CHOA LEADS: February 2023 CHOA Journal

CHOA

JOURNAL FEBRUARY 2023

CHOA LEADS

Interview with Harbir Chhina CHOA Volunteer Profile CHOA Member Corner GEOTHERMAL ENERGY SERIES Part 3 Conventional Geothermal Part 4 Enhanced Geothermal Part 5 Servicing Geothermal

Table of Contents Page 5 Interview with Harbir Chhina Page 15 CHOA Volunteer Profile GEOTHERMAL ENERGY SERIES Page 17 Part 3 Conventional Geothermal Page 47 Part 4 Enhanced Geothermal Page 69 Part 5 Servicing Geothermal CHOA MEMBER CORNER Page 43 Congratulations John Hirschmiller Page 45 Congratulations Paul Paynter Publisher: Owen Henshaw Editor: Andreea Munteanu Assistant Editor: Gordon D Holden Editorial Committee: Bruce Carey, Adrian Dodds, Owen Henshaw, Gordon D Holden, Subodh Gupta, Catherine Laureshen, KC Yeung Layout: Connor McGoran, Seema Patel, Javier Sanmiguel

CHOA.AB.CA /CANADIAN-HEAVY-OILASSOCIATION

@CDN_CHOA

INTERACTIVE CORNER

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HAIKU, FOR YOU

GH

AM

write a haiku about oil SAGD

Steam rises up Black gold shines in the light, A blessing from the earth.

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write a haiku that is subtly about the benefits of the heavy oil industry with evocative language

Vast rivers of wealth, Fueling progress and dreams, Heavy oil flows on.

CHOA JOURNAL - FEBRUARY 2023 I 4

Interview with Harbir Chhina, Cenovus CTO CENOVUS' CHIEF TECHNOLOGY OFFICER SPEARHEADED TECHNOLOGICAL ADVANCEMENTS IN THE HEAVY OIL INDUSTRY, INCLUDING THE FIRST COMMERCIAL STEAMASSISTED GRAVITY DRAINAGE OPERATION AT FOSTER CREEK

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Harbir Chhina, Cenovus' Chief Technology Officer, spearheaded key technological advancements in our oil sands industry, including the first commercial steam-assisted gravity drainage (SAGD) operation at Foster Creek. In this interview read: • How Harbir describes his 40+ years of technology development in oil sands • What’s next, technologically and commercially • What’s in store for the people who will power the future oil sands industry Interviewed in November 2022 by Owen Henshaw, Innovation Engineer at Cenovus and Board member of the Canadian Heavy Oil Association.

You have previously remarked that you worked on 25 unsuccessful pilots before the big success with SAGD at Foster Creek. What made you continue on, pilot after pilot, until you made it work?

The first thing I did this morning when I came to work was list all of the pilots I worked on in the oil sands, and it was actually more than 26.

So, we worked on many pilots in the Athabasca, Peace River, Lloydminster, and Cold Lake areas before Foster Creek. In the beginning, we were all trying to duplicate Imperial, who set the gold standard for thermal recovery by using Cyclic Steam Stimulation, or CSS, in the Clearwater formation. They were able to fracture the formation and use CSS because the Clearwater is tight and you can contain the pressure. When we tried to do the same thing as Imperial, our formations would absorb the steam like a sponge. The McMurray is connected to thief zones. There is lots of water and gas caps.

CSS was the wrong recovery method for the McMurray formation.

A number of the pilots were technical if not commercial successes. For example, the Alberta Oil Sands Technology and Research Authority Underground Test Facility (AOSTRA UTF) drilled a mining shaft over 200 meters deep in the Limestone below the oil sands, from the bottom of which we assembled a drill rig and drilled horizontal well pairs up into the McMurray formation. AOSTRA was a Crown corporation set up by Alberta Premier Peter Lougheed in 1974 to commercialize the deeply buried oil sands reservoirs, using matching contributions from industry. The pilot at UTF proved the viability of SAGD. It was not set up for commercial operation, only as a pilot.

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I learned a lot from each one of them. It helped me understand the reservoir characteristics, and what technology would work. I wish our industry would talk more about failures. There aren’t too many papers that talk about failures, but they have so much to teach us. I was in a unique position to learn from all of those until it was very easy for me to figure out what would work and what wouldn’t work at Foster Creek.

To answer your basic question, the reason I didn’t think about the unsuccessful trials was because I knew the resource was so huge, and I knew that AOSTRA was committed to making it work.

"I wish our industry would talk more about failures…they have so much to teach us. I was in a unique position to learn from all of those until it was very easy for me to figure out what would work and what wouldn’t work at Foster Creek."

What significant technological changes do you think are coming in the heavy oil industry?

In all aspects of our operations, we will continue to get better. I can give you one example. The first well at Foster Creek had 32 meters of pay (thickness of the oil sands deposit). That well pair would have recovered three to four million barrels of oil. Today we are working with 12 to 25 metres of pay and we will recover more than four million barrels per well pair. Our independent reserves evaluator used to give us a 12-metre cutoff for reserves. That dropped to 10 and now eight metres. I can confidently say our teams will be able to recover from six metres of pay.

We did a test about eight years ago at Foster Creek. We tested well pairs at six to seven metres of pay and it turned out to be just fine. It’s not something we go after today, but it’s all set up to go after later on.

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Another example is the length of our wells. For the last 25 years, everyone only went to 800 metres horizontal length because that was the limit of good well conformance. Today we have wells 1,600 metres long. In fact, we have drilled 1,600-metre wells at Sunrise where the resource is only 120 metres deep compared to 450 metres at Foster Creek. That’s harder to do because you don’t have the same weight of the pipe on the bit to help you drill. We did that with a slant rig.

In Conventional, we have drilled 6,000-metre horizontals. That’s the distance from our downtown office to the Calgary airport. Our drillers have become so good in the last 10 years and that is going to continue.

We are using inflow and outflow control devices today which gives us great control of the wells. We can turn on and off specific sections of the wells.

Today, we need workovers to do that- we need to remove the devices from the well, reconfigure them, and put them back downhole. In the future, we will figure out how to do that automatically. Robotics will play a role, both in ICDs/OCDs and elsewhere.

Christina Lake - Courtesy of Cenovus

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The other area is netback improvements. We were lucky to get 20% to 25% of the price of West Texas Intermediate (WTI) crude oil from our first project at Foster Creek. We have reached upwards of 80% today and will continue to improve that. One way we will do that is through diluent reduction. Refiners don’t like diluent. They want synthetic crude or heavy oil so that they can maximize production of gasoline, diesel, and jet fuel. When refiners receive our diluted bitumen, they have to spend energy to separate the diluent before they can process the bitumen. We are going to reduce our diluent requirements in the future. We did a pilot test at Foster Creek where we took the API from 9.5 to 17. The pipeline specification for shipping is 19 API which means that with a 17 API product, we could get rid of 80% of our diluent usage. That would not only improve our netbacks but also increase pipeline capacity because we won’t be transporting diluent back and forth to our plants.

The other thing is digital technologies. I think we have 10 million data points collected every three seconds between our projects. We are going to get better at using that data for forecasting. When are electric submersible pumps likely to fail, when will liners fail, what will the production of redevelopment wells be? Using tools like artificial intelligence and machine learning, we will get better at forecasting those sorts of things. If we can use forecasting to improve our on-time from 94% to 95% or 95.5%, that’s hundreds of millions of dollars in value. That’s the path our company is headed on.

Of course, following through on our ESG commitments will be a huge change. As an engineer, I’ve always believed that 80% of solving a problem is knowing the problem and so greenhouse gases (GHGs) are a challenge but no more difficult than getting SAGD to work. Our company is set up to face it and solve our issues. For example, the company has allocated $1 billion in our current five-year business plan just on GHG-related technologies. The Pathways Alliance is another one of those ways.

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CHOA PLATINUM SPONSORS

The Pathways companies have $24 billion committed to carbon capture and other emissions reduction projects by 2030. Nuclear reactors aren’t something we can do in eight or 10 years, but I feel that’s a real solution. In fact, our company has a percentage of General Fusion, a company that is trying to solve nuclear fusion which would be a huge breakthrough. But first let’s do fission. That’s what we need to get to net zero. It won’t help us with our 2035 target, but we do need to start now.

In 2011 you said we were in the first inning of technology development of in situ oil sands. Where are we at today?

I think we still have a long way to go. Especially when it comes to in situ. I consider us in the third to fourth inning. There are lots of things we can be innovative in to develop the oil sands like API enhancement or nuclear reactors or data analytics. I see the younger generation coming into our company and I see a lot of smart people thinking outside the box and not waiting for their leaders to tell them what to do. They want to be proud of what they are doing and make a difference. There is a lot of game left, basically. By the way, that means that the world needs our oil. I firmly believe that.

In a 2011 interview with the Glenbow Museum for its Oil Sands Oral History Project you talked about the need for an industry-led AOSTRAtype organization. Do you feel as though that has been accomplished with Pathways, COSIA, CRIN, etc.?

I would say partly. AOSTRA’s main mandate was to develop technology to commercialize the oil sands, which included both mining and in-situ. SAGD was first piloted at the AOSTRA UTF site, which paved the way for commercial success of the technology. AOSTRA success was also in supporting academia and various scientific research throughout Alberta and Canada. So, when you look at the companies that were successful at SAGD - they were involved in AOSTRA or had students associated with AOSTRA. CHOA JOURNAL - FEBRUARY 2023 I 11

AOSTRA II would be an institution whose primary focus is to provide technical solutions to Environment Social Governance (ESG) issues faced by the oil and gas industry. Issues, such as reduction of absolute GHG, fresh water usage, land footprint and addressing biodiversity. Industry needs technology development to achieve net zero target by 2050. We need more efficient ways to do CCS, develop uses for CO2 and pursue technologies like, SMNRs and other nuclear solution that will reduce GHGs. AOSTRA II would be a focal point for government funding working jointly with industry, academia and other technical institutions.

Pathways is on the right track. They have six major players and it’s CEO-led.

However, they are focusing their efforts on existing technology like carbon capture. AOSTRA II is still needed for the next generation of ideas. For example, wouldn’t it be great if we could think of a product for the CO2 we produce, like synthetic fuel, or CO2 blended into cement? Our company has a percentage of Svante, which captures carbon dioxide using a solid sorbent instead of amines which could turn out to be a cheaper way to capture CO2. It would be good to find the next generation of ideas like Svante, so I still see a lot of value in establishing the AOSTRA II where there’s some funding mechanism that helps industry advance some of these low probability ideas that aren’t at the execution stage yet and still need to be developed.

