Natural Gas is the New Coal: Will Albertans be Stranded with Billions in Fossil Fuel Debt?
- Larry Peters
- Nov 20
- 10 min read
The Carbon Double-Down: Alberta’s Centralized Bet on Inertia
Alberta’s provincial government is doubling down on natural gas, viewing it not as a bridge fuel, but as a permanent foundation for long-term economic growth. This strategy, codified in the official Natural Gas Vision and Strategy, aims to reinvigorate the sector across five key pillars, including petrochemical manufacturing, hydrogen, Liquefied Natural Gas (LNG), and industrial demand growth.1 The explicit goal is to make Alberta a global top 10 producer of petrochemicals, backed by massive capital attraction initiatives such as the Alberta Petrochemicals Incentive Program (APIP).1
This investment push is rooted in an abundance narrative that assumes perpetual growth in energy consumption. This worldview, shared by the provincial leadership and major international cartels, posits that the global energy transition will involve "diversification, not displacement".3 In this model, wind and solar are simply absorbed into a skyrocketing demand curve, rather than displacing hydrocarbons in the 21st century.3 Alberta Energy Minister Brian Jean reinforced this perspective by highlighting the province's vast untapped reserves, stating, "We're Texas-sized as far as gas goes; we've got some big numbers".4
The Scale of the Centralized Investment Risk
This philosophical commitment to long-term hydrocarbon dominance forms the basis for massive, centralized infrastructure development, committing Alberta to immense, fixed-cost liabilities. New natural gas combined cycle plants (CCGT) require substantial upfront capital. For example, a single expansion initiative at the Genesee Generating Station, touted as Canada’s most efficient natural gas combined cycle plant, represents a $1.6 billion commitment for 512 megawatts (MW) of new capacity.5
Industry analysis confirms that the cost of new CCGT construction is often exceeding $2,000 per kilowatt ($2,000/kW).6
These centralized assets are not short-term investments; they are designed for multi-decade recovery. Infrastructure like gas pipelines and major power plants are typically amortized over 40 to 50 years.7 This 50-year debt structure is profoundly misaligned with Canada’s commitment to achieving net-zero emissions by 2050. Building multi-billion-dollar, centralized assets today, with an expectation of five decades of reliable revenue, represents an investment in market inertia at the precise moment the system requires maximum agility.
The Alberta Electric System Operator (AESO) acknowledges the unprecedented complexity of this transition. AESO Board Chair Karl Johannson noted that the system is at a "critical time" due to significant energy transition activities and the move toward a new market design.8
Furthermore, AESO President and CEO Aaron Engen stated that the province’s Restructured Energy Market (REM) is necessary to manage a "more complex and dynamic system" driven by new types of supply and demand.9
This creates a structural contradiction: while the system operator is actively redesigning the grid to accommodate rapid flexibility and change, provincial policy continues to underwrite massive, long-life, fixed-location gas infrastructure, assets inherently ill-suited for the dynamic, highly competitive energy market that is already emerging.
The Stranded Asset Time Bomb: 50 Years of Debt in a Decade of Transition
The danger of this centralized commitment is the risk of generating massive stranded assets. Stranded costs are defined as the remaining unrecovered capital costs of physical assets that become uneconomic or significantly underutilized before their full amortization period is complete.7 If gas infrastructure built in the mid-2020s is financed for 40 to 50 years, full cost recovery will not occur until at least 2065, placing these assets well beyond the federally mandated timeline for decarbonization.7
Defining the Stranded Cost Mechanism
The financial risk is driven primarily by two converging forces: regulatory tightening and economic displacement. On the regulatory front, there is significant pressure, including recommendations from organizations like the Pembina Institute, to strengthen provincial carbon policies for electricity, such as reducing the benchmark or removing it entirely to zero tonnes per gigawatt hour (0 t/GWh) by 2035.10
Regulatory actions, such as increased carbon pricing, would immediately raise the operational costs of unabated gas plants, forcing them into premature retirement or expensive retrofitting.
Economically, the threat comes from the rapid decline in the Levelized Cost of Energy (LCOE) for renewable sources globally.11 New gas plants costing over $2,000/kW 6 must compete against increasingly modular and low-marginal-cost wind, solar, and storage projects. The AESO’s 2024 Long-Term Outlook is being developed amidst "substantial uncertainty" specifically driven by policy changes and technological innovation, underlining the reality that the profitability projections required to justify billion-dollar gas investments are now fundamentally unstable.12
The Consumer Debt Exposure
When centralized gas assets become obsolete or underutilized, a highly probable scenario within a decade, it becomes uneconomic to recover the outstanding fixed costs from a declining base of remaining customers.7 The critical policy decision facing Alberta is who absorbs the massive debt burden: utility ratepayers, utility shareholders, or the government itself.7
The sheer scale of the investment means that if multiple CCGT projects, each costing over a billion dollars 5, fail to recover their capital, the transferred liability to ratepayers could quickly swell into the tens of billions of dollars. This financial dynamic creates a utility "death spiral": as consumers with the financial capacity transition to decentralized, lower-cost energy options, the remaining pool of ratepayers, often those who can least afford it, is left to shoulder the entire fixed cost of the underutilized infrastructure.
