Image Credit: Paul B (Flickr)

Will Drivers Continue to be Dogged by High Gas Prices as US Strategic Oil Reserve is Replenished?

The last time the US Strategic Oil Reserves was this low was January 1985. The US population was then 238 million, The Cosby Show was the top-rated on TV, the threat of the AIDS virus was just beginning to be understood, and a newly appointed NIH Director named Anthony Fauci had just been promoted. In 37 years, some things have changed, and some things have not. One that has not is the need for reliable energy.

The Reserves reached their peak in April 2011 with 726.5 million barrels; today, we sit with 453.1 million. Will it take 37 years to replenish the more than 200 million barrels, 160 million of which have been siphoned off since March of this year?

The barrels that are being used in 2022 were ordered released by the White House to offset the domestic loss of production, pipeline distribution, and less supply being compounded by global shortages resulting from a partial embargo against Russia. The order was intended to work to lower gas prices today and help reduce the impact oil prices are having on unacceptably high inflation.

President Biden said in March that the US would release one million barrels of oil a day for six months as petroleum products spiked following the start of the Russian/Ukrainian war. The White House then said, in late July, the US would release another 20 million barrels.

To some degree, it worked as intended. There has been a fall in the price at the gas pumps over the past two months. Much of this has been supply-related, helped by the reserve releases, to a lesser extent, demand has also slowed from receding economic activity. WTI crude, the US benchmark price, has dropped around 24%.

That decline has brought US gasoline prices down from above $5 a gallon in June to $3.89 on Tuesday, August 17. Globally, other countries are tapping into their own strategic reserves as well.

What Happens When we Refill It?

The US consumed about 20 million barrels of oil a day on average in 2021, according to the EIA. During the same year, it produced 11 million barrels a day. The Biden administration is proposing to refill the stockpiles under a plan that is likely to see it order 60 million barrels this fall for delivery at an unspecified time in the future. That leaves at least another 100 million barrels to bring the country back to where we were in March 2022 – over two hundred more to bring us back to the peak. It took 37 years last time for the country to stockpile the same amount.

The current infrastructure is not supporting additional oil output, otherwise, companies would be pumping more now. On July 1, President Biden made public a five-year proposal for offshore oil and gas development in areas of existing production and said the final plan might have anywhere from zero to 11 lease sales.

The range of proposed options was between two auctions a year and none at all. The plan seemed conflicted with a desire to balance the administration’s efforts to reduce the use of fossil fuels and its calls to increase needed oil and gas.

Energy Demand Moving Forward

Does restocking the Reserves point toward high petroleum demand for a much longer time period than ever expected? Does it also create opportunities for producers of biofuels, for example, GEVO?

The current fuel issues are not going to disappear overnight. Borrowing from the future with the intent, and now a plan, to pay it back, will require more production than before. Companies that produce are not inclined to make big investments in building out a platform when the political climate is one of wanting to shut production down as soon as possible.

The cost of reducing energy output and then borrowing from reserves, especially after an unexpected embargo is placed on a major global  supplier, could keep the price of all energy elevated for a much longer time than the end of a war, of installation of coastal wind farms.

Paul Hoffman

Managing Editor, Channelchek

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Sources

https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MCSSTUS1&f=M

https://www.eia.gov/petroleum/gasdiesel/gas_geographies.php#pricesbyregion

https://www.whitehouse.gov/briefing-room/statements-releases/2022/07/26/fact-sheet-department-of-energy-releases-new-notice-of-sale-as-gasoline-prices-continue-to-fall/

https://www.niaid.nih.gov/about/director

https://www.energy.gov/articles/doe-announces-additional-notice-sale-crude-oil-strategic-petroleum-reserve

https://www.reuters.com/business/energy/biden-administration-proposes-offshore-drilling-plan-focused-mainly-us-gulf-2022-07-01/

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Image Credit: Kees Torn (Flickr)

Natural Gas Prices May Continue to Explode Through Winter

Natural-gas futures jumped to nearly $10 per million BTU today (August 23), the highest since July 2008. This is an increase of 20% over the past month, up 146% from a year ago, and up 350% from three years ago. The drop-off in commodity prices that helped bring natural gas prices down has now been more than erased by what has been extreme volatility even by natural gas price standards.

The 14-year highs reached this week in U.S. natural-gas futures point to unrelenting demand pressures, especially in Europe. There are reasons to believe the increases will continue.

The latest price spike is largely fueled by Russia’s plans to shut down one of Europe’s main fuel arteries for a few days at the end of August. It’s unclear if that shutdown, announced Friday, is actual unplanned maintenance along the Nord Stream gas pipeline or related to economic warfare by Russia as retaliation for Western Europe’s support for Ukraine.

Short supply in Europe, above-average hot weather impacting utilities’ needs in the U.S, and concerns related to hurricane season, when storms often halt production on platforms in the Gulf of Mexico, may serve to increase prices higher.

Source: Koyfin

Normally in late Summer, prices ease in anticipation of low demand fall weather. Producers and traders usually squirrel away supplies in underground caverns until winter, when demand and prices typically are at their high for the year.

This year, though, export demand, electric demand related to some of the hottest weather on record, and low production growth have kept U.S. natural-gas supplies from growing ahead of the heating season.

The U.S. Energy Information Administration (EIA) reported an unseasonably paltry offload into storage facilities. Storage grew but left a projected deficit of 12.7% to the average for this point on the calendar.

The lag in storage could be leading to a global situation if winter is colder than normal – a situation where natural gas prices may spike upward.

Production vs. Usage

EIA data show that monthly domestic production reached its highest level since the pandemic in May, though it remained short of the output record set in December 2019. And output has decreased.

U.S. demand is rising. Coal prices that have risen more sharply than gas and scarce supplies of coal have limited electric producers’ options, which have been in high demand to run air conditioners this summer. Government energy forecasters expect average daily U.S. gas consumption this year to be 3% higher. They expect year-over-year production gains at roughly the same rate.

Meanwhile, exports are set to rise this fall when one of the country’s biggest liquefied-natural-gas, or LNG, terminals resume operations. Freeport LNG’s facility on a Texas barrier island has been shut down since a fire in early June. This reduced U.S. export capacity by about one-sixth, or near 2 billion cubic feet a day. It produces roughly enough energy units to power 50,000 homes for a year it went back online and became available for U.S. consumption this summer, which helped to hold prices lower in the US. The facility said it expects to resume exports in October.

Spikes in futures prices don’t immediately translate into higher natural gas prices at home, but eventually, they do increase the average paid.

Inflation and Natural Gas

In addition to electricity prices increasing via power plants, other increases, including food prices via fertilizers, and other unexpected impacts such as glass bottle production, that add to overall inflation.

The June-July plunge in natural-gas futures prices had been one of the reasons cited why inflation in the U.S. was seen as having peaked and moving lower. Utility natural gas piped to homes accounts for about 1% of total CPI. As part of the July CPI reading, utility gas piped to homes fell by 3.6% in price from June, the first month-to-month decline since January after repeated spikes., including +8.2% in June from May and +8.0% in May from April.

Spikes in futures prices don’t immediately translate into higher natural gas prices at home, but eventually, they do. Eventually, prices average up, and we will all be sharing the cost as consumers or perhaps benefitting as investors in either natural gas companies, or more directly in funds or futures.

Paul Hoffman

Managing Editor, Channelchek

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Sources

https://globallnghub.com/front-month-rallies-to-5.html

https://www.eia.gov/todayinenergy/detail.php?id=53559

https://www.eia.gov/petroleum/supply/weekly/

A Gas Shortage Could Crunch Beer Bottles Too – WSJ

https://www.cmegroup.com/trading/energy/natural-gas/lng-futures.html

https://www.energy.gov/sites/prod/files/2017/09/f36/Understanding%20Natural%20Gas%20and%20Lng%20Options_general%20no%20appendix.pdf

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Alvopetro Announces 182-C1 Well Results

Research, News, and Market Data on Alvopetro Energy

Aug 22, 2022

CALGARY, AB, Aug. 22, 2022 /CNW/ – Alvopetro Energy Ltd. (TSXV: ALV) (OTCQX: ALVOF) announces that we have suspended testing at the 182-C1 well on our 100% owned and operated Block 182 in the Recôncavo basin. During the testing operation we perforated the entire 25m of net pay section of the well on tubing conveyed perforations in an underbalanced condition. No formation flow was observed after the initial perforations. We injected 124 barrels (“bbls”) of 15% hydrochloric acid to remove possible near wellbore damage. We then removed the liquid from the wellbore with a jet lift operation using nitrogen and coil tubing. After recovering 231 bbls of the initial 303 bbls of brine and acid we discontinued operations, due to lack of progress in removing any further liquids. We have not recovered any hydrocarbons from the wellbore and will continue to monitor the wellbore pressure from surface, but expect to permanently abandon wellbore in the future.