Just to give you an idea, we invested more than $500 million through AOSTRA, with much of that going toward development of SAGD and of course that’s generating so much profit now. You don’t need every idea to work, you just need one breakthrough.

" We need smart people with new ideas. That includes graduates from universities, colleges, and the trades. … [oil sands] will be a highly paid industry for many years to come.”

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What's your advice for people who are starting their careers in the oil industry or thinking about joining the oil industry?

For the last 20 to 25 years, what has kept me awake is people. I feel that on a personal level why I was successful was that I knew something very few people knew. I think our industry is going to go through a lot of the same and people with skillsets needed by this industry will be highly prized and we will be faced by strong competition from other industries. But we don’t see oil and gas going away, I think it’s a great opportunity. A typical career is about 40 years. I definitely think this industry will be here for 40 years plus.

Companies will need the young generation. The old generation is retiring. We need smart people with new ideas. That includes graduates from universities, colleges, and the trades. Just take the Pathways commitment of $24 billion by 2030 which requires a lot of workers, especially tradespeople.

It will be a highly paid industry for many years to come.

“I have realized that I can be a great resource and mentor for new graduates all the way up to senior executives … I know this business … I want to set people up for success.”

What keeps you coming back?

These days it’s really the people. I thought I was only good at building projects and oil sands. I have realized that I can be a great resource and mentor for new graduates all the way up to senior executives. I underestimated what I can add. I know this business. I want to see our company succeed. I want to set people up for success. I feel really good when I can make a difference that way. Someone asked me what moment I won’t ever forget. In 2019, we hit a billion barrels of total production. We had barbeques at Foster Creek and Christina Lake to celebrate and during those trips, three women came up to me independently.

They said, “Harbir, thanks for starting these projects.” They talked about how they were able to use their careers to give their kids a university or college education. That meant a lot to me. I’ve always felt attached to this company – I want the company set up to succeed after I’m gone, which is a function of the people you leave behind.

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CHOA VOLUNTEER PROFILE CHOA VOLUNTEER SPONSOR, GLJ Ltd., values the talented professionals forming the core of our association: the CHOA Volunteers!

THANK YOU!

Gordon D. Holden

We are proud to feature one of CHOA’s hardest working volunteers, Gordon D. Holden. Since joining the CHOA as a Director in 2019, he has been key to the revitalization of the organization after COVID-19. Gordon has led the Operations and Finance, Revenue, and CHOA Journal Editorial committees, oversaw the creation of the CHOA eJournal, spearheaded many events including the CHOA Connects conference, has been a member of the Executive Committee, has been vital in building relations with our corporate sponsors while opening the door for new collaborations.

“Gordon is a great facilitator and communicator who always has a way to make people smile and feel comfortable.”

In the oil and gas industry, Gordon is an experienced leader of over 45 years. He has held senior positions including as Chief Engineer at Home Oil, Chief Operating Officer at Scimitar Hydrocarbons, President & CEO at Infiniti Resources, and VicePresident at Eastshore Energy. Today he is the Principal at Energy Strategies & Projects Associates, where he advises Canadian and International midstream & upstream clients, as well as COO at Surmont Energy, a private start-up oilsands company with 100% interest in 50 square kilometres of oilsands leases 65 km south of Fort McMurray, Alberta.

“I have not many people like Gordon in my life. He starts with connection, person to person, and builds from there. I’ve learned many lessons from him in our brief time together.”

CHOA VOLUNTEER PROFILE “Since joining the CHOA, Gordon has played a key role evolving essentially every aspect of our organization. He has lead us and influenced us in so many ways; whether streamlining our operations, mentoring and developing our people, building strong relationships with our stakeholders, modernizing our brand, reinvigorating our content offerings, or boosting our resilience through governance best practice. Gordon’s fingerprints are all over the CHOA! In fact, he’s one of the main reasons we had to add “lead” to our tagline: Connect. Share. Learn. Lead. We can’t thank Gordon enough!”

“He is always organized, and so positive. He gives weight to good ideas, no matter the source”

Gordon is a familiar face for all CHOA’s new volunteers as they get acquainted with the organization. His natural leadership qualities quickly surface in any context, gently guiding while he allows each individual’s unique qualities to shine through, fostering participation and promoting a healthy team dynamic. CHOA’s members and volunteers are lucky to have someone of Gordon’s calibre in a position of leadership.

“His enthusiasm is contagious. He’s willing to look outside the box for good ideas.”

A Haiku for Gordon Thoughtful delightful content connects.

Dedicated to innovative, sustainable Canadian oil.

Moved the needle with kindness, facts and research.

- Sincere gratitude from the Team at GLJ “I have admired Gordon for years as a knowledgeable and insightful energy leader who contributes profoundly to the broader community. I am lucky to know and work with him. I am sure many others feel the same way. His deep commitment to knowledge sharing and community support carries so much positive impact. I am delighted to see him be recognized here.”

CONVENTIONAL GEOTHERMAL: A Needle in a Haystack

BY TIM MONACHELLO AND PATRICK TANG ATB CAPITAL MARKETS

This article is the third in a series on how Geothermal Energy can impact the energy industry and net-zero transition.

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CONVENTIONAL GEOTHERMAL – A NEEDLE IN A HAYSTACK Today, conventional geothermal power generation systems (“conventional geothermal”) dominate current installed geothermal power capacity globally.

While the economics of these projects is competitive with other forms of renewable power, offering significant advantages in terms of increased capacity factors and are a source of baseload continuous power, these developments have been constrained by limited availability of high-quality hydrothermal resource. “[Conventional geothermal] developments have been constrained by limited availability of high-quality hydrothermal resource.”

About Conventional Geothermal Power Generation Conventional geothermal power generation systems typically involve drilling wells into high-temperature hydrothermal reservoirs (often 250°C to >300°C) at relatively shallow depths. These reservoirs often are formed near tectonic plate boundaries or volcanically active areas where the Earth’s crust is relatively thin. Conventional geothermal power generation requires high enough temperatures at accessible depths to generate power (heat gradient), the presence of water (brine), and adequate flow rates to commercially produce high volumes of brine. Hot produced brine is flowed to surface from production wells, heat is harvested in a heat-to-power plant, and then cool water is reinjected using pumps into the reservoir through injection wells.

High-Temperature Conventional Geothermal Developments in the US are Economic We use the EIA’s estimates of the levelized cost of energy (LCOE) presented in its 2022 Annual Energy Outlook for our analysis. The LCOE represents the average revenue per unit of electricity generated to be breakeven with respect to capital and operating costs of a power plant (or storage facility in the case of levelized cost of storage).

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The EIA’s calculation of LCOE assumes a 6.2% weighted average cost of capital and a 30-year cost recovery period. We note that the AEO considers the US projects that it deems to be on the increment, which we believe would highlight the economics of projects where high-temperature resources are likely present, consistent with most conventional geothermal developments in the US. The EIA assumes capacity factors at the top end of each technology’s likely operating range. For geothermal, this is particularly impactful, as the EIA uses a 90% capacity factor vs. the 10-year range between 68.3% and 76.0%.

With this in mind, high-temperature conventional geothermal screens among the top three renewable electricity generation technologies (see Figure 8), with an LCOE at US$39.82/MWh, a US$3.33/MWh disadvantage to the first-place standalone solar, making it highly competitive with other renewable energy sources at face value without consideration that solar would require storage to be functionally equivalent to geothermal. “… high-temperature conventional geothermal screens among the top three renewable electricity generation technologies …”

When performing economic analyses for new electricity generating capacity, avoided cost must be considered. Avoided cost is a measure of what it would cost the grid to meet the demand that is otherwise displaced by the new generation capacity; said another way, avoided cost is the cost that would be incurred to supply energy using the next alternative source. This accounts for variations in daily and seasonal electricity demand and the characteristics of the existing capacity to be replaced. Using the EIA-calculated lowest avoided cost of electricity (LACE) and dividing by LCOE, the value-cost ratio is derived.

Value-cost ratios above one indicate that the technology’s value is higher than its cost, and the highest ratios offer the best value. Looking at this measure suggests that US conventional geothermal is among the most economical power generation technologies (see Figure 8). Again, we stress that this analysis is focused on incremental projects, which are likely focused on the highest temperature hydrothermal resources in the US and which are relatively scarce and concentrated in the western US, including California, Nevada, Utah, Idaho, Colorado, Oregon, and New Mexico.

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Levelized Cost of Electricity (US$/MWh) and Value-Cost Ratios for Various Technologies

*Non-dispatchable technologies cannot vary their output and generally have less value to a system relative to dispatchable sources.

Note: The levelized avoided cost of electricity represents the potential revenue available to the project owner from the sale of energy and generating capacity. It is essentially a measure of what it would cost the grid to meet the demand that is otherwise displaced by a new generation project.

Figure 8 – Levelized Cost of Electricity and Value-Cost Ratios for Various Technologies Source: Energy Information Administration, ATB Capital Markets Inc.

As shown in Figure 8, geothermal plants, combined cycle designs (natural gas, other fuels), combustion turbines and batteries are considered dispatchable technologies that can vary their output in response to electricity demand. These generally have more value to a system/grid because of their adaptability, whereas non-dispatchable technologies can only produce as much as the natural variability in their inputs (wind and sun) allow.

“Capacity factors … suggest that geothermal is second in reliability to only nuclear … [and] well above both wind in the mid-30%s and solar between 20%-25% …

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Consistency and Scalability of Geothermal is Unmatched by Renewable Peers One of the main advantages geothermal energy has over its renewable peers is that its output is relatively consistent and reliable, which is known as baseload.

Geothermal wells generally output heat at a stable rate irrespective of weather conditions, unlike solar and wind installations, which cannot provide consistent electricity production without storage. Capacity factors, which represent the average electricity generated relative to nameplate capacity, suggest that geothermal is second in reliability to only nuclear, with a capacity factor between 70%-75%, well above both wind in the mid-30%s and solar between 20%-25% (see Figure 9).

