow
Management considers adjusted funds flow to be an important measure of InPlay’s ability to generate the funds necessary to finance capital expenditures. Adjusted funds flow is a GAAP measure and is disclosed in the notes to the Company’s financial statements for the year ended December 31, 2023. All references to adjusted funds flow throughout this document are calculated as funds flow adjusting for decommissioning expenditures and transaction and integration costs. Decommissioning expenditures are adjusted from funds flow as they are incurred on a discretionary and irregular basis and are primarily incurred on previous operating assets. Transaction costs are non-recurring costs for the purposes of an acquisition, making the exclusion of these items relevant in Management’s view to the reader in the evaluation of InPlay’s operating performance. The Company also presents adjusted funds flow per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of profit per common share.
Net Debt
Net debt is a GAAP measure and is disclosed in the notes to the Company’s financial statements for the year ended December 31, 2023. The Company closely monitors its capital structure with the goal of maintaining a strong balance sheet to fund the future growth of the Company. The Company monitors net debt as part of its capital structure. The Company uses net debt (bank debt plus accounts payable and accrued liabilities less accounts receivables and accrued receivables, prepaid expenses and deposits and inventory) as an alternative measure of outstanding debt. Management considers net debt an important measure to assist in assessing the liquidity of the Company.
Supplementary Measures
“Average realized crude oil price” is comprised of crude oil commodity sales from production, as determined in accordance with IFRS, divided by the Company’s crude oil volumes. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Average realized NGL price” is comprised of NGL commodity sales from production, as determined in accordance with IFRS, divided by the Company’s NGL volumes. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Average realized natural gas price” is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company’s natural gas volumes. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Average realized commodity price” is comprised of commodity sales from production, as determined in accordance with IFRS, divided by the Company’s volumes. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Adjusted funds flow per weighted average basic share” is comprised of adjusted funds flow divided by the basic weighted average common shares.
“Adjusted funds flow per weighted average diluted share” is comprised of adjusted funds flow divided by the diluted weighted average common shares.
“Adjusted funds flow per boe” is comprised of adjusted funds flow divided by total production.
Forward-Looking Information and Statements
This news release contains certain forward–looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends”, “forecast” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the Company’s business strategy, milestones and objectives; the recognition of significant additional reserves under the heading “Corporate Reserves Information”, the future net value of InPlay’s reserves, the future development capital and costs, the life of InPlay’s reserves; the expectation that PDNP reserves will move to the PDP reserve category throughout 2023 and the timing thereof; the Company’s planned 2024 capital program including wells to be drilled and completed and the timing of the same including, without limitation, the timing of wells coming on production; 2024 guidance based on the planned capital program and all associated underlying assumptions set forth in this press release including, without limitation, forecasts of 2024 annual average production levels, adjusted funds flow, free adjusted funds flow, Net Debt/EBITDA ratio, operating income profit margin, and Management’s belief that the Company can grow some or all of these attributes and specified measures; light crude oil and NGLs weighting estimates including the expectation that the high light oil and liquids weighting will continue into 2024; expectations regarding future commodity prices; future oil and natural gas prices including the forecast that MSW differentials to WTI are forecasted to improve through 2024; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates including the expectation that downward trending operating costs will continue into 2024; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration, acquisition, development and infrastructure activities and related capital expenditures, including our planned 2024 capital program; the amount and timing of capital projects; and methods of funding our capital program.
The internal projections, expectations, or beliefs underlying our Board approved 2024 capital budget and associated guidance are subject to change in light of, among other factors, the impact of world events including the Russia/Ukraine conflict and war in the Middle East, ongoing results, prevailing economic circumstances, volatile commodity prices, and changes in industry conditions and regulations. InPlay’s 2024 financial outlook and guidance provides shareholders with relevant information on management’s expectations for results of operations, excluding any potential acquisitions or dispositions, for such time periods based upon the key assumptions outlined herein. Readers are cautioned that events or circumstances could cause capital plans and associated results to differ materially from those predicted and InPlay’s guidance for 2024 may not be appropriate for other purposes. Accordingly, undue reliance should not be placed on same.
Forward-looking statements or information are based on a number of material factors, expectations or assumptions of InPlay which have been used to develop such statements and information but which may prove to be incorrect. Although InPlay believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because InPlay can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which InPlay operates; the timely receipt of any required regulatory approvals; the ability of InPlay to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which InPlay has an interest in to operate the field in a safe, efficient and effective manner; the ability of InPlay to obtain debt financing on acceptable terms; the anticipated tax treatment of the monthly base dividend; the timing and amount of purchases under the Company’s NCIB; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and the ability of InPlay to secure adequate product transportation; future commodity prices; that various conditions to a shareholder return strategy can be satisfied; the ongoing impact of the Russia/Ukraine conflict and war in the Middle East; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which InPlay operates; and the ability of InPlay to successfully market its oil and natural gas products.
Without limitation of the foregoing, readers are cautioned that the Company’s future dividend payments to shareholders of the Company, if any, and the level thereof will be subject to the discretion of the Board of Directors of InPlay. The Company’s dividend policy and funds available for the payment of dividends, if any, from time to time, is dependent upon, among other things, levels of FAFF, leverage ratios, financial requirements for the Company’s operations and execution of its growth strategy, fluctuations in commodity prices and working capital, the timing and amount of capital expenditures, credit facility availability and limitations on distributions existing thereunder, and other factors beyond the Company’s control. Further, the ability of the Company to pay dividends will be subject to applicable laws, including satisfaction of solvency tests under the Business Corporations Act (Alberta), and satisfaction of certain applicable contractual restrictions contained in the agreements governing the Company’s outstanding indebtedness.
The forward-looking information and statements included herein are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: the continuing impact of the Russia/Ukraine conflict and war in the Middle East; inflation and the risk of a global recession; changes in our planned 2024 capital program; changes in our approach to shareholder returns; changes in commodity prices and other assumptions outlined herein; the risk that dividend payments may be reduced, suspended or cancelled; the potential for variation in the quality of the reservoirs in which we operate; changes in the demand for or supply of our products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans or strategies of InPlay or by third party operators of our properties; changes in our credit structure, increased debt levels or debt service requirements; inaccurate estimation of our light crude oil and natural gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in InPlay’s continuous disclosure documents filed on SEDAR including our Annual Information Form and our MD&A.
This press release contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about InPlay’s financial and leverage targets and objectives, potential dividends, share buybacks and beliefs underlying our Board approved 2024 capital budget and associated guidance, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. The actual results of operations of InPlay and the resulting financial results will likely vary from the amounts set forth in this press release and such variation may be material. InPlay and its management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s reasonable estimates and judgments. However, because this information is subjective and subject to numerous risks, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, InPlay undertakes no obligation to update such FOFI. FOFI contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about InPlay’s anticipated future business operations and strategy. Readers are cautioned that the FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein.
The forward-looking information and statements contained in this news release speak only as of the date hereof and InPlay does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
InPlay’s 2023 annual guidance and a comparison to 2023 actual results are outlined below.
Guidance FY 2023(1)
Actuals FY 2023
Variance
Variance (%)
Production
Boe/d
9,000 – 9,100
9,025
–
–
Adjusted Funds Flow
$ millions
$91 – $93
$92
–
–
Capital Expenditures
$ millions
$84.5
$84.5
–
–
Free Adjusted Funds Flow
$ millions
$6 – $8
$7
–
–
Net Debt
$ millions
$47 – $45
$46
–
–
(1)
As previously released January 29, 2024.
Risk Factors to FLI
Risk factors that could materially impact successful execution and actual results of the Company’s 2024 capital program and associated guidance and estimates include:
volatility of petroleum and natural gas prices and inherent difficulty in the accuracy of predictions related thereto;
the extent of any unfavourable impacts of wildfires in the province of Alberta.
