Copy of Working file March 2023 Journal

THE GREAT CANADIAN CCUS DILEMMA: Is 2023 a Make or Break Year?

Interview with Jared Dziuba, BMO Capital Markets Part 1 of 2

CHOA JOURNAL - APRIL 2023 I 10

How is Canada losing ground from a policy perspective?

One of the things I see as a problem in Canada with CO2 technology, in particular CO2 EOR, is that it is excluded from a lot of financial incentives, for it is important to understand the political backdrop in Canada, which we think has hindered effective policy formation. We describe the dilemma as a game of political chicken. There are three main stakeholders – the federal/provincial governments and industry – which have a common ambition of net zero emissions reduction and a mutual belief that the energy industry plays a key role; however, each has vastly different agendas and perspectives on how to achieve the goal. Canada’s Federal government is highly sensitive to optics of supporting industry and has a fairly punitive stance on policy solutions, while Alberta and Saskatchewan hold a strong protectionist stance, and industry is simply not going to invest without better visibility of project returns to avoid diluting shareholders. Taken together, this has created a more contentious government-industry dynamic than in other competing regions like the U.S., in our view. Currently industry is at a bit of a standstill from an economic decisionmaking perspective, with each party waiting on the others to make the next move.

Policy wise, Canada has so far introduced a large and complicated mix of adjacent policies to try and promote decarbonization, most of which are punitive in nature (for example the cost avoidance ‘incentive’ of Alberta’s TIER carbon pricing system) as opposed to supportive, and none of which are particularly effective on their own. This is unlike competing jurisdictions like the U.S. where policy measures are relatively streamlined and backed at the federal level. The main ‘carrot’ that has been offered in Canada – the federal Investment Tax Credit (ITC) – fell well short of industry’s requirements and the ‘bankable’ incentive being offered in the U.S. When we distill it down, the Canadian ITC provides <20% total cost coverage (capex and operating) for CCUS projects completed by 2030.

"Currently industry is at a bit of a standstill from an economic decision-making perspective, with each party waiting on the others to make the next move. "

This is well below what is offered in competing jurisdictions like the U.S. where as much as 2/3rds of total project costs may be effectively covered. What is more the ITC would cover merely 10% of costs for net zero scale (2050E) projects like the oil sands Pathways, underscoring that the policy measures are too short sighted and not aligned with a net zero trajectory. Finally, the complexity and lingering uncertainty associated with Canada’s framework is widely considered an administrative burden and deterrent to investment resulting in monetary and intellectual capital leakage toward opportunities elsewhere.

What factors drive CCUS economics, and what is needed to generate investable returns?

The economics of CCUS are complex, with numerous key cost and investment considerations, and this is particularly true of long-term net zero scale developments. Most pure CCUS applications are non-revenue generating projects that rely on the value of carbon credits recognized from the capture of CO2 (the sale of excess credits in secondary offset markets) and/or on policy incentives to cover capital and ongoing operating costs. The value of carbon credits in turn is contingent on an established carbon credit market and proper balance between supply and demand.

It is important to understand that industrial emitters, most of which are publicly held companies, have a duty to protect shareholder capital and a goal to enhance returns. From this perspective, the investment question is not whether industry can technically fund CCUS development, but whether projects generate acceptable returns. This seems to be largely ignored or minimized in policy debate, but is important from our perspective because without competitive policy, Canada risks capital and carbon leakage to other regions, not just in terms of project investment but intellectual capital, skilled labour, equipment, technology development.

The reality is that most large scale industrial CCUS projects in Canada are simply uneconomic without significant fiscal support, which risks diluting shareholders. For example, we estimate that the oil sands Pathways project may generate a pre-tax IRR of less than 4% without incentives, even if we assume a lofty carbon price of $170/T is applied to the value of performance credits under the Alberta TIER system (per the federal greenhouse gas price escalation plan).

"... we estimate that the oil sands Pathways project may generate a pre-tax IRR of less than 4% without incentives, even if we assume a lofty carbon price of $170/T" At lower carbon prices including the current price of $65/T, returns are negative or non-meaningful. This is simply unacceptable to emitters and their shareholders when you consider cost of capital breakevens in range of 8-12%.

In addition, sustainability pressures are ironically driving corporate hurdle rates toward 20-year highs of >30% given unprecedented underinvestment in global upstream supply and resulting strength in commodity prices. This is not to say that emitters will require corporate hurdle level returns for decarbonization investment, however competition for capital is very real including the option of returning cash to shareholders, so it certainly complicates decisions at a boardroom level.