Furthermore, within the span of a year, geothermal is relatively consistent, whereas solar suffers during the winter months and can be volatile in the summer, though ambient temperatures can affect geothermal power generation capacity to an extent.

Figure 9 – Capacity Factors for Utility-Scale Generators Primarily Using Non-Fossil Fuels Source: Energy Information Administration, ATB Capital Markets Inc.

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The Downside - Conventional Geothermal Resource is Scarce As mentioned, most hydrothermal reservoirs are found near plate boundaries or in other areas where the Earth’s crust is thin. For commercial projects, this significantly limits the availability of commercial geothermal power developments. For context, commercial conventional geothermal developments today are generally limited to the onshore red and orange areas in Figure 10.

This resource constraint has been a major limitation on the development of geothermal power capacity compared to other renewable resources that can be applied much more broadly. Since, 1990 just 1.4 GW of geothermal capacity has been added in the US, considerably below both solar and wind at approximately 121 GW and 134 GW, respectively.

While resource characteristics remain a challenge, new technologies and configurations known as enhanced geothermal systems are being developed that could make geothermal power generation economically competitive with other power sources outside of just the historically active areas, and they could ultimately make geothermal readily accessible around the globe. “… enhanced geothermal systems are being developed that could make geothermal power generation economically competitive … outside of just the historically active areas, and they could ultimately make geothermal readily accessible around the globe.”

Global Geothermal Developments Have Been Confined to High-Temperature Resources

Figure 10 – Global Geothermal Developments Have Been Confined to High-Temperature Resources Source: Clean Air Task Force, Davies 2013, ATB Capital Markets Inc. CHOA JOURNAL - FEBRUARY 2023 I 22

Case Study Ormat a Major Player in Conventional Geothermal Founded in 1965, Ormat Technologies Inc. (“Ormat”) is a leading geothermal energy producer with operations in over 30 countries and 953 MW of geothermal generation capacity (gross of 42 MW Indonesia capacity, of which ORA owns just 12.75%), of which 667 MW were generated in the US and 285 MW were generated internationally (France, Guatemala, Honduras, Indonesia, and Kenya). Ormat’s principal revenue stream is through its Electricity Segment, which designs, builds, owns, and operates geothermal power plants, solar PV, and recovered energy generation (“REG”, using Organic Rankin Cycle (ORC) waste heat to power technologies) power plants, from which it generated 88% of its 2021 revenue. All of Ormat’s US geothermal projects are conventional in nature, using binary, flash steam, or combined cycle power plants with air and/or water-cooling systems to generate power. Ormat also has a Product Segment that designs, manufactures, and sells geothermal and REG equipment, and a US-focused Energy Storage segment that provides battery storage solutions to the grid.

Ormat’s Geothermal projects represent roughly 26% of total installed US geothermal capacity (EIA), and they highlight the commercial opportunity in conventional geothermal, including: 1) High Geothermal Capacity Factors: Ormat’s geothermal power plants ran with an average 86% capacity factor in 2021, well above wind and solar, which are generally in the 20%-30% range (according to Ormat).

2) Stable, Low Risk Nature of Commercial Conventional Geothermal Projects: Each of ORA’s geothermal projects sell substantially all of their electrical output pursuant to long-term, typically fixed price, power purchase agreements (PPAs), with a weighted-average term of more than 15 years across its portfolio (at yearend 2021). ORA’s US counterparties have low credit risk (rated A3 to Baa2 by Moody’s, BB- to A by S&P), and internationally, ORA contracts with state-owned entities in countries with below investment grade credit ratings.

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3) Reasonable Return Potential for Conventional Geothermal: Since 2015, we calculate that ORA has generated average annual returns on capital employed (ROCE) of roughly 7.8%, which is reasonable considering the low-risk, recurring, and long-duration nature of geothermal cash flows. This calculation is after returns from the sale of tax benefits arising from the US Production Tax Credit for renewable energy projects, which helps fund capital outlays. This incentive structure improves returns for geothermal projects, and our calculations suggest that, without it, average annual ROCE would have been roughly 7.0% from 20152021.

1) Ormat Sees Reasonable Growth Opportunities in Conventional Geothermal: By year-end 2023, Ormat expects to have nine new geothermal projects (including expansion) online that would add roughly 111-122 MW to its capacity from year-end 2021, representing 12%-13% geothermal capacity growth over a two-year period. That said, Ormat’s project portfolio is centred on hightemperature resource areas. We believe the limited availability of these hightemperature resources has been a major governor of geothermal capacity development globally (see Figure 11).

Figure 11 – Ormat’s US Conventional Geothermal Portfolio Shows Reliance on High-Temp Resources Source: Ormat Technologies Inc., ATB Capital Markets Inc.

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Enriching Conventional Geothermal Systems Another way to drive stronger economics from geothermal developments is through the addition of secondary revenue streams and/or cost reduction technologies to projects. These generally involve additional processing applications on conventional geothermal facilities in an effort to increase the yield of a geothermal well, or adding secondary power generation to offset the parasitic load of geothermal pumps. These value-add components are shown in Figure 12 and the section below.

“Another way to drive stronger economics from geothermal developments is through the addition of secondary revenue streams and/or cost reduction technologies …”

EGS Value-Additions to the Conventional Geothermal Value Chain

Figure 12 – EGS Value-Additions to the Conventional Geothermal Value Chain Source: Terrapin Geothermics

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1) Hydrocarbon Recovery: One way to drive increased economics from geothermal wells is to add a hydrocarbon separation module to wells that can capture produced oil and gas from the reservoir, found in varying quantities depending on the resource area. While hydrocarbon separation can offer increased project economics, hydrocarbon production typically declines over time, is inconsistent across geothermal resources, somewhat increases the environmental impact of a geothermal well (Scope 3 emissions), and may require increased regulatory oversight and licensing requirements. Alternatively, a company can enhance an existing oil/gas well by adding geothermal equipment.

Case Study FutEra Power – Showcasing Geothermal Co- Production with Natural Gas FutEra Power, a subsidiary of Razor Energy Corp., has plans to develop a coproduced geothermal and natural gas power generation project by combining geothermal capacity with its existing natural gas production at its Swan Hills, AB operations. The Swan Hills formation is beneficially located in one of the highest temperature resource areas of the Western Canadian Sedimentary Basin, which provides geothermal temperatures at roughly 115°C while also being a world-class hydrocarbon resource.

The proposed $37 mn project contemplates the construction of a 5 MW geothermal power project combined with a natural gas turbine capable of boosting output to 21 MW by utilizing the natural gas separated from produced water. Viewed from another perspective, the produced water from hydrocarbon production will be used to generate power using an ORC configuration. The first phase of the project (geothermal + natural gas) is expected to offset 31,000 tCO2e/year. Then, the proposed second phase of the project contemplates the addition of a carbon sequestration module that would inject CO2 into the formation, potentially offsetting an additional 23,000 tCO2e/year and adding another revenue stream to the project (carbon offset credits).

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FutEra Power Project Demonstrates Geothermal + Natural Gas Co-Generation Potential

Figure 13 – FutEra Power Project Demonstrates Geothermal + Natural Gas Co-Generation Potential Source: Razor Energy Corp., FutEra Power, ATB Capital Markets Inc.

2) Supplementary Solar Arrays: Solar cells can be added to geothermal projects as a source of emission-free energy (aside from upstream Scope 3 emissions), which can be used to increase the efficiency of geothermal operations by offsetting the parasitic load of facility equipment – primarily pumps used to reinject water. Solar cells could also be a revenue source in jurisdictions with a carbon pricing scheme in place.

3) Direct Use: Low-grade or residual heat from produced brine can be utilized in a variety of applications, which can include green housing, fish farming, agricultural drying, heating & processing, cement and aggregate drying, and building heating and cooling. Overall, the temperatures found in most geothermal resources are too low for certain industrial applications such as hydrogen production or cement and aggregate drying applications, and we believe the previously mentioned low-grade applications are the most viable direct use applications for most geothermal projects. Direct use requires relatively close proximity to the application site and requires pipeline infrastructure to be built to transport and return water; we view this as the most significant limitation of direct use geothermal applications.

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“… in scenarios where direct use applications are viable, they can represent a significant value-enhancing secondary opportunity when paired with primary geothermal power generation.”

That said, in scenarios where direct use applications are viable, they can represent a significant value-enhancing secondary opportunity when paired with primary geothermal power generation. In our view, the proposed Alberta No.1 project by Terrapin Geothermics is a good example of this – expected returns on the project are significantly enhanced by the addition of a direct use heating revenue stream. In Figure 17, we present an economic model for the Alberta No.1 project that illustrates the large proportion of revenue that can be derived from heat sales (roughly 20% at $3.65/GJ).

Geothermal Temperature Gradients and Applications Case Study Latitude 53 – Direct Use for Aquaponics in Alberta Novus Earth’s Latitude 53 project in Hinton, Alberta, is a project that proposes to combine a conduction-based closed loop geothermal power generation system with a direct use heat installation to pipe heat to an aquaponics facility configured to grow produce and seafood. We understand the project would cost roughly $100 mn-$150 mn, including roughly $15 mn-$20 mn for well costs, $10 mn-$15 mn for power generation equipment (ORC), and likely $80 mn-$120 mn for a vertical farming/aquaponics facility. The project plans to use the majority of its 3.1 MW power capacity and the heat generated to run the aquaponics facility, with some excess power sales to the grid. The project is scoped to produce roughly 5.0 mn kg/year of produce (tomatoes, lettuce, bell peppers, swiss chard, wax beans, strawberries, and raspberries) and 500k kg of pacific white shrimp. Our understanding of initial projections suggests the project could generate upwards of $30 mn of EBITDA per year, primarily through sales of produce and shrimp, with upside based on an increasing price of carbon offsets.

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Figure 14 – Geothermal Temperature Gradients and Applications Source: U.S. Department of Energy CHOA JOURNAL - FEBRUARY 2023 I 29

Novus Earth expects to drill an exploration well to roughly 4 km depth near Hinton in late 2022 to confirm the formation’s heat and other characteristics.

Following this, Novus Earth plans to complete a funding round to finance the construction of the closed loop system, which would include two 4 km vertical well pairs and four horizontal sections. Heat at target depth is believed to be upward of 150C given a heat anomaly near Hinton, and the closed loop system could produce water to surface at roughly 130C, which would then be stepped down to roughly 70C after being utilized for power generation. The project has secured $5 mn in federal funding through the Smart Renewable Energy and Electrical Pathways program, which will be used to fund ongoing front-end engineering and design (FEED) and technical feasibility studies for the project.