changes in Federal and Provincial regulations;
the Company’s ability to secure financing for the Board approved 2024 capital program and longer-term capital plans sourced from AFF, bank or other debt instruments, asset sales, equity issuance, infrastructure financing or some combination thereof; and
those additional risk factors set forth in the Company’s MD&A and most recent Annual Information Form filed on SEDAR
Key Budget and Underlying Material Assumptions to FLI
The key budget and underlying material assumptions used by the Company in the development of its 2024 guidance are as follows:
Actuals FY 2023
Guidance FY 2023(1)
Guidance FY 2024(1)
WTI
US$/bbl
$77.62
$77.61
75.00
NGL Price
$/boe
$36.51
$36.60
$36.85
AECO
$/GJ
$2.50
$2.50
$2.35
Foreign Exchange Rate
CDN$/US$
0.74
0.74
0.74
MSW Differential
US$/bbl
$3.25
$3.25
$4.45
Production
Boe/d
9,025
9,000 – 9,100
9,000 – 9,500
Revenue
$/boe
54.45
54.00 – 55.00
51.25 – 56.25
Royalties
$/boe
6.84
6.50 – 7.00
5.90 – 7.40
Operating Expenses
$/boe
15.05
14.50 – 15.50
12.75 – 15.75
Transportation
$/boe
0.95
0.90 – 1.05
0.85 – 1.10
Interest
$/boe
1.65
1.50 – 1.70
1.50 – 2.00
General and Administrative
$/boe
3.13
3.00 – 3.30
2.50 – 3.25
Hedging loss (gain)
$/boe
(1.10)
(1.00) – (1.25)
0.00 – 0.15
Decommissioning Expenditures
$ millions
$3.3
$3.5 – $4.0
$4.0 – $4.5
Adjusted Funds Flow
$ millions
$92
$91 – $93
$89 – $96
Dividends
$ millions
$16
$16
$16 – $17
Actuals FY 2023
Guidance FY 2023(1)
Guidance FY 2024(1)
Adjusted Funds Flow
$ millions
$92
$91 – $93
$89 – $96
Capital Expenditures
$ millions
$84.5
$84.5
$64 – $67
Free Adjusted Funds Flow
$ millions
$7
$6 – $8
$22 – $32
Actuals FY 2023
Guidance FY 2023(1)
Guidance FY 2024(1)
Revenue
$/boe
54.45
54.00 – 55.00
51.25 – 56.25
Royalties
$/boe
6.84
6.50 – 7.00
5.90 – 7.40
Operating Expenses
$/boe
15.05
14.50 – 15.50
12.75 – 15.75
Transportation
$/boe
0.95
0.90 – 1.05
0.85 – 1.10
Operating Netback
$/boe
31.61
31.00 – 32.00
29.50 – 34.50
Operating Income Profit Margin
58 %
58 %
59 %
Actuals FY 2023
Guidance FY 2023(1)
Guidance FY 2024(1)
Adjusted Funds Flow
$ millions
$92
$91 – $93
$89 – $96
Interest
$/boe
1.65
1.50 – 1.70
1.50 – 2.00
EBITDA
$ millions
$98
$97 – $99
$95 – $102
Net Debt
$ millions
$46
$45 – $47
$37 – $44
Net Debt/EBITDA
0.5
0.5
0.4 – 0.5
Actuals FY 2023
Guidance FY 2023(1)
Production
Boe/d
9,025
9,000 – 9,100
Opening Net Debt
$ millions
$33
$33
Ending Net Debt
$ millions
$46
$45 – $47
Weighted avg. outstanding shares
# millions
89.1
89.1
Assumed Share price
$
2.65(3)
2.65
Prod. per debt adj. share growth(2)(5)
(8 %)
(7%) – (9%)
Actuals FY 2023
Guidance FY 2023(1)
Share outstanding, end of year
# millions
91.1
91.1
Assumed Share price
$
2.21(4)
2.21
Market capitalization
$ millions
$201
$201
Net Debt
$ millions
$46
$45 – $47
Enterprise value
$millions
$247
$246 – $248
Adjusted Funds Flow
$ millions
$92
$91 – $93
Interest
$/boe
1.65
1.50 – 1.70
Debt Adjusted AFF
$ millions
$98
$97 – $99
EV/DAAFF(5)
2.5
2.6 – 2.5
(1)
As previously released January 29, 2024.
(2)
Production per debt adjusted share is calculated by the Company as production divided by debt adjusted shares. Debt adjusted shares is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company’s current trading price on the TSX, converting net debt to equity. Future share prices are assumed to be consistent with the current share price.
(3)
Weighted average share price throughout 2023.
(4)
Ending share price at December 31, 2023.
(5)
The Company has withdrawn its 2024 and 2025 production per debt adjusted share and EV/DAAFF forecast for 2024 and 2025. The Company believes that these metrics can be quite variable and hard to reasonably estimate given the volatility in the Company’s share price, which is a material assumption used in the calculation of these metrics.
(6)
Continued commodity price volatility and current weak industry sentiment has resulted in the Company taking a conservative and disciplined approach to capital allocation in 2024 and future years. Preliminary estimates and plans for 2025 and beyond will be dependent on the stability of commodity prices and industry sentiment balancing manageable growth and ensuring the long term sustainability of our return of capital to shareholder strategy. As a result, the Company previously withdrew its preliminary estimates and plans for 2025.
• See “Production Breakdown by Product Type” below
• Quality and pipeline transmission adjustments may impact realized oil prices in addition to the MSW Differential provided above
• Changes in working capital are not assumed to have a material impact between the years presented above.
Information Regarding Disclosure on Oil and Gas Reserves and Operational Information
Our oil and gas reserves statement for the year ended December 31, 2023, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at www.sedarplus.com on or before March 31, 2024. The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties, such estimates may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. The Company’s belief that it will establish additional reserves over time with conversion of probable undeveloped reserves into proved reserves is a forward-looking statement and is based on certain assumptions and is subject to certain risks, as discussed above under the heading “Forward-Looking Information and Statements”.
This press release contains metrics commonly used in the oil and natural gas industry, such as “finding, development and acquisition costs”, “finding and development costs”, “operating netbacks”, “recycle ratios”, and “reserve life index” or “RLI”. Each of these terms are calculated by InPlay as described in the section “Performance Measures” in this press release. These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included herein to provide readers with additional information to evaluate the Company’s performance, however such metrics should not be unduly relied upon.
Finding, development and acquisition (“FD&A”) and finding and development (“F&D”) costs take into account reserves revisions during the year on a per boe basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated future development costs may not reflect total finding and development costs related to reserves additions for that year. Finding, development and acquisition costs have been presented in this press release because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure. Exploration & development capital means the aggregate exploration and development costs incurred in the financial year on exploration and on reserves that are categorized as development. Exploration & development capital excludes capitalized administration costs. Acquisition capital amounts to the total amount of cash and share consideration net of any working capital balances assumed with an acquisition on closing.
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare InPlay’s operations over time, however such measures are not reliable indicators of InPlay’s future performance and future performance may not be comparable to the performance in prior periods. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes, however such measures are not reliable indicators on InPlay’s future performance and future performance may not be comparable to the performance in prior periods.
References to light crude oil, NGLs or natural gas production in this press release refer to the light and medium crude oil, natural gas liquids and conventional natural gas product types, respectively, as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“Nl 51-101“).
Production Breakdown by Product Type
Disclosure of production on a per boe basis in this document consists of the constituent product types as defined in NI 51–101 and their respective quantities disclosed in the table below:
Light and Medium Crude oil(bbls/d)
NGLs(boe/d)
Conventional Natural gas(Mcf/d)
Total(boe/d)
Q4 2022 Average Production
3,909
1,532
25,090
9,623
2022 Average Production
3,766
1,402
23,623
9,105
Q4 2023 Average Production
4,142
1,520
23,606
9,596
2023 Average Production
3,822
1,396
22,839
9,025
2023 Annual Guidance
3,840
1,390
22,920
9,050(1)
2024 Annual Guidance
4,090
1,395
22,590
9,250(2)
Notes:
1.
This reflects the mid-point of the Company’s 2023 production guidance range of 9,000 to 9,100 boe/d.
2.
This reflects the mid-point of the Company’s 2024 production guidance range of 9,000 to 9,500 boe/d.
References to crude oil, NGLs or natural gas production in this press release refer to the light and medium crude oil, natural gas liquids and conventional natural gas product types, respectively, as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“Nl 51-101”).
BOE equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.
Initial Production Rates
References in this press release to IP rates, other short-term production rates or initial performance measures relating to new wells are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Accordingly, the Company cautions that the test results should be considered to be preliminary.
Vancouver, British Columbia–(Newsfile Corp. – March 12, 2024) – Hemisphere Energy Corporation (TSXV: HME) (OTCQX: HMENF) (“Hemisphere” or the “Company”) is pleased to announce highlights from its independent reserves evaluation (the “Reserve Report”), prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) and effective as at December 31, 2023.
In 2023, Hemisphere invested $16 million to drill eight successful Atlee Buffalo wells, upgrade facilities in Atlee Buffalo, purchase land and seismic, and pre-purchase some of the materials for its 2024 development program. With the Company’s capital additions, corporate production in 2023 increased by more than 10% year-over-year, to 3,124 boe/d (99% heavy oil). Production is currently trending over 3,450 boe/d (99% heavy oil, based on field estimates between February 10 – March 10, 2024), after significant downtime experienced in January and early February due to extreme cold weather and equipment failure.
During the year, Hemisphere also distributed $13.1 million in base and special dividends, purchased 3.2 million shares under its normal course issuer bid (“NCIB”) for a total price of $4.0 million (at an average price of $1.25/share), and exited the year in a cash position with working capital1 of over $3 million.
The Company’s continued success in the development of its enhanced oil recovery projects was recognized again by McDaniel in the Reserve Report. In the Proved Developed Producing (“PDP”) category, Hemisphere replaced 104% of 2023 production and increased reserve value by 9% to $248 million NPV10 BT. Hemisphere also grew Proved (“1P”) reserve value to $325 million NPV10 BT and Proved plus Probable (“2P”) reserve value to $416 million NPV10 BT.
The Company’s new Saskatchewan lands currently account for only 5% of 1P and 7% of 2P reserves, while making up only 3% of 1P and 5% of 2P NPV10 BT valuations of Hemisphere’s reserves. Significant reserve upside remains on Hemisphere lands if the play proves successful over the course of 2024 and beyond.
