Will Canada play energy card in a U.S.-China world?

By The Globe And Mail


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In Washington, Barack ObamaÂ’s lavish summit with Hu Jintao marks ChinaÂ’s arrival as a global force. In Canada, it raises a new wrinkle in the old struggle to attract superpower attention. A big question now is whether Canada will try to use energy and pipelines to expand its influence.

The talk from both presidents about the need to avoid rivalry underlined the critical unanswered question about what kind of superpower China will be, and how a new world order dominated by a U.S.-China “G2” will work.

That matters enormously to Canada, but so do narrow interests of getting ahead in a two-superpower world. Canadian energy attracts keen interest in both Washington and Beijing. Both are obsessed with energy security.

“At one level, we’re a tiny sideshow to the big game,” said Paul Evans, a University of British Columbia expert on Asia. “Where Canada fits in is the issue of energy, and Chinese investment in North America.”

A number of Asia-watchers here have been mounting calls to fast-track plans to build oil-and-gas pipelines to the West Coast, thereby reaching markets in Asia and creating a “strategic” relationship with China that would improve trade.

China already has an interest. Recently, it was revealed that state-controlled oil company Sinopec has an unspecified stake in Enbridge’s much-contested plans to build a Northern Gateway Pipeline to the West Coast. China Investment Corp., the giant state sovereign-wealth fund, is planning to open its first North American office in Toronto –- widely read as a signal of interest in buying Canadian resources.

Chinese companies have been tiptoeing into Canadian oil investments one step at a time, testing whether the moves raise alarm bells, and whether they’ll be approved by Ottawa. It’s financial investment for now – Alberta oil can be piped only to the United States -– but many believe it’s part of a longer-term strategy to ship oil to China to ensure supply for the fast-rising demand of Chinese industry.

Chinese interest in CanadaÂ’s oil and gas isnÂ’t always viewed with sanguine eyes in Washington. When the first substantial Chinese investment in the oil sands, PetroChinaÂ’s 2009 deal to buy two projects from Athabasca Oil Sands Corp., was being reviewed by the Canadian government, U.S. officials raised qualms, according to individuals involved.

The U.S. concern for energy security, though it clashes with environmental opposition in Congress and parts of the Obama administration, makes Canadian energy a strategic interest – a way to ensure supply for the country, including its defence establishment, in any crisis.

The fact that Canada is a rare friendly, reliable and nearby supplier of energy is “our trump card,” says Colin Robertson, a former Canadian diplomat in Washington and Hong Kong.

Energy security, and the possible shipment of Alberta oil to China, are arguments Canadians are already using to overcome environmental objections to the TransCanada Pipelines XL pipeline, which would extend an Alberta oil sands link to Texas.

Proponents of West Coast pipeline argue it would diversify markets, allow a better price for oil exports, and encourage China to improve trade arrangements with Canada, such as investment protections or a broader trade deal. Mr. Robertson argues it would also provide leverage with the United States, attracting attention to encourage the approval of pipelines, improving electricity-grid links, even speeding the flow of goods at the border.

Pipeline projects take years of regulatory and government decisions, but if the Canadian government announced it was making a West Coast pipeline a priority, it would send both an encouraging signal to China and make the United States take notice, he argues.

Some doubt that would work, unless Canada was willing to play rough and offer the United States a quid pro quo – perhaps delaying a West Coast pipeline, or discouraging fast growth in Chinese energy investment. But the real benefit of a West Coast pipeline is still diversifying markets to China, and solidifying ties with a rising power, one Conservative politician argued.

That would require controversial domestic decisions. The Northern Gateway faces stiff opposition from environmentalists and first nations. Some who favour a pipeline worry itÂ’s the wrong project because of those hurdles.

Aside from narrow economic interests, some argue that energy and pipelines are a way for Canada to expand its small role, a little, in the big game of shaping the two-superpower world.

The big question behind the Obama-Hu summit is whether superpower China joins a club of nations that deals with security outliers such as Iran and North Korea, and co-operates to create a more stable international economy. Mr. Robertson says Canada has historic, trade and people ties with both the United States and China, and real interests such as energy that concern them, that it can use to influence the new order.

“We really have an opportunity to play, if we choose to.”