Latitude 53 Project Combines Closed Loop with Direct Use in Northern Alberta

Figure 15 – Latitude 53 Project Combines Closed Loop with Direct Use in Northern Alberta Source: Novus Earth

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4) Lithium and Other Mineral Recovery: Depending on the minerals present in the reservoir, secondary mineral extraction may be value enhancing. According to a report by the California Energy Commission (CEC), lithium is often found in small but significant concentrations in geothermal brines (a few hundred ppm), and because of the high volumes of geothermal wells, geothermal brine can be a meaningful source of lithium production. A CEC report found that “the co-production of geothermal power and lithium carbonate will effectively lower the cost of geothermal power in California, making geothermal energy competitive with other sources of renewable energy”.

More specifically, the report estimates that the Salton Sea Known Geothermal Resource Area (KGRA) in California could produce over 600,000 tons/year (roughly 544,000 tonnes) of lithium carbonate with a value of roughly US$7.2bn at US$12,000/ton – which we calculate would represent over 500% of total global lithium carbonate production in 2021 (estimated to be roughly 100,000 tonnes). Secondary lithium extraction remains a relatively new concept for geothermal power projects, but increasing demand for lithium and increased R&D into cost-effective lithium extraction techniques could accelerate its commercial application over the coming years and drive stronger economics for geothermal power projects. As an example, DEEP Earth Energy Production Corp. signed an agreement in October 2021 with Prairie Lithium Corporation to exchange subsurface mineral rights and establish an Area of Mutual Interest – the partnership will enable the two companies to work collaboratively to understand and potentially commercially produce lithium from DEEP’s geothermal brine in Saskatchewan. We note that mineral extraction processes can not be used in closed loop geothermal systems, which would preclude this revenue stream from those economic analyses.

“Secondary lithium extraction remains a relatively new concept for geothermal power projects, but increasing demand for lithium and increased R&D into cost-effective lithium extraction techniques could … drive stronger economics for geothermal power projects.”

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CHOA GOLD SPONSORS

5) Carbon Capture and Storage: While it is relatively early days, a significant opportunity likely exists in pairing carbon sequestration with geothermal power projects as 1) a value-enhancing opportunity and 2) to potentially increase the efficiency of enhanced geothermal systems. In its simplest form, there is potential for geothermal power projects to inject carbon dioxide into the geothermal reservoir, either with the brine or into a separate formation. In doing so, geothermal projects could benefit from incremental revenues through access to carbon offset credits. As an example, phase two of FutEra Power’s geothermal project contemplates the addition of carbon sequestration. In more complex applications, it may be possible to replace typical water-based working fluids with supercritical carbon dioxide (scCO2) in EGS systems. While there is some disagreement from scientists, scCO2 has potential benefits over water as a working fluid, including: 1) it may offer better net heat recovery and mass productivity than water; 2) it may offer better buoyancy than water, which can improve pump efficiency; 3) the use of scCO2 may decrease or eliminate scaling issues on equipment (though it may cause other issues); and 4) scCO2 may be a better alternative to accessing hot dry rock (HDR) geothermal resources where naturally occurring groundwater is not present. “… geothermal projects could benefit from incremental revenues through access to carbon offset credits.”

Case Study No. 1 Geothermal – Alberta’s First Conventional Geothermal Project No.1 Geothermal Limited Partnership (“No. 1”), led by Terrapin Geothermics, Inc. is developing Alberta’s first conventional geothermal project, located in the Municipal District of Greenview, Alberta, just south of Grande Prairie, and targeting a geothermal resource at just 118C – near the bottom end of the viable range for binary cycle power generation. The project is slated to produce 10 MW of baseload electricity, 985 TJ/year of direct use heat to nearby industrial users, and will also generate revenue from carbon credits with an anticipated carbon offset capacity of 96,000 t/year. The project is currently under development, with an anticipated completion date in Q2/25.

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The project design includes three production wells and two injection wells connected to a binary cycle power plant at surface that would then flow into district heating infrastructure serving multiple light industrial facilities, including wood product manufacturing and sustainable agriculture in the region. Akita Drilling Ltd. was selected as the drilling provider for the project, and we understand the wellbores will vary in diameter, with the first injection well designed for a 7 1/2” production casing, while subsequent wells could be as wide as 9 5/8” or 13 3/8”. Based on our understanding of the well design, these are similar to thermal wells in the oil sands and will utilize rigs with similar specs.

Alberta No. 1 signed an MoU with Annelida Casting Innovation in April 2021 to investigate the use of geothermal heat in a direct use capacity to heat a vermicomposting facility.

Management also noted that Alberta No. 1 would also likely receive carbon credits from the Government given geothermal’s classification as a renewable. The credits would be calculated on the carbon mitigated relative to fossil fuel-based power plants.

We estimate the capital cost of the project at roughly $90 mn-$100 mn, with roughly twothirds associated with finding and development costs for downhole infrastructure and the remainder for surface facilities and district heating infrastructure. We understand well development costs alone are expected to be $7 mn-$9 mn/well. To date, the project has received $25.4 mn in funding from Natural Resources Canada’s Emerging Renewable Power Program, which matched private sector dollars 1:1 on the condition that the geothermal project design was for at least 5 MW of power (net of parasitic load); funding under the Program excluded land acquisition costs, legal costs, and certain other costs.

Overall, we believe that, if the Terrapin No.1 Geothermal project is successfully executed and proves it can meet its revenue and return targets (see Figure 16 and our demonstration modeling in Figure 17), it would demonstrate the commercial viability of conventional geothermal projects in Alberta and could spur other projects in the province.

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Project Economics Terrapin disclosed its internal expectations for a 16% IRR based on $50/tCO2e, and an IRR of 22.6% based on a ramp to the Federal Government’s $170/tCO2 by 2030 (see Figure 16).

Expected Returns on No. 1 Geothermal Project

Figure 16 – Expected Returns on No. 1 Geothermal Project Source: Terrapin Geothermics, Inc.

Conventional Geothermal Project Modeling In Figure 17, we present a model for a conventional geothermal power plant based on Terrapin’s proposed Alberta No. 1 Geothermal project in Alberta that generates revenues from the sale of power, the sale of direct heat, and from carbon credits. Our model suggests that a project of this nature could expect to generate IRRs in the 13%-26% range depending on carbon, gas, and power pricing.

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Figure 17 – Return Model Based on Terrapin’s No. 1 Geothermal Project Source: ATB Capital Markets

Key Assumptions · Nameplate Capacity: 10 MW, 78% uptime – consistent with our understanding of minimum geothermal power plant uptime and conservative relative to capacity factors for modern plants assumed to be in the 90%-95% range by the U.S. Department of Energy. · Capital Costs & Timeline: We assume a $90 mn capital cost for the project, allocated $5 mn in 2022, $15 mn in 2023, and $70 mn in 2024. We assume the project is commissioned January 1, 2025, and runs for 40 years. · Power Pricing: $100/MWh – in line with current ATB long-term assumption, plus premium for renewable baseload energy. · Gas Pricing (for Heating): $3.65/GJ–above long-term ATB estimate, assumes premium pricing or renewable energy and is inclusive of distribution costs; based on pricing assumption by Alberta-based developer. · Carbon Credit Pricing: $50/tCO2e flat rate for base case, with five scenarios (see Figure 18) ramping linearly to $210/tCO2e by 2030 in $40/tCO2e increments. Federal government carbon pricing proposal has carbon pricing ramping to $170/tCO2e by 2030. · Operating Costs: $2.0 mn per year, inclusive of sustaining capex based on discussions with developers. · Unlevered, No Grants: Our returns are on an unlevered basis with no government grants or funding.

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Sensitivities to Gas and Power Pricing We present two sensitivity analyses below, showing how the IRR of the project changes if 1) power pricing and carbon pricing are altered and 2) gas pricing (which influences the price available for direct use heat sales) and carbon pricing are altered.

Power and Gas Pricing (District Heat) Sensitivity Analysis

Figure 18 – Power and Gas Pricing (District Heat) Sensitivity Analysis Source: ATB Capital Markets Inc.

The base case, used in Figure 18, conservatively assumes that the current rate of federal carbon tax remains flat at $50/tCO2e, and assumes that power is priced at $100/MWh and district heat has a value of $3.65/GJ. In this scenario, our modeling suggests roughly a 14% IRR over a 40-year period. Assuming carbon pricing increases to $170/tCO2e, our project modeling suggests roughly a 23% IRR. At $170/tCO2e, if power pricing is reduced to $80/MWh – in line with the ATB long-term assumption, then the return falls to 21.3%. On the other end, if carbon pricing reaches $170/tCO2e by 2030 and power is priced at $120/MWh – a possibility if energy demand rises at an accelerating pace – then our modeling suggests a plant similar to Alberta No.1 could generate a 23.8% IRR. At $50/tCO2e carbon pricing, each $10/MWh step in power pricing increases/decreases IRR by roughly 0.7%-0.8%; at $170/tCO2e, each $10/MWh step increases/decreases IRR by roughly 0.6%.

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Gas pricing, on the other hand, is relatively less impactful to returns than power pricing – as is to be expected given that district heating represents the smallest proportion of our model’s baseline revenues (assuming $50/tCO2e carbon pricing). If carbon pricing increases to $170/tCO2e by 2030 and gas is priced at $3.05 – closer to the ATB long-term assumption – then return falls from 22.6% to 22.0%. If lower carbon pricing is compounded, then the worst-case return based on our model is 13.5% with $3.05/GJ gas pricing. On the other end, if carbon pricing reaches $170/tCO2e by 2030 and gas/district heat sales are priced at $4.25/GJ, then our modeling suggests the project could generate a 23.1% IRR. At $50/tCO2e carbon pricing, each $0.30/GJ-step increases/decreases IRR by roughly 0.3%; the intervals are similar at $170/tCO2e.