The primary and secondary targets of the 182-C1 well were the Agua Grande and Sergi Formations, respectively. Based on open hole logs, the 182-C1 well encountered net pay in the Agua Grande Formation very close to the main bounding fault and the well crossed over the fault before encountering the secondary target in the Sergi Formation. We plan to drill a follow up well, 182-C2, to assess the Agua Grande reservoir quality and to target the Sergi Formation further east from the bounding fault. We expect to spud the 182-C2 well later in August.

Corporate Presentation

Alvopetro’s updated corporate presentation is available on our website at:http://www.alvopetro.com/corporate-presentation. 

Social MediaFollow Alvopetro on our social media channels at the following links:

Twitter – https://twitter.com/AlvopetroEnergyInstagram – 
https://www.instagram.com/alvopetro/LinkedIn – 
https://www.linkedin.com/company/alvopetro-energy-ltdYouTube: https://www.youtube.com/channel/UCgDn_igrQgdlj-maR6fWB0w

Alvopetro Energy Ltd.’s vision is to become a
leading independent upstream and midstream operator in Brazil. Our
strategy is to unlock the on-shore natural gas potential in the state of Bahia
in Brazil,
building off the development of our Caburé natural gas field and our strategic
midstream infrastructure.

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.

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 exploration and development prospects of Alvopetro and
the expected timing of certain of Alvopetro’s operational activities. The
forward?looking
statements are based on certain key expectations and assumptions made by
Alvopetro, including but not limited to expectations and assumptions concerning
testing results, equipment availability, the timing of regulatory licenses and
approvals, the success of future drilling, completion, testing, recompletion
and development activities, the outlook for commodity markets and ability to
access capital markets, the impact of the COVID-19 pandemic, the performance of
producing wells and reservoirs, well development and operating performance, foreign
exchange rates, general economic and business conditions, weather and access to
drilling locations, the availability and cost of labour and services,
environmental regulation, including regulation relating to hydraulic fracturing
and stimulation, the ability to monetize hydrocarbons discovered, the
regulatory and legal environment and other risks associated with oil and gas
operations. The reader is cautioned that assumptions used in the preparation of
such information, although considered reasonable at the time of preparation,
may prove to be incorrect. Actual results achieved during the forecast period
will vary from the information provided herein as a result of numerous known
and unknown risks and uncertainties and other factors. Although Alvopetro
believes that the expectations and assumptions on which such forward-looking
information is based are reasonable, undue reliance should not be placed on the
forward-looking information because Alvopetro can give no assurance that it
will prove to be correct. Readers are cautioned that the foregoing list of
factors is not exhaustive. Additional information on factors that could affect
the operations or financial results of Alvopetro are included in our annual
information form which may be accessed on Alvopetro’s SEDAR profile at www.sedar.com.
The forward-looking information contained in this news release is made as of
the date hereof and Alvopetro undertakes no obligation to update publicly or
revise any forward-looking information, whether as a result of new information,
future events or otherwise, unless so required by applicable securities laws.

SOURCE Alvopetro Energy Ltd.

Image Credit: Alberta Newsroom (Flickr)

Biden Signs Inflation Reduction Act: Its Climate Promise Relies Heavily on Carbon Capture, Meaning Thousands of Miles of Pipeline

President Joe Biden signed a sweeping climate, energy and health care bill on Aug. 16, 2022, that contains about US$370 billion to foster clean energy development and combat climate change, constituting the largest federal climate investment in history.

Several studies project that its climate and energy provisions could enable the United States to reduce its greenhouse gas emissions by around 40% below 2005 levels by 2030. That would be a significant improvement over the current projections of around 27%, and it could put the U.S. within hailing range of its pledge under the Paris Agreement to reduce emissions by at least 50% by 2030.

Notably, one linchpin of the new climate provisions is a set of incentives to substantially expand technologies that capture carbon dioxide and either store it underground or ship it for reuse.

So far, the uptake of carbon capture technologies has been slow. The costs are high, and these technologies can require miles of pipeline and vast amounts of underground storage, both of which can trigger local backlash. A recent study projected that the U.S. would have to construct 65,000 miles of carbon dioxide pipelines to achieve net-zero emissions in 2050, a whopping 13 times the current capacity.

I’m the former founding co-director of the Institute for Carbon Removal Law &  Policy at American University. While the new law, known as the Inflation Reduction Act, has many provisions designed to jump-start the carbon removal sector, it’s far from certain that the industry will be able to move quickly.

One-Sixth of all Emissions Cuts

The Inflation Reduction Act includes two primary types of carbon capture.

Carbon capture and storage entails capturing carbon dioxide generated during power generation and industrial processes, such as steel and concrete production, and transporting it for storage or use. The most common use to date has been for enhanced oil recovery – injecting the gas into oil and gas reservoirs to extract more fossil fuels.

It also seeks to drive deployment of direct air capture technologies, which can pull carbon dioxide out of the air.

A Princeton University analysis estimated that pertinent provisions of the legislation “would increase the use of carbon capture 13-fold by 2030 relative to current policy,” with only a modest amount projected to come from carbon dioxide removal. This could translate into about one-sixth to one-fifth of its projected carbon dioxide emissions reductions.

Consistent with most of its other energy and climate provisions, the Inflation Reduction Act seeks to drive widespread deployment of carbon removal technologies through incentives. Most importantly, it substantially amends a provision of the U.S. tax code
referred to as 45Q, which is designed to drive corporate investments in carbon
capture.

Under its provisions, tax credits for capturing carbon dioxide at industrial facilities and power plants would increase from $50 per ton today to up to $85 per ton if the carbon is stored. If the carbon is used instead for oil drilling, the credit would go from $30 today to $60 per ton.

Credits for capturing carbon from air via direct air capture would also dramatically jump, from $50 to $180 per ton if the carbon dioxide is stored, and from $35 currently to $130 per ton if it is used.

The new law also moves back the deadline for starting construction of carbon capture facilities that qualify from 2026 to 2033, reduce the minimum capture requirements for obtaining credits, and permit direct payments for the full value of credits for the first five years of a project’s operation in lieu of tax credits.

Missing Pieces

Currently there are only a dozen carbon capture and storage facilities in the U.S. and a couple of direct air capture facilities removing a small amount of carbon from the air.

There’s a reason the uptake of carbon capture, particularly direct air capture, has been slow. Direct air capture cost estimates vary from $250 to $600 per ton, according to one analysis, while experts have estimated that a price under $100 and closer to $50 could create a market.

Some experts believe that the Inflation Reduction Act sufficiently ratchets up 45Q credits to start driving widespread construction of carbon capture and storage facilities in the power and industrial sectors. Others believe that the direct pay provision is “the fundamental missing piece” for carbon capture and storage because project developers and sponsors can avoid the often onerous and costly process of raising tax equity to qualify to use the credits.

There’s hope that the increase in credit values for direct air capture will help to foster “synthetic economics” for this nascent market, infusing sufficient capital to develop technologies at scales that are profitable.

Pipeline Challenges Ahead

However, while the Inflation Reduction Act may appear helpful on a theoretical basis, both carbon capture and storage and direct air capture could face some serious headwinds over the course of the next decade and beyond.

One major challenge could be resistance to the construction of pipelines to transport carbon dioxide to storage sites. In recent years, counties and private landowners in Iowa have voiced opposition to such projects, particularly the idea that the state might allow pipeline builders to seize private land for their projects.

Pipeline construction is also a point of contention for environmental groups, especially environmental justice organizations, and could lead to protracted litigation. This stems in part from a carbon dioxide pipeline rupture in Satartia, Mississippi, in 2020, which hospitalized 45 people.

If public opposition delays construction, projects could be pushed past the window for the incentives, leaving developers with expensive projects. While some studies argue that enhanced oil recovery results in a net reduction in carbon dioxide emissions, this may ultimately be a hard political sell for local communities.

The Inflation Reduction Act may ultimately brighten the prospects for carbon removal in America, but this is by no means assured, especially in the optimistic time frame of the next decade.

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Monday, August 15, 2022

Alvopetro Energy (ALVOF)
No surprises in quarterly results, time to shift focus to the future

Alvopetro Energy Ltd.’s vision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.

Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.

Refer to the full report for the price target, fundamental analysis, and rating.

Alvopetro Energy reported 2022-2Q results significantly higher than last year and in line with expectations. Production of 2,359 boe/d (versus 2,361 last year and 2,501 last quarter) reflects a 5-day suspension of production in preparation for a processing plant expansion. The average gas price was $11.90/mcf. versus $6.06/mcf last year. With higher pricing, sales rose 93%, fund flow from operations rose 127%, and net income rose 74%. Results were in line with our expectations.