Consistent with McDaniel’s 2022 year-end evaluation, the Reserve Report incorporates full corporate abandonment, decommissioning, and reclamation costs (“ADR”) in the PDP category. Hemisphere has always been cautious of acquiring additional wellbore and facility liabilities. A direct result of this strategy is that Hemisphere’s reserves retain more comparative value per barrel than companies with additional ADR liabilities that must be deducted from their base valuations. Management estimates that total undiscounted and uninflated existing ADR is $8.3 million ($2.3 million NPV10 BT, with costs inflated at 2%/yr), which includes all ADR associated with both active and inactive wells, pipelines, and facilities regardless of whether such wells, pipelines, and facilities had any attributed reserves. Based on public information, Hemisphere stands out among its industry peers as being within the top 8% of Alberta oil and gas operators for its industry-leading liability management ratio (“LMR”) of 17, resulting in Hemisphere having less than 1% of its PDP net present value impaired by ADR.
Hemisphere’s low decline, long life, and high value reserves are a sign of the tremendous resource the Company has been developing over the past number of years. These valuable assets are the backbone of Hemisphere and are expected to generate significant free cash flow as they continue to grow with planned additional development and optimization of enhanced oil recovery techniques.
2023 Reserve Highlights
Proved Developed Producing (“PDP”) Reserves
NPV10 BT of $248 million, an increase of 9% over year-end 2022 and equivalent to $2.49 per basic share.
Replaced 104% of 2023 production through organic development.
Maintained reserve volumes year-over-year at 8.2 MMboe (99.6% heavy crude oil).
Achieved a 2-year FD&A cost of $9.30/boe (including changes in future development capital (“FDC”)) for a recycle ratio of 5.4.
RLI of 7.2 years based on 2023 production.
Proved (“1P”) Reserves
NPV10 BT of $325 million, an increase of 5% over year-end 2022 and equivalent to $3.27 per basic share.
Replaced 90% of 2023 production through organic development.
Maintained reserve volumes year-over-year at 12.1 MMboe (99.4% heavy crude oil).
Achieved a 2-year FD&A cost of $14.82/boe (including changes in FDC) for a recycle ratio of 3.4.
RLI of 10.6 years based on 2023 production.
NAV of $3.18 per fully diluted share based on Reserve Report pricing assumptions.
NAV of $3.28 and $4.27 per fully diluted share based on Reserve Report run internally at McDaniel’s pricing sensitivities of US$80 and US$100 WTI flat pricing.
Proved plus Probable (“2P”) Reserves
NPV10 BT of $416 million, an increase of 5% over year-end 2022 and equivalent to $4.19 per basic share.
Replaced 125% of 2023 production through organic development.
Maintained reserve volumes at 16.3 MMboe (99.4% heavy crude oil).
Achieved a 2-year FD&A cost of $14.91/boe (including changes in FDC) for a recycle ratio of 3.4.
RLI of 14.3 years based on 2023 production.
NAV of $4.03 per fully diluted share based on Reserve Report pricing assumptions.
NAV of $4.12 and $5.36 per fully diluted share based on Reserve Report run internally at McDaniel’s pricing sensitivities of US$80 and US$100 WTI flat pricing.
2023 Independent Qualified Reserve Evaluation
The reserves data set forth below is based upon an independent reserves evaluation prepared by McDaniel dated March 11, 2024 with an effective date of December 31, 2023, and is in accordance with definitions, standards, and procedures contained within COGEH and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserve information as required under NI 51-101 will be included in Hemisphere’s Annual Information Form which will be filed on SEDAR+ on or before April 30, 2024. Due to rounding, certain totals in the columns may not add in the following tables. All dollar values are in Canadian dollars, unless otherwise noted.
Pricing Assumptions
McDaniel’s independent evaluation was based on the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. (the “3-Consultant Average Price Forecast”) at January 1, 2024, with the following table detailing pricing and foreign exchange rate assumptions. Hemisphere’s corporate production historically averages a discount of approximately $4.50 to WCS pricing. When compared to last year’s 3-Consultant Average Price Forecast dated January 1, 2023, the current WCS pricing outlook is down approximately 1% in 2024, and up 1% thereafter over the next 15-year period. The 2024 3-Consultant Average Price Forecast uses a 5-year 2024-28 WTI price of US$76.33/bbl and WCS price of Cdn$81.11/bbl.
3-Consultant Average Price Forecast January 1, 2023
3-Consultant Average Price Forecast January 1, 2024
WTI Crude Oil ($US/bbl)
Edmonton Light Crude Oil ($Cdn/bbl)
Western Canadian Select WCS Crude Oil ($Cdn/bbl)
AECO Spot Price ($Cdn/MM Btu)
Inflation (%)
US/Cdn Exchange Rate ($US/$Cdn)
WTI Crude Oil ($US/bbl)
Western Canadian Select WCS Crude Oil ($Cdn/bbl)
Edmonton Light Crude Oil ($Cdn/bbl)
AECO Spot Price ($Cdn/MM Btu)
Inflation (%)
US/Cdn Exchange Rate ($US/$Cdn)
2024
78.50
97.74
77.75
4.40
2.3
0.765
2024
73.67
92.91
76.74
2.20
0
0.745
2025
76.95
95.27
77.55
4.21
2
0.768
2025
74.98
95.04
79.77
3.37
2
0.765
2026
77.61
95.58
80.07
4.27
2
0.772
2026
76.14
96.07
81.12
4.05
2
0.768
2027
79.16
97.07
81.89
4.34
2
0.775
2027
77.66
97.99
82.88
4.13
2
0.772
2028
80.74
99.01
84.02
4.43
2
0.775
2028
79.22
99.95
85.04
4.21
2
0.775
2029
82.36
100.99
85.73
4.51
2
0.775
2029
80.80
101.94
86.74
4.30
2
0.775
2030
84.00
103.01
87.44
4.60
2
0.775
2030
82.42
103.98
88.47
4.38
2
0.775
2031
85.69
105.07
89.20
4.69
2
0.775
2031
84.06
106.06
90.24
4.47
2
0.775
2032
87.40
106.69
91.11
4.79
2
0.775
2032
85.74
108.18
92.04
4.56
2
0.775
2033
89.15
108.83
92.93
4.88
2
0.775
2033
87.46
110.35
93.89
4.65
2
0.775
2034
90.93
111.00
94.79
4.98
2
0.775
2034
89.21
112.56
95.77
4.74
2
0.775
2035
92.75
113.22
96.69
5.08
2
0.775
2035
90.99
114.81
97.68
4.84
2
0.775
2036
94.61
115.49
98.62
5.18
2
0.775
2036
92.81
117.10
99.64
4.94
2
0.775
2037
96.50
117.80
100.59
5.29
2
0.775
2037
94.67
119.45
101.63
5.03
2
0.775
2038
98.43
120.16
102.60
5.40
2.00
0.78
2038
96.56
121.83
103.66
5.14
2.00
0.78
Summary of Reserves(1)
Heavy Oil
Conventional Natural Gas
Total
Reserves Category
(Mbbl)
(MMcf)
(Mboe)
Proved
Developed Producing
8,196
173
8,225
Developed Non-Producing
34
7
35
Undeveloped
3,756
250
3,798
Total Proved
11,987
429
12,058
Probable
4,231
188
4,262
Total Proved plus Probable
16,217
617
16,320
Note:
(1)Reserves are presented as “gross reserves” which are the Company’s working interest reserves before royalty deductions and without including any royalty interests.
Summary of Net Present Value of Future Net Revenue, Before Tax (“NPV BT”) (1)(2)
NPV BT (M$, except per share amount)
Discounted at (% per Year)
Reserves Category
0%
5%
10%
Proved
Developed Producing
363,872
295,324
247,832
Developed Non-Producing
720
603
513
Undeveloped
126,954
97,757
76,777
Total Proved
491,546
393,685
325,121
Probable
190,663
126,483
91,337
Total Proved plus Probable
682,209
520,168
416,458
Per basic share(3)
Proved Developed Producing
3.66
2.97
2.49
Proved
4.95
3.96
3.27
Proved plus Probable
6.87
5.24
4.19
Notes: (1)Based on the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. at January 1, 2024, as outlined in the table herein entitled “Pricing Assumptions”. (2)It should not be assumed that the estimates of net present value of future net revenues presented in this table represent the fair market value of Hemisphere’s reserves. (3)Based on there being 99,340,339 issued and outstanding shares of the Company as of December 31, 2023.
Future Development Costs (“FDC”)
The following summarizes the development costs deducted in the estimation of the net present value of the future net revenue attributable to 1P and 2P reserves.