Case Study Imperial Valley – Value Enhancements in California The Imperial Valley geothermal complex located in California is made up of 11 geothermal power plants – one owned by EnergySource and 10 owned by CE Generation, LLC (subsidiary) and operated by CalEnergy Operating Corporation (subsidiary), which are both ultimately controlled by Berkshire Hathaway Energy (BHE Renewables), a subsidiary of Berkshire Hathaway Inc. The complex is situated within the Salton Sea KGRA, and the 11 plants together have a net generating capacity at nearly 400 MW, positioning it as the second-highest generating geothermal field in the US behind The Geysers. In the Imperial Valley, two additional geothermal power generation projects are currently being developed, each with a non-traditional feature.

The first, put forth by Controlled Thermal Resources (“CTR”), is the Hell’s Kitchen Lithium and Power project, which is designed and planned to deliver 50 MW in geothermal electric power generation in 2023 and 20,000 tonnes of lithium hydroxide in 2024. Drilling commenced in Q4/21, and the target depth for the two wells was pegged at approximately 8,000 ft. Following the completion of drilling, brine testing must be conducted to prepare for power production and lithium extraction. Capital costs are not known at this time.

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The second project, known as Project #501, is being spearheaded by GeoGenCo and is a closed loop EGS system, though technical specifications are scarce. The project is designed to deliver 18.5 MW (net) of geothermal electricity from an already drilled well. No capital costs were disclosed, and an expected commissioning date is not available, though GeoGenCo notes that the project is “shovel ready” and could be completed within 14 months of securing financing. If successful, Project# 501 could be among the first commercial, large-scale, closed loop systems that we are aware of. We note that, unlike other proposed closed loop designs, Project# 501 will access a high-temperature resource (roughly 370°C at roughly 3,500 m depth).

Beyond these two projects, BHE Renewables is currently constructing a demonstration project in the Salton Sea KGRA to recover lithium from geothermal brine to produce lithium chloride. Expected completion of this demonstration project is in 2022. Concurrently, BHE Renewables is developing a separate demonstration project to convert lithium chloride into battery-grade lithium carbonate with a 2024 completion date. Upon completion of both projects, the production process could be deployed on any of the Company’s 10 geothermal power plants at Imperial Valley as soon as 2024.

Appendices A, B, C, and D here.

The next articles in this series will drill down further, into Enhanced Geothermal, Opportunities for the Oil and Gas Service Sector, Economic and Strategic Factors, and the Regional Landscape for Geothermal Development.

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CHOA LEARNS: ENERGY CHANGEMAKERS

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Welcome to CHOA LEARNS: Energy Changemakers!

This year-long series of short, interactive talks will feature scientists and leaders who are shaping the future of Canadian energy. Talks will feature unique insight gained on the leading edge of energy innovation.

We’ll kick off this series on February 16th with discussion of new (and previously overlooked) opportunities for geothermal energy. Upcoming topics will include CCUS, solvent innovation, and more. Participants will directly shape this series by choosing future topics to explore.

All talks will also include dedicated time to network and learn from each other.

Let’s get together for breakfast and learn something new! www.CHOA/event/energychangemakers

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ENERGY CHANGEMAKERS IN ACTION 16 February 2023 - the Calgary Petroleum Club

Join the Energy Changemakers for the next event of the series on March 21st!

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CHOA MEMBER CORNER

CONGRATULATIONS JOHN HIRSCHMILLER! CHOA and GLJ Ltd. are proud to congratulate and announce that their very own John Hirschmiller has been selected as a Best Oral Presentation at the 2022 GeoConvention Partnership. With over 350 presentations voted on, his paper & presentation, ''Beyond EOR- Evaluating the Geothermal Potential of Historic Gas and Oil Fields'' was selected as one of the top.

You can watch John's presentation here: https://lnkd.in/gEN_JsYB CHOA wants to extend a special THANK YOU to John Hirschmiller for kicking off the year-long series CHOA LEARNS: Energy Changemakers on February 16th with an insightful discussion of new opportunities for geothermal energy.

These short, interactive talks feature scientists and leaders who are shaping the future of Canadian energy.

Check the upcoming events here: https://choa.ab.ca/events/

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place your ad here Contact us for details office@choa.ab.ca

ZEROING METHANE EMISSION DATATHON

The SPE Calgary Section has teamed up with their friends at the SPE Gulf Coast Section, along with ‘Untapped Energy,’ Canadian Heavy Oil Association (CHOA), Energy Transition Alberta, and the SPE Gaia Sustainability Program to organize a data event like no other! Driven by the desire to use real data to solve a real problem, to elevate data literacy and to make new professional connections, all while having fun!

THE CHALLENGE Quantifying greenhouse gas (GHG) emissions is a crucial part of Environmental, Social and Governance corporate strategy. Our goal is to provide datathon participants with a high quality hands on learning experience in this area by working on an industry-relevant problem with real data. One emerging topic is the analysis of methane emissions, such as comparing “bottom-up” estimates using activity and emissions factors, with “top-down” approaches using satellite data. www.speuntapped.com

CHOA MEMBERS CORNER Paul Paynter received the Queen Elizabeth II Platinum Jubilee Medal

We proudly congratulate long-time CHOA member Paul Paynter for his recent award: the Queen Elizabeth II Platinum Jubilee medal, presented to him in December 2022 by Alberta’s Lieutenant Governor, the Honourable Salma Lakhani, AOE B.Sc., LLD (Hon).

Paul has worked tirelessly to promote and grow the energy industry, and the Alberta and western Canada economies. Since 2005, he had made significant contributions to our community, which welcomed him and his then-young family when they immigrated from the UK to Canada. Paul is a well-known face of Calgary's downtown, all the way back when he was Director of the British Trade Office in Calgary, which became later a full Consulate.

Later, Paul promoted Calgary and Alberta as the prime investment destination for both traditional and new forms of energy in his role with Calgary Economic Development, spearheading successful trade missions to Asia, South America, and Australia. He then opened the Saskatchewan Research Council office in Calgary, which was the first Saskatchewan Crown Corporation office outside the province. Paul has been instrumental in convening industry operators for ground-breaking applied research projects to enhance heavy and tighter oil production, while reducing emissions and water usage across the Western Canadian Sedimentary Basin. He also played an important role in the World Petroleum Council (Canada) Board that is bringing the World Petroleum Congress to Calgary this coming September 2023.

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CHOA MEMBERS CORNER

CONGRATULATIONS PAUL PAYNTER! Paul never runs out of energy and is currently responsible for developing and promoting the business of Calgary-based General Energy Recovery Inc (GERI), with its patented, groundbreaking portable steam and flue gas Direct Contact Steam Generation Technology. Paul is convinced that GERI’s technology is a lowcost solution to the key target of enhancing heavy oil recovery, while using significantly less water and generating much lower emissions. Paul’s strong understanding of the energy industry and his personal drive towards reducing greenhouse gas emissions led GERI’s penetration into the low-emissions thermal recovery market.

Paul has Bachelor’s and Master’s degrees in Politics, Philosophy, and Economics from Oxford University. Paul became a Canadian citizen in 2010.

He has been married to Claudia for 33 years and they have two grown children, Holly and Guy, who both attended Mount Royal University. Paul has volunteered for many charitable organizations including the Rotary Club of Calgary and the Shaw Charity Classic. Following the devastating 2013 floods in Alberta, Paul spent innumerable hours clearing basements in Calgary and Exshaw and delivering vital supplies to displaced High River residents in locations such as Vulcan and Okotoks.

CHOA congratulates Paul on receiving this prestigious award!

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TURNING UP THE HEAT: Enhanced Geothermal

BY TIM MONACHELLO AND PATRICK TANG ATB CAPITAL MARKETS

This article is the fourth in a series on how Geothermal Energy can impact the energy industry and net-zero transition.

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What deep drilling means for unlocking geothermal energy in new areas Next-generation technology, e.g., plasma, laser-assisted, and millimeter wave drilling Horizontal and fractured well designs for geothermal reservoir creation Closed-loop systems being developed by an Alberta technology company ENHANCED GEOTHERMAL SYSTEMS – INNOVATION TO BRING GEOTHERMAL MAINSTREAM In areas where high-permeability, high-temperature geothermal resources are not readily available (such as Alberta), enhanced geothermal systems (EGS) have been, or are being, developed that can be used to enhance the efficiency and/or economics of a geothermal project. While the term EGS has sometimes been used to refer to just fractured geothermal systems and AGS (advanced geothermal systems) has been used to define other next generation systems, for our purposes, we use the term “EGS” to refer to all next-generation geothermal systems, which encompasses both new geothermal downhole technologies that can improve the power generation capabilities of lower-temperature resources outside of known hydrothermal plays, new configurations that allow for deeper commercial drilling, and technologies that utilize geothermal resources devoid of an aquifer. While most EGS applications are in relatively early stages of development and commercialization, we believe the wide scale adoption of geothermal energy is dependent on EGS technologies driving the economic viability of projects in areas previously unconducive to geothermal resource development.

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“… wide scale adoption of geothermal energy is dependent on enhanced geothermal systems (EGS) technologies driving the economic viability of projects in areas previously unconducive to geothermal resource development.”

Enhanced Geothermal Systems I) Deep Geothermal Resource Development: Commercial geothermal power development generally requires a geothermal resource at roughly 150°C, and higher-temperature resources will yield better economics. Perhaps the largest single headwind facing geothermal development has been that hydrothermal resources are generally too cold for power generation at commercially accessible depths. Nevertheless, higher geothermal temperatures can be found around the globe at deeper intervals.

While the geothermal gradient is not consistent around the globe, the temperature of the Earth’s crust increases around 2°-3°C/100m in depth on average, though this can range from 1°C-5°C/100 m. At roughly 10 km depth, 150°C geothermal resource is nearly ubiquitous across the continental United States, while at 3 km depth, most resource is in the 75°-100°C range except for certain high-temperature geothermal sites that are the primary focus of current conventional developments. That said, leading-edge drilling technologies in the oil and gas sector have shown the ability to drill wells over 7-10 km (total measured depth), though these wells are typically only a few kilometers deep and sometimes over 7 km in lateral length, and well diameters are significantly narrower than for commercial geothermal development.

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With Technological Advances, Deep Drilling Could Unlock Geothermal Around the Globe

Figure 19 – With Technological Advances, Deep Drilling Could Unlock Geothermal Around the Globe Source: National Renewable Energy Laboratory, Department of Energy, University of Michigan, ATB Capital Markets Inc.