This mandatory subsidization of legacy infrastructure results in dramatically higher per-unit utility charges for the remaining centralized customers, translating the financial failure of long-term planning into a structural, multi-generational household energy debt.
The AESO’s effort to modernize the market through the Restructured Energy Market (REM) includes tools like Locational Marginal Pricing (LMP).9
While intended to attract investment and provide stronger signals for where to build, the adoption of such advanced pricing mechanisms could actually accelerate the stranding of currently planned gas plants. If new centralized assets are built based on an outdated assumption of traditional baseload demand, the introduction of LMP could quickly reveal their suboptimal dispatch characteristics and geographic disadvantage against strategically located renewables and storage, economically penalizing them faster than traditional market forces would allow.
The Decentralized Disruptor: The Big Rock Solar Case Study
While the government invests in centralized fossil fuel inertia, the market is already building the architecture of the decentralized future. The Big Rock Solar Project exemplifies this transformation, moving beyond single-source generation into integrated, flexible supply. The project consists of a 90-megawatt solar power plant paired with a 40-megawatt battery energy storage system.13 This integrated system provides both renewable generation and the stability required to manage intermittency, demonstrating a fully viable utility-scale solution.14
The Solar Club Model: Bypassing Centralized Debt
The financial disruption inherent in this shift is perhaps best illustrated by the Big Rock Solar Club model.
The critical feature of this model is the highly attractive export rate offered to members. The club provides a "HI Rate" of 33.00 cents per kilowatt hour (¢/kWh) for members exporting excess electricity back to the grid.16 This rate is exceptionally high compared to standard low-load consumption rates (which can be as low as 6.74 ¢/kWh in some programs).16 This high export incentive fundamentally changes the economics of energy consumption, powerfully encouraging residential and commercial consumers to invest in rooftop solar, behind-the-meter generation, and local storage.
Market Transformation and Load Erosion
The proliferation of these decentralized assets directly undermines the long-term capacity factors and profitability of new CCGT plants. Centralized gas plants are built to provide consistent, high-capacity baseload power, often predicated on stable industrial demand which constitutes over 60 percent of Alberta’s historical load.17
However, when thousands of homes and businesses become "prosumers" (producers and consumers), the load profile of the province becomes increasingly fragmented and difficult to predict. Decentralized generation shaves off peak daytime demand, injecting power into the grid precisely when centralized baseload generation needs to recover its operating costs.
This results in severe compression of the profit window for centralized gas plants. Instead of operating profitably as baseload providers, they are increasingly forced into less profitable, more volatile "peaking" roles, which reduces their capacity factors and ultimately accelerates the capital erosion of billion-dollar investments.5
The AESO has explicitly stated that the new REM design is driven by the need to manage a more dynamic and complex electricity grid resulting from these technological changes.9 By continuing to invest in massive, fixed baseload gas capacity, the government is betting against the complexity and dynamism that its own system operator is actively planning to facilitate.
The Bill Comes Due: Who Pays for Yesterday’s Technology?
The risk of stranded capital is dangerously compounded by a systemic failure in managing the subsequent decommissioning liabilities. This issue reveals a striking regulatory double standard in Alberta.
The Regulatory Double Standard for Decommissioning
In response to public concerns regarding land reclamation and legacy costs, the Government of Alberta has established strict, mandatory financial security requirements for new wind and solar projects, effective January 1, 2025.18
Under these rules, operators must provide government-held security, a percentage of the estimated reclamation cost, starting at 30 percent at registration and escalating to 60 percent by year 15 of operation.18 This security is specifically designed to transfer the financial default risk away from the public and ensure funds are available for restoration should the operator fail to meet their end-of-life obligations.19
In stark contrast, large thermal power plants, including the new natural gas facilities, typically fall under the broader, older liability management framework overseen by the Alberta Energy Regulator (AER).19 This framework, designed holistically for the entire oil and gas sector, lacks the specific, mandatory, escalating, percentage-based financial security requirements now applied to renewables.
The Orphan Well Association Parallel: The Ultimate Warning
The failure of Alberta’s legacy liability system to ensure companies maintain sufficient financial capacity for site closure is best demonstrated by the Orphan Well Association (OWA). The OWA is a nonprofit organization responsible for the abandonment and reclamation of wells and facilities when companies go bankrupt.21 The OWA is funded by an annual levy paid by the entire energy industry, a cost that is inevitably passed down to consumers.22
The burden on the OWA is growing. The annual levy has been increased, for instance, to $135 million 22, and cleanup timelines are continuously extended, demonstrating that the system relies on public backstopping instead of guaranteed, pre-funded security.22 This is the central policy error that is now being repeated.
Financial Risk Synthesis: The Power Plant Orphan
The absence of mandatory, upfront, dedicated financial security for multi-billion-dollar gas assets leave Albertans dangerously exposed to an "Orphan Power Plant" crisis.