Forecast Costs (M$)
1P
2P
2024
16,410
16,410
2025
22,959
28,051
2026
7,087
12,648
2027
3,501
3,501
Subsequent years
–
–
Total Undiscounted
49,956
60,609
Total Discounted at 10%
43,568
52,209
Finding, Development and Acquisition Costs (“FD&A”) Costs and Recycle Ratios(1)(2)
2023
2-Year Totals/Average
FD&A
PDP
1P
2P
PDP
1P
2P
Exploration, development and acquisition capital (M$)(3)(4)
14,543
31,570
Total changes in FDC (M$)
-528
4,869
10,094
-2,527
2,191
9,888
Total FD&A Capital, including changes in FDC (M$)
14,015
19,412
24,637
29,044
33,762
41,458
FD&A Reserve additions, including revisions (Mboe)
1,181
1,027
1,425
3,123
2,278
2,780
FD&A costs(5), including changes in FDC ($/boe)
11.87
18.90
17.28
9.30
14.82
14.91
Recycle Ratio(6)
3.8
2.4
2.6
5.4
3.4
3.4
Notes: (1)All financial information included in this news release is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2023, which have not yet been approved by the Company’s Audit Committee or Board of Directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to change as a result of the completion of the independent audit on Hemisphere’s financial statements for the year ended December 31, 2023, and the review and approval of same with the Company’s Audit Committee and Board of Directors. (2)See “Oil and Gas Advisories” and “Oil and Gas Metrics”. (3)Exploration, development and acquisition capital excludes capitalized administration costs. (4)The aggregate of the exploration, development and acquisition capital incurred in the financial year and change during that year in estimated future development costs generally will not reflect total finding, development and acquisition costs related to reserve additions for that year. (5)FD&A costs are calculated as the sum of exploration, development and acquisition capital plus the change in future development capital (FDC) for the period divided by the change in reserves for the period, including on acquisition lands. FD&A costs take into account reserves revisions during the year on a per boe basis, and 2023 production of 3,124 boe/d. (6)Recycle ratio is calculated as Operating field netback divided by FD&A costs. Operating field netback is a non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similarmeasures presented by other entities. Refer to the sections “Non-IFRS and Other Specified Financial Measures” and “Financial Information”. The Company‘s estimated operating field netback in 2023 was $45.41/boe (unaudited) and 2-year 2022/23 average operating field netback was $50.67/boe.
Reserve Life Index (“RLI”)
As of December 31, 2023(1)
PDP
7.2
1P
10.6
2P
14.3
Note: (1)Calculated as the applicable reserves volume divided by Hemisphere’s average 2023 production of 3,124 boe/d.
Net Asset Value (“NAV”)(1)
As at December 31, 2023
(MM$ except share amounts)
3-Consultant Average Price Forecast
US$80 WTI
US$100 WTI
1P NPV10 BT(2)
325
336
441
2P NPV10 BT(2)
416
426
558
Undeveloped Land and Seismic(3)
3
Proceeds from Stock Options
9
Working Capital(4)
3
Million Shares Outstanding (fully diluted)
107
1P NAV per share (fully diluted)
$3.18
$3.28
$4.27
2P NAV per share (fully diluted)
$4.03
$4.12
$5.36
Notes: (1)Calculated using the respective net present values of 1P and 2P reserves, before tax and discounted at 10%, plus internally valued undeveloped land & seismic and proceeds from and stock options, plus working capital(4), and divided by fully diluted outstanding shares. Net present values are shown at various price forecasts including the 3-Consultant Average Price Forecast used in the McDaniel Reserve Report, as well as sensitivities run internally at McDaniel’s flat WTI price forecasts of US$80 and US$100 WTI paired with US$19.32 and US$23.45 WCS differentials, respectively, and 1.37 USD/CAD FX. (2)100% of existing and future corporate ADR has been included in the McDaniel Reserve Report. Total corporate ADR accounted for in the 2023 reserve report, including that for future development, amounts to $3.0 million NPV10 BT in the 1P category and $3.1 million NPV10 BT in the 2P category. (3)Based on an internal evaluation by management of Hemisphere as of December 31, 2023, with an average value of $75.87 per acre for 31,295 undeveloped net acres, and $0.55 million for seismic. (4)Working Capital is a non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to the section “Non-IFRS and Other Specified Financial Measures”. All financial information as at December 31, 2023 is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2023, which has not yet been approved by the Company’s Audit Committee or Board of Directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to changes as a result of the completion of the independent audit on Hemisphere’s financial statements for the year ended December 31, 2023, and the review and approval of same with the Company’s Audit Committee and Board of Directors.
About Hemisphere Energy Corporation
Hemisphere is a dividend-paying Canadian oil company focused on maximizing value per share growth with the sustainable development of its high netback, low decline conventional heavy oil assets through water and polymer flood enhanced recovery methods. Hemisphere trades on the TSX Venture Exchange as a Tier 1 issuer under the symbol “HME” and on the OTCQX Venture Marketplace under the symbol “HMENF”.
For further information, please visit the Company’s website at www.hemisphereenergy.ca to view its corporate presentation or contact:
Don Simmons, President & Chief Executive Officer Telephone: (604) 685-9255 Email: info@hemisphereenergy.ca
Definitions and Abbreviations
bbl
barrel
US$
United States dollar
Mbbl
thousands of barrels
Cdn$
Canadian dollar
MMbbl
millions of barrels
M$
thousand dollars
boe
barrel of oil equivalent
MM
million
boe/d
barrel of oil equivalent per day
NPV BT
Net Present Value of future net revenue, before tax
Mboe
thousands of barrels of oil equivalent
NPV10 BT
NPV BT, discounted at 10%
MMboe
millions of barrels of oil equivalent
FX
Foreign Exchange
MMcf
million cubic feet
FDC
Future Development Costs
MMbtu
million British Thermal Unit
FD&A
Finding, Development and Acquisition
AECO
Alberta Energy Company
NAV
Net Asset Value
WCS
Western Canadian Select
RLI
Reserve Life Index
WTI
West Texas Intermediate
Forward-Looking Statements
This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the Company’s expectations that its assets are expected to generate significant free funds flow as they continue to grow with planned additional development and optimization of enhanced oil recovery techniques; the volumes of Hemisphere’s oil and gas reserves and the estimated net present values of the future net revenues of such reserves; the Company’s estimates of ADR; and the Company’s anticipated filing date for its annual information form for the year ending December 31, 2023; upside potential on Hemisphere’s Saskatchewan properties in 2024 and beyond. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
The estimates of Hemisphere’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In addition, forward-looking statements or information are based on a number of material factors, expectations or assumptions of Hemisphere which have been used to develop such statements and information, but which may prove to be incorrect. Although Hemisphere believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Hemisphere can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: that Hemisphere will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities are consistent with past operations; the quality of the reservoirs in which Hemisphere operates and continued performance from existing wells; inflation rates and cost escalations; the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Hemisphere’s reserve volumes; certain commodity price and other cost assumptions; continued availability of debt and equity financing and cash flow to fund Hemisphere’s current and future plans and expenditures; the impact of increasing competition; the general stability of the economic and political environment in which Hemisphere operates; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of Hemisphere to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Hemisphere has an interest in to operate the field in a safe, efficient and effective manner; the ability of Hemisphere to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Hemisphere to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Hemisphere operates; and the ability of Hemisphere to successfully market its oil and natural gas products.
The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; regulatory risks, including penalties or other remedial action; the ability of the Company to maintain legal title to its properties; changes to, or restrictions of, labour, supplies, and infrastructure as a result of COVID-19; changes in the demand for or supply of Hemisphere’s products, the early stage of development of some of the evaluated areas and zones; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Hemisphere or by third party operators of Hemisphere’s properties; changes in budgets; increased debt levels or debt service requirements; inaccurate estimation of Hemisphere’s oil and gas reserve volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in Hemisphere’s public disclosure documents, (including, without limitation, those risks identified in this news release and in Hemisphere’s annual information form).
The forward-looking information and statements contained in this news release speak only as of the date of this news release, and Hemisphere does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
Oil and Gas Advisories
All reserve references in this news release are “gross” or “Company interest reserves”. Such reserves are the Company’s total working interest reserves before the deduction of any royalties and without including any royalty interests of the Company.
It should not be assumed that the net present value of the estimated net revenues presented in this news release represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserve estimates of Hemisphere’s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. Estimates of net present value and future net revenue contained herein do not necessarily represent fair market value. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions in evaluating Hemisphere’s reserves will be attained and variances could be material.
All future net revenues are estimated using forecast prices, arising from the anticipated development and production of our reserves, net of the associated royalties, operating costs, development costs and abandonment and reclamation costs and are stated prior to provision for interest and general and administrative expenses. Future net revenues have been presented in this news release on a before tax basis.
“Boe” means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. Boe’s may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Oil and Gas Metrics
This news release contains metrics commonly used in the oil and natural gas industry, such as finding, development and acquisition (“FD&A”) costs, “recycle ratio”, “operating field netback” and “reserve life index (“RLI”)”. These terms do not have a standardized meaning and the Company’s calculation of such metrics may not be comparable to the calculation method used or presented by other companies for the same or similar metrics, and therefore should not be used to make such comparisons.
“Finding, development and acquisition costs” or “FD&A costs” are calculated as the sum of exploration, development and acquisition capital plus the change in future development capital (“FDC”) for the period divided by the change in reserves for the period, including on acquisition lands. FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the exploration, development and acquisition costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total FD&A costs related to reserves additions for that year. Management uses FD&A costs as a measure of capital efficiency for organic reserves development.