The Deeper the Hotter: While the geothermal gradient is not consistent across the globe, on average the temperature of the Earth’s crust increases around 23°C /100m in depth, though this can range from 1°C-5°C/100m.

Geothermal Could be Accessible Everywhere with Deep Drilling: At roughly 10km depth, nearly all of the continentals U.S. has geothermal temperatures at or above 150 °C, which is hot enough for power generation.

Technological Development is Required: Current technology can drill wells to total measured depths in the 7-10 km range, though these are generally significantly narrower boreholes than are required in geothermal drilling, and measured depths highly weighted to the lateral section.

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Superhot Rock Geothermal Could Be the Holy Grail At depths of 10-20 km, high-temperature geothermal resource can be found nearly everywhere on Earth. This resource, known as superhot rock (SHR) geothermal, has been dubbed “the holy grail” of geothermal, as it has the potential to unlock access to commercial temperature resource regardless of location.

For context, a report by the Clean Air Task Force (CATF) suggests that SHR resources could deliver mature LCOEs in the US$0.020-$0.035/kWh range (US$20-$35/MWh) which it views as competitive with other dispatchable and intermittent energy sources. For context, the EIA estimates the LCOE for geothermal plants entering service in 2027 to be $39.82/MWh, and this is effectively based on incremental developments in currently feasible areas only.

Superhot Rock Systems Could be a Game Changer, but Require Innovation

Figure 20 – Superhot Rock Systems Could be a Game Changer, but Require Innovation Source: Clean Air Task Force, ATB Capital Markets Inc. CHOA JOURNAL - FEBRUARY 2023 I 51

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While drilling SHR systems appears attractive, there are at present certain challenges that require innovation to overcome. Primary challenges include: Current Well Development Technology Not Suited for SHR Depth and Temperature: Depth limitations on current mechanical drilling techniques have not generally been tested, as most hydrocarbon wells are shallower than SHR depths, and rigs are generally designed to drill significantly farther both horizontally and vertically. In addition, SHR reservoirs are located within crystalline basement rock, which is generally harder than sedimentary rock deposits closer to the surface. Ultra-hard rock drilling can increase the cost of mechanical drilling techniques as equipment wear and time to drill increases in harder formations. Moreover, mechanical drilling technologies and well construction materials are generally designed for temperatures in the 150°- 300°C range and not for >400°C. At these elevated temperatures, the physical properties of metal parts, drilling fluids, well casing and cement can be altered.

Basement Rock Generally Requires Reservoir Creation: Aquifers are not generally present within basement rock formations, and they would require the artificial creation of fresh water reservoirs by fracturing rock while limiting seismic risk and limiting or eliminating the use of fracturing chemicals.

Drilling Innovations Could Unlock Ultra-Deep Wells Energy drilling is a new frontier of drilling technology that looks to replaces or supplement mechanical drilling techniques with new technology using a form of focused energy to soften, melt, or vaporize rock. Millimeter wave drilling, plasma drilling and hybrid mechanical-laser drilling technologies are being developed that could significantly increase the depth capacity of commercial drilling operations and potentially reduce cost by up to 90% vs. current mechanical drilling technology. These technologies are generally in their infancy and are likely at least 5-10 years away from commercialization, in our view.

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Quaise – Millimeter Wave Drilling: Quaise is developing a technology that harnesses fusion research out of MIT to deploy millimeter wave technology using a gyrotron at surface that would essentially vaporize hard-rock formations. The technology has been shown to work in small-scale demonstrations, and a 3,300 ft demonstration well is being planned with partner AltaRock. Quaise plans to use mechanical drilling technologies to drill to basement rock, then switch to millimeter wave drilling to drill to depths up to roughly 20 km.

We understand this technology could offer additional benefits: 1) not requiring drilling fluids given that the pressure generated from the vaporization of rock would ensure overpressure drilling; and 2) the heat created from the formation vaporization could eliminate the need for wellbore casing, as the heat essentially creates a glass liner on the surface surrounding the well bore (known as vitrification).

Figure 21 – Quaise Assembly Diagram Source: Quaise Energy

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If successful, Quaise estimates that its technology could be up to 90% cheaper than conventional deep well drilling technologies. We note that, in August of 2021, Nabors Industries made a US$12 mn investment in Quaise, with Nabors’ Chairman, President and CEO stating, “We see in Quaise one of the most potentially disruptive technologies in the space, and we believe the team is well positioned to capture the ultimate potential of this technology.”

GA Drilling – Plasma Drilling: GA Drilling, based in Slovakia, is developing PlasmaBit® technology, which essentially uses a pulsed plasma technology to create short, high-energy pulses at high frequency causing acute increases in rock temperature that disintegrate the rock’s surface.

GA Drilling also contemplates using mechanical drilling technologies to reach basement rock and then deploying PlasmaBit® technology using a coiled tubing unit to reach depths of 10 km or more. We understand that GA Drilling’s PlasmaBit® has yet to be proven in the field, though it has undergone extensive lab testing. We note that, in March of 2022, Nabors Industries made a US$8 mn investment in GA Drilling. Nabors noted that it planned to leverage GA Drilling’s Centre of Excellence and to integrate GA Drilling’s technology into its ecosystem and further remarked that “Nabors intends to become a key player in the upcoming expansion of geothermal energy.”

Foro Energy – Laser-Assisted Drill Bits: Foro Energy is developing a laser-assisted drill bit that uses advanced fiber optics to transmit highpowered lasers for use in deep drilling operations. The lasers are paired with mechanical drill bits and are used to essentially soften the formation for mechanical drilling. Foro Energy states that its laser-assisted drill bits could be 10 times more economical than conventional drilling technology in hard rock formations. We also note that Fraunhofer IPT, along with “LaserJetDrilling” project partners, is developing another system that would combine lasers with mechanical drill bits for use in hard-rock formations.

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CHOA SILVER SPONSORS

II) Horizontal and Fractured Well Designs: Horizontal well designs are being used to increase the productivity of producing geothermal wells by increasing the area that wells collect water within the high-temperature producing formation, and some projects have also enhanced flow rates in lower-permeability formations by fracturing the reservoir. In addition to improved production rates per well, pad well designs can increase cost efficiencies, as multiple wells can be drilled from a single surface location. There are numerous companies developing technologies to optimize fractured well designs for geothermal – leaders include Fervo Energy and Sage Geosystems. DEEP Earth Energy Production Corp. is an example of a company that plans to utilize horizontal drilling for geothermal power development – the initial phase of its project is planned with 34 horizontal well bores (18 producing and 16 injecting), each with a vertical depth of roughly 3,500 m and a horizontal reach of 3,000-4,000 m.

III) Closed Loop Geothermal Systems: In our view, closed loop geothermal systems are the furthest departure from conventional geothermal systems, as they do not use reservoir water directly. Instead, closed loop systems are designed to use a thermosiphon to circulate water through a closed loop without the need for pumps. The closed loop design uses heat-to-power generators to produce electrical power. Closed loop designs rely on the advanced horizontal drilling capabilities developed in the oil and gas industry to drill multiple horizontal wells that are connected within the reservoir to create a loop.

“Closed loop designs rely on the advanced horizontal drilling capabilities developed in the oil and gas industry to drill multiple horizontal wells that are connected within the reservoir to create a loop.”

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Closed loop designs are in the early days of development, but they offer significant potential advantages over conventional designs: 1) they do not rely on well permeability or natural flow rates, which can increase the applicability to less favourable resource environments; 2) they reduce the impact of produced brine on equipment (including scale, corrosion, etc.); 3) they do not require pumps, which significantly reduces or eliminates the parasitic load on the system; and 4) they could offer greater dispatchability compared to conventional geothermal power plants. That said, the closed loop design does not allow for the extraction of hydrocarbons or other minerals from the formation. Closed loop systems are being advanced by companies in both Canada and the US, of which we highlight Canada-based Eavor Technologies (see below) and US-based GreenFire Energy.

Case Study: Eavor-Loop – Using Innovation to Solve Conventional Issues Founded in 2017 in Calgary, Alberta, Eavor Technologies is a pioneer of conduction- based closed loop geothermal systems, and it is developing technologies that we believe could be transformative for geothermal energy developments. We understand Eavor has developed and patented many innovations that could enable the drilling of hermetically-sealed closed loop geothermal systems, which do not rely on aquifers or require pumps, use a thermosiphon to create flow, and could potentially be drilled almost anywhere on Earth.

Eavor also claims a multitude of other advantages of its design. In future designs (Eavor-Loop 1.0 and Eavor-Loop 2.0; see Figure 22), Loops will be placeable in various 3D planes from a single surface location, increasing heat extraction from the resource and consolidating wellbores into a single facility.

As such, this would allow geothermal to be economically developed from areas not previously thought to be feasible using conventional or other enhanced geothermal systems.

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Furthermore, the thermosiphon can be started and stopped without any input power, meaning that the geothermal power plants can be used to efficiently meet power demands (“load-following”). When flows are halted, the working fluid can absorb more geothermal heat and, upon restart, the higher temperature working fluid can push power generation rates above normal operating capacity for a period of time – up to three times as much – making Eavor’s technology suitable for both baseload power and peaking power plants. This feature, called dispatchability, allows for Eavor-Loops to work symbiotically with intermittent power such as wind and solar.

Eavor Capital Costs and LCOE Management claims that the power generation of Eavor-Loops is both highly reliable, predictable, and each Loop can last for roughly 100 years. The output of each Loop is simply a function of the well design and the thermal resource, which can vary meaningfully from project to project and can impact returns.

Capital Cost: While project costs are subject to significant variability; we understand that Eavor-Lite costs roughly $25 mn, and Eavor’s Germany project (four Eavor-Loop 1.0s) is slated to cost roughly $220 mn. Beyond this, Eavor’s management has estimated that it would cost roughly $100 bn to develop 2,500 Eavor-Loops through 2030. Based on this, we estimate that each Eavor-Loop could cost roughly $30 mn-$60 mn to develop. At roughly $10 mn/MW, the capital cost of Eavor-Loops is significantly higher than most renewable projects, but Eavor-Loops benefit from low operating costs, high utilization, and significantly longer useful lives than solar or wind projects, with a 100-year expected life.