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ERCOT Issues RFP to Procure Capacity to Alleviate Winter Concerns

ERCOT Winter Capacity RFP seeks up to 3,000 MW through generation and demand response to bolster Texas grid reliability during peak load, leveraging Reliability Must-Run, incentive factors, and EEA risk mitigation for the 2023-24 season.

 

Key Points

An ERCOT initiative to procure 3,000 MW of generation and demand response to reduce EEA risk and improve reliability.

✅ Targets 3,000 MW from generation and demand response

✅ Uses RMR-style contracts with flexible incentive factors

✅ Aims to lower EEA probability below 10% this winter

 

The Electric Reliability Council of Texas (ERCOT) issued a request for proposals to stakeholders to procure up to 3,000 MW of generation or demand response capacity to meet load and reserve requirements during the winter 2023-24 peak load season (Dec. 1, 2023, through Feb. 29, 2024), amid ongoing Texas power grid challenges across the region.

ERCOT cited “several factors, including significant peak load growth since last winter, recent and proposed retirements of dispatchable Generation Resources, and recent extreme winter weather events, including Winter Storm Elliott in December 2022, Winter Storm Uri in February 2021, and the 2018 and 2011 winter storms, each of which resulted in abnormally high demand during winter weather.” It now seeks additional capacity under its “authority to prevent an anticipated Emergency Condition,” reflecting nationwide blackout risks identified by grid experts.

In its notice regarding the RFP, ERCOT identified a number of mothballed and recently decommissioned generation resources that may be eligible to offer capacity under the RFP. It further stated that offers must comport with the format of its “Reliability Must-Run” agreement but could include a proposed “Incentive Factor” that reflects the revenues the unit owners determine would be necessary to bring the unit back to operation. It added that the Incentive Factor is not necessarily limited to 10%. Providers of eligible demand response can submit offers based on similar principles that are not necessarily constrained by cost. The notice identifies potential acceptable sources of demand response, describes certain parameters for the kinds of demand response that are permitted to respond to the RFP, and outlines the time periods during which ERCOT must be able to deploy the demand response resources to improve electricity reliability across the system.

To meet the Dec. 1, 2023, service start date, ERCOT developed an aggressive timeline to solicit and evaluate proposals through the RFP. Responses to the RFP are due Nov. 6, 2023. ERCOT’s schedule provides that it will notify market participants that obtain awards on Nov. 23, 2023. Expect contracts to be executed by Nov. 30, 2023.

Unlike Regional Transmission Organizations in the Northeastern United States, ERCOT does not have a capacity market. Instead, ERCOT relies on a high price cap of $5,000 per MWh for its energy market (decreased from the $9,000 per MWh cap in effect during Winter Storm Uri) and an Operating Reserve Demand Curve adder that pays additional funds to generators supplying power and ancillary services, an area recently scrutinized for improper payments when supply conditions are tight. In the wake of Winter Storm Uri, some calls were made to have ERCOT adopt a capacity market for reliability reasons, and a number of legal battles continue to play out in the wake of Winter Storm Uri. (See recent McGuireWoods legal alert “Winter Storm Uri Power Dispute Reaches the Supreme Court of Texas.”) Though a capacity market was not adopted, the Texas Legislature approved a $7.2 billion loan program, widely described as an electricity market bailout for generators, to build up to 10,000 MW of dispatchable generation. The legislature also approved a version of the Public Utility Commission of Texas’ proposal to establish a “Performance Credit Mechanism,” but with a cost cap of $1 billion.

The loss of life and economic impacts of Winter Storm Uri in 2021, along with the energy crunches and calls for conservation this past summer, are driving changes to ERCOT’s “energy-only” market, including electricity market reforms under consideration. Texas policymakers are providing multiple financial incentives to promote investment in dispatchable on-demand generation, and voters will consider funding to modernize generation measures this year to make the Texas grid more reliable and able to deal with power demand from a growing economy and increased demand for electricity driven by weather. In the meantime, ERCOT’s plan to procure 3,000 MW through this RFP process is a stopgap measure intended to bolster reliability for the upcoming winter season and lower the probability of load shed in the event of severe winter weather.

 

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Tesla CEO Elon Musk slams Texas energy agency as unreliable: "not earning that R"

ERCOT Texas Power Grid Crisis disrupts millions amid a winter storm, with rolling blackouts, power outages, and energy demand; Elon Musk criticizes ERCOT as Tesla owners use Camp Mode while wind turbines face icing

 

Key Points

A Texas blackout during a winter storm, exposing ERCOT failures, rolling blackouts, and urgent grid resilience measures.