Positive pricing will continue for the immediate future and beyond. Contracted gas prices were set at $11.28/mcf. effective August 1, 2022. We believe the price Alvopetro will receive over the six months of this period’s pricing to be above $11.28/mcf and closer to $11.50/mcf. based on current exchange rates. Prices would have been set at a higher level had the increase not been constrained by a ceiling. In fact, Alvopetro management showed a chart with current prices indicating prices might have been as high $20 had there not been a ceiling. The indicated price is so far above the ceiling price that pricing will most likely be at the ceiling for the foreseeable future even if energy prices or the Real pull back from current levels….

This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).

*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision. 

Image Credit: Victor Leshyk (MIT News)

A New Method Boosts Wind Farms’ Energy Output, Without New Equipment

David L. Chandler | MIT
News Office

Virtually all wind turbines, which produce more than 5 percent of the world’s electricity, are controlled as if they were individual, free-standing units. In fact, the vast majority are part of larger wind farm installations involving dozens or even hundreds of turbines, whose wakes can affect each other.

Now, engineers at MIT and elsewhere have found that, with no need for any new investment in equipment, the energy output of such wind farm installations can be increased by modeling the wind flow of the entire collection of turbines and optimizing the control of individual units accordingly.

The increase in energy output from a given installation may seem modest — it’s about 1.2 percent overall, and 3 percent for optimal wind speeds. But the algorithm can be deployed at any wind farm, and the number of wind farms is rapidly growing to meet accelerated climate goals. If that 1.2 percent energy increase were applied to all the world’s existing wind farms, it would be the equivalent of adding more than 3,600 new wind turbines, or enough to power about 3 million homes, and a total gain to power producers of almost a billion dollars per year, the researchers say. And all of this for essentially no cost.

The research is published today in the journal Nature Energy, in a study led by MIT Esther and Harold E. Edgerton Assistant Professor of Civil and Environmental Engineering Michael F. Howland.

“Essentially all existing utility-scale turbines are controlled ‘greedily’ and independently,” says Howland. The term “greedily,” he explains, refers to the fact that they are controlled to maximize only their own power production, as if they were isolated units with no detrimental impact on neighboring turbines.

But in the real world, turbines are deliberately spaced close together in wind farms to achieve economic benefits related to land use (on- or offshore) and to infrastructure such as access roads and transmission lines. This proximity means that turbines are often strongly affected by the turbulent wakes produced by others that are upwind from them — a factor that individual turbine-control systems do not currently take into account.

“From a flow-physics standpoint, putting wind turbines close together in wind farms is often the worst thing you could do,” Howland says. “The ideal approach to maximize total energy production would be to put them as far apart as possible,” but that would increase the associated costs.

That’s where the work of Howland and his collaborators comes in. They developed a new flow model which predicts the power production of each turbine in the farm depending on the incident winds in the atmosphere and the control strategy of each turbine. While based on flow-physics, the model learns from operational wind farm data to reduce predictive error and uncertainty. Without changing anything about the physical turbine locations and hardware systems of existing wind farms, they have used the physics-based, data-assisted modeling of the flow within the wind farm and the resulting power production of each turbine, given different wind conditions, to find the optimal orientation for each turbine at a given moment. This allows them to maximize the output from the whole farm, not just the individual turbines.

Today, each turbine constantly senses the incoming wind direction and speed and uses its internal control software to adjust its yaw (vertical axis) angle position to align as closely as possible to the wind. But in the new system, for example, the team has found that by turning one turbine just slightly away from its own maximum output position — perhaps 20 degrees away from its individual peak output angle — the resulting increase in power output from one or more downwind units will more than make up for the slight reduction in output from the first unit. By using a centralized control system that takes all of these interactions into account, the collection of turbines was operated at power output levels that were as much as 32 percent higher under some conditions.

In a months-long experiment in a real utility-scale wind farm in India, the predictive model was first validated by testing a wide range of yaw orientation strategies, most of which were intentionally suboptimal. By testing many control strategies, including suboptimal ones, in both the real farm and the model, the researchers could identify the true optimal strategy. Importantly, the model was able to predict the farm power production and the optimal control strategy for most wind conditions tested, giving confidence that the predictions of the model would track the true optimal operational strategy for the farm. This enables the use of the model to design the optimal control strategies for new wind conditions and new wind farms without needing to perform fresh calculations from scratch.

Then, a second months-long experiment at the same farm, which implemented only the optimal control predictions from the model, proved that the algorithm’s real-world effects could match the overall energy improvements seen in simulations. Averaged over the entire test period, the system achieved a 1.2 percent increase in energy output at all wind speeds, and a 3 percent increase at speeds between 6 and 8 meters per second (about 13 to 18 miles per hour).

While the test was run at one wind farm, the researchers say the model and cooperative control strategy can be implemented at any existing or future wind farm. Howland estimates that, translated to the world’s existing fleet of wind turbines, a 1.2 percent overall energy improvement would produce  more than 31 terawatt-hours of additional electricity per year, approximately equivalent to installing an extra 3,600 wind turbines at no cost. This would translate into some $950 million in extra revenue for the wind farm operators per year, he says.

The amount of energy to be gained will vary widely from one wind farm to another, depending on an array of factors including the spacing of the units, the geometry of their arrangement, and the variations in wind patterns at that location over the course of a year. But in all cases, the model developed by this team can provide a clear prediction of exactly what the potential gains are for a given site, Howland says. “The optimal control strategy and the potential gain in energy will be different at every wind farm, which motivated us to develop a predictive wind farm model which can be used widely, for optimization across the wind energy fleet,” he adds.

But the new system can potentially be adopted quickly and easily, he says. “We don’t require any additional hardware installation. We’re really just making a software change, and there’s a significant potential energy increase associated with it.” Even a 1 percent improvement, he points out, means that in a typical wind farm of about 100 units, operators could get the same output with one fewer turbine, thus saving the costs, usually millions of dollars, associated with purchasing, building, and installing that unit.

Further, he notes, by reducing wake losses the algorithm could make it possible to place turbines more closely together within future wind farms, therefore increasing the power density of wind energy, saving on land (or sea) footprints. This power density increase and footprint reduction could help to achieve pressing greenhouse gas emission reduction goals, which call for a substantial expansion of wind energy deployment, both on and offshore.

What’s more, he says, the biggest new area of wind farm development is offshore, and “the impact of wake losses is often much higher in offshore wind farms.” That means the impact of this new approach to controlling those wind farms could be significantly greater.

The Howland Lab and the international team is continuing to refine the models further and working to improve the operational instructions they derive from the model, moving toward autonomous, cooperative control and striving for the greatest possible power output from a given set of conditions, Howland says.

“This paper describes a significant step forward for wind power,” says Charles Meneveau, a professor of mechanical engineering at Johns Hopkins University, who was not involved in this work. “It includes new ideas and methodologies to effectively control wind turbines collectively under the highly variable wind energy resource. It shows that smartly implemented yaw control strategies using state-of-the-art physics-based wake models, supplemented with data-driven approaches, can increase power output in wind farms.” The fact that this was demonstrated in an operating wind farm, he says, “is of particular importance to facilitate subsequent implementation and scale-up of the proposed approach.”

Reprinted with the permission  MIT News http://news.mit.edu/

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Alvopetro Announces Record Funds Flow from Operations for the Second Quarter of 2022 & Q2 Results Webcast

Research, News, and Market Data on Alvopetro Energy

Aug 11, 2022

CALGARY, AB, Aug. 11, 2022 /CNW/ – Alvopetro Energy Ltd. (TSXV: ALV) (OTCQX: ALVOF) announces operating and financial results for the second quarter of 2022 including record funds flow from operations of $12.4 million. We will host a live webcast to discuss Q2 2022 results on Friday August 12, 2022 beginning at 8:00 am Mountain time.

All references herein to $ refer to United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.