If a utility operating a $1.6 billion CCGT 5 faces insolvency years before its 50-year amortization period is complete, the extensive industrial cleanup obligations, which are complex and costly, will likely fall outside of pre-funded accounts. Given that the existing generalized liability management framework produced the Orphan Well crisis, building new high-value, long-life assets under the same deficient system signals a failure to learn from past financial mistakes.
By demanding fiscal prudence and guaranteed security only from emerging, low-risk solar and wind projects, while exempting the multi-billion-dollar, high-risk gas projects from the same standard, the government is deliberately socializing the greatest potential long-term decommissioning risk onto Alberta ratepayers.
The asymmetry in risk exposure is clear:
Table: Comparison of Decommissioning Liability Security in Alberta
Asset Class | Amortization Period | Mandatory Upfront Financial Security | Public/Ratepayer Default Exposure |
New Natural Gas Power Plants | 40–50 years 7 | Not specifically required on the same percentage basis as renewables | High risk. Failure leads to potential "Orphan Power Plant" cleanup funded by consumer levies or taxes.21 |
New Wind and Solar Projects | Shorter, asset specific | Yes, mandatory security required (30% up to 60% by Year 15) 18 | Low. Security funds are available to the landowner/regulator upon operator default.19 |
Conclusion: A Clear Signal Ignored
Alberta stands at a critical juncture where technological reality is rapidly outpacing entrenched policy. The government’s strategy of doubling down on centralized natural gas generation is a costly gamble on a 50-year future that the market is already rejecting.
The signal from the ground is unambiguous: the future of energy is decentralized, flexible, and rapidly decreasing in cost. Projects like the Big Rock Solar Club, which offers a 33.00 ¢/kWh export rate 16 to incentivize behind-the-meter generation, illustrate how quickly consumer-driven markets can erode the baseload demand that centralized gas plants rely upon for profitability.
This technological momentum guarantees that new, multi-billion-dollar gas assets will face reduced capacity factors and premature obsolescence, becoming stranded assets well before their long-term debt is repaid.
Coupling this financial risk with a deficient liability management framework, one that mandates security for low-risk solar but exempts high-cost gas, ensures that the inevitable debt will be transferred to Albertan ratepayers and taxpayers.
Unless the provincial government acknowledges the accelerating energy transition and immediately mandates stringent, pre-funded financial security for all new centralized gas plants, Albertans face the prospect of inheriting billions of dollars in fossil fuel debt, making natural gas the expensive, stranded legacy of the next generation.
Frequently Asked Questions (FAQ)
What is a stranded asset in the context of power generation?
A stranded asset is infrastructure, such as a power plant or pipeline, that loses its economic value or regulatory viability well before the end of its intended operating life, meaning the original capital investment cannot be fully recovered.7
Why are new natural gas plants considered a financial risk in Alberta?
New gas plants are designed to operate for 40 to 50 years to recover their multi-billion dollar capital costs.5 This timeline extends past net-zero commitments, exposing them to high risks from accelerating decarbonization policies and displacement by cheaper, faster-to-deploy renewable energy coupled with battery storage.23
How is the Big Rock Solar Club disrupting the energy market?
The Solar Club facilitates decentralized power generation, offering highly competitive export rates (e.g., 33.00 ¢/kWh) for members selling excess solar back to the grid.16 This incentivizes residential and commercial adoption of solar and storage, thereby eroding the stable, predictable baseload demand that centralized gas plants rely on.
Who pays for the cost of decommissioning a power plant?
Legally, the owner or operator is required to decommission and reclaim the site.19 However, if the operating company goes bankrupt, the liability falls to taxpayers or is funded through industry levies, as demonstrated by the Orphan Well Association.21
Is there a regulatory difference in liability requirements between solar and natural gas plants?
Yes. New solar and wind projects, effective 2025, face mandatory, upfront financial security requirements that escalate over time to cover reclamation costs.18 Comparable, stringent security requirements are not mandated for large natural gas thermal plants, leaving the public exposed to greater default risk.19
What is the "Oil and Gas Forever" worldview adopted by the government?
This policy view, shared by major oil producers, assumes that renewable energy will not displace hydrocarbons but will merely be absorbed into continually increasing global energy demand, justifying continued large-scale investment in fossil fuel infrastructure.3
What role does the AESO’s Restructured Energy Market (REM) play in this transition?
The REM is designed to create a more dynamic market with enhanced operational services, necessary to manage the complex grid resulting from intermittent renewables and changing demand patterns.9 This shift towards complexity increases the market vulnerability of rigid, centralized assets.
What is the scale of the investment risk in a single new gas facility?
A single new combined cycle gas expansion, such as the one at the Genesee Generating Station, represents an investment of $1.6 billion for 512 MW of capacity, demonstrating the concentrated financial exposure inherent in the centralized strategy.5
Bibliography
14 url: https://www.aeso.ca/grid/transmission-projects/need-for-big-rock-solar-battery-project-connection/
21 url: https://www.aer.ca/understanding-resource-development/project-life-cycle/suspension-and-abandonment
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