✅ Millions without power amid record cold and energy demand

✅ Elon Musk criticizes ERCOT over grid reliability failures

✅ Tesla Camp Mode aids warmth during extended outages

 

Tesla CEO Elon Musk on Wednesday slammed the Texas agency responsible for a statewide blackout amid a U.S. grid with frequent outages that has left millions of people to fend for themselves in a freezing cold winter storm.

Musk tweeted that Texas’ power grid manager, the Electricity Reliability Council of Texas (ERCOT), is not earning the “R” in the acronym, highlighting broader grid vulnerabilities that critics have noted.

Musk moved to Texas from California in December and is building a new Tesla factory in Austin. His critique of the state’s electrical grid operator came after multiple Tesla owners in the state said they had slept in their vehicles to keep warm amid the lingering power outage.

In 2019, Tesla released a vehicle with a “Camp Mode,” which enables owners to use the vehicle’s features – like lights and climate control – without significantly depleting the battery.

“We had the power go out for 6 hours last night. Our house does not have gas, and we ran out of firewood... what are we going to do,” one Reddit user wrote on “r/TeslaMotors.”

“So my wife my dog and my newborn daughter slept in the garage in our Model3 all nice and cozy. If I didn't have this car, it would have been a very rough night.”

More than two dozen people have died in the extreme weather this week, some while struggling to find warmth inside their homes. In the Houston area, one family succumbed to carbon monoxide from car exhaust in their garage. Another perished as they used a fireplace to keep warm.

Utilities from Minnesota to Texas and Mississippi have implemented rolling blackouts to ease the burden on power grids straining to meet extreme demand for heat and electricity, as longer, more frequent outages hit systems nationwide.

More than 3 million customers remained without power in Texas, Louisiana and Mississippi, more than 200,000 more in four Appalachian states, and nearly that many in the Pacific Northwest, according to poweroutage.us, which tracks utility outage reports, and advocates warn that millions could face summer shut-offs without protections.

ERCOT said early Wednesday that electricity had been restored to 600,000 homes and businesses by Tuesday night, though nearly 3 million homes and businesses remained without power, as California turns to batteries to help balance demand. Officials did not know when power would be restored.

ERCOT President Bill Magness said he hoped many customers would see at least partial service restored soon but could not say definitively when that would be.

Magness has defended ERCOT’s decision, saying it prevented an “even more catastrophic than the terrible events we've seen this week."

Utility crews raced Wednesday to restore power to nearly 3.4 million customers around the U.S. who were still without electricity in the aftermath of a deadly winter storm, even as officials urge residents to prepare for summer blackouts that could tax systems further, and another blast of ice and snow threatened to sow more chaos.

The latest storm front was expected to bring more hardship to states that are unaccustomed to such frigid weather — parts of Texas, Arkansas and the Lower Mississippi Valley — before moving into the Northeast on Thursday.

"There's really no letup to some of the misery people are feeling across that area," said Bob Oravec, lead forecaster with the National Weather Service, referring to Texas.

Sweden, known for its brutally cold climate, has offered some advice to Texans unaccustomed to such freezing temperatures, as Canadian grids are increasingly exposed to harsh weather that strains reliability. Stefan Skarp of the Swedish power company told Bloomberg on Tuesday: “The problem with sub-zero temperatures and humid air is that ice will form on the wind turbines.”

“When ice freezes on to the wings, the aerodynamic changes for the worse so that wings catch less and less wind until they don't catch any wind at all,” he said.

 

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California proposes income-based fixed electricity charges

Income Graduated Fixed Charge aligns CPUC billing with utility fixed costs, lowers usage rates, supports electrification, and shifts California investor-owned utilities' electric bills by income, with CARE and Climate Credit offsets for low-income households.

 

Key Points

A CPUC proposal: an income-based monthly fixed fee with lower usage rates to align costs and aid low-income customers.

✅ Income-tiered fixed fees: $0-$42; CARE: $14-$22, by utility territory

✅ Usage rates drop 16%-22% to support electrification and cost-reflective billing

✅ Lowest-income save ~$10-$20; some higher earners pay ~$10+ more monthly

 

The Public Advocates Office (PAO) for the California Public Utilities Commission (CPUC) has proposed adding a monthly income-based fixed charge on electric utility bills based on income level.  