Financial and Operating Highlights – Second Quarter of 2022

• Daily sales averaged 2,359 boepd in Q2 2022, consistent with the Q2 2021 average of 2,361 boepd and a 6% reduction from the Q1 2022 average of 2,501 boepd as a result of a planned five-day shut-down of our gas processing facility to complete necessary work in advance of the facility expansion.
• On February 1, 2022, our contracted natural gas price under our long-term gas sales agreement increased 48% to Brazilian real (“BRL”)1.94/m3. With all natural gas sales in Q2 2022 at this higher price and an appreciation of the BRL relative to the USD compared to Q2 2021, our average realized natural gas price increased to $11.90/Mcf compared to the Q2 2021 average price of $6.06/Mcf and the Q1 2022 average price of $10.03/Mcf. Higher commodity prices resulted in a 93% increase in our natural gas, condensate and oil revenue compared to Q2 2021.
• With higher realized sales prices, our operating netback increased to $63.96 per boe in Q2 2022, an improvement of 103% from Q2 2021 and 19% from Q1 2022.
• We generated cash flows from operating activities of $13.0 million ($0.38 per basic share and $0.35 per diluted share) and funds flows from operations of $12.4 million ($0.37 per basic share and $0.34 per diluted share), increases of $7.3 million and $7.0 million, respectively compared to Q2 2021.
• We reported net income of $6.6 million, an increase of $2.8 million compared to Q2 2021.
• Capital expenditures totaled $6.3 million, focused on drilling costs for our 182-C1 and 183-B1 wells, long lead purchases, final costs for our Murucututu field production facility installation on other development costs on our Murucututu project.
• We repaid an additional $2.5 million of our credit facility, bringing the balance outstanding to $2.5 million. As at June 30, 2022, we had a net working capital surplus of $11.6 million, including $13.7 million in cash and cash equivalents. The Company’s working capital net of our credit facility balance improved to $9.1 million, compared to $7.3 million as of March 31, 2022.
• Effective August 1, 2022 our natural gas price has been set at BRL1.94/m3 or $11.28/Mcf (based on our average heat content to date of 107% and the July 31, 2022 BRL/USD foreign exchange rate of 5.19). The adjusted price is based on the ceiling price in the contract, which was adjusted to $10.22/MMBtu effective August 1, 2022. While the ceiling price increased by 6% from the February 1, 2022 ceiling price, due to the appreciation of the BRL relative to the USD in the first half of 2022 compared to the latter half of 2021, the BRL denominated contractual price remained consistent. This price will be effective for all natural gas sales from August 1, 2022 to January 31, 2023.

The following table provides a summary of Alvopetro’s financial and operating results for three and six months ended June 30, 2022 and June 30, 2021. The consolidated financial statements with the Management’s Discussion and Analysis (“MD&A) are available on our website at www.alvopetro.com and will be available on the System for Electronic Document Analysis and Retrieval (SEDAR) website at www.sedar.com.

Second Quarter 2022 Results Webcast

Alvopetro will host a live webcast to discuss Q2 2022 financial results at 8:00 am Mountain time on August 12, 2022. Details for joining the event are as follows:

Date: August 12, 2022Time: 8:00 AM Mountain/10:00 AM Eastern
Link: https://us06web.zoom.us/j/89887067576Dial-in
Numbers: https://us06web.zoom.us/u/kSVhrrkB0Webinar
ID: 898 8706 7576

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.

Corporate Presentation

Alvopetro’s updated corporate presentation is available on our website at: http://www.alvopetro.com/corporate-presentation. 

Social Media

Follow Alvopetro on our social media channels at the following links:

Twitter – https://twitter.com/AlvopetroEnergy Instagram – 
https://www.instagram.com/alvopetro/ LinkedIn – 
https://www.linkedin.com/company/alvopetro-energy-ltd

Alvopetro Energy Ltd.’s vision is to become a
leading independent upstream and midstream operator in Brazil. Our
strategy is to unlock the on-shore natural gas potential in the state of Bahia
in Brazil,
building off the development of our Caburé natural gas field and our strategic
midstream infrastructure.

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.

Non-GAAP and Other Financial Measures

This news release contains references to various non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures as such terms are defined in National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure. Such measures are not recognized measures under GAAP and do not have a standardized meaning prescribed by IFRS and might not be comparable to similar financial measures disclosed by other issuers. While these measures may be common in the oil and gas industry, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. The non-GAAP and other financial measures referred to in this report should not be considered an alternative to, or more meaningful than measures prescribed by IFRS and they are not meant to enhance the Company’s reported financial performance or position. These are complementary measures that are used by management in assessing the Company’s financial performance, efficiency and liquidity and they may be used by investors or other users of this document for the same purpose. Below is a description of the non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures used in this news release. For more information with respect to financial measures which have not been defined by GAAP, including reconciliations to the closest comparable GAAP measure, see the “Non-GAAP
Measures and Other Financial Measures” section of the Company’s MD&A which may be accessed through the SEDAR website at www.sedar.com.

Non-GAAP Financial Measures

Operating netback

Operating netback is calculated as natural gas, oil and condensate revenues less royalties and production expenses. This calculation is provided in the “Operating Netback” section of the Company’s MD&A using our IFRS measures. The Company’s MD&A may be accessed through the SEDAR website at www.sedar.com. Operating netback is a common metric used in the oil and gas industry used to demonstrate profitability from operations.

Non-GAAP Financial Ratios

Operating netback per boe

Operating netback is calculated on a per unit basis, which is per barrel of oil equivalent (“boe”). It is a common non-GAAP measure used in the oil and gas industry and management believes this measurement assists in evaluating the operating performance of the Company. It is a measure of the economic quality of the Company’s producing assets and is useful for evaluating variable costs as it provides a reliable measure regardless of fluctuations in production. Alvopetro calculated operating netback per boe as operating netback divided by total sales volumes (barrels of oil equivalent). This calculation is provided in the “Operating Netback” section of the Company’s MD&A using our IFRS measures. The Company’s MD&A may be accessed through the SEDAR website at www.sedar.com. Operating netback is a common metric used in the oil and gas industry used to demonstrate profitability from operations on a per unit basis (boe).

Operating netback margin

Operating netback margin is calculated as operating netback per boe divided by the realized sales price per boe. Operating netback margin is a measure of the profitability per boe relative to natural gas, oil and condensate sales revenues per boe and is calculated as follows:

Funds Flow from Operations Per Share

Funds flow from operations per share is a non-GAAP ratio that includes all cash generated from operating activities and is calculated before changes in non-cash working capital, divided by the weighted the weighted average shares outstanding for the respective period. For the periods reported in this news release the cash flows from operating activities per share and funds flow from operations per share is as follows:

Capital Management Measures

Funds Flow from Operations 

Funds flow from operations is a non-GAAP capital management measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. The most comparable GAAP measure to funds flow from operations is cash flows from operating activities. Management considers funds flow from operations important as it helps evaluate financial performance and demonstrates the Company’s ability to generate sufficient cash to fund future growth opportunities. Funds flow from operations should not be considered an alternative to, or more meaningful than, cash flows from operating activities however management finds that the impact of working capital items on the cash flows reduces the comparability of the metric from period to period. A reconciliation of funds flow from operations to cash flows from operating activities is as follows:

Net Working Capital

Net working capital is computed as current assets less current liabilities. Net working capital is a measure of liquidity, is used to evaluate financial resources, and is calculated as follows: 

Working Capital Net of Debt (Net Debt)

Working capital net of debt is computed as net working capital surplus decreased by the carrying amount of the Credit Facility. Working capital net of debt is used by management to assess the Company’s overall financial position. As of June 30, 2022, Alvopetro’s net working capital surplus exceeds the balance outstanding on the Credit Facility.

Supplementary Financial Measures

“Average realized natural gas price – $/Mcf” is comprised of natural gas sales as determined in accordance with IFRS, divided by the Company’s natural gas sales volumes.

“Average realized NGL – condensate price – $/bbl” is comprised of condensate sales as determined in accordance with IFRS, divided by the Company’s NGL sales volumes from condensate.

“Average realized oil price – $/bbl” is comprised of oil sales as determined in accordance with IFRS, divided by the Company’s oil sales volumes.

“Average realized price – $/boe” is comprised of natural gas, condensate and oil sales as determined in accordance with IFRS, divided by the Company’s total natural gas, condensate and oil sales volumes (barrels of oil equivalent).

“Royalties per boe” is comprised of royalties, as determined in accordance with IFRS, divided by the total natural gas, condensate and oil sales volumes (barrels of oil equivalent).

“Production expenses per boe” is comprised of production expenses, as determined in accordance with IFRS, divided by the total natural gas, condensate and oil sales volumes (barrels of oil equivalent).

BOE Disclosure

The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6 Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this MD&A are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

Forward-Looking Statements and Cautionary Language

This news release contains forward-looking information within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward?looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning the plans relating to the Company’s operational activities, the expected natural gas price, gas sales and gas deliveries under Alvopetro’s long-term gas sales agreement, exploration and development prospects of Alvopetro, the expected timing of certain of Alvopetro’s testing and operational activities, future results from operations, and the Company’s plans for dividends in the future. The forward?looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to equipment availability, the timing of testing of the 182-C1 and the 183-B1 wells and the results from such testing, the timing of regulatory licenses and approvals, the success of future drilling, completion, testing, recompletion and development activities, the outlook for commodity markets and ability to access capital markets, the impact of the COVID-19 pandemic 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. In addition, the declaration, timing, amount and payment of future dividends remain at the discretion of the Board of Directors. Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our restated annual information form which may be accessed on Alvopetro’s SEDAR profile at www.sedar.com. The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

SOURCE Alvopetro Energy Ltd.