“Exploration, development and acquisition capital” means the aggregate exploration, development and acquisition costs incurred in the financial year, and excludes capitalized administration costs.
“Recycle ratio” is a Non-IFRS ratio calculated as the Operating field netback divided by the FD&A cost per boe for the year.Operating field netback is a non-IFRS financial measure (refer to the section “Non-IFRS and Other Specified Financial Measures”). Management uses recycle ratio to relate the cost of adding reserves to the expected cash flows to be generated.
“Reserve life index” is calculated as total company interest reserves divided by annual production, for the year indicated.
“NAV per fully diluted share” is calculated using the respective net present values of 1P and 2P reserves, before tax and discounted at 10%, plus internally valued undeveloped land & seismic and proceeds from warrants and stock options, plus working capital, and divided by fully diluted outstanding shares. Net present values are shown at various price forecasts including the 3-Consultant Average Price Forecasts used in the McDaniel Reserve Report, as well as sensitivities run internally at McDaniel’s flat WTI price forecasts of US$80 and US$100 WTI paired with US$19.32 and US$23.45 WCS differentials respectively, and 1.37 USD/CAD FX. Management uses NAV per share as a measure of the relative change of Hemisphere’s net asset value over its outstanding common shares over a period of time.
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.
Financial Information
Certain financial information included in this news release is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2023, which have not yet been approved by the Company’s Audit Committee or Board of Directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to change as a result of the completion of the independent audit on Hemisphere’s financial statements for the year ended December 31, 2023, and the review and approval of same with the Company’s Audit Committee and Board of Directors. All amounts are expressed in Canadian dollars unless otherwise noted.
Non-IFRS and Other Specified Financial Measures
Certain measures commonly used in the oil and natural gas industry referred to herein, including “Working Capital” and “Operating field netback”, do not have standardized meanings prescribed by IFRS and therefore may not be comparable with the calculation of similar measures by other companies. These non-IFRS measures are further described and defined below. Investors are cautioned that these measures should not be construed as alternatives to or more meaningful than the most directly comparable IFRS measures as indicators of Hemisphere’s performance. Set forth below are descriptions of the non-IFRS financial measures used in this news release.
“Working Capital” is closely monitored by the Company to ensure that its capital structure is maintained by a strong balance sheet to fund the future growth of the Company. Working Capital is used in this document in the context of liquidity and is calculated as the total of the Company’s bank debt plus current assets, less current liabilities, excluding the fair value of financial instruments, lease and decommissioning liabilities.
($MM)
Twelve Months Ended December 31, 2022 (unaudited)
Bank debt
$
–
Current assets
13.3
Current liabilities
(9.9
)
Working Capital
$
3.4
“Operating field netback” is calculated as oil and gas sales, less royalties, operating expenses, and transportation costs on an absolute and per barrel of oil equivalent basis. Operating netback per boe and Operating field netback per boe are calculated by dividing the respective terms by the applicable barrels of oil equivalent of production. A reconciliation of Operating netback and Operating field netback per boe to the most directly comparable measure calculated and presented in accordance with IFRS is as follows:
($/boe)
Twelve Months Ended December 31, 2022 (unaudited)
Average realized sales
$
74.05
Royalties
(14.89
)
Operating and transportation expenses
(13.75
)
Operating field netback
$
45.41
The Company has provided additional information on how these measures are calculated in the Management’s Discussion and analysis for the year ended December 31, 2022 and for the three and nine month periods ended September 30, 2023, which are available under the Company’s SEDAR+ profile at www.sedarplus.ca.
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.
1 Working Capital is a non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to the sections “Non-IFRS and Other Specified Financial Measures” and “Financial Information”.
In a major development in the uranium mining sector, ATHA Energy Corp. and Latitude Uranium Inc. announced the successful completion of their merger on March 7, 2024. Through this strategic transaction, ATHA has acquired 100% of the outstanding common shares of Latitude Uranium, making the latter a wholly-owned subsidiary.
The merger brings together two promising uranium players, combining their complementary assets and expertise to create a formidable force in the industry. Latitude Uranium shareholders received 0.2769 ATHA common shares for each share held, resulting in ATHA issuing approximately 64.4 million new shares.
This deal marks a significant milestone for ATHA, adding historical resources to its portfolio and expanding its reach across multiple high-grade uranium jurisdictions. The combined company now boasts a diverse range of exploration catalysts, including the Angilak and CMB uranium discoveries, with historical resource estimates of 43.3 million lbs and 14.5 million lbs U3O8, respectively.
Moreover, ATHA now holds the largest cumulative exploration package in both the Athabasca Basin and Thelon Basin, two of the world’s most prominent basins for uranium discoveries, with a total of 6.5 million acres. Additionally, the company has a 10% carried interest in a portfolio of claims in the Athabasca Basin operated by industry leaders NexGen Energy Ltd. and IsoEnergy Ltd.
Troy Boisjoli, CEO of ATHA, expressed enthusiasm about the merger, stating, “This acquisition marks a significant milestone for the Company by adding historical resource to our portfolio and enabling us to expand the reach of our robust balance sheet across a diverse range of exploration catalysts.”
The Resurgence of Uranium Mining
The ATHA-Latitude Uranium merger comes at a time when the uranium mining industry is experiencing a resurgence, driven by the global push towards clean energy and the pivotal role of nuclear power in achieving carbon neutrality goals.
As countries around the world seek to reduce their reliance on fossil fuels and transition to more sustainable energy sources, the demand for uranium is expected to increase significantly. Nuclear power plants, which generate electricity without emitting greenhouse gases, are attracting renewed interest as a viable solution to meet energy needs while addressing climate change concerns.
This resurgence has sparked a flurry of activity in the uranium mining sector, with companies scrambling to secure promising exploration projects and develop new mines to meet the anticipated demand. Established players and emerging companies alike are vying for a share of this lucrative market, fueled by the potential for substantial returns on investment.
However, the uranium mining industry is not without its challenges. Stringent regulations, environmental concerns, and the need for significant capital investment present hurdles that companies must navigate cautiously. Responsible exploration and mining practices, combined with robust risk management strategies, are crucial for long-term success in this sector.
Nonetheless, the ATHA-Latitude Uranium merger positions the combined entity as a formidable player in the uranium mining landscape. With a diverse portfolio of assets, historical resources, and strategic partnerships, the company is well-positioned to capitalize on the growing demand for uranium and contribute to the global transition towards a more sustainable energy future.
As the world grapples with the twin challenges of meeting energy needs and addressing climate change, the uranium mining industry is poised to play a pivotal role. Companies like ATHA, armed with extensive resources and a solid growth strategy, may emerge as key players in this exciting and rapidly evolving sector.
CALGARY, AB, March 5, 2024 /CNW/ – Alvopetro Energy Ltd. (TSXV: ALV) (OTCQX: ALVOF) announces February 2024 sales volumes of 1,477 boepd including natural gas sales of 8.3 MMcfpd, associated natural gas liquids sales from condensate of 72 bopd and oil sales of 19 bopd, based on field estimates. February sales volumes were impacted by reduced nominations from our offtaker, Bahiagás mainly in the latter half of February. Effective March 1, 2024 deliveries to Bahiagás have increased back to over 10.6 MMcfpd.
Natural gas, NGLs and crude oil sales:
February2024
January 2024
Natural gas (Mcfpd), by field:
Caburé
7,875
9,305
Murucututu
449
382
Total Company natural gas (Mcfpd)
8,324
9,687
NGLs (bopd)
72
75
Oil (bopd)
19
9
Total Company (boepd)
1,477
1,699
Corporate Presentation
Alvopetro’s updated corporate presentation is available on our website at:
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:
boepd
=
barrels of oil equivalent (“boe”) per day
bopd
=
barrels of oil and/or natural gas liquids (condensate) per day
Mcf
=
thousand cubic feet
Mcfpd
=
thousand cubic feet per day
MMcfpd
=
million cubic feet per day
NGLs
=
natural gas liquids
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.
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 expected natural gas price, natural gas sales and natural gas deliveries under the Company’s long-term gas sales agreement. The forward‐looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to expectations and assumptions concerning expectations regarding Alvopetro’s working interest and the outcome of any redeterminations, the success of future drilling, completion, and testing, equipment availability, the timing of regulatory licenses and approvals, recompletion and development activities, the outlook for commodity markets and ability to access capital markets, the impact of global pandemics and other significant worldwide events, 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, 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.sedarplus.ca. 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.
Oil prices have staged a strong rally over the last few trading sessions, with both Brent and West Texas Intermediate (WTI) crude futures settling above $80 and $83 per barrel respectively on Friday. This marks the highest level for oil prices since November 2023. The recent surge has been driven by growing signs of tightness in global oil supplies along with heightened geopolitical risks in the Middle East.