The rate change is designed to lower bills for the lowest-income residents while aligning billing more directly with utility costs. 

PAO’s recommendation for the Income Graduated Fixed Charge places fees between $22 and $42 per month in the three major investor-owned utilities’ territories, including an SDG&E minimum charge debate under way, for customers not enrolled in the California Alternative Rates for Energy (CARE) program. As seen below, CARE customers would be charged between $14 per month and $22 a month, depending on income level and territory.

For households earning $50,000 or less per year, the fixed charge would be $0, but only if the California Climate Credit is applied to offset the fixed cost.

Meanwhile, usage-based electricity rates are lowered in the PAO proposal, part of major changes to electric bills statewide. Average rates would be reduced between 16% to 22% for the three major investor-owned utilities.

The lowest-income bracket of Californians is expected to save roughly $10 to $20 a month under the proposal, while middle-income customers may see costs rise by about $20 a month, even as lawmakers seek to overturn income-based charges in Sacramento.

“We anticipate the vast majority of low-income customers ($50,000 or less per year) will have their monthly bills decrease by $10 or more, and a small proportion of the highest income earners ($100,000+ per year) will see their monthly bills rise by $10 or more,” said the PAO.

The charges are an effort to help suppress ever-increasing electricity generation and transmission rates, which are among the highest in the country, with soaring electricity prices reported across California. Rates are expected to rise sharply as wildfire mitigation efforts are implemented by the utilities found at fault for their origin.

“We are very concerned. However, we do not see the increases stopping at this point,” Linda Serizawa, deputy director for energy, PAO, told pv magazine. “We think the pace and scale of the [rate] increases is growing faster than we would have anticipated for several years now.”

Consumer advocates and regulators face calls for action on surging electricity bills across the state.

The proposed changes are also meant to more directly couple billing with the fixed charges that utilities incur, as California considers revamping electricity rates to clean the grid. For example, activities like power line maintenance, energy efficiency programs, and wildfire prevention are not expected to vary with usage, so these activities would be funded through a fixed charge.

Michael Campbell of the PAO’s customer programs team, and leader of the proposed program, likened paying for grid enhancements and other social programs with utility rate increases to “paying for food stamps by taxing food.” Instead, a fixed charge would cover these costs.

PAO said the move to lower rates for usage should help encourage electrification as California moves to replace heating and cooling, appliances, and gas combustion cars with electrified counterparts. In addition, lower rates mean the cost burden of running these devices is improved.

 

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Alberta ratepayers on the hook for unpaid gas and electricity bills from utility deferral program

Alberta Utility Rate Rider will add a modest fee to electricity bills and natural gas charges as the AUC recovers outstanding debt from the COVID-19 deferral program via AESO and the Balancing Pool.

 

Key Points

A temporary surcharge on Alberta power and gas bills to recover unpaid COVID-19 deferral debt, administered by the AUC.

✅ Applies per kWh and per GJ based on consumption

✅ Recovers unpaid balances from 2020-21 bill deferrals

✅ Collected via AESO and the Balancing Pool under AUC oversight

 

The province says Alberta ratepayers should expect to see an extra fee on their utility bills in the coming months.

That fee is meant to recover the outstanding debt owed to gas and electricity providers resulting from last year's three-month utility deferral program offered to struggling Albertans during the pandemic.

The provincial government announced the utility deferral program in March 2020 then formalized it with legislation, alongside a consumer price cap on power bills that shaped later policy decisions.

The program allowed residential, farm and small commercial customers who used less than 250,000 kilowatt hours of electricity per year — or consumed less than 2,500 gigajoules per year — to postpone their bills amid the COVID-19 pandemic.

According to the province, 350,000 customers, or approximately 13 per cent of the natural gas and electricity consumer base, took advantage of the program.

Customers had a year to repay providers what they owed. That deadline ended June 18, 2021.

The Alberta Utilities Commission (AUC), which regulates the utilities sector and natural gas and electricity markets and oversees a rate of last resort framework, said the vast majority of consumers have squared up.

But for those who didn't, provincial legislation dictates that Alberta ratepayers must cover any unpaid debt. The legislation exempts Medicine Hat utility customers for electricity and gas co-operative customers for gas.