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LCOE: Currently, we understand Eavor’s LCOE is well above economic levels - likely in the $250/MWh range. That said, Eavor is targeting a $50/MWh LCOE, driven by efficiency gains from drilling techniques, project design, and other optimizations as the Company improves its commercial deployment. Specifically, Eavor believes that if its well test in New Mexico goes as planned, it could achieve $50/MWh reliably in the Southwest US – where the geothermal heat gradient is ~60C/km) – over the next 3-4 years.

At the $50/MWh target LCOE, Eavor-Loops could be competitive with other renewable forms of power generation but could offer significant advantages over wind and solar including 1) being a source of baseload power and not having intermittency issues and 2) the ability be deployed in regions where wind and solar resource are sub-economic or where land costs are prohibitively expensive.

The Path to Commercial Eavor-Loops Eavor Technological Development – From Pilot to Scalable Commercial Application

Figure 22 – Eavor Technological Development – From Pilot to Scalable Commercial Application Source: Eavor Technologies Inc., ATB Capital Markets Inc. CHOA JOURNAL - FEBRUARY 2023 I 60

Phase 1: Eavor-Lite Demonstration Facility – Complete

Eavor’s pilot project, Eavor-Lite, demonstrated the Eavor-Loop technology near Rocky Mountain House, Alberta. The Eavor-Lite facility produces roughly 1 MW thermal and can be fitted with an ORC to generate power; we understand that an ORC would be roughly 10% efficient at current formation temperature. Precision Drilling was selected as the drilling contractor for this project, and two of the Company’s rigs broke ground in 2019. Spud to rig release was 46 days. In doing this pilot, Eavor achieved certain goals.

From an overall perspective, demonstration of its technology in a less geothermally-active area (75C, low relative to more common formations in Iceland or the US) showed prospective customers the applicability of its closed loop geothermal design in a more common resource environment.

Eavor’s pilot also served to prove that the Company could: 1. Drill and Connect Laterals: Critics of Eavor’s design noted the technical difficulty of drilling and connecting two laterals to form a loop. However, Eavor leveraged technology from the oil sands – geomagnetic positioning, in particular – to accurately position wellbores well beneath the Earth’s surface.

2. Maintain Wellbore Integrity: Given the vertical depth and lateral length of the lateral – and the predominantly sandstone composition of the targeted formation – there was some belief that casing/cementing the wellbore (specifically the lateral section) would be a challenge. As we understand, however, Eavor’s reliance on a “rock pipe” design does not require difficult casing/cementing jobs. The positive pressure of the wellbore prevents the wellbore from collapsing, and the working fluid used by Eavor is specially formulated to prevent fluid migration to the formation.

3. Initiate a Thermosiphon: While proved in concept, a thermosiphon of this scale had not been commonly seen. Eavor-Lite showcased how the closed loop thermosiphon would work without parasitic load.

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Phase 2: Southern US Test Well Could Prove Deep-Drilling at High Temperatures – Planning

Eavor has plans to drill a test well in the southern US in 2022, which is planned to be a long-reach geothermal well with a multi-kilometer portion of the well drilled through hard-rock below the sedimentary rock layer. This well, which we understand is expected to cost roughly $10-$15 mn to drill, has potential to be among the deepest commercial-grade wells drilled, and it will target downhole temperatures exceeding 300C. This project intends to prove: 1. Efficient Hard-Rock Drilling Capabilities: While Eavor has not disclosed details, we understand it has developed a drilling technique that it believes can rapidly drill through high-temperature, hard-rock formations at economical rates of penetration (ROP). In our view, success here would be not only a major breakthrough for Eavor, but also a major breakthrough for the geothermal industry, as it would mark a significant step forward in the development of deep geothermal and SHR geothermal systems.

2. Use of Guidance Systems in High-Temperature Reservoirs: Eavor’s planned test well will include a small offshoot well that Eavor will use to test that its guidance systems will work both at extreme depths and at temperatures in excess of 300C. We understand that Eavor’s novel drilling technique is designed to protect its guidance systems from extreme heat.

This test is designed to show that multiple legs can be successfully connected in deep, high-temperature reservoirs. If the Phase 1 test well at this site successfully proves Eavor’s ability to drill and connect wells at extreme depths and temperatures, it would also set the stage for Eavor to complete a full-scale Eavor-Loop 2.0 at the site. It would also be a significant step forward in Eavor’s drive to improve economics – management believes a successful test would validate its line of sight to $50/MWh LCOE in high-temperatures resources in the Western US. CHOA JOURNAL - FEBRUARY 2023 I 62

Phase 3: Eavor-Loop 1.0 The First Commercial Application in Germany – Planning

In May 2020, Eavor announced that it had entered into a letter of intent with Enex Power Germany to jointly develop an Eavor-Loop 1.0 (shallow configuration) at Geretsried in Bavaria, Germany. Enex was granted a geothermal concession/lease in 2004 and drilled two exploratory wells, with the most recent well drilled in 2017. Neither of the two wells was capable of producing fluid hot enough for conventional geothermal to be feasible.

However, the formation temperature and geothermal gradient (roughly 300°C) was suitable for the development of an Eavor-Loop that would be capable of generating power and providing heat for district heating applications.

At the latest update, surface construction is slated to begin in October 2022, and it will be funded by Eavor. Eavor expects to use grant funding and inflows from strategic investments for downhole construction, scheduled to be completed in 2025, though we understand that full funding is not yet secured.

Commercially, the project will be eligible for payments under the German Government’s Renewable Energy Sources Act, which augments the electricity price received for 20 years from the date of project commissioning and will result in a fixed power price of €252/MWh (roughly C$400/MWh). Under Germany’s Energiewende (“energy transition”) policy, which aims to develop low-carbon, environmentally-friendly, and affordable power sources, Eavor’s technology was selected – indicating the strategic fit of geothermal developments with German environmental and energy policy.

Phase 1, with a cumulative 10 MW design, includes four Eavor-Loop 1.0s with a $220 mn budget (see Figure 21). We believe the well costs of the project are likely at least double the cost to drill in Alberta given the lack of oil and gas services, and we believe the costs of this project are likely to be elevated given it would be the first Eavor-Loop 1.0 drilled.

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Similar to Eavor-Lite, the location was strategically chosen to demonstrate the applicability of the technology in a lower-temperature resource. We believe the project economics will be weak, likely even delivering a negative return profile.

That said, the site is largely a demonstration of the technology at scale, and future technology and process innovations are expected to meaningfully improve economics on future projects.

Long-Term: A Goal to Deliver Power and/or Heat to 10 Million Homes over the Next Decade We believe the appetite for geothermal today is high: we understand Eavor alone currently has hundreds of prospective projects worth over $25 bn in capital cost, which would add reliable baseload power and help contribute to power producers’ desire to achieve energy independence.

Eavor has set a goal to build enough capacity to deliver heat and/or power to roughly 10 million homes (we estimate roughly 10,000 MW of capacity) over the next decade. To achieve this goal, management estimates roughly 2,500 Eavor-Loops (implying roughly 4 MW/loop) will need to be built, requiring roughly $100 bn in investment (roughly $40 mn/loop, or roughly $10 mn/MW of capacity). We understand Eavor currently has hundreds of prospective projects worth over $25 bn in capital cost, including equity and/or licensing agreements with third parties, shovel-ready projects, and royalty projects. We believe success and learnings in Eavor’s ongoing Germany-based Eavor-Loop could provide a catalyst to accelerate additional international project starts.

Appendices B and C here.

The next articles in this series will drill down further Opportunities for the Oil and Gas Service Sector, Economic and Strategic Factors, and the Regional Landscape for Geothermal Development.

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CHOA BRONZE SPONSORS

SERVICING GEOTHERMAL: Can O&G Contractors Benefit?

BY TIM MONACHELLO AND PATRICK TANG ATB CAPITAL MARKETS Geothermal could be a major opportunity for the oil and gas service sector.

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The potential size of the geothermal opportunity for O&G contractors How this opportunity varies in size with different future scenarios How existing wells might be re-purposed for geothermal This article is the fifth in a series on how Geothermal Energy can impact the energy industry and net-zero transition.

GEOTHERMAL COULD BE A MAJOR OPPORTUNITY FOR THE OIL AND GAS SERVICE SECTOR Geothermal has historically been a relatively immaterial source of demand for energy services companies given commercial limitations have constrained the development of geothermal projects outside of preferred hydrothermal resource areas. That said, innovations, along with carbon pricing mechanisms, provide reason to believe geothermal could become a meaningful opportunity for energy services companies over the medium to long term. “… innovations, along with carbon pricing mechanisms, provide reason to believe geothermal could become a meaningful opportunity for energy services companies over the medium to long term.”

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In this section, we highlight both the strategic investments being made across the energy services landscape in geothermal and the direct exposures of certain players. Ultimately, we believe North American contract drillers and other supplementary drilling services providers are likely to benefit from increased geothermal drilling activity, which could backfill any declines in oil and gas drilling over the coming decades. In addition, several international service contractor heavyweights in the upstream space have decades of experience in conventional geothermal developments.

Based on a progressive growth trajectory through 2050, we estimate geothermal developments could ultimately drive demand for an incremental 125-130 rigs globally by 2041-2050, including roughly 50 rigs in the US, representing roughly a $9 bn-$16 bn annual global upstream well development opportunity excluding expenditures on surface facilities and infrastructure.

Strategic Investments and Direct Exposure to Geothermal by Energy Services Companies Over recent years, energy services companies have increasingly announced strategic investments in geothermal companies. Fundamentally, we believe the development of geothermal has benefitted significantly from the expertise and technologies developed in the energy services industry. This expertise is now being leveraged more directly to solve longstanding problems and improve geothermal development technologies to improve economics and ultimately bring geothermal systems to the masses. See Figure 23 for an overview of energy services companies with exposure to geothermal development – either directly or through strategic investment.

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“… expertise and technologies developed in the energy services industry … [are] now being leveraged more directly to solve longstanding problems and improve geothermal development technologies to improve economics and ultimately bring geothermal systems to the masses.”

Energy Services Companies with Exposure to Geothermal

Figure 23 – Energy Services Companies with Exposure to Geothermal (Priced August 8, 2022) Source: Company Reports, FactSet, ATB Capital Markets Inc.

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Geothermal Likely to be a Growing Source of Rig Demand

Our analysis suggests that the global build-out of geothermal power generation could be a significant opportunity for upstream energy services companies, particularly for drilling contractors and other drilling-oriented service lines.