For investors in the oil and gas sector, the combination of bullish supply and demand fundamentals and rising geopolitical tensions point to potential upside in oil prices through 2024. Here are some of the key factors driving the latest rally:
Supply Fundamentals Point to Tightness
On the supply side, oil prices are being lifted by OPEC+’s continued restraint on production increases. The group of major oil producers is expected to extend production cuts beyond their planned exit in March, tightening global supplies. Additionally, near-term futures contracts are trading at a premium to later dated contracts, a condition known as backwardation which signals tight supplies.
Asia Demand Exceeding Expectations
At the same time, oil demand has proved resilient, especially in Asia. Demand out of Asia has exceed expectations in recent months, even as parts of Europe remain locked down. With economies reopening as vaccine rollouts accelerate, pent-up travel demand in Asia is set to further boost oil consumption over 2023. The combination of robust demand growth and limited supply increases has led to a rapid drawdown of global oil inventories since the start of the year.
Middle East Tensions Creating Geopolitical Risk Premium
On top of bullish market fundamentals, ongoing tensions in the Middle East are layering fears of potential supply disruptions. Attacks on oil tankers transiting through the critical Red Sea route has rerouted tanker traffic and added to insurance costs. Escalating violence between Israel and Hamas has raised concerns over stability in the region.
Most importantly, oil prices could spike dramatically if Iran-backed Houthis were to target vessels travelling through the Strait of Hormuz. This critical passageway between Oman and Iran handles around 30% of all seaborne-traded crude oil globally. Any military clashes or outright closure of the Strait would severely constrain global oil flows and lead to a price spike.
Upside Risks Outweigh Downsides for Oil Prices
In summary, investors should be aware of the multitude of upside risks supporting higher oil prices as we progress through 2024. While oil demand may moderate as economies eventually normalize post-pandemic, OPEC+ restraint and the risk of supply disruptions look set to keep the market tight.
As leading investment banks like Goldman Sachs have noted, their base case forecast of $70-90 per barrel for Brent could easily see upside, with geopolitics posing the main risk. For investors, oil exploration and production companies as well as oil services firms stand to benefit most from higher prices. Integrated majors may lag on share price gains though due to their downstream refining exposure. Overall, oil markets appear set to tighten further, making the case for investors to overweight the energy sector.
CALGARY, AB, Feb. 26, 2024 /CNW/ – Alvopetro Energy Ltd. (TSXV:ALV) (OTCQX: ALVOF) announces our reserves as at December 31, 2023 with total proved plus probable (“2P”) reserves of 8.7 MMboe and a before tax net present value discounted at 10% (“NPV10”) of $309.7 million, risked best estimate contingent resources of 5.4 MMboe (NPV10 $126.1 million) and risked best estimate prospective resources of 9.6 Mmboe (NPV10 $184.9 million). The reserves and resources data set forth herein is based on an independent reserves and resources assessment and evaluation prepared by GLJ Ltd. (“GLJ”) dated February 26, 2024 with an effective date of December 31, 2023 (the “GLJ Reserves and Resources Report”).
The GLJ Reserves and Resources Report incorporates Alvopetro’s working interest share of remaining recoverable reserves held by Alvopetro in the Caburé and Murucututu natural gas fields and the Bom Lugar and Mãe-da-lua oil fields as well as Alvopetro’s working interest share of remaining recoverable resources held by Alvopetro in the Murucututu natural gas field. With respect to Murucututu, Bom Lugar, and Mãe-da-lua, Alvopetro’s working interest share is 100%. With respect to the unitized area (the “Unit”) which includes our Caburé and Caburé Leste fields (collectively referred to as “Caburé” in this news release) and two fields held by our third-party partner in the Unit, Alvopetro’s working interest share as of December 31, 2023 was 49.1%, with the remaining 50.9% held by our partner. As previously announced by the Company, the first redetermination of the working interests to each party commenced in the fourth quarter of 2023. The parties engaged an independent expert (the “Expert”) to evaluate the redetermination. Pursuant to the provisions of the UOA, where an Expert is engaged, the Expert’s determination shall be made using what is commonly referred to as the “pendulum” method of dispute resolution. Under this method, the Expert is not required or permitted to provide their own interpretation but is required to select the single Final Proposal (between the two partner’s respective Final Proposals), which, in the Expert’s opinion, provides the most technically justified result of the application of the relevant information and data and material provided to the Expert consistent with the UOA and all related documents. As of the date of this news release, the outcome of the Expert’s decision and the resulting working interest to Alvopetro following the decision is uncertain. The resulting impact on Alvopetro’s reserves and future cash flows may be material and may have a material adverse effect on Alvopetro. The impact on Alvopetro’s working interest will be effective on the first calendar day of the second month following the date of the decision of the Expert, subject to any government approvals that may be required. The decision of the Expert is expected near the end of the first quarter of 2024. The GLJ Reserves and Resource Report and the references included herein are based on the 49.1% interest in Caburé, Alvopetro’s working interest share as of December 31, 2023. The reserves data included in this news release and in the GLJ Reserves and Resources Report may be materially impacted following the Expert’s decision.
All references herein to $ refer to United States dollars, unless otherwise stated.
December 31, 2023 GLJ Reserves and Resource Report:
Proved reserves (“1P”) decreased 30% to 2.7 MMboe Proved reserves mainly due to 2023 production and technical revisions related to the 197-1 and 183-1 Murucututu wells. Alvopetro is working to enhance production from these wells with optimizations in 2024.
2P reserves decreased 4% from 9.0 to 8.7 MMboe after 0.8 MMboe of production in 2023. Production in 2023 was offset by improved recovery factors at Caburé due to the agreed Unit development plan and new additions associated with the discovery at the 183-A3 well in the Caruaçu Formation.
Proved plus Probable plus Possible reserves (“3P”) increased to 15.2 MMboe from 14.4 MMboe as a result of additions associated with the discovery at the 183-A3 well in the Caruaçu Formation.
2P NPV10 decreased 11% to $309.7 million due to changes in forecast natural gas prices and 2023 production offset mainly by additional value associated with discovered zones in the Caruaçu Formation on our Murucututu natural gas field.
Risked best estimate contingent resources increased from 2.9 MMboe to 5.4 MMboe at December 31, 2023 with a NPV10 of $126.1 million, increases from December 31, 2022 of 84% and 103% respectively. The increases were associated with the discovery at the 183-A3 well in the Caruaçu Formation.
Risked best estimate prospective resources decreased from 12.5 MMboe to 9.6 MMboe with a NPV10 of $184.9 million, decreases of 23% and 29% respectively from December 31, 2022. The decrease was due primarily to adjustments to the probabilistic models incorporating the logs results for the Gomo zone at the 183-A3 well.
SUMMARY
December 31, 2023 Gross Reserve and Gross Resource Volumes: (1)(2)(3)(4)(5)(6)
See ‘Footnotes’ section at the end of this news release
PRICING ASSUMPTIONS – FORECAST PRICES AND COSTS
GLJ employed the following pricing and inflation rate assumptions as of January 1, 2024 in the GLJ Reserves and Resources Report in estimating reserves and resources data using forecast prices and costs.
Year
Brent Blend Crude Oil FOB North Sea ($/Bbl)
National Balancing Point (UK)($/MMBtu)
NYMEX Henry HubNear Month Contract($/MMBtu)
Alvopetro-Bahiagas Gas Contract$/MMBtu(Current Year)
As of February 1, 2024, Alvopetro’s contracted natural gas price under the terms of our long-term gas sales agreement is based on the ceiling price within the contract. Pricing is forecast to stay slightly below the ceiling for future price adjustments. The ceiling price incorporates assumed US inflation of 2%.
GLJ RESERVES AND RESOURCES REPORT
The GLJ Reserves and Resources Report has been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) that are consistent with the standards of National Instrument 51-101 (“NI 51-101”). GLJ is a qualified reserves evaluator as defined in NI 51-101. The GLJ Reserves and Resources Report was an evaluation of all reserves of Alvopetro including our working interest share as of December 31, 2023 of the Unit (referred to herein as the Caburé natural gas field), our Murucututu natural gas project, as well as our Bom Lugar and Mãe-da-lua oil fields. The GLJ Reserves and Resources Report also includes an evaluation of the gas resources of our Murucututu natural gas field. In addition to the reserves assigned to our Murucututu field, contingent resource was assigned to the area in proximity to our existing Murucututu reserves, deemed to be discovered. The area mapped by 3D seismic west and north of the area defined as contingent was assigned prospective resource. Additional reserves and resources information as required under NI 51-101 will be included in the Company’s Annual Information Form for the 2023 fiscal year which will be filed on SEDAR+ (www.sedarplus.ca) by April 30, 2024.