Friday, August 12, 2022

InPlay Oil (IPOOF)
Another solid quarter with results generally in line with expectations

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, CFA, Senior Research Analyst, Noble Capital Markets, Inc.

Refer to the full report for the price target, fundamental analysis, and rating.

InPlay reported sold 2022-2Q results. Production (9,063 boe/d) was a bit below our expectations due to difficulties trucking out oil due to wet weather (55 boe/d reduction). On the other hand, oil and natural gas pricing was above expectations at C$116.74 (versus our C$105 estimate) and C$7.61 per mcf. (versus our C$6.90 per mcf. estimate). Notably, lifting and operating costs were a modest $12.28/boe down from first quarter LOE of $12.96. The net effect was adjusted fund flow (C$40.9m vs. C$38.7m) and net income (C$29.0m/$0.32 vs. C$27.8m/$0.32) in line with expectations.

Accelerated drilling program is showing signs of success. InPlay drilled five wells during the quarter. Drill time has been reduced to 10-11 days. InPlay did not indicate the cost to drill the wells, but we assume original drilling cost of C$2.5 million may be coming down. The company anticipates drilling three wells in the third quarter despite delays due to wet weather. …

This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).

*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision. 

Image Credit: Kishjar (Flickr)

OPEC Sees a Better Balance of Supply and Demand in New Forecast

The Organization of Petroleum Exporting Nations (OPEC) released a 92-page report dated August 11, 2022, on the state of the global oil market. The topics include expected supply and demand balance shifts, global demand expectations, world economy expectations, and physical versus futures prices. The OPEC Monthly Oil Market Report suggests the cartel is not expecting to increase output.

Supply

The global oil supply has risen steadily over the past several months. This includes OPEC coordination with countries participating in the Declaration of Cooperation (DoC). However, ongoing low overall investment is limiting non-OPEC oil supply growth. Signs of slowing growth in the world economy and oil demand have been causing a better balance of output and consumption.

The oil market since the beginning of 2022 has been riddled with price volatility, this became much more pronounced after February 2022. The late winter imbalances were triggered by concerns in Eastern Europe. Sanctions on Russian oil by some major oil importing nations served to increase the premium that was built into crude prices. The sanctions led to significant changes to inter-regional trade flows. This raised supply concerns heading into the summer travel season.

The early summer was characterized by increased pressure on prices in most regions and soaring prices. This created a situation that resulted in crude differentials rising to record-high levels in 2Q22, along with steepening backwardation, a situation where physical oil is priced higher than futures contracts.

Demand

The OPEC report shows fundamentals in the physical oil market remain heightened, and volatility in the futures markets is reacting to expectations of lower GDP growth. Lower growth expectations are fed by rising worldwide inflation and the central banks’ reaction to slow economies.

Another factor impacting world demand is the US dollar’s value which strengthened further against major currencies. Oil is priced in US Dollars. Moreover, market price volatility contributed to reduced market liquidity, as seen in declining futures and options open interest in ICE Brent and NYMEX WTI dropped in July 2022 to the lowest since June 2015.

Source: OPEC Monthly Oil Market Report (August 2022)

Prices

Fuel prices surged in the first half of the year due to lower supplies amid refinery closures and a busy refinery turnaround season. The summer also ushered in stronger fuel consumption as pandemic-related travel restrictions were lifted in most regions. Adjustments to flow tied to the war in Eastern Europe further produced tightness. Combined, this all worked to push oil prices to record highs in June.

Jet fuel became the second strongest performer in the US product market. The product saw its price benefit from growing international air travel.

Prices peaked in June, with US gasoline reaching $193.06/b, up by $97.79/b, or 103%, y-o-y.

In July, rising refinery run rates reduced some of the tightness, mostly in US Gulf Coast (USGC), where product prices declined by $26.83/b, on average. In Europe, average prices declined the least,  $20.24/b, m-o-m.

Looking Ahead

Refined product markets in the coming months are expected to experience seasonal support from transport fuels, while fuel sales could increase from the trend of moderating product prices.

Available refinery capacity will be helped by the operational ramp-up of at least two large capacity additions last year. These include the Middle East. The countries participating in the DoC will continue to monitor market developments and seek investment to help ensure adequate levels of capacity and bolster their efforts to maintain a stable oil market balance which is perceived to be in the interest of producers and consumers alike.

Paul Hoffman

Managing Editor, Channelchek

Suggested Content

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Why Natural Gas Opportunities Should Not Always be Lumped in With the Oil Sector

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Energy Industry Report – The Outlook for Energy Stocks Remains Favorable

Sources

https://momr.opec.org/pdf-download/

https://www.bloomberg.com/news/articles/2022-08-11/opec-sees-global-oil-market-tipping-into-surplus-this-quarter

https://www.investopedia.com/terms/b/backwardation.asp#:~:text=Key%20Takeaways,months%20through%20the%20futures%20market.

https://www.wsj.com/articles/opec-cuts-oil-demand-forecasts-as-economic-growth-slows-11660220861?mod=hp_lead_pos2

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InPlay Oil Corp. Announces Second Quarter 2022 Financial and Operating Results Highlighted by Record Quarterly Production and Financial Results, and a Fully Conforming and Increased Credit Facility

News and Market Data on InPlay Oil Corp

August 11, 2022 08:00 ET | Source: InPlay Oil Corp.

CALGARY, Alberta, Aug. 11, 2022 (GLOBE NEWSWIRE) — InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) announces its record setting financial and operating results for the three and six months ended June 30, 2022. InPlay’s condensed unaudited interim financial statements and notes, as well as Management’s Discussion and Analysis (“MD&A”) for the three and six months ended June 30, 2022 will be available at “www.sedar.com” and our website at “www.inplayoil.com”. Our updated corporate presentation will also soon be available on our website.

Second Quarter 2022 Financial & Operating Highlights

• Achieved record average quarterly production of 9,063 boe/d⁽¹⁾ (57% light crude oil and NGLs), an increase of 68% from second quarter production in 2021 of 5,386 boe/d⁽¹⁾ (68% light crude oil and NGLs) and an increase of 10% compared to our previous record of 8,221 boe/d
  ⁽¹⁾ (59% light crude oil and NGLs) in the first quarter of 2022. Average production per weighted average basic share increased 32% compared to the second quarter of 2021 (43% on a debt adjusted⁽⁴⁾ basis) and 10% compared to the first quarter of 2022 (17% on a debt adjusted basis).
• Generated record quarterly adjusted funds flow (“AFF”)⁽²⁾ of $40.9 million ($0.47 per weighted average basic share⁽³⁾), an increase of 398% compared to $8.2 million ($0.12 per weighted average basic share) in the second quarter of 2021 and an increase of 39% compared to $29.4 million ($0.34 per weighted average basic share) in the first quarter of 2022, our prior record quarter.
• Increased operating netbacks⁽⁴⁾ by 84% to $61.02/boe from $33.09/boe in the second quarter of 2021 and by 32% compared to $46.06/boe in the first quarter of 2022, our prior record quarter.
• Realized quarterly record operating income⁽⁴⁾ and operating income profit margin⁽⁴⁾ of $50.3 million and 71% respectively compared to $16.2 million and 64% in the second quarter of 2021; $34.1 million and 65% in the first quarter of 2022, our prior record quarter.
• Reduced operating expenses to $12.28/boe compared to $12.51/boe in the second quarter of 2021 and $12.96/boe in the first quarter of 2022, despite rising costs of services in the industry.
• Generated free adjusted funds flow (“FAFF”)
  ⁽⁴⁾ of $23.1 million, a quarterly record for the Company, resulting in a 31% reduction to net debt from March 31, 2022.
• Achieved a quarterly annualized net debt⁽²⁾ to earnings before interest, taxes and depletion (“EBITDA”)⁽⁴⁾ ratio of 0.3x, compared to 1.9x in the second quarter of 2021 and 0.6x in first quarter of 2022 and a trailing twelve month net debt to EBITDA ratio of 0.5x to June 30, 2022.
• Realized net income of $29.0 million ($0.33 per basic share; $0.32 per diluted share).