"When the program was announced, it was very clear that it was a deferral program and that the monies would need to be paid back," said Geoff Scotton, a spokesperson with the Alberta Utilities Commission.

"Now we're in the situation where the providers, in good faith, who enabled those payment deferrals, need to be made whole. That's really the goal here."

Amount to be determined
Margeaux Maron, a spokesperson for Associate Minister of Natural Gas and Electricity Dale Nally, said based on early estimates, $13 to $16 million of $92 million in deferred payments remain outstanding.

As a result, the province expects the average Albertan will end up paying, unlike jurisdictions offering a lump-sum credit, a fraction of a dollar extra per monthly gas and electricity bill over a handful of months.

Scotton said at this point, there are too many unknown factors to know the exact size of the rate rider. However, he said he expects it to be modest.

Scotton said affected parties first have until the end of this week to notify the AUC exactly how much they are still owed.

Those parties include the Alberta Electric System Operator and the Balancing Pool, who essentially acted as bankers with respect to the distribution and transmission of the utilities to customers who deferred their payments.

Regulated service providers may also seek reimbursement on administrative and carrying costs, even as issues like a BC Hydro fund surplus spark debate elsewhere.

Then, Scotton said, once the outstanding amounts are known, the AUC will hold a public proceeding, similar to a Nova Scotia rate case, to determine the amount and the duration of the rate rider to be applied to each natural gas and electricity bill.

The amount will be based on consumption: per kilowatt hour for electricity and per gigajoule for natural gas.

That means larger businesses will end up paying more than the average Albertan.

Scotton said the AUC will expedite the hearing process and it expects to have a decision by the end of the summer.

Rate rider a 'surprise'
Joel MacDonald with Energyrates.ca — an organization which compares energy rates across the country — said it's not the amount of the rate rider that bothers him, but the fact that the repayment process wasn't made clear at the onset of the program.

"It came to us as a bit of a surprise," MacDonald said.

He said what was sold as a deferral program seems more like an electricity rebate program, or an "ability to pay" program.

"As opposed to the retailers looking into collection methods, anything that wasn't paid is basically just being forced upon all Alberta consumers," MacDonald said.

The expectation set out in the deferral legislation and regulations state utility providers such as Enmax and Epcor are expected to use reasonable efforts to try to collect the unpaid balances. It must then detail those reasonable efforts to the AUC.

A spokesperson for Enmax said it first works with its customers to find manageable payment arrangements and connects them with support services if they are unable to pay.

Then, if payment can't be arranged, it said it will work with a collection agency, which may even result in disconnection of service.

The spokesperson said only after all efforts have failed would Enmax seek reimbursement through this program.

Use tax revenues?
MacDonald also questioned why a government program isn't being paid for through general tax revenues.

He compared the utility deferral program to a mortgage subsidy program.

"Imagine that [Canada Mortgage And Housing Corporation] said, 'Hey, we had to give mortgage deferrals and some of these people never paid back their deferrals, so we're going to add an extra $300 to everyone's mortgage,'" he said.

"You'd expect that to come off of some sort of general taxation — not being assigned to other people's mortgages, right?"

In response, Maron said due to the current fiscal challenges facing the government — and the expected minimal costs to consumers, and even as a consumer price cap on electricity remains in place — it was determined that a rate rider would be an appropriate mechanism to repay bad debt associated with the program.

Scotton said rate riders aren't unusual — they're used to fine-tune rates for a set period of time.

He said under normal circumstances, regulated service providers can apply to the AUC to impose a rate rider to recover unexpected costs. And in some instances, they can provide a credit.

But in this situation, he said the debt is aggregated and, in turn, being collected more broadly.

 

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Project examines potential for Europe's power grid to increase HVDC Technology

HVDC-WISE Project accelerates HVDC technology integration across the European transmission system, delivering a planning toolkit to boost grid reliability, resilience, and interconnectors for renewables and offshore wind amid climate, cyber, and physical threats.

 

Key Points

EU-funded project delivering tools to integrate HVDC into Europe's grid, improving reliability, resilience, and security.

✅ EU Horizon Europe-backed consortium of 14 partners

✅ Toolkit to assess extreme events and grid operability

✅ Supports interconnectors, offshore wind, and renewables

 

A partnership of 14 leading European energy industry companies, research organizations and universities has launched a new project to identify opportunities to increase integration of HVDC technology into the European transmission system, echoing calls to invest in smarter electricity infrastructure from abroad.