What is the outlook for technology costs? How does net zero scope and the ‘emissions complexity curve’ influence long-term costs and investment decisions?

To add further complexity to the CCUS returns equation, there are several important long-term cost considerations that factor into the economic evaluation of emitters. I would emphasize here that the economic decision in net zero scale CCS is not simply based on costs and returns of the next phase of capacity, or an individual project. Rather, emitters have to consider the full long-term abatement cost curve associated with these projects. This is unique relative to typical economic evaluations for primary business investments. In the end, we believe that it is difficult from the perspective of emitters to have faith in meaningful cost reductions for Canadian CCUS for several reasons, especially for long-term, net zero scale projects and hub developments.

Key to our thinking is what we call the emissions “complexity curve.” While we have a good understanding of the costs and operating challenges associated with existing CCS applications in natural gas processing, hydrogen production, biofuels etc, the vast majority of future emissions sources will be increasingly difficult and costly to capture. There are many competing forces at work, but we believe generally more than put upward risk on costs over time. These include factors like lower CO2 concentration levels from post-combustion gas emissions sources, sources that contain more contaminants, smaller scale emissions or those with unique infrastructure requirement and, finally, emissions sources that may not be capturable with traditional CCS technology.

It is estimated that more than 60% of the market opportunity for carbon capture is in post-combustion emissions, with very low CO2 concentrations and often more contaminants than existing CCUS applications. It has been well established that capture costs for lower concentration sources are higher taking into account additional processing for contaminants, higher solvent regeneration and potentially higher maintenance downtime.

"... we expect that inflation could be a meaningful offset to technology savings."

Another factor related to the complexity curve are logistics of gathering and transporting CO2 for net zero hub developments. Many hubs like Pathways will require long-distance pipeline and/or multi-source gathering infrastructure to transport and sequester captured CO2. Generally, transport costs increase with distance but decrease with scale, which makes the investment decision in infrastructure not only a significant one in terms of dollars, but also a very longterm commitment. In these cases emitters need to understand the costs of capture for all future emissions sources that will fill the pipeline. This is particularly true of the Pathways project which may ultimately need to transport more than 40 MT/year of CO2 a distance of over 400 km to reach adequate pore space. A related factor is the cost of gathering from several smaller sources like in situ oil sands operations, or hub models that draw on multiple industrial facilities.

It is a common assumption that the cost of carbon capture will decline over time with advancements in technology. Indeed, there has been some anecdotal evidence based on pilot work of emerging technologies that the costs of next generation capture could come down. Pre-pandemic estimates from the International Energy Agency (IEA) pointed to possible cost reductions of 2030% on average, and as much as 50% for certain applications like postcombustion power generation by 2030.That said, many of these technologies are still in demonstration stage and need to be proven in a real-world setting at commercial scale. Importantly, we expect that inflation could be a meaningful offset to technology savings. We are seeing substantial inflation pressure within the energy industry due to scarcity of skilled workers and equipment. Service cost inflation in North America measured 20-30% in 2022 alone, and we expect that these pressures could persist, particularly with a widescale decarbonization “boom.” We have certainly seen this play out in the Alberta energy market before with rapid development of oil sands capacity leading up to 2008 contributing to substantial local industry inflation and cost overruns.

How does the game of chicken between government and emitters end?

At this point it appears that the federal government is waiting on western Provinces to show their hand in contributing support to CCUS projects before making any additional commitments, as well as finalizing terms associated with its proposed ITC and cap on oil & gas industry emissions. Unfortunately, we also sense that the Alberta government is in a relatively early stage of evaluating its options and understanding industry’s needs. So while some proposals have been tentatively tabled – such as a possible expansion of the Alberta Petrochemical Incentive Program in the province’s recent budget – we anticipate that the final word will not be publicized until after the upcoming provincial election in late May. Inherent in this is further risk and uncertainty stemming from a possible change in leadership. In our view a turnover in party leadership could have more negative consequences for industry in terms of financial incentives for decarbonization.

Jared Dziuba, CFA, Analyst BMO Capital Markets Jared Dziuba, CFA, has over 15 years experience as an equity research analyst with BMO Capital Markets, covering a full spectrum of subsectors within the global oil & gas industry. In his current role, Jared oversees the execution of industry thematic research, providing insight to BMO’s institutional investor clients on emerging trends that influence the long-term investment prospects of the energy business.

Interviewed in March 2023 by Owen Henshaw, Innovation Engineer at Cenovus and Board member of the Canadian Heavy Oil Association.