Financial and Operating Results:

Second Quarter 2022 Financial & Operations Overview:

Production averaged 9,063 boe/d⁽¹⁾ (57% light crude oil & NGLs) of sales in the second quarter of 2022, not including over 5,000 bbls of light crude oil inventory build (equal to over 55 bbls/d during the quarter) that was not sold due to difficulty trucking oil as a result of wet weather at the end of June. NGL’s were slightly lower than expected in the quarter due to certain third party facilities having leaner liquids cuts in the quarter. Production increased by 68% compared to 5,386 boe/d⁽¹⁾ (68% light crude oil & NGLs) in the second quarter of 2021 and 10% compared to 8,221 boe/d⁽¹⁾ (59% light crude oil & NGLs) in the first quarter of 2022. This resulted in a quarterly record $40.9 million of AFF generated during the second quarter of 2022 and $23.1 million in FAFF which reduced net debt levels by 31% from March 31, 2022 to $50.5 million at June 30, 2022. Liquidity ratios to the end of the quarter improved significantly resulting in a quarterly annualized net debt to EBITDA ratio of 0.3x and a trailing twelve month net debt to EBITDA ratio of 0.5x to June 30, 2022.

InPlay’s capital program for the second quarter of 2022 consisted of $17.8 million of capital expenditures. During the quarter, InPlay drilled three (3.0 net) 1.5 mile Extended Reach Horizontal (“ERH”) wells in Pembina which were completed and tied in and came on production at the end of May. The Company also finished the drilling operations of an additional two (1.9 net) 2 mile ERH wells in Willesden Green. Completions of these wells was delayed due to the wet weather in June but have now been completed and are in the early cleanup phase. Construction of a modular multi-well facility in Willesden Green began during the quarter to accommodate current and future drilling in the area.

As a result of using a consistent drill crew since the beginning of the year and exceptional project execution, the two 2 mile ERH wells in Willesden Green were drilled in 10.3 and 10.7 days respectively, which were among the fastest drilling operations for 2 mile wells in the area. In comparison to the last 2 mile wells drilled by the Company in Willesden Green in 2018, drilling times improved by approximately 20% which is a positive result for the Company and is an example of InPlay’s continuous drive to achieve operational efficiencies.

Efficient field operations and increased production levels resulted in the Company achieving lower operating expenses of $12.28/boe compared to $12.51/boe in the second quarter of 2021 and $12.96/boe in the first quarter of 2022. This is a significant achievement given the inflationary pressures and supply chain disruptions facing our industry. The resulting operating income and operating income profit margin for the second quarter of 2022 were quarterly records for the Company at $50.3 million and 71% respectively.

Credit Facilities

InPlay is pleased to announce that it has entered into an amended credit facility with its first-lien and second-lien lenders resulting in a fully conforming revolving credit facility with an increased total lending capacity and borrowing base of $110 million. InPlay’s credit facility is now comprised of a $100 million revolving credit facility and a $10 million operating line of credit (together, the “Credit Facility”). The term out date of the Credit Facility has been extended to May 30, 2023 with a maturity date of May 30, 2024. As part of the renegotiated Credit Facility, the Company’s previously outstanding $25 million term facility with the Business Development Bank of Canada (“BDC”) and the remaining $14 million of its senior term facility have been repaid.

InPlay is also pleased to announce that Canadian Western Bank (“CWB”) and BDC have joined ATB Financial as members of the amended Credit Facility syndicate.

The outcome of the Credit Facility redetermination is an extremely positive result for the Company and is anticipated to reduce overall interest costs and provide InPlay with a stable liquidity position.

Outlook

The Company’s strategy has been focused on delivering measured but top-tier production growth amongst our light oil peers while seeking to maximize FAFF which has been used to reduce debt and leverage ratios. Results from our high quality asset base has allowed us to exceed our expectations with production growth per share of 32% (43% on a debt adjusted per share basis) in the past year. Strong and record setting operational and financial performance combined with continued commodity price strength has placed InPlay well ahead of schedule in the reduction of debt levels. The Company has achieved a 0.5x trailing twelve months net debt to EBITDA ratio in the second quarter of 2022 with expectations of leverage ratios continuing to drop throughout the balance of the year based on current commodity prices.

Although the world economic picture and energy prices remain volatile, the Company finds itself in the best operational and financial position in our history. We believe that a target of approximately 0.5x trailing twelve months net debt to EBITDA is a prudent leverage ratio in a higher commodity price environment and will provide the Company significant financial flexibility in a volatile pricing environment. Having achieved this target and with leverage continuing to drop, the Company is now evaluating a potential return of capital to shareholders, while continuing to pursue other accretive acquisition opportunities, with the ultimate goal of strong overall returns to shareholders.

Wet weather in late June delayed the start of our third quarter capital program. The program is now well underway with drilling operations ongoing on the third well of a three (2.9 net) ERH well pad in Willesden Green which is expected to be on production in late August. The drilling operations of an additional two (1.9 net) ERH wells in Willesden Green are planned for the third quarter which are expected to be on production late in September. The Company’s third quarter drilling program is in an area with anticipated higher oil weightings which is expected to result in increased liquids percentages into the second half of the year.

As a result of the strong operational results to date, the Company’s previously released 2022 guidance⁽⁵⁾ is reiterated with annual average production anticipated to be 8,900 to 9,400 boe/d⁽¹⁾.

InPlay plans on releasing our inaugural sustainability report in September. In addition, an operational update, a long range forecast, and an update on the evaluation of a potential return to shareholders is expected to be released in September.

Management would like to thank our employees, board members, lenders and shareholders for their support and we look forward to continuing our journey of deleveraging and delivering strong returns to shareholders in a sustainable, prudent and responsible manner.

For further information please contact:

Notes:

1. See “Production Breakdown by
   Product Type” at the end of this press release.
2. Capital management measure. See
   “Non-GAAP and Other Financial Measures” contained within this press
   release.
3. Supplementary financial measure.
   See “Non-GAAP and Other Financial Measures” contained within this press
   release.
4. 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.
5. See “Reader Advisories – Forward
   Looking Information and Statements” and InPlay’s press release dated May
   11, 2022 for full details and key budget and underlying assumptions
   related to our 2022 capital program and associated guidance.

Reader Advisories

Non-GAAP and Other Financial Measures

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 (“FAFF”)”, “operating income”, “operating netback per boe”, “operating income profit margin”, “Net Debt to EBITDA” and “Debt adjusted production per share”. 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

Management considers free adjusted funds flow (“FAFF”) and FAFF per share important measures to identify the Company’s ability to improve its financial condition through debt repayment, which has become more important recently with the introduction of second lien lenders, on an absolute and weighted average per share basis. 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. FAFF per share is calculated by the Company as FAFF divided by weighted average outstanding shares. Refer below for a calculation of historical FAFF and 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.

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.

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 is 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 is a key performance indicator as it adjusts for the effects of changes in annual production in relation to the Company’s capital structure. Refer below for a calculation of Production per debt adjusted share.

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 (“AFF”) is a GAAP measure and is disclosed in the notes to the Company’s consolidated financial statements for the year ending December 31, 2021 and the most recently filed quarterly financial statements. All references to AFF throughout this document are calculated as funds flow adjusting for decommissioning expenditures and transaction and integration costs. This item is adjusted from funds flow as decommissioning expenditures are incurred on a discretionary and irregular basis and are primarily incurred on previous operating assets and 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 AFF per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of profit (loss) per common share.

Net Debt

Net debt is a GAAP measure and is disclosed in the notes to the Company’s consolidated financial statements for the year ending December 31, 2021 and the most recently filed quarterly financial statements. The Company closely monitors its capital structure with a 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 production. 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 production. 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 production. 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 production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

“AFF per weighted average basic share” is comprised of AFF divided by the basic weighted average common shares.

“AFF per weighted average diluted share” is comprised of AFF divided by the diluted weighted average common shares.

“AFF per boe” is comprised of AFF 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”, “targets”, “framework” 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 including, without limitation, the anticipated continuation of debt reduction the anticipated impact of the redetermined Credit Facility; improved leverage ratios and generation of FAFF; the Company’s targeted net debt to EBITDA ratio of 0.5 times; future intentions regarding the implementation of a return of capital program and the timing thereof; statements regarding the Company’s plans or expectations for the initiation of a potential dividend, the reaching of targets and satisfaction of conditions thereto and the amount and timing thereof; expectations regarding future commodity prices; future oil and natural gas prices; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; 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 2022 capital program and associated guidance.

Without limitation of the foregoing, readers are cautioned that the Company’s return to shareholders framework including future dividend payments to shareholders of the Company, if any, and the level thereof remains uncertain and accordingly management’s expectations related thereto should not be unduly relied upon. 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 implement a return to shareholder program will be subject to applicable laws, including satisfaction of solvency tests under the ABCA, and satisfaction of certain applicable contractual restrictions contained in the agreements governing the Company’s outstanding indebtedness.