The HVDC-WISE project, in which the University of Strathclyde is the UK’s only academic partner, is supported by the European Union’s Horizon Europe programme.

The project’s goal is to develop a toolkit for grid developers to evaluate the grid’s performance under extreme conditions and to plan systems, leveraging a digital grid approach that supports coordination to realise the full range of potential benefits from deep integration of HVDC technology into the European transmission system.

The project is focused on enhancing electric grid reliability and resilience while navigating the energy transition. Building and maintaining network infrastructure to move power across Europe is an urgent and complex task, and reducing losses with superconducting cables can play a role, particularly with the continuing growth of wind and solar generation. At the same time, threats to the integrity of the power system are on the rise from multiple sources, including climate, cyber, and physical hazards.

 

Mutual support

At a time of increasing worries about energy security and as Europe’s electricity systems decarbonise, connections between them to provide mutual support and routes to market for energy from renewables, a dynamic also highlighted in discussions of the western Canadian electricity grid in North America, become ever more important.

In modern power systems, this means making use of High Voltage Direct Current (HVDC) technology.

The earliest forms of technology have been around since the 1960s, but the impact of increasing reliance on HVDC and its ability to enhance a power system’s operability and resilience are not yet fully understood.

Professor Keith Bell, Scottish Power Professor of Future Power Systems at the University of Strathclyde, said:

As an island, HVDC is the only practical way for us to build connections to other countries’ electricity systems. We’re also making use of it within our system, with one existing and more planned Scotland-England subsea link projects connecting one part of Britain to another.

“These links allow us to maximise our use of wind energy. New links to other countries will also help us when it’s not windy and, together with assets like the 2GW substation now in service, to recover from any major disturbances that might occur.

“The system is always vulnerable to weather and things like lightning strikes or short circuits caused by high winds. As dependency on electricity increases, insights from electricity prediction specialists can inform planning as we enhance the resilience of the system.”

Dr Agusti Egea-Alvarez, Senior Lecturer at Strathclyde, said: “HVDC systems are becoming the backbone of the British and European electric power network, either interconnecting countries, or connecting offshore wind farms.

“The tools, procedures and guides that will be developed during HVDC-WISE will define the security, resilience and reliability standards of the electric network for the upcoming decades in Europe.”

Other project participants include Scottish Hydro Electric Transmission, the Supergrid Institute, the Electric Power Research Institute (EPRI) Europe, Tennet TSO, Universidad Pontificia Comillas, TU Delft, Tractebel Impact and the University of Cyprus.

 

Climate change

Eamonn Lannoye, Managing Director of EPRI Europe, said: “The European electricity grid is remarkably reliable by any standard. But as the climate changes and the grid becomes exposed to more extreme conditions, energy interdependence between regions intensifies and threats from external actors emerge. The new grid needs to be robust to those challenges.”

Juan Carlos Gonzalez, a senior researcher with the SuperGrid Institute which leads the project said: “The HVDC-WISE project is intended to provide planners with the tools and know-how to understand how grid development options perform in the context of changing threats and to ensure reliability.”

HVDC-WISE is supported by the European Union’s Horizon Europe programme under agreement 101075424 and by the UK Research and Innovation Horizon Europe Guarantee scheme.

 

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Trump's Vision of U.S. Energy Dominance Faces Real-World Constraints

U.S. Energy Dominance envisions deregulation, oil and gas growth, LNG exports, pipelines, and geopolitical leverage, while facing OPEC pricing power, infrastructure bottlenecks, climate policy pressures, and accelerating renewables in global markets.

 

Key Points

U.S. policy to grow fossil fuel output and exports via deregulation, bolstering energy security, geopolitical influence.

✅ Deregulation to expand drilling, pipelines, and export capacity

✅ Exposed to OPEC pricing, global shocks, and cost competitiveness

✅ Faces infrastructure, ESG finance, and renewables transition risks

 

Former President Donald Trump has consistently advocated for “energy dominance” as a cornerstone of his energy policy. In his vision, the United States would leverage its abundant natural resources to achieve energy self-sufficiency, flood global markets with cheap energy, and undercut competitors like Russia and OPEC nations. However, while the rhetoric resonates with many Americans, particularly those in energy-producing states, the pursuit of energy dominance faces significant real-world challenges that could limit its feasibility and impact.