December 31, 2023 Reserves Information:
Summary of Reserves (1)(2)(3)
Light & Medium Oil
Conventional Natural Gas
Natural Gas Liquids
Oil Equivalent
Company Gross
Company Net
Company Gross
Company Net
Company Gross
Company Net
Company Gross
Company Net
(Mbbl)
(Mbbl)
(MMcf)
(MMcf)
(Mbbl)
(Mbbl)
(Mboe)
(Mboe)
Proved
Producing
8
7
11,460
11,000
122
117
2,039
1,957
Developed Non-Producing
142
133
–
–
–
–
142
133
Undeveloped
–
–
2,951
2,818
54
52
546
522
Total Proved
150
140
14,411
13,818
176
169
2,727
2,612
Probable
302
285
31,175
29,859
486
465
5,983
5,726
Total Proved plus Probable
451
425
45,586
43,677
662
634
8,711
8,338
Possible
224
211
34,253
32,785
565
540
6,497
6,215
Total Proved plus Probable plus Possible
675
635
79,839
76,462
1,226
1,174
15,208
14,553
See ‘Footnotes’ section at the end of this news release
Summary of Before Tax Net Present Value of Future Net Revenue – $000s(1)(2)(3)(7)(8)
Undiscounted
5 %
10 %
15 %
20 %
Proved
Producing
114,762
106,922
100,204
94,364
89,230
Developed Non-Producing
6,337
5,157
4,257
3,570
3,040
Undeveloped
18,155
14,371
11,425
9,181
7,467
Total Proved
139,254
126,450
115,886
107,115
99,738
Probable
391,202
263,064
193,771
151,218
122,597
Total Proved plus Probable
530,456
389,514
309,657
258,333
222,335
Possible
538,835
271,641
172,416
124,475
96,580
Total Proved plus Probable plus Possible
1,069,291
661,155
482,073
382,808
318,915
See ‘Footnotes’ section at the end of this news release
Summary of After Tax Net Present Value of Future Net Revenue – $000s(1)(2)(3)(7)(8)
Undiscounted
5 %
10 %
15 %
20 %
Proved
Producing
107,434
100,320
94,209
88,886
84,200
Developed Non-Producing
5,623
4,552
3,728
3,098
2,613
Undeveloped
14,191
11,454
9,192
7,412
6,022
Total Proved
127,248
116,326
107,129
99,396
92,834
Probable
297,522
205,240
153,457
120,748
98,250
Total Proved plus Probable
424,769
321,565
260,586
220,145
191,085
Possible
388,926
204,696
133,885
98,386
77,076
Total Proved plus Probable plus Possible
813,695
526,262
394,471
318,531
268,160
See ‘Footnotes’ section at the end of this news release
Future Development Costs (1)(2)(3)(7)(8)
The table below sets out the total development costs deducted in the estimation of future net revenue attributable to proved reserves, proved plus probable reserves and proved plus probable plus possible reserves (using forecast prices and costs), by field, in the GLJ Reserves and Resources Report. Total development costs include capital costs for drilling and completing wells and for facilities but excludes abandonment and reclamation costs.
The future development costs for the Caburé field include Alvopetro’s working interest share (49.1%) for three development wells in the proved category and an additional two development wells in the probable and possible categories. Also included in future development costs for Caburé are costs associated with a facilities upgrade planned at the field for compression of natural gas to be delivered to Alvopetro’s natural gas processing facility. In prior years, Alvopetro reflected all equipment rental payments associated with our Gas Treatment Agreement with Enerflex Ltd. as part of future development costs; however in 2023, such costs are now incorporated within operating expense along with other operating costs associated with the agreement. The future costs associated with equipment rental are also reflected as a capital lease obligation on our financial statements.
The future development costs for the Murucututu field in the proved category include one development well and stimulation costs for the 183-1 and 183-A3 wells and one project to improve recovery from the 197(1) well. The probable category also includes an additional two development wells along with additional stimulation projects at the 183-1 and 183-A3 wells. The possible category includes one additional well.
The future development costs for Bom Lugar in the proved category include costs to stimulate the BL-06 well drilled by Alvopetro in 2023. Costs in the probable category also include one development well and costs for facilities upgrade. Future development costs at the Mãe-da-lua field relate to a stimulation of the existing producing well.
Alvopetro’s share of future development costs are summarized as follows:
$000s, Undiscounted
2024
2025
2026
2027
2028
Remaining
Total
Proved
Caburé Natural Gas Field
6,993
–
–
–
–
–
6,993
Murucututu Gas Field
2,050
6,885
–
–
–
–
8,935
Bom Lugar Oil Field
–
510
–
–
–
–
510
Mãe-da-lua Oil Field
–
551
–
–
–
–
551
Total Proved
9,043
7,946
–
–
–
–
16,989
Proved Plus Probable
Caburé Natural Gas Field
6,993
2,504
–
–
–
–
9,497
Murucututu Gas Field
3,950
20,655
–
–
–
–
24,605
Bom Lugar Oil Field
–
6,059
–
–
–
–
6,059
Mãe-da-lua Oil Field
–
551
–
–
–
–
551
Total Proved Plus Probable
10,943
29,769
–
–
–
–
40,712
Proved Plus Probable Plus Possible
Caburé Natural Gas Field
6,993
2,504
–
–
–
–
9,497
Murucututu Gas Field
3,950
27,540
–
–
–
–
31,490
Bom Lugar Oil Field
–
6,059
–
–
–
–
6,059
Mãe-da-lua Oil Field
–
551
–
–
–
–
551
Total Proved Plus Probable Plus Possible
10,943
36,654
–
–
–
–
47,597
See ‘Footnotes’ section at the end of this news release
Reconciliation of Alvopetro’s Gross Reserves (Before Royalty) (1)(2)(3)(8)
Proved(Mboe)
Probable(Mboe)
Proved Plus Probable(Mboe)
Possible(Mboe)
Proved plusProbable plus Possible(Mboe)
December 31, 2022
3,909
5,128
9,037
5,345
14,382
Discoveries
–
1,398
1,398
2,488
3,886
Extensions
–
148
148
(148)
–
Technical Revisions
(400)
(690)
(1,090)
(1,188)
(2,278)
Production
(782)
–
(782)
–
(782)
December 31, 2023
2,727
5,983
8,711
6,497
15,208
See ‘Footnotes’ section at the end of this news release.
December 31, 2023 Murucututu Contingent Resources Information:
Summary of Unrisked Company Gross Contingent Resources (1)(2)(5)(6)
Development Pending Economic Contingent Resources
Low Estimate
Best Estimate
High Estimate
Conventional natural gas (MMcf)
20,952
32,062
35,433
Natural gas liquids (Mbbl)
386
591
653
Oil equivalent (Mboe)
3,878
5,935
6,559
See ‘Footnotes’ section at the end of this news release.
Summary of Before Tax Net Present Value of Future Net Revenue of Unrisked Contingent Resources- $000s (1)(2)(5)(6)(7)(8)
Undiscounted
5 %
10 %
15 %
20 %
Low Estimate
279,201
146,114
91,400
63,327
46,651
Best Estimate
470,246
226,624
139,760
97,612
73,016
High Estimate
540,860
246,103
148,348
102,781
76,691
See ‘Footnotes’ section at the end of this news release.
The GLJ Contingent Resource Report for Murucututu assumes capital deployment starting in 2025 for the drilling and completion of wells with total project costs of $20.8 million and first commercial production in 2025. The information presented herein is based on company net project development costs. The recovery technology assumed for purposes of the estimate is based on established technologies utilized repeatedly in the industry.
There can be no certainty that the project will be developed on the timelines discussed herein. The project is based on a pre-development study. Development of the project is dependent on several contingencies as further described in this news release. Significant positive factors relevant to the estimate include existing production in close proximity, proximity to infrastructure, existing long-term gas sales agreement and corporate commitment to the project. Significant negative factors relevant to the estimate include reservoir performance and the economic viability of the project (with sensitivity to low commodity prices), access to and amount of capital required to develop resources at an acceptable cost, and regulatory approvals for planned activities including stimulations and new infrastructure developments.
Summary of Development Pending Risked Company Gross Contingent Resources(1)(2)(5)(6)
The GLJ Reserves and Resources Report estimates the Chance of Development as the product of two main contingencies associated with the project development, which are: 1) the probability of corporate sanctioning, which GLJ estimates at 95%; 2) the probability of finalization of a development plan, which GLJ estimates at 95%. The product of these two contingencies is 90%. As there is no risk related to discovery, the Chance of Commerciality for the contingent resource is therefore 90% which is the risk factor that has been applied to the Development Risked company gross contingent resources and the net present value figures reported below.
Low Estimate
Best Estimate
High Estimate
Conventional natural gas (MMcf)
18,909
28,936
31,978
Natural gas liquids (Mbbl)
349
533
590
Oil equivalent (Mboe)
3,500
5,356
5,919
See ‘Footnotes’ section at the end of this news release.
Summary of Development Pending Risked Before Tax Net Present Value of Future Net Revenue of Contingent Resources- $000s(1)(5)(6)(7)(8)
Undiscounted
5 %
10 %
15 %
20 %
Low Estimate
251,978
131,868
82,489
57,153
42,102
Best Estimate
424,397
204,528
126,134
88,095
65,897
High Estimate
488,126
222,108
133,884
92,760
69,214
See ‘Footnotes’ section at the end of this news release.
December 31, 2023 Murucututu Prospective Resources Information:
Summary of Unrisked Company Gross Prospective Resources (1)(2)(4)(6)
Prospective Resources
Low
Best
High
Conventional natural gas (MMcf)
31,903
64,251
101,392
Natural gas liquids (Mbbl)
588
1,184
1,869
Oil equivalent (Mboe)
5,905
11,893
18,768
See ‘Footnotes’ section at the end of this news release.