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 and the anticipated lifting of certain restrictions on the payment of distributions to shareholders which currently exist thereunder; 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; expectations regarding the potential impact of COVID-19 and the Russia/Ukraine conflict; 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. 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 COVID-19 pandemic and the Russia/Ukraine conflict; changes in our planned 2022 capital program; changes in commodity prices and other assumptions outlined herein; the risk that the Company is unable to implement a return to shareholder strategy or, if implemented, the risk that dividend payments thereunder 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, and potential dividends and share buybacks, 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 best 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.

The key budget and underlying material assumptions used by the Company in the development of its 2022 guidance including forecasted production, operating income, capital expenditures, AFF, FAFF, FAFF yield, Net Debt, Net Debt/EBITDA, EV/DAAFF, production per debt adjusted share growth are as follows:

• 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 Dec 31, 2021 and Dec 31, 2022.

Test Results and Initial Production (“IP”) Rates
Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long term performance or of ultimate recovery. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed.

Production Breakdown by Product Type
Disclosure of production on a per boe basis in this press release consists of the constituent product types as defined in NI 51-101 and their respective quantities disclosed in the table below:

Notes:

1. This reflects the mid-point of the
   Company’s 2022 production guidance range of 8,900 to 9,400 boe/d.
2. With respect to forward-looking
   production guidance, product type breakdown is based upon management’s
   expectations based on reasonable assumptions but are subject to
   variability based on actual well results.

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.

Tuesday, August 09, 2022

Gevo (GEVO)
Management makes case that market is bigger than expected

Gevo’s mission is to transform renewable energy and carbon into energy-dense liquid hydrocarbons. These liquid hydrocarbons can be used for drop-in transportation fuels such as gasoline, jet fuel, and diesel fuel, that when burned have potential to yield net-zero greenhouse gas emissions when measured across the full lifecycle of the products. Gevo uses low-carbon renewable resource-based carbohydrates as raw materials, and is in an advanced state of developing renewable electricity and renewable natural gas for use in production processes, resulting in low-carbon fuels with substantially reduced carbon intensity (the level of greenhouse gas emissions compared to standard petroleum fossil-based fuels across their lifecycle). Gevo’s products perform as well or better than traditional fossil-based fuels in infrastructure and engines, but with substantially reduced greenhouse gas emissions. In addition to addressing the problems of fuels, Gevo’s technology also enables certain plastics, such as polyester, to be made with more sustainable ingredients. Gevo’s ability to penetrate the growing low-carbon fuels market depends on the price of oil and the value of abating carbon emissions that would otherwise increase greenhouse gas emissions. Gevo believes that its proven, patented, technology enabling the use of a variety of low-carbon sustainable feedstocks to produce price-competitive low carbon products such as gasoline components, jet fuel, and diesel fuel yields the potential to generate project and corporate returns that justify the build-out of a multi-billion-dollar business.

Michael Heim, CFA, Senior Research Analyst, Noble Capital Markets, Inc.

Refer to the full report for the price target, fundamental analysis, and rating.

Gevo reported 2022-2Q results generally in line with expectations. Revenues are modest ($0.1m vs. $0.3m and our $1.0m est.). Operating costs have become more stable and predictable leading to steady EBITDA losses ($11.0m vs. $17.2m and our $11.4m est.). Net losses met expectations ($16.1m or $0.06 p/s vs. $19.1m or $0.09 p/s and our $14.0m or $0.06 p/s). The real story, however, is not near-term results but plant developments, financing, and contract signings.

Gevo was active in all aspects of the business. The company signed five new take-or-pay jet fuel contracts and now totals 350m gal./year or $2.2 billion. This is more contracted outtake than the projected NZ1 plant production. Management’s vision is to use NZ1 to demonstrate economics but has a clear eye on replicating the project. In fact, it plans to continue to sign contracts for production beyond 2027. Speaking of NZ1, Gevo has recently purchased land for the plant and says it is on schedule for a 2025 start-up….

This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).

*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision. 

Gevo Reports Second Quarter 2022 Financial Results

Research, News, and Market Data on Gevo

GEVO
TO HOST CONFERENCE CALL TODAY AT 4:30 P.M. EDT/2:30 P.M. MDT

ENGLEWOOD, Colo., Aug. 08, 2022 (GLOBE NEWSWIRE) — Gevo, Inc. (NASDAQ: GEVO) (“Gevo”, the “Company”, “we”, “us” or “our”) today announced financial results for the second quarter of 2022 and recent corporate highlights.

Recent Corporate Highlights

• On July 18, 2022, Gevo signed a financeable fuel sales agreement with American Airlines, Inc. to supply 100 million gallons per year of SAF for five years from Gevo’s future commercial operations. The table below summarizes the supply agreements executed since April 1, 2022:

• Gevo now has more than 350 million gallons per year (“MGPY”) of financeable SAF and hydrocarbon fuel supply agreements, which based on current market projections and operating assumptions, represent approximately $2.1 billion in expected revenue per year, inclusive of the value of environmental benefits. These types of contracts are expected to assist Gevo in obtaining project debt financing.
• On June 5th, 2022, Gevo executed a registered direct offering of 33.3 million shares to certain institutional investors. That offering closed on June 8th, 2022, providing net proceeds of $139.0 million. As part of the offering, Gevo issued 33.3 million Series 2022-A Warrants with an exercise price of $4.37 per share.
• The Company’s Net-Zero 1 project is on schedule and the Company continues to work towards completion of the various milestones for 2022, including, among others, executing certain commercial development, build, own and operate agreements, and selecting an EPC contractor for the project.
• On July 25, 2022, the Company completed the purchase of approximately 245 acres near Lake Preston, South Dakota for its Net-Zero 1 production facility.
• Gevo’s renewable natural gas (“RNG”) project in Northwest Iowa is now generating biogas from all three dairies and the RNG produced is expected to ramp toward nameplate capacity of 355,000 MMBtu throughout the second half of 2022.

2022 Second Quarter Financial
Highlights

• Ended the quarter with cash, cash equivalents, restricted cash and marketable securities of $546.8 million compared to $475.8 million as of the end of Q4 2021
• Revenue of $0.1 million for the quarter compared to $0.3 million in Q2 2021
• Loss from operations of $(16.1) million for the quarter compared to $(19.1) million in Q2 2021
• Non-GAAP cash EBITDA loss¹ of $(11.0) million for the quarter compared to $(17.2) million in Q2 2021
• GAAP net loss per share and non-GAAP adjusted net loss per share² of $(0.06) for the quarter compared to $(0.09) in Q2 2021

Management Comment

Commenting on the second quarter of 2022 and recent corporate events, Dr. Patrick R. Gruber, Gevo’s Chief Executive Officer, said, “Given our continued success in securing SAF supply agreements as well as the additional interest that we are witnessing in the marketplace, there should not be any question about the potential size of the market for renewable fuels. The opportunities in front of us over the next decade and beyond are large and rapidly growing. Our goal is to build SAF production capacity at a rate that will establish Gevo and its partners as a market leader and powerhouse in the renewable fuels sector. It all starts with NZ1, the engineering and design is going well. Based on what we see today we expect to stay on schedule for the 2025 start-up.” Dr. Gruber also remarked that, “Gevo’s RNG project continues to ramp to nameplate capacity of 355,000 MMBtu. All three dairies are now producing biogas which is then upgraded and injected into the sales pipeline. That RNG is sold into the California market by our marketing partner, BP. We continue to collect the performance data for our application to the California Air Resource Board to receive LCFS credits and the Renewable Fuel Standard Program for RINs.”

Second Quarter 2022 Financial
Results

During the three months ended June 30, 2022, we sold 9 thousand gallons of SAF, isooctane, and isooctene from our Luverne Facility. Revenue decreased $0.3 million during the three months ended June 30, 2022, compared to the three months ended June 30, 2021, due to the Luverne Facility being operated for the Company’s development projects on a as needed basis.

Cost of goods increased $1.0 million during the three months ended June 30, 2022, compared to the three months ended June 30, 2021, primarily due to an increase in direct labor and utility expenses as the Luverne Facility was not fully staffed during the second quarter of 2021 due to the COVID-19 pandemic. The majority of our costs are related to the production of SAF, isooctane, and isooctene as we continue to develop and tailor our Luverne Facility demonstration operations to support our focus on advancing technology, testing and optimizing alternative feedstocks, yeast strains, and unit operations as well as partnership development for integrated GHG reductions. Cost of goods sold also includes a $2.1 million net realizable gain adjustment made to our finished goods and work in process inventory. There were no inventory net realizable value adjustments recorded during the three months ended June 30, 2021, as the Luverne Facility was temporarily shut down due to the COVID-19 pandemic.

Research and development expense increased $0.6 million during the three months ended June 30, 2022, compared to the three months ended June 30, 2021, primarily due to an increase of laboratory expenses and additional stock-based compensation expense.