The Energy Dominance Vision

Trump’s energy dominance strategy revolves around deregulation, increased domestic production of oil and gas, and the rollback of climate-oriented restrictions. During his presidency, he emphasized opening federal lands to drilling, accelerating the approval of pipelines, and, through an executive order, boosting uranium and nuclear energy initiatives, as well as withdrawing from international agreements like the Paris Climate Accord. The goal was not only to meet domestic energy demands but also to establish the U.S. as a major exporter of fossil fuels, thereby reducing reliance on foreign energy sources.

This approach gained traction during Trump’s first term, with the U.S. achieving record levels of oil and natural gas production. Energy exports surged, making the U.S. a net energy exporter for the first time in decades. Yet, critics argue that this policy prioritizes short-term economic gains over long-term sustainability, while supporters believe it provides a roadmap for energy security and geopolitical leverage.

Market Realities

The energy market is complex, influenced by factors beyond the control of any single administration, with energy crisis impacts often cascading across sectors. While the U.S. has significant reserves of oil and gas, the global market sets prices. Even if the U.S. ramps up production, it cannot insulate itself entirely from price shocks caused by geopolitical instability, OPEC production cuts, or natural disasters.

For instance, despite record production in the late 2010s, American consumers faced volatile gasoline prices during an energy crisis driven by $5 gas and external factors like tensions in the Middle East and fluctuating global demand. Additionally, the cost of production in the U.S. is often higher than in countries with more easily accessible reserves, such as Saudi Arabia. This limits the competitive advantage of U.S. energy producers in global markets.

Infrastructure and Environmental Concerns

A major obstacle to achieving energy dominance is infrastructure. Expanding oil and gas production requires investments in pipelines, export terminals, and refineries. However, these projects often face delays due to regulatory hurdles, legal challenges, and public opposition. High-profile pipeline projects like Keystone XL and Dakota Access have become battlegrounds between industry proponents and environmental activists, and cross-border dynamics such as support for Canadian energy projects amid tariff threats further complicate permitting, highlighting the difficulty of reconciling energy expansion with environmental and community concerns.

Moreover, the transition to cleaner energy sources is accelerating globally, with many countries committing to net-zero emissions targets. This trend could reduce the demand for fossil fuels in the long run, potentially leaving U.S. producers with stranded assets if global markets shift more quickly than anticipated.

Geopolitical Implications

Trump’s energy dominance strategy also hinges on the belief that U.S. energy exports can weaken adversaries like Russia and Iran. While increased American exports of liquefied natural gas (LNG) to Europe have reduced the continent’s reliance on Russian gas, achieving total energy independence for allies is a monumental task. Europe’s energy infrastructure, designed for pipeline imports from Russia, cannot be overhauled overnight to accommodate LNG shipments.

Additionally, the influence of major producers like Saudi Arabia and the OPEC+ alliance remains significant, even as shifts in U.S. policy affect neighbors; in Canada, some viewed Biden as better for the energy sector than alternatives. These countries can adjust production levels to influence prices, sometimes undercutting U.S. efforts to expand its market share.

The Renewable Energy Challenge

The growing focus on renewable energy adds another layer of complexity. Solar, wind, and battery storage technologies are becoming increasingly cost-competitive with fossil fuels. Many U.S. states and private companies are investing heavily in clean energy to align with consumer preferences and global trends, amid arguments that stepping away from fossil fuels can bolster national security. This shift could dampen the domestic demand for oil and gas, challenging the long-term viability of Trump’s energy dominance agenda.

Moreover, international pressure to address climate change could limit the expansion of fossil fuel infrastructure. Financial institutions and investors are increasingly reluctant to fund projects perceived as environmentally harmful, further constraining growth in the sector.

While Trump’s call for U.S. energy dominance taps into a desire for economic growth and energy security, it faces numerous challenges. Global market dynamics, infrastructure bottlenecks, environmental concerns, and the transition to renewable energy all pose significant barriers to achieving the ambitious vision.

For the U.S. to navigate these challenges effectively, a balanced approach that incorporates both traditional energy sources and investments in clean energy is likely needed. Striking this balance will require careful policymaking that considers not just immediate economic gains but also long-term sustainability and global competitiveness.

 

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