Summary of Before Tax Net Present Value of Future Net Revenue of Unrisked Prospective Resources – $000s (1)(4)(6)(7)(8)
Undiscounted
5 %
10 %
15 %
20 %
Low Estimate
395,126
179,911
96,052
56,094
34,354
Best Estimate
959,658
413,788
227,919
142,785
96,201
High Estimate
1,628,234
680,308
376,039
240,051
165,845
See ‘Footnotes’ section at the end of this news release.
The GLJ Reserves and Resources Report for Murucututu prospective resources assumes capital deployment starting in 2026 for the drilling and completion of wells and pipeline expansion costs, with total project costs of $75.8 million and first commercial production in 2026. The information presented herein is based on company project development costs. The recovery technology assumed for purposes of the estimate is based on established technologies utilized repeatedly in the industry.
There can be no certainty that the project will be developed on the timelines discussed herein. Development of the project is dependent on several contingencies as further described in this news release. The project is based on a conceptual study. Significant positive factors relevant to the estimate include existing production in close proximity, proximity to infrastructure, existing long-term gas sales agreement and corporate commitment to the project. Significant negative factors relevant to the estimate include reservoir performance and the economic viability of the project (with sensitivity to low commodity prices), access to and amount of capital required to develop resources at an acceptable cost, and regulatory approvals for planned activities including stimulations and new infrastructure developments.
Summary of Development Risked Company Gross Prospective Resources(1)(2)(4)(6)
The GLJ Reserves and Resources Report estimates the Chance of Commerciality as the product between the Chance of Discovery and the Chance of Development. The Chance of Discovery of the prospective resources has been assessed at 90%, while the Chance of Development has been assessed as the same as for the Contingent Resources described above at 90%. The resulting Chance of Commerciality is 81%, which has been applied to the company gross unrisked prospective resources and the net present value figures reported below.
Low
Best
High
Conventional natural gas (MMcf)
25,876
52,112
82,237
Natural gas liquids (Mbbl)
477
961
1,516
Oil equivalent (Mboe)
4,790
9,646
15,222
See ‘Footnotes’ section at the end of this news release.
Summary of Development Risked Before Tax Net Present Value of Future Net Revenue of Prospective Resources- $000s(1)(4)(6)(7)(8)
Undiscounted
5 %
10 %
15 %
20 %
Low Estimate
320,477
145,922
77,906
45,497
27,864
Best Estimate
778,356
335,614
184,859
115,810
78,027
High Estimate
1,320,623
551,782
304,997
194,700
134,513
See ‘Footnotes’ section at the end of this news release.
Upcoming 2023 Results and Live Webcast
Alvopetro anticipates announcing its 2023 fourth quarter and year-end results on March 19, 2024 after markets close and will host a live webcast to discuss the results at 8:00am Mountain time, on March 20, 2024. 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.
References to Company Gross reserves or Company Gross Resources means the total working interest share of remaining recoverable reserves or resources held by Alvopetro before deductions of royalties payable to others and without including any royalty interests held by Alvopetro. With respect to the Caburé natural gas field, Alvopetro’s working interest was 49.1% as of December 31, 2023 but is subject to redetermination, the first of which is currently underway. The outcome of this redetermination is unknown and the resulting impact on the reserves presented herein may be material.
(2)
The tables above are a summary of the reserves of Alvopetro and the net present value of future net revenue attributable to such reserves as evaluated in the GLJ Reserves and Resources Report based on forecast price and cost assumptions. The tables summarize the data contained in the GLJ Reserves and Resources Report and as a result may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.
(3)
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
(4)
Prospective Resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. There is no certainty that any portion of the prospective resources will be discovered and even if discovered, there is no certainty that it will be commercially viable to produce any portion. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery as described in footnote 6.
(5)
Contingent Resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates as described in footnote 6 and may be subclassified based on project maturity and/or characterized by their economic status. The Contingent Resources estimated in the GLJ Reserves and Resources Report are classified as “economic contingent resources”, which are those contingent resources that are currently economically recoverable. All such resources are further sub-classified with a project status of “development pending”, meaning that resolution of the final conditions for development are being actively pursued. The recovery estimates of the Company’s contingent resources provided herein are estimates only and there is no guarantee that the estimated resources will be recovered. There is uncertainty that it will be commercially viable to produce any portion of the resources. Actual recovered resource may be greater than or less than the estimates provided herein.
(6)
Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
(7)
The net present value of future net revenue attributable to Alvopetro’s reserves and resources are stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, well abandonment and reclamation costs for only those wells assigned reserves and material dedicated gathering systems and facilities. The net present values of future net revenue attributable to Alvopetro’s reserves and resources estimated by GLJ do not represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve and resource estimates of the Company’s reserves and resources provided herein are estimates only and there is no guarantee that the estimated reserves and resources will be recovered. Actual reserves and resources may be greater than or less than the estimates provided herein.
(8)
GLJ’s January 1, 2024 escalated price forecast is used in the determination of future gas sales prices under Alvopetro’s long-term gas sales agreement and for all forecasted oil sales and natural gas liquids sales. See https://www.gljpc.com/sites/default/files/pricing/Jan24.pdf for GLJ’s price forecast.
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 news release are in United States dollars, except as otherwise noted.
Abbreviations:
1P
=
proved reserves
2P
=
proved plus probable reserves
3P
=
proved plus probable plus possible reserves
Mbbl
=
thousands of barrels
Mboe
=
thousand barrels of oil equivalent
MMbtu
=
million British Thermal Units
MMcf
=
million cubic feet
MMboe
=
million barrels of oil equivalent
$000s
=
thousands of U.S. dollars
Oil and Natural Gas Advisories
Oil and Natural Gas Reserves
The disclosure in this news release summarizes certain information contained in the GLJ Reserves and Resources Report but represents only a portion of the disclosure required under NI 51-101. Full disclosure with respect to the Company’s reserves as at December 31, 2023 will be included in the Company’s annual information form for the year ended December 31, 2023 which will be filed on SEDAR+ (www.sedarplus.ca) on or before April 30, 2024. The GLJ Reserves and Resources Report incorporates Alvopetro’s working interest share of remaining recoverable reserves and resources. With respect to the Caburé natural gas field, Alvopetro’s working interest was 49.1% as of December 31, 2023 but is subject to redetermination, the first of which is currently underway. The outcome of this redetermination is unknown and the resulting impact on the reserves and the net presented value of future net revenue attributable to such reserves as presented herein may be material.
All net present values in this press release are based on estimates of future operating and capital costs and GLJ’s forecast prices as of December 31, 2023. The reserves definitions used in this evaluation are the standards defined by COGEH reserve definitions and are consistent with NI 51-101 and used by GLJ. The net present values of future net revenue attributable to the Alvopetro’s reserves estimated by GLJ do not represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of the Company’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
Contingent Resources
This news release discloses estimates of Alvopetro’s contingent resources and the net present value associated with net revenues associated with the production of such contingent resources as included in the GLJ Reserves and Resources Report. There is no certainty that it will be commercially viable to produce any portion of such contingent resources and the estimated future net revenues do not necessarily represent the fair market value of such contingent resources. Estimates of contingent resources involve additional risks over estimates of reserves. Full disclosure with respect to the Company’s contingent resources as at December 31, 2023 will be contained in the Company’s annual information form for the year ended December 31, 2023 which will be filed on SEDAR+ (www.sedarplus.ca) on or before April 30, 2024.
Prospective Resources
This news release discloses estimates of Alvopetro’s prospective resources included in the GLJ Reserves and Resources Report. There is no certainty that any portion of the prospective resources will be discovered and even if discovered, there is no certainty that it will be commercially viable to produce any portion. Estimates of prospective resources involve additional risks over estimates of reserves. The accuracy of any resources estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While resources presented herein are considered reasonable, the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. Full disclosure with respect to the Company’s prospective resources as at December 31, 2023 will be contained in the Company’s annual information form for the year ended December 31, 2023 which will be filed on SEDAR+ (www.sedarplus.ca) on or before April 30, 2024.
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.
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 redetermination and Alvopetro’s working interest share of the unitized area and the potential impact of the redetermination on Alvopetro, plans relating to the Company’s operational activities, proposed development activities and the timing for such activities, capital spending levels and future capital costs, the expected natural gas price, gas sales and gas deliveries under Alvopetro’s long-term gas sales agreement. The forward‐looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to expectations and assumptions concerning the timing of regulatory licenses and approvals, equipment availability, the success of future drilling, completion, testing, recompletion and development activities, the performance of producing wells and reservoirs, well development and operating performance, expectations regarding Alvopetro’s working interest and the outcome of any redeterminations, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, the outlook for commodity markets and ability to access capital markets, foreign exchange rates, general economic and business conditions, the impact of the COVID-19 pandemic, weather and access to drilling locations, the availability and cost of labour and services, 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.sedarplus.ca). 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.