Selling, general and administrative expense increased $4.4 million during the three months ended June 30, 2022, compared to the three months ended June 30, 2021, primarily due to increases in personnel costs related to strategic new hiring, stock-based compensation, and professional fees.

Preliminary stage project costs are related to our Verity and future Net-Zero Projects and consist primarily of employee expenses and consulting costs. Preliminary stage project costs decreased $5.2 million during the three months ended June 30, 2022, compared to the three months ended June 30, 2021, primarily because we began capitalizing our RNG and NZ1 project costs in 2021.

Other operations expense increased $0.6 million during the three months ended June 30, 2022, compared to the three months ended June 30, 2021, primarily related to unallocated engineering and consulting services.

Depreciation and amortization expense increased $0.3 million during the three months ended June 30, 2022, compared to the three months ended June 30, 2021, primarily due to the amortization of our patents.

We incurred no gain (loss) from the change in the fair value of the derivative warrant liability in the three months ended June 30, 2022. The last of the liability warrants expired in February 2022.

There were no significant changes in interest expense during the three months ended June 30, 2022, compared to the three months ended June 30, 2021.

Interest and dividend income increased $0.1 million during the three months ended June 30, 2022, compared to the three months ended June 30, 2021, primarily due to the interest earned on our investments partially offset by the amortization of the bond premiums.

Other income (expense) increased $2.7 million during the three months ended June 30, 2022, compared to the three months ended June 30, 2021, primarily due to our receipt of $2.9 million from the US Department of Agriculture’s Biofuel Producer Program to support biofuel producers who faced unexpected losses due to the COVID-19 pandemic. The Biofuel Producer Program grants are not tax-exempt.

Non-GAAP cash EBITDA loss³ in the three months ended June 30, 2022, was $(11.0) million, compared with a $(17.2) million non-GAAP cash EBITDA loss in the same period in 2021.

During the six months ended June 30, 2022, net cash used for operating activities was $17.1 million compared to $19.5 million for the six months ended June 30, 2021. The $2.4 million decrease was primarily due to increased costs associated with our production of isobutanol and hydrocarbon products for market development, process technology and related process engineering work. In addition, we had increases in personnel expenses to support the growth in business activity, partnership development and Verity development expenses.

Webcast and Conference Call
Information

Hosting today’s conference call at 4:30 p.m. EDT (2:30 p.m. MDT) will be Dr. Patrick R. Gruber, Chief Executive Officer, L. Lynn Smull, Chief Financial Officer, Tim Cesarek, Chief Commercial Officer, and John Richardson, Director of Investor Relations. They will review Gevo’s financial results and provide an update on recent corporate highlights.

To participate in the live call, please register through the following event weblink: https://register.vevent.com/register/BI82c9f363e71c46baa4a8d5e9764fcdbd. After registering, participants will be provided with a dial-in number and pin.

To listen to the conference call (audio only), please register through the following event weblink: https://edge.media-server.com/mmc/p/65vvqgmx.

A webcast replay will be available two hours after the conference call ends on August 8, 2022. The archived webcast will be available in the Investor Relations section of Gevo’s website at www.gevo.com.

About Gevo

Gevo’s mission is to transform renewable energy and carbon into energy-dense liquid hydrocarbons. These liquid hydrocarbons can be used for drop-in transportation fuels such as gasoline, jet fuel, and diesel fuel, that when burned have potential to yield net-zero greenhouse gas emissions when measured across the full lifecycle of the products. Gevo uses low-carbon renewable resource-based carbohydrates as raw materials, and is in an advanced state of developing renewable electricity and renewable natural gas for use in production processes, resulting in low-carbon fuels with substantially reduced carbon intensity (the level of greenhouse gas emissions compared to standard petroleum fossil-based fuels across their lifecycle). Gevo’s products perform as well or better than traditional fossil-based fuels in infrastructure and engines, but with substantially reduced greenhouse gas emissions. In addition to addressing the problems of fuels, Gevo’s technology also enables certain plastics, such as polyester, to be made with more sustainable ingredients. Gevo’s ability to penetrate the growing low-carbon fuels market depends on the price of oil and the value of abating carbon emissions that would otherwise increase greenhouse gas emissions. Gevo believes that it possesses the technology and know-how to convert various carbohydrate feedstocks through a fermentation process into alcohols and then transform the alcohols into renewable fuels and materials, through a combination of its own technology, know-how, engineering, and licensing of technology and engineering from Axens North America, Inc., which yields the potential to generate project and corporate returns that justify the build-out of a multi-billion-dollar business.

Gevo believes that Argonne National Laboratory GREET model is the best available standard of scientific based measurement for life cycle inventory or LCI.

Learn more at Gevo’s website: www.gevo.com

Forward-Looking Statements

Certain statements in this press release may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to a variety of matters, including, without limitation, whether our fuel sales agreements are financeable, the timing of our Net-Zero 1 project, our financial condition, our results of operation and liquidity, our business development activities, our Net-Zero Projects, our RNG Project, our fuel sales agreements, our plans to develop our business, our ability to successfully develop, construct and finance our operations and growth projects, our ability to achieve cash flow from our planned projects, the ability of our products to contribute to lower greenhouse gas emissions, particulate and sulfur pollution, and other statements that are not purely statements of historical fact These forward-looking statements are made based on the current beliefs, expectations and assumptions of the management of Gevo and are subject to significant risks and uncertainty. Investors are cautioned not to place undue reliance on any such forward-looking statements. All such forward-looking statements speak only as of the date they are made, and Gevo undertakes no obligation to update or revise these statements, whether as a result of new information, future events or otherwise. Although Gevo believes that the expectations reflected in these forward-looking statements are reasonable, these statements involve many risks and uncertainties that may cause actual results to differ materially from what may be expressed or implied in these forward-looking statements. For a further discussion of risks and uncertainties that could cause actual results to differ from those expressed in these forward-looking statements, as well as risks relating to the business of Gevo in general, see the risk disclosures in the Annual Report on Form 10-K of Gevo for the year ended December 31, 2021 and in subsequent reports on Forms 10-Q and 8-K and other filings made with the U.S. Securities and Exchange Commission by Gevo.

Non-GAAP Financial Information

This press release contains financial measures that do not comply with U.S. generally accepted accounting principles (GAAP), including non-GAAP cash EBITDA loss, non-GAAP adjusted net loss and non-GAAP adjusted net loss per share. Non-GAAP cash EBITDA loss excludes depreciation and amortization and non-cash stock-based compensation from GAAP loss from operations. Non-GAAP adjusted net loss and adjusted net loss per share exclude non-cash gains and/or losses recognized in the quarter due to the changes in the fair value of certain of Gevo’s financial instruments, such as warrants, convertible debt and embedded derivatives, from GAAP net loss. Management believes these measures are useful to supplement its GAAP financial statements with this non-GAAP information because management uses such information internally for its operating, budgeting and financial planning purposes. These non-GAAP financial measures also facilitate management’s internal comparisons to Gevo’s historical performance as well as comparisons to the operating results of other companies. In addition, Gevo believes these non-GAAP financial measures are useful to investors because they allow for greater transparency into the indicators used by management as a basis for its financial and operational decision making. Non-GAAP information is not prepared under a comprehensive set of accounting rules and therefore, should only be read in conjunction with financial information reported under U.S. GAAP when understanding Gevo’s operating performance. A reconciliation between GAAP and non-GAAP financial information is provided in the financial statement tables below.

¹Cash EBITDA
loss is a non-GAAP measure calculated by adding back depreciation and
amortization and non-cash stock-based compensation to GAAP loss from
operations. A reconciliation of cash EBITDA loss to GAAP loss from operations
is provided in the financial statement tables following this release.
²Adjusted net loss per share is a non-GAAP measure calculated by
adding back non-cash gains and/or losses recognized in the quarter due to the
changes in the fair value of certain of our financial instruments, such as warrants,
convertible debt and embedded derivatives, to GAAP net loss per share. A
reconciliation of adjusted net loss per share to GAAP net loss per share is
provided in the financial statement tables following this release.
³ Cash EBITDA loss is a non-GAAP measure calculated by adding
back depreciation and amortization and non-cash stock compensation to GAAP loss
from operations. A reconciliation of cash EBITDA loss to GAAP loss from
operations is provided in the financial statement tables following this release.

Gevo, Inc.
Condensed Consolidated Balance Sheets Information
(Unaudited, in thousands, except share and per share
amounts)

Gevo, Inc.
Condensed Consolidated Statements of Operations Information
(Unaudited, in thousands, except share and per share
amounts)

Gevo, Inc.
Condensed Consolidated Statements of Comprehensive Income
(Unaudited, in thousands, except share and per share
amounts)

Gevo, Inc.
Condensed Consolidated Statements of Stockholders’ Equity
Information
(Unaudited, in thousands, except share amounts)