We present three scenarios for the pace of global geothermal power generation growth through 2050. The first scenario is based on the IEA’s prescribed path of geothermal electric generation capacity within its Net Zero by 2050 report (left panel of Figure 24), which forecasts geothermal to grow to 126 GW by 2050, the second is based on a more progressive trajectory to 126 GW global capacity in 2050, which we believe is more realistic given the pace of innovation and geothermal activity today (middle panel of Figure 24), and the third is a more aspirational scenario where geothermal innovations and/or incentives drive geothermal to represent 1.0% of the IEA’s estimate for global electricity generation capacity by 2050 (roughly 33 TW total, geothermal representing roughly 334 GW). See Appendix D for a more detailed overview of our scenario analysis and assumptions.

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Global Upstream Geothermal Activity and Market Size Scenarios

Figure 24 – Global Upstream Geothermal Activity and Market Size Scenarios Source: International Energy Agency, ATB Capital Markets Inc.

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Scenario 1: IEA Net Zero by 2050 Scenario – Key Assumptions and Conclusions

Steep Near-Term Capacity Growth: Our first scenario, which is based on the IEA’s Net Zero by 2050 progression, suggests a ramp in global geothermal electrical generation capacity from roughly 16 GW in 2022 to 52 GW by 2030, 98 GW by 2040, and 126 GW by 2050. This scenario assumes US geothermal capacity will maintain roughly a 30% global share.

Global Market Size Would Peak in 2022-2030 Period: This scenario suggests that the global geothermal upstream development market would peak in the 20222030 period at roughly $7 bn- $13 bn/year excluding expenditures for facilities and related infrastructure.

Upstream Activity to Peak Near 100 rigs/year in 2022-2030 Period: This scenario suggests that global upstream geothermal rig demand would peak in the 2022-2030 period, with total average annual geothermal rig demand of roughly 100 rigs, declining in future decades to only roughly 40 rigs in the 2040-2050 period as incremental capacity additions decline and development efficiencies are implemented.

Near-Term Expansion is Unlikely, in Our View: This scenario suggests the highest level of near-term geothermal activity, which we believe is largely implausible given the current levels of geothermal activity and given our view of geothermal projects likely to be developed over the foreseeable future (2-5 years). That said, we believe the IEA’s 2050 exit rate of roughly 126 GW of geothermal electrical capacity is highly achievable given progression of technologies being developed today.

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Scenario 2: ATB Net Zero by 2050 Progressive Growth – Key Assumptions and Conclusions Progressive Capacity Growth to IEA’s Net Zero by 2050 Exit Capacity: Our second scenario is based on our view that the IEA-prescribed ramp in global geothermal capacity is too fast to be plausible. As such, we maintain the exit 2050 capacity level for geothermal electrical generation, both globally and for the US as prescribed by the IEA, but we adopt a more back-end loaded capacity growth profile. For context, we assume global capacity could grow from roughly 16 GW in 2022 to roughly 36 GW by 2030, to roughly 77 GW by 2040, and to 126 GW by 2050. We also incorporate the DOE’s GeoVision projection for US geothermal capacity to grow to roughly 60 GW by 2050. Overall, this trajectory dictates an accelerating pace of upstream activity through 2040 as next generation geothermal technologies are commercialized and a relatively flat pace of development from the 2031-2040 to 2041-2050 periods. For context, we believe there are roughly 150-250 geothermal wells likely to be drilled globally in 2022, representing demand for just 10-20 rigs globally, while our progressive growth scenario suggest this could grow to roughly 450 wells by 2025 and to roughly 1,600 wells by 2030.

Global Upstream Market Size to Grow to Roughly $5 bn-$10 bn by 2031-2050 Period: This scenario suggests that global geothermal upstream development would grow from roughly a $3.9 bn-$7.0 bn per year market in the 2022-2030 period to a $5.4 bn-$10.0 bn per year market in the 2031-2040 period and holding roughly flat from that level in the 2041-2050 period. This scenario suggests that the US upstream geothermal market size could increase from roughly $1.2 bn-$2.1 bn per year in the 2022-2030 period to $1.6 bn-$2.9 bn per year in the 2031-2040 period and $4.1 bn-$7.4 bn per year in the 2041-2050 period.

Upstream Rig Demand to Increase to Roughly 70-75 Rigs per Year in 2031-2050 Period: Our progressive growth scenario suggests that upstream global geothermal rig demand could increase from roughly 53 rigs on average in the 2022-2030 period to 74 rigs in the 2031-2040 period and staying largely flat at that level in the 2041-2050 period. For the US, this scenario suggests average annual rig demand for geothermal would grow from 16 rigs in the 2022-2030 to 22 in the 2031- 2040 period and 56 in the 2041-2050 period.

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Scenario 3: ATB 1% of Global Electricity Capacity by 2050 – Key Assumptions and Conclusions Break-Through Innovations Could Propel Geothermal Capacity Expansion: Our third scenario is based on geothermal breakthrough innovations driving a significant increase in global geothermal electrical capacity share from roughly 0.2% of in 2022 to roughly 0.3% by 2030, roughly 0.6% by 2040, and 1.0% of the IEA’s total projected global electrical power generating capacity in 2050. Specifically, this progression reflects an increase in global geothermal electrical capacity from roughly 16 GW in 2022 to roughly 334 GW by 2050. We believe the commercial development of deep closed-loop systems and superhot rock geothermal are enough to drive this level of adoption given their potential to make geothermal both economically competitive with other renewable resources and increase access to geothermal energy around the globe. In this scenario, geothermal may become a choice renewable source of energy given that it is a baseload source of energy, low emission, and offers longer useful lives versus other renewables.

Growth to 1.0% of Global Electric Generation Capacity Could Grow Upstream Geothermal Market Opportunity to $18 bn-$32 bn by 2031-2050 Period: This scenario suggests that global geothermal upstream development could grow from roughly a $5.5 bn-$10.0 bn per year market in the 2022-2030 period to an $18 bn-$32 bn per year market in the 2031-2040 period and holding roughly flat from that level in the 2041-2050 period. This scenario suggests that the US upstream geothermal market size could increase from roughly $1.6 bn-$3.0 bn per year market in the 2022-2030 period to a $5.4 bn-$9.6 bn/year market in the 20312040 period, and holding roughly flat from that level in the 2041-2050 period.

Upstream Rig Demand to Increase to Roughly 240-250 Rigs per Year in 20312050 Period: To get to 1.0% of global energy capacity would suggest that upstream global geothermal rig demand could increase from roughly 76 rigs on average in the 2022-2030 period to 243 rigs in the 2031-2040 period and staying largely flat at that level in the 2041-2050 period. For the US, this scenario suggests average annual rig demand for geothermal would grow from 23 rigs in the 2022-2030 to 7075 in the 2031-2050 period. Our analysis assumes a 30% US market share of global geothermal capacity.

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Potential to Convert Oil & Gas Wells to Geothermal While often contemplated, the use of oil and gas wells for geothermal source of heat has not been widely explored. The challenges cited with the conversion of existing oil and gas wells into geothermal producing wells are numerous, though the primary challenges are 1) the depth of most oil and gas wells is too shallow to produce high enough temperatures for effective geothermal energy production and 2) most oil and gas wells are drilled with wellbore diameters too narrow for conventional and commercial geothermal flow rates.

Nevertheless, companies are looking at ways to both harness geothermal energy from producing oil and gas wells and convert end-of-life oil and gas wells to geothermal wells. FutEra Power, a subsidiary of Razor Energy, is one example of a company leveraging existing oil and gas wells (see previous article for a detailed overview of its project). GeoGen Technologies is an example of a company developing technologies to commercially convert end-of-life oil and gas wells to geothermal power generation.

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CASE STUDY: GeoGen Technologies Inc. – New Life for End-of-Life O&G Assets GeoGen Technologies Inc. (not to be confused with GeoGenCo), is a Calgary, Alberta- based start-up attempting to redefine the potential for geothermal energy production from end-of-life oil and gas assets by rethinking the method of power generation.

To address the challenges related to converting oil and gas wells to geothermal wells, GeoGen has designed a possible solution: downhole mechanical energy generation in a closed-loop system contained within a single wellbore (see Figure 25). GeoGen’s patent-pending design would utilize existing horizontal oil and gas wells at the end of their productive lives, which would otherwise be candidates for abandonment. These liability wells would be sealed from the formation, and tubing would be suspended into the well bore to form a closedloop system in which cooler geothermal fluid would flow down the suspended tubing to the horizontal section where it would be heated and then would flow back up the sides of the wellbore to surface. The flow of the geothermal fluid through the system would be driven by a thermosiphon effect, but rather than generating power at surface using heat-to-power generation equipment, GeoGen’s design generates power using a downhole turbine generator. This type of mechanical power generation could enable lower temperature resources to be economic for geothermal power generation given that binary cycle power generation is not efficient at lower temperatures. GeoGen believes its system could generate roughly 100 kW of electricity per well based on bottom hole temperatures as low as 80°C. GeoGen’s approach is unique in that it utilizes lower temperature resources typical of oil and gas formations, and projects are relatively small and shortcycle, which lends itself to scale efficiencies if the technology could be proven viable on a wide scale. By reusing end-of-life wells, GeoGen’s design avoids drilling costs and significant resource risk relative to other geothermal options.

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GeoGen envisions that a conversion would take a matter of months from conception to power generation, and it is targeting roughly $0.7 mn-$1.0 mn per conversion over time. GeoGen claims over 50,000 wells in North America are conversion candidates. A GeoGen conversion would significantly defer abandonment costs and, dependent on the regulatory regime, would potentially even defer abandonment liabilities indefinitely.

GeoGen estimates that its geothermal conversion without a liability deferral, assuming $120/MWh power price and $80/ton carbon, could offer a roughly 12% IRR; assuming a deferral of $150k abandonment liabilities, the IRR on conversion could increase above 15%.

We understand GeoGen has agreed to develop a test well that is likely to be commissioned in 2022 or 2023 with a Canadian oil and gas producer, and this test well could meaningfully change the perception of geothermal conversions from end-of-life oil and gas assets. We note that the availability of horizontal wells at end of life is currently limited, but it should increase over time as shale wells mature.

Appendix D here.

The next articles in this series will drill down further into Economic and Strategic Factors, and, finally, the Regional Landscape for Geothermal Development.

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